殼牌 (SHEL) 2012 Q1 法說會逐字稿

Welcome to the Royal Dutch Shell Q1 announcement call.

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

(Operator Instructions) I would like to introduce our host, Mr. Simon Henry.

Please go ahead.

Thanks very much, Operator.

Welcome to Royal Dutch Shell's first-quarter 2012 results presentation.

Good morning, or good afternoon, wherever you may be.

I'll take you through the results and the portfolio development for the quarter and leave plenty of time for questions.

First of all, though, cautionary statement.

Quarterly results are important, but they still remain a snapshot of performance in a volatile industry, where we are in the process of implementing a long-term strategy.

First-quarter earnings excluding identified items, was $7.3 billion.

Also an earnings per share increase of 15% compared to the first quarter last year.

With $2.4 billion of divestments in the quarter, we're increasing divestment target for this year from $2 billion to $3 billion range to at least $4 billion.

Underlying oil and gas production increased by 4% in the quarter.

We started up new projects in upstream and now in the downstream to further growth.

And we continue to mature new options, mostly of course in the upstream, with successful drilling in the Gulf.

And new exploration acreage in the quarter.

So this continues progress we made on the new options in 2011.

For example the Abadi floating LNG project in Indonesia and the additional liquids-rich shale positions.

The dividend for quarter one will increase year over year, with a strategy delivering underlying and sustainable financial growth.

So we're making good progress against that target to deliver a more competitive performance.

I'll give you some more detail, starting with the macro environment.

If you look at the macro picture compared to the first quarter last year, all prices are higher.

There is an increase in the differential between Brent and WTI.

Our overall global natural gas realizations increased from the first quarter 2011.

Although, of course, the US, Henry Hub-related prices declined quite sharply.

Our overall refining, marketing, and chemicals margins were all weaker for Shell year over year.

Currently, we're seeing a very mixed picture on energy demand.

Oil prices have been supported by geo-political events, despite a market which, in our view, is fundamentally well supplied.

We've seen LNG demand increasing year over year, led by Asia.

In the US, combination of improving economic conditions and low gas prices are now stimulating gas demand.

But European gas demand remains weak, due to the weak overall economic conditions and basically price competition with coal.

In oil products, our underlying volumes were flat quarter one to quarter one.

Demand is being eroded in developed markets by high prices.

Our volume was flat in Europe and the US, and firm demand for branded fuels in Asia.

Economic outlook remains very uncertain, particularly in Europe, where many commentators see the prospects of a new recession.

Those are the Q1 to Q1 trends.

In aggregate, a weak demand picture, little evidence for fundamental year over year recovery.

Or, in fact, much improvement since the fourth quarter 2011.

Before I turn to earnings, let me just highlight that we published country level tax information for the first time yesterday.

And Shell is committed to high standards of transparency to all stakeholders.

And we've had a number of questions from you on this topic.

And I hope, if you access the information on the website, you'll find this information useful.

And I would be happy to take any questions you might have on it.

Moving on to the earnings, current cost of supply, CCS, earnings in the quarter, including the identified items, was $7.7 billion.

Excluding identified items, the earnings were $7.3 billion.

Earnings per share increased 15% compared to 2011.

On a quarter one to quarter one basis, earnings in upstream were higher, in downstream lower.

Cash flow generated from operations was $13.4 billion.

Dividends in the quarter were $2.7 billion, of which $1 billion was settled with the new shares under the scrip dividend program.

Now, we are offering the scrip again for the first quarter 2012.

We have recently restarted share buybacks in the quarter, the second quarter, that is.

And that's part of our overall strategic intention to offset dilution from the scrip.

Scrip dividends have now totaled over $5 billion since we launched in 2010.

Just let me talk about the business performance in a little more detail.

Upstream earnings, excluding identified items, are $6.3 billion in the first quarter.

And that's an increase of 35% versus the same quarter last year.

The earnings were, of course, driven by higher oil and international gas prices.

But also by volume growth from high-margin new projects, particularly in Qatar.

And also a positive environment for gas trading.

There were some offsets from higher cost and depreciation and lower US Henry Hub gas prices.

The headline oil and gas production for first quarter was 3.6 million barrels of oil equivalent per day.

That is an increase of 4% excluding asset sales exit and price impacts.

In addition, we had some 80,000 barrels of oil equivalent per day of entitlement loss from profit-sharing contracts, as our lower entitlement kicked in at contracted milestones.

And high oil prices moved some PSCs out of cost recovery mode.

The LNG sales volumes grew by 17% quarter one to quarter one.

That reflects basically growth from Qatargas 4 and Nigeria LNG.

The year over year planned maintenance impacts were negligible in the first quarter, upstream and downstream.

So during the second quarter, though, of 2012, looking forward, there will be higher levels of planned maintenance activities on offshore fields in the Americas, in Asia-Pacific, and in Europe.

This is expected to lead to a production impact, a negative impact, of some 50,000 barrels of oil equivalent per day across second quarter, and that's compared to the second quarter in 2011.

In Qatar, Pearl gas-to-liquids projects continues to make good progress.

We're on track to reach full capacity in the middle of 2012, as always planned.

We are running plant maintenance on sections of both the Pearl trains during the second quarter.

These pit stops, they are part of the start-up phase of the project, clearly impact production.

The three large start-ups last year -- Qatargas 4, Pearl, and the Athabasca oil sand project in Canada -- are capable of producing 450,000 barrels of oil equivalent per day at their peak production or capacity.

These three projects alone produced some 360,000 barrels a day in the first quarter.

That compares with 130,000 barrels a year ago.

So clearly significant growth from them.

And clearly also further growth to come.

I would expect the three projects to deliver a fairly similar production level in the second quarter as first quarter this year, reflecting the pit stops I just mentioned.

Turning now to the downstream.

Excluding identified items, the downstream CCS earnings were $1.1 billion.

That's lower than year-ago levels.

Oil products results were lower than year-ago levels.

But similar year over year numbers in chemical.

In aggregate, refining marketing and trading margins were all weaker compared to Q1 2011, somewhat less from the Raizen joint venture in Brazil and from lower operating costs.

However, we did see an improvement in refining, chemicals and trading conditions compared to the fourth quarter 2011, which was a particularly weak quarter.

Although marketing margins were weaker sequentially.

This was due to continuing rising oil prices in a weak demand environment.

Chemicals and refinery manufacturing availability were both higher than a year ago.

They also improved against what was not a good fourth quarter.

We're expecting worldwide refinery and chemicals availability for the second quarter '12 to be in line with the second quarter 2011.

These are better figures from downstream overall, but clearly, still a difficult environment.

And we're just not where we want to be here.

So those are the earnings.

Turning to cash flow.

Cash generation on a 12-month rolling basis was some $50 billion, including $6.8 billion of divestment proceeds.

With an average Brent price across that period of $115 per barrel.

Both the upstream and the downstream segments generated surplus cashflow after investment.

As a result, the gearing at the end of the first quarter sat at 9.9%.

That compares with 13% at the end of the fourth quarter.

And clearly, we're moving lower in the zero to 30% range as, of course, you would expect in strong oil price conditions.

Disposals are an important element to Shell's capital efficiency and our overall portfolio enhancement program.

And the divestments broadly matched acquisitions in recent years.

We're making good progress this year, with $2.4 billion of divestments in this quarter.

We'll also find further deals that we'll complete later in 2012.

So, as a result, we now expect over $4 billion of asset sales in 2012.

That's an increase, of course, from our previous $2 billion to $3 billion guidance.

We sold some $36 billion in assets in the last five years.

Rollovers ran 17% of our capital employed.

And I'm particularly pleased in this quarter to welcome new strategic partners into our Prelude floating LNG venture in Australia.

Where impacts of Japan, KOGAS Korea and CPC in Taiwan have now joined us.

This partnership monetizes some of our own Shell optionality at an early stage and are part of Shell's plans for new growth in global gas.

Our organic spending guidance total of capital investment for 2012 remains at $32 billion, excluding, as we said before, up to $1 billion dollar of spend, assuming we get access to drill in Alaska this year.

We continue to look for additional acreage positions in exploration and undeveloped resource positions.

We spent around $0.6 billion on this in the first quarter.

Quite likely there is more to come as we go through the year.

Let me update you on progress on the growth portfolio.

Production has now commenced at the Caesar/Tonga project in the Gulf of Mexico.

And the Pluto LNG project in Australia is reached ready for startup status.

Together, the two upstream projects are expected to add a total of 40,000 barrels of oil equivalent per day and 0.9 million tons per annum of LNG.

On the downstream side, we've just started processing crude in the Port Arthur refinery expansion project.

That will create the largest refinery in the United States, some 600,000 barrels a day of overall total refining capacity.

These three projects are all part of the diverse portfolio, some 26 projects, we previously discussed that Shell is developing worldwide today.

We're driving the targets that we've set for cash flow and production.

We also made progress maturing new projects with medium-term growth potential during the quarter.

We signed up over 77,000 square kilometers of acreage so far this year, including high potential frontier positions in deepwater in Nova Scotia and in Canada, in Tanzania offshore, and in the Orange Basin in South Africa.

In the Gulf of Mexico, we had good drilling results in the Appomattox prospect.

This is a Jurassic reservoir.

So new to the industry we are just learning.

So we're now estimating $0.5 billion barrels of potential in this field.

We also see further upside potential as we drill new wells in the area.

Now, earlier this week, we announced an intended cash offer for Cove Energy plc in the UK.

And this was recommended by Cove's board.

This is part of a strategy to build up our presence in East Africa.

And Cove would mark our entry into Mozambique gas and also new exploration potential in both Mozambique and Kenya.

The total cost for Shell is expected to be just below $2 billion.

That includes the price to Cove shareholders and an estimate of the capital gains tax charge.

So, good progress on the growth portfolio.

The call wouldn't be complete without some comments on dividends.

Shell has a strong track record on dividends.

Dividends are the Company's main route to return cash to shareholders.

Over the last 10 years, we've paid more dividends than any of our sector peer group.

And absent further changes to stated dividends, we will still be the largest dividend payer in our peer group.

We haven't cut our dividend for decades.

And I would just like to reiterate we maintained our dividend across the credit crisis, despite the pressures we were under.

We used the balance sheet to maintain both the dividend and the growth spending in 2009-10.

And that was in a period when many investors worried we would be forced into a curve.

We have reduced our costs, we are delivering growth, and it is this structural improvement that is driving the increase in dividends that we confirmed today.

That's a return to growth after a pause in 2010 and '11.

Now, oil prices have almost doubled since 2009, whereas defining margins in the US natural gas price clearly have remained low, or gotten lower.

We as a company must look through the short-term volatility when we plan for dividends.

And we take decisions on a long-term policy basis.

There is no simple mechanical formula.

The resumption of the measured affordable dividend growth that we've confirmed today reflects the improving underlying financial position of the Company and the delivery of our strategy, in line with policy.

So just let me summarize before we go to questions.

First-quarter earnings have increased from year-ago levels, driven by operating performance, new projects, and strong oil prices.

And this is despite the continued challenges for our industry in the downstream and in North American natural gas pricing.

With $2.4 billion of divestments in the quarter, we're increasing the divestment target for the year to over $4 billion.

Our underlying oil and gas production increased by 4% in the quarter.

We're starting up new projects in upstream and downstream for further growth.

The dividend for quarter one will increase, with our strategy delivering sustainable financial growth.

And we continue to mature growth options and, of course, mostly in the upstream.

So, making good progress against targets to deliver a more competitive performance.

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

And please, could we just have one or two questions each so everybody has the opportunity.

Operator, please, could you poll for questions?

Thank you.

(Operator Instructions) Teplan Justalingram from Nomura International.

Thank you for your comments.

Two questions, please.

Firstly, a very good number in integrated gas.

I'm being greedy, but is there any way to disclose the split between GTL and LNG?

Or, put it another way, could you give us maybe the delta quarter on quarter for LNG and some comments on whether you think this result is sustainable going forward?

Secondly, there have been some media headlines this morning about your intentions in Mozambique.

Could you confirm whether you've already been in discussions with some of the existing players in Mozambique before you made a higher bid for Cove?

And is it right to guess that you're pretty confident you're going to increase the state beyond Cove?

Thank you.

Thanks, Teplan.

Thanks for the comments.

Integrated gas is indeed the main driver of the improved upstream earnings before the sand cash flow.

It is, of course, the strategy playing out in action.

We've been saying for sometime this is core to Shell strategy.

So an increase of $1.35 billion-or-so in the earnings.

Qatar, both projects are responsible for about 60% of that.

The remainder is split roughly equally between additional volumes ahead of Nigeria and Russia, better pricing.

And better opportunities from cargo diversions, simply because we have more LNG to work with.

And, of course, the markets being fairly tight in the quarter.

So it is strategy coming into action.

In the same macro, then, yes, it would be basically sustainable.

It's also fairly robust, given, as you're probably aware, the majority of the LNG volumes and obviously the GTL volumes are oil price linked.

Very little exposure, by definition, in the integrated gas segment to lower prices.

For example, in the US or spot prices in Europe.

Media headlines on Mozambique and Cove, I have to say I've not read them so I can't comment specifically.

But what we have said is, firstly, the bid, 8.5% effectively of the Rovuma Area 1 license.

It is agreed by the Cove directors, but clearly, there is a period to go before we can close out that deal.

So we're hopeful that we bring not only the right price to the Cove shareholders, but also the right capability to get the governmental approval, which we need.

8.5% remains perhaps a little low for a Shell presence in what hopefully will be quite a large LNG development.

And we are and will remain interested in increasing from that level of involvement.

I really can't comment on whether we have or will hold discussions with individual members in the existing consortia, either in that area or elsewhere.

I can just confirm that, yes, of course, we're interested, but one step at a time.

We must close the Cove deal first.

Okay.

Can I just come back to your comment on LNG and Q1.

You talked about it being a tight quarter.

Do you see that going into Q2 and beyond for 2012, please?

In general, yes, although it is a bit seasonal.

So the demand can come off a bit across the summer.

Depends on how warm it is in countries with lots of air conditioning.

So in general, the demand is higher than it was a year ago.

We will see Pluto coming on.

There's a couple of other smaller projects likely to come on during the year.

But most of the volume's already sold into long-term contracts.

There are various Chinese Regas terminals opening up, capacity expanding.

India is fairly strong in its demand for LNG at the moment.

So, as we look across a variety of markets, we do expect the market to stay pretty tight.

Great, thank you.

John Rigby from UBS.

Just two questions.

The first is, I noted what looked like a fairly pointed remark about your downstream, what sounded like a remark that suggested you wanted further improvement.

And I just wondered whether you could talk about what you can do excluding any kind of rebound in refining conditions, albeit that, of course, they have improved in the second quarter.

I say that in the context of a refining business that I think has barely made money in any quarter since 2007 or 2008.

The second is, just on your commentary at the end, on the dividends and the balance sheet, I think you brought that in.

I take your point about where oil prices are, but as you said, downstream's not great.

As you're generating a level of cash flow now which is pretty similar or in line with the kind of number, aspiration you want to do at midcycle.

So what are you thinking about how you'll deal with what is very impressive level of free cash flow generation that you're now starting to throw off?

Thanks.

Thanks, John.

Downstream, fundamentally, the comments are driven by the fact there's one-third of the capital employed, and in this quarter (inaudible), I think, of the earnings.

So that's the reference.

That's not really where we want to be in the downstream.

We certainly have seen some challenges in refining margins, but clearly, we don't necessarily control those.

Our aim in the portfolio has been, remains, and probably will be, to be in large, complex refineries that are geographically well suited.

Port Arthur, for example, Pernis, Rheinland, Singapore.

But there are clearly still some challenges at the periphery in refining.

Our marketing businesses typically have held up well, but there is weak demand, to be fair, in developed markets.

We need to make more of the positions we have.

We need to ensure that we're meeting customer requirements at lower costs.

And I think there are an element of optimization of margin delivery around trading, supply, refining envelopes, as we are adjusting to feeding pretty much the same marketing demand with a lower refining capacity.

So there's some optimization we can do.

Upside in the quarter, availability was 94% in refining.

So we're actually got better availability than we've had for quite sometime.

The challenge is actually utilizing all of it in the challenging markets.

I would also just highlight, as we go forward, clearly Port Arthur and Raizen are both contributing, or hopefully going to contribute, more over time because both of those are effectively growing in the business.

Unfortunately, there is no silver bullet, hence the longish answer.

We have to pull all of those levers to get the returns back to where we need to be.

And dividend time, ESO, in fact past 12 months and the previous quarter, the 12 months leading up to that, our cash flow from ops excluding the divestments, was $43 billion.

Which coincidentally was the target that we had set for 2012.

Bearing in mind there were $10 billion, nearly now, $11 billion dividend.

Plus the ongoing net capital investment expectation of $30 billion.

Gearing is coming down.

We are doing a little bit of buyback.

Clearly, we need to keep a couple billion in the pocket for Cove, assuming it goes ahead.

But just to be clear, the dividend is linked to the underlying structural cash flows, not linked to the gearing.

Put the gearing, the balance sheet, to one side.

So the underlying cash flow is coming through.

But there is more to come.

As that more to come feeds through, then, as we said before, the board has the discussion every quarter, and is sensitive to the comments they hear.

So let's see as we go forward.

No projection for when we'd consider further growth.

Okay, great.

Thanks a lot.

Iain Reed from Jefferies.

Could you just come back on the dividend statements you just made.

You probably see what Exxon announced the other day and Chevron.

And historically, yes, you have been the biggest dividend payer.

But you're not going to be now with Exxon's increase.

And obviously they had substantial buyback, as well.

I take your point on the historical levels of what you've paid out.

But it looks like you're slipping behind some of your competitors now in terms of what's going on today.

So, does the board take into account these kind of competitive pressures that obviously investors can switch their attention from one dividend payer to another?

Because obviously the analysis you've done is looking at other companies in the same peer group.

And secondly, on US gas, is it possible to say how much of the US gas you're producing at the moment is nonliquid related -- i.e., pure dry gas?

And what's your plan for investments in growing that number while Henry Hub is at these sorts of levels?

Okay.

My arithmetic could be wrong, but I think we still are the biggest payer.

(inaudible) competitor now, I accept that.

We're still pretty high in the payout ratio.

And I think the moves we see are quite good, because it starts to level the playing field a bit.

The majors now, their payout ratios are converging.

So I guess it means game on.

If we're all on the same payout ratio, then we better start growing the earnings and cash flow competitively.

So good to see that we are in more of a level competition.

If you added buybacks, it wouldn't be that level.

I'm talking about the dividends.

Buybacks are primarily a management of gearing and the balance sheet issue.

So underlying cash flow growth will be the driver of our competitive position and that will directly flow through into dividend.

So, to answer your questions, does the board take this into account.

Absolutely, they do, and they have been asking, how do the Americans get away with so much lower payout and yield for quite sometime?

US gas percentage in LRF, we have not a lot of production in the liquids-rich shale at the moment.

Almost all of our US gas is, in practice, dry gas production.

The liquids-rich shale and associated production at the end of the quarter was just over 10,000 barrels.

By the end of fourth quarter, sorry, end of the year.

At the end of the quarter, it was around 40,000 barrels.

So we are growing that quickly in the Eagle Ford area.

That figure does include the gas that comes with the liquids.

So our aim as we go through the year, we were 240,000 barrels.

So in terms of the first quarter onshore, unconventional activity production, gas and liquids, we expect that to grow through the year.

But we are basically still in the process of switching drilling activity from dry gas to wet gas or liquids.

Difficult to project exactly what the outcome is.

But the net impact is probably less volume in 2012, more in 2013.

I'll give you an update more specifically, I expect, later in the year.

Okay, thanks a lot.

Martijn Rats from Morgan Stanley.

Two questions, if I may.

The FAS 69 disclosure and the 20-F shows that the upstream production costs excluding taxes went from $11 on a per barrel basis to roughly $13.5.

So they went up something like 23% from 2010 to 2011.

I was wondering whether you could comment on what is driving that change.

Are you already seeing significant cost inflation coming through?

Are there mix effects going on and driving that OpEx per barrel figure?

And secondly, again, in the 20-F, there was a comment in the CO statement from Mr. Voser where he writes -- I believe we can get more value out of our assets.

The uptime of our processing facilities could be greater.

And there are significant savings to be realized in our supply chains.

I was wondering whether you could make any comment over broadly the order of magnitude of the additional value that he's talking about there.

And also broadly the time horizon over which these additional savings and additional value could be realized.

Thanks, Martijn.

You have been doing some good homework there.

Production increased $11 to $23, and fundamentally there are some mix effects there.

For example, the oil sands comes onstream.

You saw the berth costs coming in Qatar.

And our cost per barrel in, for example, the onshore activity that I just talked about, the onshore gas is fundamentally higher.

There's also some foreign exchange impacts.

So all of those put together are really driving the costs up.

And plus, I think there was a bit -- there was somewhat less deepwater production from pretty much the same cost base.

And that was the McCondo-related issue.

So all of those things lifted the unit cost.

But also, I need to recognize that almost everything I've just said were in areas where fiscal treatments are relatively attractive, as well.

So we have more access to the price upside.

Cost is only one side of the margin question.

The question on more value if we could get our uptime in the right place.

We've used numbers internally to have this discussion.

It's somewhere between $2 billion and $3 billion and it's split roughly equally between upstream and downstream.

And that's a gross margin price of any additional cost.

That's fundamentally a value that we've left on the table from incidents that we can or should prevent in an operational sense.

Or ways of just sustaining uptime longer in a safe and responsible manner on the assets which we operate.

So that's what we are shooting for internally.

Supply chain benefits, definitely in the billions.

We spent on third-party goods and services last year $70 billion in terms of contract placements with third parties, $70 billion.

There is some inflation out there.

But right now, certainly even including last year, the potential for us to improve from some of the things we've been implementing over the past three, four years, such as the global framework agreement, our demand, simplifying our standards, improving the supplier relationships, integrating into the supplier relationships.

You can see on a spend of $70 billion.

We ought to be able to take more out than we suffer cost inflation going into that number.

So some of that shows through in lower CapEx.

Some shows through in lower OpEx.

Potential remains, the forward potential, in the billions of dollars.

We don't have a specific number for it, though.

So hopefully that gives you some size of the price.

Yes, thanks.

That's quite helpful.

In terms of timing, would you expect that those savings, and the additional value can be delivered from measures that have been taken in the past?

Or is this very much an effort that still needs to be undertaken and will only pay off over a number of years going forward?

We have 90,000 people working in Shell, and it can take some time to improve and gauge and motivate 90,000 people.

So things don't happen overnight.

Sometimes we need to spend a bit of money and sometimes we just have to learn through continuous improvement on the job.

So this is not a one-quarter program.

But it is something we would expect to see over the next two to three years delivered into the bottom line.

Okay, thank you.

Michelle Della Vigna from Goldman Sachs.

I just had a very quick question.

You mentioned Alaska.

I was wondering what the key thresholds are for you to be able to start the drilling there.

And what kind of potential size you're looking for the exploration targets.

Thanks, Michelle.

This is possibly the most important single milestone of this year.

What does it take to drill?

There are three things we're working on.

One is operational.

The second is regulatory.

The third is the legal, or the litigation access.

Operationally, we planned two rigs and around 35 other vessels, which will provide all the support logistics, including, of course, the oil spill response.

Some of that, including the two rigs, is either on station in Alaska or on its way to Alaska at the moment.

So it's a huge logistical exercise, a bit like moving a fleet into the Alaskan borders.

So operationally, it's not easy operationally but we're on track.

The second point, regulatory permits.

A significant number of permits are required, everything from explorations to air quality permits.

All regulatory permits are either achieved and in hand or we expect to receive in good time to be able to start drilling in the third quarter.

On the last comment, we haven't an expected size of prospect but we have actually invested around $4 billion to date in Alaska.

So you can be fairly sure that we're looking for something big enough to justify that level of investment and the persistence that we've had to show over the five, six years in which we've been preparing to drill.

So the third challenge, I'm afraid, is a legal one.

This is the US, so we have one no control, and two not necessarily too much of a firm view about what the outcome might be.

What we have seen in previous years is that some of our friends have launched legal action at the last minute in courts, not necessarily predictable.

And that has led to difficulties in going forward.

This year, we've invited the courts to consider the litigation that we expect in good time such that geo process can be considered, the exploration plans, and other regulatory processes can be considered by the courts in Alaska in good time, to give either a yes or a no to the plan to drill in the third quarter.

Now, that does not rule out unpredictable events in the US legal system.

Having said that, we are confident that we are ready, willing and able to drill, and that we can do so in a very safe and responsible manner.

And we look forward to the successful campaign this year.

Great, thanks.

Alex Dezine from Citi.

Can you talk a little bit about the financial framework which you view the Mozambique acquisition around?

Some indication of how you think about pricing, et cetera.

And returns.

And then, secondly, unrelated, can you just remind us what contribution and when you're expecting from the Port Arthur upgrade this year?

Thanks, Alex.

Financial framework around Mozambique -- (inaudible) initially and the strategic framework.

Current LNG market is 240 million tons per annum.

We expect growth in the next 10 years basically to 400 million tons per annum.

And there are a significant number of projects already filling that gap.

But we expect growth beyond that, potentially to 500 million and beyond as a result of our assessment of the gas markets in countries that are likely to import LNG.

It's a huge market.

It is growing.

Our current capacity is 21 million tons per annum.

Our amount under construction is 7 million.

And we are looking at 15 million tons per annum, excluding Mozambique, of new potential projects.

We need to do a significant number of new projects in addition to our projects already under construction, just to keep the market share in what is a fast-growing and attractive business.

Witness the $2.4 billion in the integrated gas segment in the previous quarter.

So there's great returns, good projects, long lifecycle.

And Shell is clearly a significant and very competitive player, the largest private player in this attractive industry.

So financial framework has got to be seen in that context.

If we are successful in entering Mozambique and the project goes ahead, then we would be looking at ranking that against other LNG opportunities.

We can't do everything I just talked about, but we will do the better ones.

So it actually provides a bit of diversification in the portfolio away from Australia, for example, where all our projects under construction today are actually in Australia.

Although many of those we're now looking at are not; such as Canada, Indonesia, and hopefully now Mozambique.

And pricing and returns, there's no reason why Mozambique should not be as good, if not better than our current LNG projects.

Clearly, the entry cost is only going to be a small part of the overall investment, because a large LNG development has huge capital investments associated.

Now, we don't have a figure for that.

You would need to ask the operator.

But they talk of 17 TCF to 30 TCF, and potentially 30 million tons per annum of LNG.

So it would be significant investment that we'd need to rank against other alternatives.

On the balance sheet in general, clearly the $2 billion is affordable.

But the increase in the asset sales is not entirely unconnected with the potential to add new assets to the portfolio.

So as we monetize either non-core assets or we dilute them, smaller shares and important assets under construction, that enables us to recycle and expand the diversity in the portfolio.

So that's how you can see it, both strategically and financially.

Port Arthur.

Some of the downstream units are working already with finished product.

The distillation unit has crude cycling at the moment.

The hydrocracker will start up by the end of the quarter.

Collectively, probably not a huge impact on the second quarter.

Should start to see some contribution in the third quarter.

Please just do remember it's actually embedded at a 50/50 joint venture with Saudi Aramco.

So we just see the equity share of earnings in Motiva joint venture.

At the moment, the margins are maybe not that attractive in the Gulf Cost.

But over the cycle we expect Port Arthur to be a significant contributor to the downstream earnings.

Thank you very much.

Rahim Karim, Barclays.

Two questions, if I may.

The first was just around the cash flow for the quarter.

On an underlying basis, ex working cap, we saw a small decline year-on-year.

It seems to me that's to do with cash paid.

I was wondering if you could just give us a bit more color on that.

And how you see that moving forward, whether we should expect an increase in the cash tax rate.

And whether that relates to Pearl or anything else, if you can give us any color there.

And then secondly, on the Gulf of Mexico and Appomattox -- apologies for the pronunciation -- if you could perhaps give us some color on when we could expect FYD, what the potential upside is in terms of resources there.

Thanks, Rahim.

Two important questions.

The CFFO for the quarter at $13 billion, basically the same as it was last year, excluding working cap.

The primary difference is actually the tax paid.

You are absolutely correct.

Tax payments tend to run in line with previous year's profits.

Of course, in 2011, the profit was higher than it was in 2010.

So there's an element of, yes, we pay more, but then last year, we earned more.

And it's not impacted by things like Qatar.

Although Qatar is clearly in a profitable situation at the moment, and paying tax.

So what can you expect going forward?

The quarter-on-quarter variations won't be so high.

And over a rolling 12-month basis, the cash tax paid catches up with, broadly speaking, the earnings.

There are also some one-off effects where divestments don't always carry the same overlaid tax rate, effective tax rate, as the underlying earnings.

So it should structurally improve going forward.

Gulf of Mexico exploration, we talked specifically about Appomattox doubling the potential resource there up to $500 million barrels.

But it's worth just reflecting.

We are bringing Caesar/Tonga on onstream.

In fact, Anadarko brought it onstream for us in March.

We are building Mars B, Cardaman, and also BC-10 Phase 2 in Brazil.

And we have three opportunities in the Gulf, of which Appomattox is actually the largest.

But Stones and Vito are the other two that we're currently appraising ahead of, hopefully, FIDs in the not-too-distant future.

Appomattox is the largest.

It's also probably the most uncertain, because it's in that new East Gulf area in the Jurassic play.

We are appraising.

We have just appraised.

That's the driver of the doubling.

We will drill, hopefully, another couple of wells in the area.

We already have the Vicksburg discovery also in that area.

We have 75% or 80% Shell working interest in quite a bit of acreage in the area.

And we're fundamentally aiming to appraise and understand that area while we progress all three of those prospects towards FID.

Our aim generally in the Gulf is to create the production line of assets where we design one, build many, in terms of the surface and subsurface facilities.

We are doing everything we can to bring investment decisions forward, but Appo is so potentially large and uncertain that we're probably several years away from investment decision.

It's worth saying on the Gulf, actually, we've stemmed the decline post McCondo.

We've not started to grow it again.

But primarily Perdido has been the factor there.

We are now 90,000 barrels oil equivalent per day in Perdido, which is good to see.

And there's still further growth to come.

Peking probably next year on Perdido.

So thanks for that, good opportunity just to get the over view into the Gulf.

Very important area.

It's 50,000 barrels a day below where we would have hoped to have been.

It's been slower to get back to operation there, but we do have five floaters drilling at the moment, four platform rigs, one floater in a new deepwater rig in a testing mode and we've got another one on the way.

So by the end of the year, we hope to have seven floating deepwater rigs.

Thanks.

Peter Hudson from RBC.

A couple quick questions.

Actually both in the US, one in the upstream, one in the downstream.

The proxability in the US, below $10 a barrel operating.

Now, you talked about reducing the investment in tight gas.

Are we seeing any effects impacting the volume yet?

And what else maybe is in those numbers that might be affecting this quarter?

I wonder whether any of the costs associated with Alaska is showing as operating cost or is that fully treated as CapEx at this stage?

The second question is, you also talked about the squeeze on demand for oil products.

This is particularly visible in Europe, where I think year on year, it was down about 8%.

We haven't seen that in the reported numbers in the States and I'm assuming that is due to exports possibly.

But there seem to be a big difference between the reported sales in the US compared to Europe.

And I'm just trying to understand why that might be.

I'll try and help, Peter, thanks.

The oil products is outside of the back-end demand products.

Interesting fact there.

The Rhine river, it hasn't rained enough.

It was low.

Therefore, it was difficult to move product.

Therefore, we sold considerably less than one might have hoped to do in both commercial and trading in a supply sense.

At some point it was beginning to threaten supply security.

Fortunately, it started to rain again, but had quite an impact in the quarter.

So that explains Europe against the United States.

Our own volumes in the US being generally maintained, but the market is flat.

It's not clear is it going up, or is it going down.

We'll see as we go into the driving season.

Profitability upstream in the Americas, absolutely right.

It is somewhat less than we might have wished for.

And, yes, there is some of the Alaska spend going into OpEx.

We don't capitalize until we drill.

But other factors that were quite significant in the quarter, we have quite significant maintenance activity in the oil sands in Canada.

We are seeing higher depreciation and amortization, partly as a result of early production in the onshore gas or liquids-rich shales, carries quite significant unit depreciation because we are quite slow and conservative to actually recognize proved reserves there.

Clearly, the gas prices, the natural gas prices, had quite an impact.

And in Canada in particular, the WTI discount has an impact on crude realized prices.

All of those factors are keeping the Americas earnings low.

Which is unfortunate, but hopefully not all sustainable issues as we go forward.

We are switching out our gas into liquids-rich shales.

That is having, as I mentioned earlier, not too much volume impact now.

It may have 20,000, 30,000 barrels a day impact by the end of the year relative to where we might otherwise have been.

But as we switch into what is essentially an appraisal activity on the liquids-rich opportunities in Canada and the US, we won't replace it with liquids production this year.

But it will create the potential for liquids production next year.

So it will be a value upgrade, assuming like-for-like drilling activity.

So we're just managing this within the overall capital, also our operational capability.

We're running about just under 40 rigs at the moment, of which we are shifting probably more than 50% towards the liquids opportunities.

Hopefully that covers everything.

Okay, thanks.

Kim Fustier from Credit Suisse.

I had a couple of questions, if I could.

Firstly, could you just give us an update on your latest strategy in North American gas, particularly your plans to build a large-scale GTL plant in Louisiana.

And how that would compare to economics on LNG exports.

Clearly, you're bullish on the LNG market long-term.

Is that something you're eventually going to consider?

And secondly, could you comment on your latest thinking in Australian LNG?

Again, there's some headlines saying you're prepared to cooperate with other players on Queensland coalbed methane.

And how the economics there would compare to Mozambique.

Thank you.

Thanks, Kim.

North American gas strategy, fundamentally, we're looking at 42 CF-plus of gas.

Which in a $2 world, we probably would prefer to monetize as something other than natural gas.

So we are looking at four different ways of doing that, of which LNG and GTL are two.

The other two are gas direct into transport.

LNG uses fuel for trucks, ships, or rail.

Or gas to chemicals, which essentially is an ethane play in the Pennsylvania region.

Gas to liquids -- yes, we are looking to replicate what we've done in Qatar on the Gulf Coast.

Not necessarily in Louisiana.

We're looking in Texas, as well as Louisiana.

Essentially looking for brownfield opportunities, existing infrastructure, access to the gas, gas network.

And looking at what have we learned in Qatar that can bring the costs down, increase the yield, increase the efficiency.

It will take some time, a year or two, to work that through.

And then several years to construct.

So we're some time away from making a decision on gas to liquids.

More likely towards the end of the decade before we get production.

It does look attractive.

How does it compare with LNG export?

It depends, of course, on the answer to what will the cost be and what will the yield be.

But there's not a lot of difference there, I wouldn't say, at the moment.

LNG export, we would expect, and are giving priority to exports from Canada on the West Coast to Asia.

And we are working with our Asian partners, potential customers, of course; KOGAS, Mitsubishi and PetroChina.

So our focus on LNG export is primarily on Canada.

As for the US, it's possible, but looks a little expensive in terms of getting access to facilities.

So focus on Canada.

CSG, coal steam gas, or CBM, in Australia.

Just to reiterate, there are four projects planned.

Three under construction, plus our LNG project, where the LNG is in the feed process.

Potential FID, maybe the end of next year.

Clearly, CSG is not like Sakhalin.

We've started up Sakhalin o a handful of wells and it runs at full capacity on nine wells.

To run big LNG on the CSG basis, you may need several thousand wells, which you can't just start, drill and start up on day one.

So it is clearly a challenge for all the projects to have enough gas availability to run the trains economically.

What I said before -- I have not seen what actually has been reported -- was that we have plenty of gas for our two-train project.

We're prepared to choose our timing of FID to minimize the potential impact of inflation.

And in the meantime, if and as we develop production capability, we're open to discussion with other projects on provision of gas into other people's facility.

And that doesn't mean it's going to happen, but we are open for discussion.

Just to be clear, we're value-driven here.

We're not in any particular hurry.

We will develop the upstream and the midstream according to what makes best sense in getting the right balance between production, cost, and ultimate market access.

So the work program at the moment is feed, potentially FID end of next year.

Hopefully that's fairly clear.

Thanks.

Jason Kenney from Santander.

Two points of clarification, and sorry if you covered this already.

But was the tax charge lower than expected at 42% I think it was 45% in 2011.

And can you just tell me what the tax charge might be this year?

And then, secondly, on the exploration expense, I think it's $362 million, which looks low.

In fact, it's the lowest since Q1 2009.

So presumably a one-off low charge, but what would you assume is a run rate for the rest of 2012?

Thanks, Jason.

Tax charge is not really lower than expected.

We've got fundamentally, we're shifting earnings from high-tax regimes to low-tax regimes, which will show through over time.

So, Qatar, US, Canada, relatively low tax.

And just to note, we did publish some of the country tax revenue payments yesterday.

Difficult to forecast, because it does depend on maintaining that mix, but no surprises.

There were more one-offs last year than there were this year, as the divestments carried more one-off issues.

Exploration expense -- we expect to spend $5 billion on exploration this year.

$2 billion on the onshore type activity, $3 billion on more traditional primarily offshore type activity.

I would expect a higher run rate than a few hundred million.

We're on track to spend that money.

Some of what we spent in the first quarter was effective acreage acquisition, which we don't expense.

We don't expense acquisition, we don't expense drilling.

Most of the rest gets expensed, unless it's associated directly with successful efforts.

So it's just a question of phasing of activity and then type of activity in the current quarter.

Okay.

Thanks very much.

Lucas Hermann from Deutsche Bank.

Just a couple points of clarification perhaps.

Athabasca oil sands -- can you just expand on the maintenance comments and give us some indication of when you might perhaps be moving towards capacity on that project?

And secondly, I just wondered whether you could make any commentary at all about the acreage that you've actually acquired in the States, and what your initial appraisal activity suggests in terms of which acreage is more or less attractive.

I presume, Lucas, the second question is about the liquids-rich shales?

Yes, sorry, it is liquids.

Okay.

Many thanks.

In the first quarter in Canada in the oil sands, we have unplanned maintenance events.

We're still learning a bit about managing some of this, these assets.

And they contribute to some of the numbers I talked about earlier in terms of the potential value left on the table.

We are, however, improving.

When will we be at capacity?

We've shown every individual piece of the value chain works at capacity.

In fact, the upgrade is work above capacity.

What we've not yet done is delivered that capacity on all parts of the value chain consistently over time.

So we've had weeks not only at capacity, but actually above capacity, at both the mine sites and the upgraders.

So we have ongoing, both short-term maintenance activity, but most importantly, the debottlenecking projects, which will not only increase the overall capacity, they will help improve the reliability.

It's typical -- just for information -- for mine sites to be built, for some reason, with a target reliability and availability of in the low 80%.

Given that we manage better than that in most of the rest of our portfolio, that's what we've been working on over the past two to three years.

And we are steadily lifting that towards 90% and beyond.

Acreage purchased in the US and Canada, liquids-rich shales -- we tend to look at it globally as much as just North America.

But specifically in North America, we've picked up acreage, obviously, in the Eagle Ford, which we are drilling.

That's the most advanced.

It's the only one that has material production for us.

But we have acreage also in the Mississippi lime and several plays in Canada, including the Alberta Bakken and the du Bonnet play, which is the geological name rather than the Company.

We are currently operating nine rigs in appraisal and development, another four in exploration.

We would expect that to increase over the coming months.

Those are the areas that we're focusing on.

We have other acreage that we may not get the rigs to as quickly.

But we are certainly pushing the boundaries of all of our existing acreage to the extent we can to produce wet gas.

And Simon, when you talked earlier about 40,000 barrels a day from the Eagle Ford, gas and oil, can you give us some sense as to what the proportion of that 40,000 comes from liquids?

It's not just Eagle Ford, by the way, the 40,000 barrels.

But it will depend on how the plays play out.

Just one comment worth making on the LRS plays, they are not the same as each other.

They are not even the same -- if we're drilling wells a kilometer apart, we're getting quite different results.

And that's exactly the same as the rest of the industry.

This is an immature activity.

It is not as mature as the gas.

And it's very difficult for anybody to project specific outcomes based on what we know about reservoirs.

That includes the Williston Bakken as well.

So it remains uncertain.

It's an exploration play.

It's early appraisal.

40,000, might be 50/50.

It's probably not going to be a long way away from 50/50.

But we can't be more specific at the moment.

As we drill these prospects out, and as the industry drills the prospects out, we'll see more realism, I think, in expectations, both cost recovery and the asset prices that people are paying.

Almost all our acreage is what we call emerging or (inaudible).

None of it is mature to the extent of having a high level of production.

Okay.

And Simon, sorry, can I just ask you one other.

Chemicals -- can you give us any idea what proportion of profit now is coming from the US relative to, say, a year ago?

Just to get a sense of how Europe, rest of world has moved at a time when prices have been going up and demand's probably been weaker, whilst US has been supported by faltering input costs and ongoing steady demand.

I can't give you an exact percentage, but it's certainly better in the US compared to a year ago.

Europe is down partly because we sold Stanley.

And partly because Asia is also down.

There's been some destocking and sales down a bit.

But the US is up.

The rest of the world, down.

But primarily, that just reflects strategic choices that are playing out in what is still an attractive market medium term.

And we think we're in a lot better position than we were previously.

But is that split 50/50, 60/40?

Can't really give that, Lucas.

Okay, thank you.

Robert Kessler from Tudor, Pickering, Holt & Co.

Question on your Marcellus spend.

A partner of yours in the area apparently has chosen not to consent to incremental drilling in the region, thereby implying your net CapEx should increase in the short-term.

That to me begs the question, how do you manage your budget in the Marcellus?

Do you manage to a dollar spend, or do you manage to an activity level?

I have to say, I don't manage it at all.

I manage more at the portfolio level and the guys on the ground manage it.

So you're absolutely right.

Well informed that there are nonconsent partners in the Marcellus.

And of course if we drill that acreage, their back-end costs are a multiple of the original costs.

So effectively, we're acquiring acreage by drilling it, or acquiring a higher share in the acreage by drilling it.

We will indeed do that where it makes sense.

And the Marcellus is certainly an area where we see low cost and high potential overall.

So we'll continue to do it.

In the short-term, clearly, it does increase the CapEx.

Our actual drilling spend in Marcellus, not that material for the group.

Technically, we leave it with the guys who run the onshore operation to maximize value rather than worry specifically about number of wells or number of rigs.

In general, would you expect your activity level to be flat for the balance of the year, or increase, decrease, even qualitatively?

I think our net activity will increase.

But it will increase on the liquids and the exploration and appraisal.

We're moving rigs away from Haynesville and Pine Dale, both basically flat in Marcellus and Grand Birch.

And increasing everywhere else.

Got you.

Thanks very much.

Irene Himona, Soc-Gen.

I had a couple of questions, please.

So first, on the income statement, I see interest expense at $552 million.

On an annualized basis, about 6% of your debt.

And that compares with only about 3% last year.

So I just wonder if there's something going on there, if there's any guidance for what we can expect.

Secondly, you make reference to a good contribution in your downstream of the Brazilian JV, Raizen.

I wonder if you can give us some visibility on how material that is.

And also the JV's looking to perhaps acquire BG's stake in Comgas.

How does it fit in, in this strategy?

What is the game plan there?

Thank you.

Thanks, Irene.

Interest expense is higher as a percentage of the debt in the earnings this year because we are capitalizing less interest.

A year ago, we were capitalizing more interest into projects such as Pearl and Canada.

We typically only capitalize interest into very large projects.

And so I think that's the primary driver of that.

Raizen materiality, it's hopefully several hundred million dollars per quarter.

It is being driven, or helped at the moment by good sugar and ethanol prices.

So far, we have had a very successful operational start-up.

As I mentioned, it's not always easy bringing together two cultures.

But we found very good strategic alignment.

Cosan is a good partner.

And we are seeing more synergies, more opportunities than we'd originally envisioned in the original operation, which has been good so far.

Cosan independently and separately have indeed made a bid to purchase the stake, 60%-plus stake, that BG holds in Comgas.

Where we hold most of the remaining share of Comgas.

A little bit of it is actually on the public markets in Brazil.

I can't say what our reaction, because it's a deal in process, might be.

But this is not necessarily here a multi-party squeeze-out of BG.

This is a Cosan-BG deal.

It's not a Shell deal.

Longer term, of course, Cosan's interests are basically for them to determine and you to talk to them about.

But if their interests are in the energy sector development in Brazil, the clean energy sector development, these are the statements that they make, then Comgas is not only well-placed being in Sao Paolo state and being close to a lot of their current activities.

It has potential longer-term for synergies with Raizen.

But there are no current plans to merge or take the strategy together.

Okay, thanks.

Can I just very quickly ask about, going back to the point for the potential for GTL in the US.

Obviously the life of such a project is 30 years plus.

ET's a free market.

The project's economics do depend on the oil-to-gas price differential.

Isn't it a little bit risky to bet that the current differential remains in place for that time period?

Fair question, but I would push back.

It doesn't actually depend on the differential.

It depends on the difference between oil price and cost of gas, if we're producing our own gas.

It only depends on the differential if you're buying the gas.

What you give up if the Henry Hub gas price were to go to $10, $11 again would be the opportunity cost, of course.

So what is does actually, it derisks the portfolio from just being pure natural gas, by converting some of the natural gas to oil.

So it's really a play on what we see the long-term oil price, As long as we've got low cost gas in our own portfolio.

So that's how we think about it.

So the question we need strategically to consider, which is being considered, but if I had an answer, I would probably be looking to share it within the strategy discussion.

What is the proportion of the total gas resource base on which we want to effectively develop liquids-related pricing exposure?

And it's not necessarily 100%, but I don't know what the number is.

But the priority we are giving at the moment, as I mentioned earlier, Canadian LNG and we're looking at GTL.

That may not use a significant demand of the 40-plus TCF that we actually have.

But it's something on which strategy will evolve as we get a better view of the costs and the economics and the relative attractiveness.

Thank you.

Neil Morton from Berenberg.

I have a couple of questions.

The first is on the Q1 earnings.

I might be reading too much into this, but your opening line was emphasizing that these snapshot is part of the long-term strategy.

I just wondered whether perhaps you felt that Q1 was perhaps a little bit ahead of where you expected it to be, perhaps trading or, of course, seasonality.

Perhaps you could comment on that.

And just secondly, when you were commenting on Alaska, it did remind me that both Exxon and ENI have recently advanced their offshore plans in Russia, given a change in the tax regime.

Could you perhaps update us on your plans there, please?

Thank you.

Thanks, Neil.

I think you may be reading something in there that was maybe not intended.

But the snapshot is essentially the same phrase we used in Q4.

We don't lose a lot of sleep if we have a particularly bad quarter as long as the strategy is being delivered.

We don't celebrate too wildly with a good quarter.

We have to look through cycles.

So, yes, Q1 looks like a particularly good quarter.

But then if you put the last six months together, that's perhaps more representative of where we see we are on the overall delivery journey.

Alaska, or arctic more generally, our focus clearly is in the US, on Alaska.

And Greenland, where we will do some further study work this year, looking to drill in the not-too-distant future, we hope.

Russia as a whole, big country, lot of acreage.

Some of the acreage being taken up.

We're always open to discussion with Russian partners.

But we need to be able to find an outcome that suits both their needs and our needs, and that's not yet been possible for us.

But we have a good relationship with both Gazprom and Rosneft.

Maybe that will ultimately lead to further opportunity.

But in the short- and medium term, we have quite a lot of arctic exposure, quite a lot of arctic experience.

And that's where we'll be focusing our efforts.

Thank you.

Hutan Yazari from Bank of America.

Just a quick question regarding gas pricing in China.

Given your unconventional position there, I just wanted to see if you could give us a sense as to how much the Chinese are using that to promote gas on gas competition in the country?

And whether that's beginning to affect LNG prices and the levels that you're beginning to -- that you're achieving on the new contracts that you're signing out there.

Thanks, Hutan.

It's a good question, but you're probably slightly ahead of the game in terms of an answer I can give you.

Just to be clear, the Chinese energy policy at the moment in the 12th five-year plan is clear.

They expect to grow gas as a share of primary energy demand from 4% in 2010 to 10% or higher by 2020.

So probable trebling or more of the total gas demand in-country as a result of needing to meet the demand that is growing.

But also for a cleaner form of energy.

So it's got quite strong support already in the policy.

And that policy was predicated mainly on imports; either pipeline or LNG.

LNG typically is setting market prices on the coast.

Further inland the prices tend to be a netback against those coastal prices.

There has been a policy to raise prices from their current levels, which are certainly higher than North American at the moment anyway, towards the import parity over time.

Essentially what you say, the gas-on-gas competition.

But prices are set differently for different consumers as well.

So everything you say, you ask about is very valid, but all of the answers come not from Shell, but from the government.

And I'm sure that they will be taking into account exactly what is the potential of shale gas.

We don't know that yet.

That's what we're trying to help establish, together with PetroChina, at least in the acreage we're working together.

So we completed 11 wells last year.

We would hope to complete quite a few more this year, maybe around 25.

By the beginning of next year, we will have a much better feel for what's the real volume potential and what is the cost of producing that volume when we see that.

And possibly more broadly across the country.

I'm sure the government will consider long-term policy that will encourage the development.

Now, what the outcome of that actually is in pricing terms, just don't know yet.

Great question, but about at least 12 months, if not 24 too early.

Understood.

Thank you very much.

Kirin Moda from ING.

One question.

With regard to selling 32% of your Prelude in the percent stake to some Asian partners, what are your intentions there for the future?

Are you trying to accelerate the exploration efforts there in that area?

And also with regard to further [FMMT] projects starting up there, like a [Concet] or something like that?

Thanks.

There are three partners that have come in.

IMPEX, Cogas, and CPC.

Now, two of them are clearly LNG customers for Shell and interested in LNG supply back to their home base.

And so, for us, that's a typical way of derisking an equity LNG project, where we started at 100% bringing in customers.

The impacts are slightly different.

You have noted in Q4 2011 we agreed to enter the Abadi floating LNG project in Indonesia, which is an IMPEX project.

We have joined the 30% share of that project and they have come in per share of our project.

It's part of a developing relationship with IMPEX.

Who we do work with elsewhere in the world, as well.

For example, in Kazakhstan.

We feel it's a good way for Shell to derisk the project, monetize some of the potential value in the project, but also to maintain existing relationships and other opportunities.

And the book value of $500 million I think in this project, is that (inaudible) what has been done on FLNG?

And the exploration activity.

Ken Milliger, Market Securities.

I just had one question regarding the share class.

So can we have an update on the potential merger of the Class A and B please?

Sorry, it was not easy to hear you.

There's some background noise.

Okay.

The question was about potential merger of A and B shares.

We discussed this a little back in February.

Is it something we would like to do?

Clearly, it would simplify and remove some restrictions we have in terms of our financial and corporate framework.

The previous issues we talked about.

There's some withholding tax challenges.

We would need some agreement basically from the Dutch government.

Now, you are probably aware, that there is no Dutch government.

As of the weekend, unfortunately, the government was unable to reach an agreement on the budget.

We do not know when the next election will be.

But there is talk of maybe a six-month period and then potentially month after that to form a new coalition.

From a Shell perspective, this means it's very difficult to expect or even to try for any discussion about the conditions under which we could merge the shares.

I'm afraid that's probably off the agenda relative to where we were in February.

We would hope to be able to raise that when there is a new government in place in the Netherlands.

Okay.

Thank you.

Okay.

I think that's all the questions.

Thank you very much to all of you for both listening and for your questions.

I hope that was helpful in your understanding of our business.

Second-quarter results will be released on the 26th of July.

Peter and I will talk to you all then.

And the intention is to make that a face-to-face meeting in London.

So quite literally, I look forward to seeing you all again in the near future.

Thank you for today.

Thank you.

This concludes the Royal Dutch Shell Q1 results announcement call.

Thank you for participating.

You may now disconnect.