殼牌 (SHEL) 2012 Q2 法說會逐字稿

Good afternoon, ladies and gents.

I'm the security manager for the Grand St.

Paul's.

Just want to have a quick brief on fire regulations over here.

Just to let you know that we do not have any fire drills on for today.

Also to let you know that should you hear the alarm -- we have a two-stage alarm where we have to go and investigate the alarm first and then when you hear the second alarm and if it is a continuous alarm, then we have members of our team who will be escorting you out accordingly.

Thank you very much.

Thank you very much.

Great.

Welcome to the Royal Dutch Shell second-quarter 2012 results presentation.

So, Simon and I will take you through the results and update you on where we are with our strategy.

And then there will be plenty of time for questions at the end.

We will take questions here from the room but also from the Web.

Obviously you know the drill on this one.

Let me start with the overview.

The global economy and the energy markets are likely to see continuous high volatility.

This is really an interplay between structural growth in energy demand and on the other side some unprecedented geopolitical events such as we see playing out in the Eurozone at the moment, (inaudible) comes to mind and others.

Now, this is a very complex landscape for us in the energy industry and in a highly interconnected world.

Therefore, we see a lot of opportunities for a global, integrated Company like Shell.

We are on track for our cash flow targets of up to $200 billion for 2012 to 2015, which as you know is some 15% higher than the previous four years.

We're also on track for oil and gas reduction of some 4 million barrels of oil equivalent per day in 2017 and 2018, the outcome of our investment decisions and financial targets.

Now this is an ambitious program and we have got lots to do, so let me over the next few minutes update on where we are with our progress on all of this.

Our Q2 2012 CCS earnings excluding identified items, were $5.7 billion or $13 billion for the first half.

And in the second quarter we had a lot of planned maintenance actually as some of it we have indicated and we also had some timing issues on dividend payments.

That together was roughly $500 million which you need to take into account when you look at our clean earnings.

Now we are seeing the impact of the weaker economy in our results.

We saw $4 billion of assets in the first six months of the year as we improved Shell's capital efficiency from -- and before strategic partnerships and upgrade the portfolio.

The underlying upstream volumes were good.

They were up 4%.

We have new projects under construction for medium-term growth making deliberate top-down choices with our investments where we can add value with technology, with integration and the scale of Shell.

We are also working hard to get choice into our portfolio with new exploration acreage and new integrated gas opportunities crystallizing and 2012, and I come back to that with a slide later on.

So it has been a busy time and still is a busy time in 2012 and I will give you now some more details on the issues which we are working on.

First, let me start with continuous improvement.

We are working on these programs across the Company and the opportunities they run actually into the billions of dollars from a potential point of view.

In downstream, for example, where industry returns are likely to remain under pressure for some time, we have put all the work into reducing our unplanned downtime in our refineries and chemical plants.

There is clearly more to come here, but what we have seen so far are very positive trends with actually the first half unplanned downtime at historically low levels and a top quartile industry performance.

The Port Arthur Refinery Expansion Project on the Gulf Coast, which had crew distillation unit damage shortly after startup is not yet in the figures on this chart.

The Motiva joint venture which runs this plant expects the crude unit restarts to be delayed into 2013.

Let me just be clear, we are not happy with this and we are investigating and we are working hard to turn this around and actually learn out of the incident.

On the Upstream side, we are coming to the end of the ramp up of the three large projects.

We have been working for the last six years or so.

Qatar Energy, and GTL and Canada Oil sands and I think many of you have been -- have had the chance to visit these assets.

Large-scale, taking low Upstream volumes into end-user products and markets makes investments in infrastructure and technology.

These are all the scenes where Shell adds a lot of value.

Qatargas 4 Energy achieved full production in 2011 and it has already delivered 9.8 million tonnes of energy in 11 countries.

AOSP Expansion 1 in Oil Sands Canada has been operating at all quality adjusted design rates in the second quarter.

Pearl Gas To Liquids has already produced 4.5 million tonnes of NGLs and GTL product and bolsterings have run at 90% to 100% of design rates.

This is a great achievement and Pearl is one of a kind of an asset and some of you or most of you have seen it as well.

Now, we have already learned a lot about this facility which gives us new opportunities for continuous improvements.

Maintenance started in the second quarter will continue during the third quarter, impacting production with minor modifications as we get both GTL trains and the utilities running as a single integrated asset.

This is all building up to the final slate and marketing the higher value products, on what I call the downstream side of the project, essentially a gas-based refinery.

Now I want to change the emphasis here.

The last six years have been all about the construction and ramp up phase of these exciting projects.

Going forward on these three, it is all about safe and reliable production operations getting more out of the assets from things like debottlenecking of oil sands, for example, catalyst improvements, more product placed in high-value specialty markets and petrochemicals opportunities in Qatar and maximizing commercial returns in the integrated value chains on all of these projects.

So you might hear less about them in our presentations but they are going to be important drivers of the results.

First-half 2012 production from these three was 360,000 boe per day, compared to 184 per day in the first half of '11.

They generated $2.7 billion or 12% of the first half of our CFFO, cash flow from operations, $1.8 billion or 14% of first-half earnings.

I think if you look at Shell's growth profile in the last few years, the investment profile was really dominated by Qatar and by Canada.

Now there is an important shift in our project flow here, because these three are now on stream with a large number of projects driving the next wave of growth.

This of course diversifies shareholder risk compared to the position in the last few years.

Some 60% of our Upstream spending this year, for example, is in North America and in Australia.

We have around 8 billion barrels of resources under construction, over 20 projects under way and more than 30 -- more on the drawing board to sustain our growth profile.

Now all of this built-in to the cash flow and production targets that we have set for the Company which I mentioned earlier.

Now asset sales are part of our business model.

We have sold $31 billion of assets in the last five years, which is a rollover of nearly 15% of our capital employed.

At the same time, we are recycling some of that capital into new growth positions for example, exploration LNG options.

Asset sales in the last 18 months were twice more than the positions we have bought.

Now there is no precise target to match these figures, but they do tend to balance out over time.

Acquisitions need to compete with organic projects on a profitability basis.

This is a tough hurdle, I can tell you, to get the best returns really for our shareholders.

Cove is a recent example of this capital (technical difficulty).

Let me turn to exploration.

We are driving our resources growth with exploration and (inaudible).

We have been reloading our exploration portfolio in the last few years with a buildup of Frontier exploration acreage, tight gas and shale plays as well as maintaining an active drilling portfolio in our more mature hard lands.

We have had three successful offshore wells so far in 2012, all in the Gulf of Mexico.

Two of oil appraisal, appraisals confirming the 500 million boe resources at Appo and at the recent Vito appraisal now confirmed at 300 million boe resources.

Now, these should both should actually be adding to our bottom line in the second half of the decade.

We have drilled some 50 exploration and appraisal wells worldwide and liquids rich shales and tight gas in the first half of the year and you can see actually some of the names on the chart.

So while the results in China Gas and in North America liquids rich shale are encouraging, but more work is needed to demonstrate commerciality.

Now I am also looking forward to some interesting well results in the next six months or so.

For example, we have French Guiana and Alaska being drilled over the next six months.

Now let's just look at Alaska for an update here.

We are getting ready to spud new wells offshore in Alaska this summer.

A great deal of planning has gone into this program with over 20 vessels to cover the drilling and contingencies.

Ice conditions will dictate how long the drilling season will last with the slower start due to the heavy ice conditions.

We are planning for two exploration well completions this year with potential for drilling top-hole section on further locations which we expect to drill next year.

This is an important step for us in Alaska in what could actually become a substantial, although long-term province for Shell.

Now before I pass you over to Simon, let me make some comments on North American gas.

On the gas drilling side, we are continuing to spend at the low end of our potential range with around 160 exploration and development wells in the first half of this year.

This is similar to last year.

Focusing on acreage, acreage retention and the lowest cost place across the country there.

We are working on a series of integrated gas options where I think Shell has a very strong credential.

We have 0.3 million tonnes per annum of LNG for transport under development in Canada and we are working on two similar projects in the United States which we expect to launch shortly.

You may have seen we recently signed a memorandum of understanding with Travel Centers of America to sell liquefied natural gas to heavy-duty road transport customers in the US.

This is at about 100 sites nationwide.

On the LNG export side, we are working with strategic partners on a 12 million tonne per annum LNG project in Canada.

They gas supply for this project could include the resources from Shell's Western Canadian gas positions.

This includes Groundbirch where resources have increased from 6 Tcfe in 2008 to potentially more than 12 today through drilling programs in recent years.

We have doubled the resources potential here since we actually acquired Duvernay.

Now we have further natural gas value chain options on the drawing board.

This is LNG, this is gas-to-chemicals but also gas-to-liquids.

We will say more about those in the future, but I think there is a very strong opportunity set emerging here for Shell.

So overall, good progress on the strategy, the development project flow and the broadening out that our pre-FID option set.

Now over to Simon to talk about Q2 results in some more detail and update you on the financial side.

Thank you, Peter.

Good afternoon.

As I've said before, quarterly results are very relevant, but good or bad they are really only a snapshot of performance in what is a volatile industry where we are actually implementing a long-term strategy with a rather longer wavelength for the three months.

So I'll just start with the macro environment.

If you look at the macro compared with a year ago second quarter 2011, oil prices and the global natural gas realizations declined from a year ago and this change reflects some easing of the geopolitical pressures that were actually boosting the oil prices a year ago.

In North America, the Henry Hub natural gas price has essentially halved due to the supply bubble from shale gas.

But outside of North America, the natural gas realizations, they were broadly unchanged Q2 to Q2, some regional differences but supported by of course time lagged oil price linkages where gas prices don't yet reflect the fall in the oil price.

Industry refining margins were higher in Europe and they fell in the US and in Singapore, particularly in Asia Pacific.

Industry chemical margins rose in the US on the back of tight supply.

In Europe, they were underpinned by the falling naphtha price but in Asia Pacific again, they remain low due to weak demand.

The overall trading environment for oil and gas has been softer than a year ago with overall weak demand but also lower daily price volatility than we saw last year.

So basic message is we continue to see a very mixed picture on overall energy demand and the consequences for results.

So oil demand in total did increase year on year, and LNG demand remains strong.

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

In fact, we are seeing coal substituting gas at the moment for power production particularly in the UK.

And in the Downstream, we do see evidence of a slowdown at the end of the second quarter and as we have effectively entered the third quarter with softer industry refining margins in the US and in Asia Pacific, so still very mixed.

Turning now to the earnings in the quarter itself, CCS earnings, current cost of supplies were for the quarter including the identified items of $6 billion, excluding the identified items, the CCS earnings were $5.7 billion and the earnings per share decreased by 13% -- 13% -- as compared with the second quarter 2011.

On a Q2 to Q2 basis, we saw slightly higher earnings in the Downstream, lower figures in the Upstream.

Cash flow from operations was over $13 billion.

Dividends declared in the quarter, $2.8 billion.

We are offering the Scrip Dividend again for the second quarter 2012, and the buybacks, which are aimed at offsetting the dilution from Scrip over time should surpass $1 billion year-to-date this week.

So let me talk just a bit more about business performance firstly on the Upstream.

The Upstream earnings excluding identified items were $4.5 billion second quarter and that's a decrease of 17% versus the same quarter 2011.

Weaker oil and gas prices, weaker gas trading conditions, they were the main drivers of the decline and that is about $700 million at the quarter 2 to quarter 2 impact.

We did see positive earnings momentum from growth projects.

The deferral of a second-quarter dividend payment into Q3 by one of our LNG joint ventures combined with planned maintenance that we did highlight back in April of 50,000 barrels of oil equivalent per day greater than we were seeing a year ago.

They took around $500 million off the earnings on the Q2 to Q2 comparison.

A lot of that 50,000 was oil rather than gas.

The first half oil and gas production in total was 3.3 million barrels of oil equivalent per day.

That is an underlying production increase for the half of 4%, same as the quarter, compared to last year.

The growth comes as a result of a multiyear investment in new oil and gas fields and the programs to increase the production uptime both of which Peter referred to.

So comments on Upstream for the third quarter.

Now, during the third quarter, looking ahead, there will continue to be planned maintenance mostly now in Asia Pacific and Europe and relative to Q3 last year, that is about 25,000 barrels a day oil equivalent impact.

Three recent large startups that Peter showed, Qatar and Canada, they produced 360,000 barrels a day oil equivalent in the second quarter 2012.

We expect similar production from these assets in the third quarter, same as the first quarter as well.

So as you also may remember, the UK government announced a tax increase for the Upstream business back in the first quarter 2011.

That legislation has now just been enacted.

So we're expecting to see a net charge of somewhere between $300 million and $350 million in the third quarter of 2012 that will be related to the change in the tax basis for abandonment costs in the North Sea.

That is a charge and it will be treated as an identified item.

Turning now to the Downstream, excluding identified items, the Downstream CCS earnings were $1.3 billion and that is slightly higher than year ago.

Oil products numbers were slightly higher, slightly lower numbers from Chemicals.

So all products earnings reflected improvement in the overall refining margin environment, slightly lower marketing and trading results, although overall market and trading was basically in the expected band.

Chemicals earnings declined and that was driven by essentially weaker margins across all of the main product lines, weaker demand in Asia Pacific than projected.

We are expecting worldwide Refinery and Chemicals availability for the third quarter of 2012 to be slightly lower than it was in third quarter last year due to higher planned maintenance in Refinery and Chemicals manufacturing units.

So those are the earnings.

Now turning to the cash flow.

The cash generation on a 12-month rolling basis, excluding working capital, was some $47 billion and that included $7.3 billion of disposal proceeds and over that 12 month period, the average Brent price has been $112 per barrel.

The cash flow generation has been underpinned by strong oil prices, clearly, but by the ramp up of new projects, some support from the timing of dividends declared across the 12-month period by our equity affiliates.

The Upstream generated cash flow after -- sorry, the Upstream generated surplus cash flow after investment, the Downstream was broadly cash neutral before any payment of the dividend.

It's good to see the cash flow that we have been generating, but we are looking for more from the Company here, as you know, this is a core part of our strategy and medium term target set.

Turning now to the balance sheet.

Firstly gearing, sits at 8.1% at the end of the quarter.

That compares with 10% at the end of the first quarter, continuing to move lower in the 0% to 13% range.

Now you would expect this in the oil price even though it came down still above $100.

We continue and intend to continue paying competitive and affordable dividends.

We've got a great track record on dividends and they are our main route to return cash to yourselves, to shareholders.

You can see the spending levels for the first half of 2012 on the slide here.

$11 billion on a net basis, deducting the divestments, but are including $1 billion so far this year approximately for acreage acquisitions, some of which were on the slide that Peter used earlier.

Now we are on track to spend around $32 billion this year of organic spending.

You can see investment picking up on the projects that we have under construction, 24 major Upstream projects, Peter had on the map.

We invested $8 billion in the quarter.

We are on a burn rate for $32 billion for the year.

We will see some further buildup in the spending run rate in the second half given the project flow.

And as Peter noted, we are moving from a period of bringing acreage in from an exploration perspective to drilling it, particularly areas of course, French Guiana and Alaska.

And we expect to invest about $1 billion this year on Alaska and we have now effectively absorbed that amount into the $32 billion capital investment outlook.

We are doing well on divestment.

We have reached our $4 billion target for the full year in the first half of the year.

I do expect more to come on the divestment side, but we will update you on that as we go forward.

So that is where we are on the finances overall.

We are improving the cash flow both from the macro but also more importantly from the project flow.

We have a competitive payout picture and we are showing good progress on the current investment program.

Peter, back to you.

Thanks, Simon.

Let me just summarize before we go into the questions.

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

We are making good progress with our strategic themes; that is performance focus, growth delivery and maturing new growth options.

Canada and Qatar are in the delivery phase and we have diversified our development portfolio for the next tranche of work.

We are working hard to generate more choice in our pre-FID option set to get the best balance of risk and reward for shareholders.

This is all coming through in our results, improving financial performance and new projects for the future.

Shell adds value through innovative technology, sustainable growth, integration across the value chain and by creating long life returns for shareholders.

This is competitive and an innovative strategy.

With that, let's take your questions.

I think we will start off here in the room.

I will ask two max at the beginning.

If we have time we will go around a little bit more.

And then we also go onto the Web from time to time.

Let me get organized.

Okay.

Irene?

Thank you.

It's Irene Himona, Societe Generale.

I had two questions please.

Peter, you referred to a multibillion-dollar opportunity from improving the operational reliability of the assets.

Indeed you had an incident this quarter at Port Arthur.

You had an incident in Singapore last quarter, I think.

The US refining has been in some trouble for a number of years.

There seems to be a systemic issue and I guess the question is, do we know what the key cause is?

And when you refer to the multibillion-dollar opportunity, how can we quantify or think about that?

My second question was on exploration.

You highlighted a large number of prospects that you are drilling in the second half.

Could we perhaps focus on the Chinese shale gas opportunity?

You have made some discoveries.

You sound quite excited about that.

How can we think about the time frame of commercializing that?

And also, longer term, the potential impact of that on your LNG business?

I am thinking here about the threat to the oil price link in your Asian LNG contracts?

Thank you.

Okay.

Thanks for your questions.

I think I take the LNG and take the first one and Simon is working with me on China.

He can take the shale gas one.

On your first question, I have to in a very strong way push back on your word systematic.

Because we are running a big refinery system and you can have incidents.

The important thing is actually that you, A, learn out of it.

You know what it is.

And you make absolutely clear that over the years you are actually improving your operational, your assets, your safety and your integrity performance.

We have worked very hard on that the last six to eight years and we have clearly improved in all of our stats which we also make available in our sustainability report.

They are all trending in the right direction which is a strong improvement over the last 10 years.

Safety and asset integrity are key components of our culture at Shell, and I am very proud that with all of the optimization which we have done on the continuous improvement, the piece which we have excluded is safety and environment and is asset integrity.

We have spent more than $6 billion over the last few years to improve our asset integrity.

So whilst we don't like incidents like that, there were happening in normal operations, so not as part of the startup and obviously we are learning out of them and we will leverage the issues.

The continuous improvement is a sum of a lot of different projects and initiatives and they are not only here to actually lower the cost.

That will be the wrong description for that.

What they actually generate is more value for the longer term.

Some of them bring you an optimized cost basis and it goes into the billion.

If you look at our base cost, apart from the increased production, (inaudible) fees, fees which we have, we are still seeing continuous cost take-out across the organization.

But we also see a lot of initiatives coming in to improve actually in the longer term, the way we can deliver values.

So this is a program which will, in my opinion, never stop.

That is why it is called continuous improvement because we always work on it and it's always driven at the beginning at least, it is driven from top down, but it is over time, it is driven by the organization itself because it becomes part of your culture.

On the second one, I start with the macro picture on the LNG and then actually Simon can give the details.

On the LNG forecast which we see across the world and specifically in Asia, we see a kind of a doubling of the LNG consumption between now and 2030.

This is driven -- a lot is driven by China but also by other countries who are now starting to import LNG.

In most of these countries we still have a very low percentage of actually gas in their energy mix so there is quite a huge potential there still.

And in China itself, there is only 4% in the energy mix is gas at the moment and I think the more domestic gas we actually find, the more we will see a switch from other energy sources into gas and into LNG.

So we don't see actually the demand slowing down.

Let me also just be clear on this discussion about oil price linked or not linked.

I think the market at the end will determine the price and if you take a $3.00 or let's say a $4.00 Henry Hub, that gives you $11.00 $12.00 landed in Tokyo.

If you are not in the spot market dealing at the moment, which is 14, 15, in a normal price environment, there is actually not much of a difference between an oil price linked, what they call and a Henry Hub delivered into Asia.

I think the customers in Asia, they are very keen on long-term reliable supply and if they actually get the energy from big infrastructure projects like an LNG plant, that is actually what they want and what they look for and therefore, I think you will have a return for those who build these things and that is expressed at the moment in an oil price linked type of formula.

Because what we are replacing is mainly oil exposure and industrial oil and hence actually to have the same formula for them is quite, quite interesting.

I think we should change our talk and really start to talk about gas prices landed in Asia and that even cheaper Henry Hub is actually no longer that far away.

I think that is the way you approach it, and then the other thing is how we are actually optimizing the gas in North America, and we can talk about that later.

There is plenty to be done there.

Some results from China.

Thanks, Peter.

This is strategic play, so I'll just talk about maybe the overall picture and then specific results.

A few years ago, the first development, Chiang Mai, we got up and running with PetroChina, as a result of that, good relationship, good operational performance, safety environment.

We have developed a series of further opportunities within China initially with PetroChina but you will have seen hopefully in yesterday's press release we announced first agreed deals with CNOOC, which are obviously offshore deals, one in China and one in Gabon.

So, [Chang Bay] was our first.

Yesterday, we announced an extension of the nature of the license in Chang Bay and not just in time but in scope, so additional laterals, different development horizons, but we will build out potentially additional resources and additional production from our existing main operated activity.

A couple of years ago we started to look at the onshore tight gas and shale gas activities, as Peter says, the two of us spent quite a bit of time on airplanes to Beijing.

There are now several players in our portfolio with PetroChina.

We have two in Szechuan Province in the South/Southwest and we have mainly CBM opportunities in the North in Inner Mongolia in Shaanxi and Shaanxi Province.

We are drilling -- we spent last year around $450 million.

This year we -- over $500 million.

We are drilling -- could get close to 20 wells this year.

It is still very much exploration and appraisal so we're not doing pad drilling at single well from the pad, looking at what is the scale, what is the nature of the reservoir, what would be the cost to develop, what would be an appropriate development plan.

It is looking like it will be into next year probably toward the middle of next year before we really have a good feel, particularly on the 2 Shaanxi developments, as to what is the appropriate commercial development program.

So far, we have had a range of outcomes on wells, good, bad, some interesting, not quite what was expected but usually in that sense, better than expected.

We don't know yet the full answer to your question.

In a year's time, we will.

We will share it as we go forward.

There is definitely great potential there.

It is a question of how to make it economic.

We have not stopped looking for further acreage either.

There are several other opportunities in the country, including potentially wet or more liquids oriented opportunities.

And if we are able to mature those, we will tell you about it.

Okay.

(inaudible)

Afternoon.

Theepan Jothilingam, Nomura.

Two questions, please.

Firstly, just focusing on the Gulf of Mexico.

I was wondering whether you could just give us a view on the short-term profile there?

And then clearly you are making a lot of progress on exploration with Vito and Appo.

What is the aspiration in terms of sort of production level, sort of towards 2017, 2018?

And then, I guess, there still remains a perception that sort of your short to medium term growth opportunities are biased to Australia.

I was wondering is there a case to reduce that exposure, or how do you go about mitigating the risk on cost inflation or project execution risk?

Thank you.

Thanks, Theepan.

I'll start with Australia.

In the meantime, you can think about the Gulf.

On Australia, indeed, there is no doubt about cost pressure in the country.

We are active in Gorgon, as you may know, we are (inaudible) active in the shareholder there and we are driving Prelude at the moment, Pluto through Woodside just came on stream.

I think we are quite immune in that sense on the cost pressure on the Prelude side because that is being constructed in Korea and therefore we are not exposed to the labor costs actually in Australia.

It will be anchored offshore, etc.

On the other two, they are operated by Chevron, so I guess you need to ask them in terms of the cost pressure etc.

I would just say from our side, we will be having our plans and we will presenting to you that should actually cover that.

Then comes the next wave.

Now the next wave on the one side we had is Arrow where we took a very deliberate decision to actually not rush Arrow through.

We saw the other three projects coming in.

The prices were going up, labor costs were going up and hence we took a decision to A, it is also it is new to us, we want to learn it properly, to actually -- and we have our Chinese partner.

So we are actually taking (inaudible) so we are preparing FID, we're looking at how to procure, how much we -- how we can actually optimize the use of our wells management joint venture which we have with the Chinese, how much we can do in modular design later on.

So what we are trying to do is really to work, how we have done it in Canada a few years ago when the cost exploded, how we can actually work in a smarter way to keep the costs better under control.

Then we have (inaudible), we have Sunrise coming as well.

I think that is early.

We are in the phase looking at that cost, so we will see where they go and what solutions we have there.

So one of the strategic reasons why I am quite keen to have options in the portfolio, is also -- I don't want to get pushed into the wrong development at the wrong time.

Now Australia has obviously some advantages because you may actually delay it, which you may not do in other countries because you have permits expiring, etc.

etc.

So really having a rich [follow] early on in your maturation pipeline, is something which we are aiming at.

What we then pull through, that [follow] developed molecules and the plants, that is obviously very -- that is where you can't stop and that is where you have to be sure and you have the profitability with the right costs, etc.

etc.

In Arrow, when we heard that, for example, one of the suppliers is the EPC contract for all of the three, and is promising us the fourth A team, then we get very suspicious because you normally don't get four A teams.

You may get one and then you pay the price for the rest.

So we are trying to read all of this and slow down when we have to slow down.

So Australia is a key component for our growth but we will not overdo it (inaudible) not getting the right profitability out of it.

The Gulf?

Gulf of Mexico, just in the context of deepwater overall, the constraining factor is basically rigs, how many rigs can you operate safely and cost effectively.

A year ago we were operating 12 rigs.

We are heading towards, by the end of this year, 16 rigs.

This is a global number.

We are bringing on stream some new rigs, part owned or 10-year leased by Shell that are so far performing extremely well early on in their life cycle.

At the moment six of those rigs are in the Gulf, one is in French Guiana, one is in Brazil.

The rest are elsewhere.

By the end of the year, we would expect eight floating rigs, four platform rigs potentially operating in the Gulf, so 11 or 12 drilling operations in the Gulf.

So significant step up, obviously compared to where we were during the moratorium, but even compared to before the moratorium.

We just had Caesar/Tonga come on stream.

We have Mars B going very well.

It was one of the pictures that Peter showed in terms of construction.

Our production in the second quarter is about 180,000 barrels a day.

Now, that's a low point, is a low point for two reasons.

One, we had a project as we turned the corner post moratorium in fact, but we had a lot of downtime in terms of the quarter itself.

Going forward, we will have less downtime and we will continue to turn the corner because Caesar/Tonga is on.

We are drilling the infill wells around Ursa, around Mars, and Perdido is still in a ramp up phase.

So it will flow forward with growth.

Mars B is the next big boost coming on in a couple year's time.

That will then be supplemented by Vito, Appomattox and Stones.

Vito and Appo get bigger every time we look at them, so, to be honest, the FID has got a little bit further out, but for good reasons.

We're trying to work the most appropriate development concept, how big a facility do we need to work, and the same is true of Stones.

So which one gets to FID first?

Not sure, could be Stones even, but over time, from that 180 sort of minimum, we should do considerable growth just in the Gulf of Mexico, but those projects will have to compete, we hope.

With French Guiana, we are doing appraisal in Brazil and one or two of the other deepwater activities around the world, so our limit is going to be number of rigs and how we choose to use them.

But so far, some good progress this year and hopefully some exciting news to come later in the year as one of those rigs is on its way to Alaska, of course.

Thanks, Simon.

I'll take one more in the room and then I come to the Web.

Hi, Iain Reid from Jefferies.

A couple questions about your North American gas assets.

We started to see some companies write down the value of the their dry gas assets in the US and I am just wondering how comfortable you feel about your carrying values given the acquisitions you made in the past?

Future gas prices you can see on the screen.

And secondly, on LNG export, there is quite a big queue of proposed facilities in advance of anything you might put in there.

And if you add up the numbers there, you get to quite a big number in terms of what could be exported from the US.

I wonder how much comfort you would have in the US government about -- if you go in there at the tail end of this, whether you will get approval for an LNG export scheme or for whatever magnitude you are thinking of, to deliver a few years down the line?

What is the US government thinking about this because obviously you don't want to go ahead if you don't feel you're going to have the capacity approved?

Okay.

I'll take the second, you'll take the carrying value one.

The question is really about the carrying value of the North American gas assets that we've acquired over the past few years and we talked about $17 billion.

It is a bit more than that now because we've been investing further in them on the 40 Tcf asset base.

We do an impairment review, file euros in review every third quarter.

So we're about to enter this year's program.

We have been using $4.00 to $6.00 for that the same way that we talk about investment decisions that we make.

Last year, everything was fine.

What will change this year is not so much pricing outlook, I suspect, it is what is the drilling program outlook, because we have shifted the drilling now 20 rigs onshore and North America now on liquids rich activity.

It was I think five or six a year ago.

And that is halved the gas drilling activity.

We are doing very little, for example, in Wyoming or in Louisiana at the moment.

Only gas drilling is in Canada and Marcellus.

I don't know what the outcome will be.

We will just do the normal work, looking forward long-term gas prices for the Q3 results and we will let you know at the time.

But I can tell you that in the second quarter, despite the current gas price, all our basins are actually operating on a cash positive basis.

On the export opportunities, first of all, as you know, we're working on Canada, so that we are optimistic there, so that is clearly moving in the right direction for the 12 million tonnes, and we signed up in the pipeline, billed it etc., etc.

So with our partners, we are progressing there.

It still has to go through permitting processes and that takes some time so FID is not going to be tomorrow.

It will take its time.

If we then move southwards, I think the base assumption here is there will be energy export.

The question then is how much.

If I take you from a very strategic point of view, I think you will see in North America and specifically in the US, that they have got an energy situation now which could bring them pretty close to energy independence over the next 20 years if the Gulf, if Alaska, if liquids rich shale, if the gas actually takes off and is kept in the country, replacement of coal driven power generations through gas, etc.

etc.

But on top of it, it could also actually bring a lot of manufacturing industries back into the country, petrochemical industries back into the country because you have a cheap source of the feedstock.

And that all equals drops in revenues in the US.

So I think whoever is in charge of the energy policy, well, what (inaudible) in the US (inaudible) also one in Europe, at one stage, we'll have -- we will look at this as -- on the one side, as a pure energy policy but on the other side, also about jobs and revenues and actually having, let's say industries back home.

So therefore, I think you could think of a very high number of LNG exports.

I think the markets will actually drive the right number at the end, from an export point of view on the gas side, but also from a demand point of view inside the country.

Governments will give you most probably incentives, schemes, tax incentive schemes to invest in the United States.

So therefore, I think there will be a natural kind of cap most probably not enforced by the government but because of measures they take, it will get to one, therefore, I think I would agree with you, if you have got 10 or 20 in the pipeline, you most probably need to be in the earlier half rather than in the second half in order to have some certainty of that.

Now we are working on LNG projects also in the United States.

We will inform about that going forward, but we are looking at that and I will make it here very clear, we are looking at that not just somewhere in the country, but also at the Gulf Coast Basin.

And we are looking at whatever opportunities we have there and we will see how we can actually link that into our very well-developed gas change strategy, which we are pursuing, which LNG and transport to liquids to chemicals, LNG export, and we will then determine how we move actually the molecules around.

One from the Web?

(Operator Instructions).

Jon Rigby, UBS.

Yes, thank you.

Two questions, one on the Upstream, one on the Downstream.

On the Downstream, I know you have done an awful lot of work in the restructuring of the business, buying, selling, improving refineries in particular.

But you just don't seem to be getting a huge amount of leverage in terms of your earnings or your UNIX earnings, is that a fair observation?

And if it is, what are the moving parts going forward that you think will restore both earnings and cash flows to something more acceptable?

And the second is just on your US upstream earnings, could you give a bit more insight into the moving parts that drove what looks like a very low earnings figure this time around?

I think the point is about low levels of Gulf of Mexico production, but can we just go into a bit more detail about what is happening there?

Thanks.

Thanks Jon, for the questions.

I give the Upstream to Simon and I will handle in the Downstream.

Upstream first?

Thanks, Jon, for the question.

The Upstream earnings were impacted by a series of relatively small things, some of which are one-off, some of which are short- to medium-term and some of which are potentially long-term issues all working in the wrong direction in a given quarter, some of which were already flagged into the market.

I'll start with some of the short-term one-offs.

The production maintenance that we talk about was primarily in the US.

It was on oil projects and it was in a period where obviously margins would have been good.

Some shorter-term impacts, we see in Canada oil being produced but the realized bitumen and the synthetic crude post upgrading prices, the bitumen was about $65.00, the synthetic grew to about $80.00 so an additional discount to WTI of around $15.00.

And that has widened from more like $5.00 a year ago.

That -- some of that is a short-term issue, some logistics constraints in the Chicago area, getting that crude out of Canada and into a refining network.

Some of it is a medium-term issue because it is WTI linked, but long term, it is less of an issue, because those distribution systems will even themselves out.

We did see increased depreciation in the quarter, significant amount of this is to be expected.

It's new production coming on stream.

For example, in the Gulf, and early on in a project, particularly a deepwater project, you do see higher unit cost depreciation.

That unit depreciation goes down as you prove up more reserves as data on the reservoir comes through.

The same happens onshore, it's not through December, it's just a lot more wells and smaller numbers but they add up to material impact.

We are moving those rigs from gas-to-liquids rich shale.

We are therefore not proving up as much reserve in the gas activities as we might have hoped to, at pace, and that has led to high unit depreciation, not only on the gas but also on the early liquids production.

So you are seeing probably for the next year or two, higher unit depreciation until that settles out as we recognize more reserves through more drilling in the basins we focus on.

We have then got more exploration and more feasibility expense, more seismic expense and more feasibility expense on the project.

Peter just talked about LNG, GTL, gas-to-chemicals, you can't do the study and the design work without spending some money.

That is all coming through in the same quarter.

It is not one off, it won't go away, but it is good leading to future opportunity.

So a combination of all of those things.

If they each only take $50 million, $100 million out relative to expectations, that is what leads to the results you see.

So fundamentally, it is a cash positive business.

You can see the cash flow coming through, and it is a business in a strategic transition.

It was a quarter in which most of the wind blew in the wrong direction.

Hopefully, that helps, Jon.

Peter?

Thanks, Simon.

On the Downstream, we have worked on the Downstream over the last few years in order to get to a portfolio which we see as a portfolio to go forward.

That included significant downscaling of refineries, so we sold significant [battles] there or we closed them and changed them into depots.

Some are still in the making and we have talked about them.

Some will change over the next 12 to 24 or 30 months.

We have also significantly actually purified our marketing portfolio, sold-out of smaller countries where we have no economy of scale in order to actually take costs out and capital out.

So, I think we have the portfolio now.

There is still the real drive on continuous improvement because we need to bring now some of the assets back up to top quartile performance.

That is where the focus is at this stage and that in itself also then takes costs out.

And we have seen, for example, when you look at some benchmarking from the market which we see and the refining business is pretty much benchmarked that we are actually now operating costs we are getting closer and closer to the first quartile.

So that is all there.

If I take the marketing and the trading business, quite clearly the trading is really linked to the refining business.

I personally don't look at the refining business in isolation.

I look at the chain including trading, including our fuels B2B business because that is now our retail business.

That is where the molecules are going and therefore we look at that strand.

If you take that, integrated value chain, quite clearly in the second quarter, we saw that compared to last year's second quarter, where there was a lot of volatility in the oil market, in the product market because of Libya, for example, this was different this year, therefore we added less value by using our refinery molecules into the system.

We had obviously a decreasing pricing environment.

Whilst we kept prices, the volume at the same time was coming down so Q2 was a quarter which where we adjusted from a high to a low, where oil process price is not a lot of volatility around it from a trading point of view.

So going forward, this is not about reshaping the portfolio more.

It is actually operating it at a top quartile performance in order actually to get our performance in line with where we want to be, where we actually can generate the necessary returns, and the cash flow.

Now on the cash flow side, that is the piece which I don't agree entirely with you that we need to further improve that.

If you look back over the last four or five years, I think the Downstream cash flow is actually the key piece which is underestimated.

You had most of the time you have in the billions cash surplus.

Balance sheet was one of the strong contributors actually to the dividends over the last five, six, seven years, so this is not about generating even more cash out of it.

Obviously if we improve our earnings then we will have an impact, quite clearly.

But it's about the operational performance, we are not entirely satisfied and the base costs are still being worked and we had good progress in Q2.

Now the one piece which you always have to exclude, but I don't take that as an excuse, but just as a number that you know, in the whole refining business, we had some $200 million of foreign exchange, as well, which obviously impacted our refinery results in Q2.

But to be very transparent, you benefited on the cost side and the marketing side because you had a weaker euro and therefore we have a lot of euro costs.

That helps us actually in that sense.

So this is not a construction site which we need to change.

This is about having the right portfolio and working the operational excellence into the portfolio.

Thanks.

Do we have another one.

We will take one and then we come back to questions.

Robert Kessler, Tudor, Pickering, Holt.

Hi, good day, gentlemen.

I just wanted to ask you a bit about the CapEx.

If I understand correctly, the $32 billion previously did not include the extra billion of potential for Alaska.

Now I think you said it does include the Alaska, so my question is, is that accurate?

What has moved out to make room for that?

Yes, thanks for the question.

I think it is correct your understanding.

It is now $32 billion, with the $1 billion.

I would just say we are doing more or less the same activities.

There is maybe some brief phasing in it, not the bulk of it but we are clearly also seeing some impact through our exercises and through our initiatives, which we are doing and actually getting some of our procured costs down.

We have a very strong drive there, and in all of our enterprise framework agreements where we actually are procuring costs from our suppliers, we have signed hundreds of them and actually we got between 10% and 25%, 30% lower prices.

So discounts on it, that is anyway also flowing back in.

And then as I have said, some deferment is also happening and you may remember last year we had a very strong rephasing from 2011 into 2012, and there also most probably we assume something similar to happen this year, and that's not entirely the case.

Lucas?

Thanks, Peter.

Simon, can I just come back to the Americas and two questions.

The first goes back to the statement you made when we went to Canada in 2010.

You talked about production in the region could reach 1 million barrels a day and you talked about the intent to invest in a potentially $40 billion over the '11 through '14 period.

Now I can see the $40 billion going in.

$15 billion has gone over the last year and a half.

So you're in line there.

But I just wondered how you felt about the million or the approaching million barrel a day status?

And secondly, going back to Jon's question if I look at the capital that you've now got wrapped up in the Americas in total, it looks like it is about $85 billion, $90 billion capital employed on which even if I start adding back, the numbers you are talking around this quarter, I am looking at something like maybe $2 billion, 2 and a bit billion or so of net income.

How do you give me confidence that the returns in that business are actually going to move to anything near respectable because it is not the way things appear today, and I hear what you say on cash and cash flow.

The problem is I can't see the cash flow numbers on the Americas Upstream, I just get the two lumped together.

So I guess the question is twofold.

Firstly, CapEx is going in, but are the production barrels actually effectively cash coming out.

And two, is just the volume of capital in and the absence of profit that is coming out and when does that actually turn around?

He asked you -- (laughter)

I was going to pass it back to.

Thank you, Lucas.

Thank you for reminding us of the previous statements.

I can't confirm all your numbers, but you are not far out in terms of the -- or certainly what we had said in the past about the capital employed is a very significant part of the total 210.

Therefore, the current reserve on capital is somewhat lower than we might seek.

We knew this was going to be the case because of the nature of the investment program.

And I will start at the end, CFFO transparency in the quarter just over $1 billion came into that Upstream Americas, excluding working capital.

A bit less than in the first quarter.

That's a quarterly number.

So second quarter number, and will presumably increase given all of the one-off factors I previously referred to.

Upstream Americas, you have to think of as not one business.

Each of the different activities has a different profile.

The heavy oil is now solidly profitable, solidly cash generative and the return on capital is okay.

It can improve with some of the programs Peter talked about, but it is improving.

Our unit costs are $10.00 a barrel lower today than they were a year ago.

So we are down below $40.

We are at benchmark, top quartile levels in that mining activity.

We have got bottlenecking opportunities.

We have opportunities to the steam assisted Carmon Creek to grow but we won't be putting a lot of capital into that business relative to the rest.

The deepwater business, just talked about, with it low, hopefully at 180, that has significant growth potential from the things I talked about.

Again, is solidly profitable, good returns, high oil price upside.

So the issue is not everything across the Americas, it is primarily the onshore activity.

That was the also the main driver of the production target, so in the two areas I talked about, heavy oil and Gulf of Mexico, deepwater, and Brazil as well, which also fits the Gulf of Mexico profile, we are pretty much on target for what we said in 2010.

The big difference is onshore gas and liquids rich shales.

And in fact, liquids rich shales didn't really feature in the discussion back in 2010.

So we have cut back, I would say, we were planning by now 50 to 60 rigs on gas drilling alone and a rapid development in gas.

We have now dropped below 20 and even in that, there is less of it going onto development than scale onto appraisal, which is preparation for a recovery in gas prices.

No point in producing now if you can prepare, sit on and produce in the future.

So our actual level of activity is about a quarter of what we expected in the gas, but the molecules are still there.

Most of them are in Marcellus and Western Canada and the breakeven there is at or heading towards $3.00 economic breakeven; cash breakeven is more like $1.50 once you are up and running.

The switch to liquids rich shales, now we are immature basins relatively other than Eagle Ford Shale so we're up about 10,000 barrels a day production there now.

But it will take some time to come through.

We will only see momentum there in 2013.

How much momentum will depend on how successful the exploration and appraisal work that we are doing, and most of the basins were named on the early exploration sheet, but basically it's in Western Canada, in or around Duvernay in the Canadian piece of the Bakken.

It is in Mississippian Lime in Kansas in the Utica, and in Eagle Ford in the United States.

We will have drilling later this year in the Neuquen in Argentina in the Vaca Maerta play, and in general, on gas and drilling activity, we have also shifted some emphasis outside the US.

So Ukraine, China, South Africa, the big gas plays is where we may well -- we've only got so many drilling engineers as well, so it will be less in the US.

It will be more developing.

So whether the million barrels a day will get delivered at the same time is a moot question; whether we deliver very significant growth around the world from a combination of that which is in the Americas and unconventional activity globally, I think very much on track, in fact, the portfolio is a lot stronger than it was two years ago.

We would expect to see returns in the Americas overall continue to carry the weight of that capital employed for some time now.

There is little we can do other than write off huge amounts and that is not in the plan.

But it is -- between now and the end of the decade, it is the primary engine of growth for this Company, and I haven't even mentioned French Guiana and Alaska, both of which could potentially absorb capital, but be looking at production by the end of the decade.

I think he was inviting you to write it off, so you get a better return, I think.

That's what he was saying (inaudible) (laughter)

It's Alastair Syme from Citigroup.

Can I -- I'm probably just asking actually quite a similar question.

If you look at the $50 billion of cash flow, I know I am sort of giving you round numbers '12 through '15 at $100 oil, and you try and sensitize that for sort of $3.00 gas and $15.00 Canadian discounts, is there a big delta that we need to be building into our assumptions, because we are kind of at $39 billion today.

So I am trying to reconcile those numbers in my head.

The $39 billion?

Yes, thanks, Alastair.

The $39 billion is a 12 month period in which we are still ramping up.

Gas, there is a sensitivity, but it is not many, many billions.

And deepwater Gulf of Mexico is probably much more significant in terms of will we or won't we deliver the projects we spoke about earlier.

The Canadian one, it depends how sustainable those discounts prove to be.

We expect logistical constraints to progressively be removed and we are taking part in some of those, whether it is reversal of pipelines in the US or the construction of new pipelines from Canada further south.

So by the middle of the decade, we'd expect that all the discounts to have compressed.

The question is how quickly will they compress and it's not a hugely material factor, but it is one we need to manage carefully.

Peter, is there anything else you would --?

I think more in a general way, we have to -- the $200 billion, or if you divide by four then your rough number at 50.

We have clearly said that from a gas point of view, we would expect to be in the range of four to six somewhere in 2015.

That may not happen.

That is what Simon just said.

Where the refinery margins will be, we will see by then.

But I don't think -- I would still say we are on track to deliver that.

There are some challenges in there, but that's fine.

But we are on the way to deliver this, and as you know, cash flow is the key target which we have across the Company and that is where the focus is.

So we are on these targets, some challenges, but we are exactly two quarters in at the moment.

So, there is another few years to come.

I'll go back to the Web and then I come back to you.

Jason Kenney, Santander.

Hi there.

Thanks for taking my question.

Two if I may.

Can you confirm that you are pursuing the position in Shtokman?

And if so, what it is that you find attractive about that asset or the potential role in its development?

And then secondly on East Africa, appreciate your comments on the capital discipline showed by withdrawing from Cove but do you still see a material position to Shell in the current discoveries offshore, Mozambique or otherwise in that region via M&A or maybe even organic pursuit?

Okay.

Thank you very much, Jason.

I take both of them.

Russia, we delivered so far the only sub-Arctic (inaudible) LNG play.

We are very happy with Sakhalin, it's going very well, producing more and generating more cash.

That is with Gasprom and our Japanese partners.

We also have (inaudible) producing that is also with Gasprom now and we have been very open that we would not be against further investments in some projects where Shell can add value.

They are various ways of doing that, and therefore we always look at options.

But I guess you would expect I will not confirm the questions regarding Shtokman.

I will confirm that we are interested in further investing in Russia and the recent changes in the tax systems, or in the tax schemes, either Arctic or tight oil or tight gas.

Thus obviously give us some more leverage or some more opportunities and the clear drive from the President Putin to more investments in Russia, may also open up some avenues.

So interested part and this is more or less the same answer as for East Africa.

We have a very rich portfolio.

We have plenty of projects in the pipeline, either under construction or in the pre-FID stage.

They all, whatever we do in the future, has to compete against those, and then it will either bring them in and take something else out or we may actually develop some of it later on as I have said.

At the same would apply for Russian projects like in East Africa.

Now let me first say in East Africa we have -- not in Mozambique, but in Tanzania, we have some organic plays which we are obviously -- that is on the exploration side.

It is also on the map which we have shown, so that is one avenue.

In totality, the LNG projects which we have across the world, if I start to list them, you will see that we have plenty of things, so we already talked about those in our Australia number; Canada, we talked.

We also have obviously in Indonesia, we have Abadi, so there are plenty of things already -- plenty of things which we are still evaluating.

East Africa is an interesting province, it is a big resource.

It needs, obviously, skills which can do upstream, midstream and downstream, therefore it's an interesting environment, but the valuation has to be right and that is where we took a view on Cove, we took a view on the valuation.

But we also took a view on the process itself and therefore, we will look at other opportunities if they come along.

They have not, I think, we have a rich portfolio already so we will see what we do.

Any questions inside now?

I said back there first and then there is one, I think, more on the Web.

There are at least four.

We have four in here.

I just want to make sure I don't forget the web side.

Okay.

Hi, it's Hootan Yazhari from Bank of America Merrill Lynch.

Just coming back to your US business.

There is much talk of shifting the focus as many people have away from dry gas to liquids rich acreage.

But there doesn't seem to be a lot of talk about how NGL liquids are really suffering on the pricing side and realizations there continue to come down.

Is there any chance of this derailing your plans?

Or indeed pushing you towards more capital intensive moves down there to actually really realize value from that portfolio as in moving more into petrochemicals, more into GTL, more into sort of LNG distribution on shore, anything like that?

I mean I would love to hear your thoughts on that?

Yes, thanks for the question.

Quite clearly the way I would describe our strategy at the moment is we have got some liquids rich shale, but we have a lot of gas and we have got the stuff which is in between.

What we are looking is actually to change the exposure we have to some cheap prices into exposure, higher up the value chain, and there you have got various ways of doing that.

And we are firmly already in the business of pushing LNG into transport.

Within Canada, we are doing that in the US and by the way, we do the same -- we are starting in China, we are starting in Europe on the same.

So that is a business model which is coming, which really brings Upstream and Downstream together, because you need the customs on the one side because we know them from the retail business and from the B2B business and you bring them together with Upstream, so that is really taking advantage of the differential between Henry Hub and diesel at the end of the day.

That's one.

So we are driving that.

And the same in that similar area is actually for shipping, so we are running bigger projects already in other parts, not in North America, but we are also looking into that at the moment where the shipping industry will replace diesel engines with -- so with gas engines, so that is another area.

Then the next one which we are looking into in Pennsylvania is to take the gas into chemicals, so this is clearly a cracking route, which gives us higher exposure from a value point of view.

We are looking into that, and we are -- have identified the site, now it is a sculpting exercise, etc.

The next one, we talked already which will be LNG export and LNG consumption in other areas inside the US.

And then the last one will be gas-to-liquids.

That is what we just built in Qatar.

Can we do the same in the US?

Where would we do it?

How big it will be, how are the economics?

How expensive will be building something like this because one of the issues you have obviously in the US now, it could lead to a cost explosion let's say for example, around the Gulf Coast because everything is being built there, and therefore we take a view on that and we will also take a view on how we time this.

But clearly a strategy to get the cheap feedstock into something more value adding is something which plays to our strengths because we are an integrated Company.

We can develop these things.

So that is where a lot of effort is being spent at the moment to figure out in how we want to use the molecules which we have or the resources in the ground, how we want to use them, how much we want for example, to buy from the market rather than use our equities.

But these are all the things which we are thinking about at the moment.

And we will let you all know the way we develop this.

But we have got, as Simon said already, quite a sizable team now in the US looking at that.

There was one hand somewhere here and then come back to you, so --

Thank you.

It's Neill Morton at Berenberg.

Two options questions.

And the first one is East Africa, the second on the big three projects, I almost forgot them there.

(inaudible) You recently introduced the concept of net CapEx, selling assets to buy assets.

And when you were bidding for Cove, I think you actually linked it to the decision to sort of farm down at Prelude, to balance the cash in cash out.

Given the fact that the cost of entry into East Africa is likely to be in the several billions of dollars, do you envisage offsetting that in your disposals?

Do you -- would you envisage using the balance sheet to build the position there or are you agnostic?

The second question on the big three, is that -- you said you mentioned it was 360 in Q1, Q2 and Q3.

When do you envisage the combined projects reaching a plateau?

Thank you.

Okay.

I think on the first one really goes into portfolio management and you are using Prelude as an example.

We brought Inpex, for example, into Prelude, and Inpex brought us into Abadi in Indonesia.

Both are floating LNG developments, so most probably you can add one and one together why this has happened.

So clearly, we are looking at these type of things.

I said before, we sold some $12 billion of assets where we made 6 as acquisitions, but I said you cannot always think that it will match this all the time one to one, but there is clearly a strategic thinking here and this is when Simon and I discuss these type of proposals with the businesses, they always -- when they come up with more CapEx they know what especially on acquisitions they already know we better bring something which we also can sell.

Because there is a dimension here that you just don't want to increase, let's say, your human capital you are spending in all of these projects.

There is a limit to how much you can do.

There is a limit from a financial framework point of view.

There is a capital risk premium that you want to maintain.

You don't want to spread yourself too much around.

So that all comes together but I don't want you to walk out of here and say, they will always match the two.

They are -- over time you may have been -- we may go a little bit long for two years and then we go long on the other side for two years.

But there is certainly a portfolio optimization game here happening.

On your other question, quite clearly we gave you an outlook into Q3 with the maintenance which we are doing in Pearl to adjust completely the two trades and actually take full advantage of the slate of products which we can run now as we have proven all of the technologies we have ramped up.

My expectation is that that is pretty much done during the third quarter, so we should hopefully by then kind of go into the fourth quarter and get after the run rates we are aiming at.

Now you have to be careful on the oil sands, because in oil sands, there is always a capacity issue depending on which ore grade you're actually digging through in your oil sands.

That is why we normally say that is the capacity you can reach depending on what oil percentage you have there.

But there we are talking about a few thousand barrels rather than 100,000 barrels.

So I think in the second half of this year, we will see all of these three projects then becoming really fully operational and we will optimize the products later on an ongoing basis.

Someone's hand.

Hi, it's Martijn Rats at Morgan Stanley.

The last time we were in this room, we all had a lot of questions why the dividend didn't go up more than it went, and I think it is fair to say you expressed some caution and conservatism.

Now we're having a quarter where Simon runs us through a list of a few things that sort of seem to have gone against the results.

And it sort of makes you wonder whether sort of back six months ago, you were already thinking about perhaps some specific things that you might need to face during the year where you might really think about -- there is always something that we need to anticipate.

I was just wondering if sort of in retrospect you can sort of comment on how that discussion went and how you see sort of that specific aspect going forward?

Also with that I have one more smaller question.

There seems to be a few headlines on discussions with InterOil in Papua New Guinea.

I was wondering if you could elaborate on that?

Yes, okay.

I think, as it is dividend, they both go to Simon, but let me also just say something from here both in the Board -- the discussions with the Board are very simple.

They are on dividends.

They are long-term and we have a policy and we take a long-term view.

So short-time macroeconomic assumptions do normally not play a big role because we really take long-term views.

But it is true when we had the first quarter, I was not very optimistic on the economy and I was very clear that I see the world going into a slowdown and that has happened.

Now on your second point, which is do you foresee some changes over time?

No, we don't.

But we also emphasize in a very strong rate quarterly results and Simon said in his part, there is snapshot and we have this interesting situation with this dividend from this LNG joint venture.

If that comes in two days earlier or later, does it really matter to us?

No, but you can have a big miss in the market and that could be a problem.

So I think where I sit, I take a through the quarter view, a long-term view, but from an operational performance point of view clearly.

Every month the results need to be delivered, but I can tell you if you have got more security issues in Nigeria, our production can go more up and down and that can wipe out growth and that is actually not what I want to talk with shareholders.

I want to talk how we actually deliver the value in the long term.

Over to you on Papua New Guinea and the rest of the dividend.

There is probably only one thing to add to the dividend.

While we don't let the macro drive it entirely, we did have some concerns about where the macro might go six months ago.

Peter was on record saying exactly that, sometime in June, I think.

Three days later, the price dropped $20 to 90, so we thought if it stays there, dividend will be off the discussion.

So I think the market is more concerned about that linkage than we might be.

PNG; there is gas, there is an intent for LNG projects from the government.

The government we have been talking to for a couple of years now.

They announced last year that we were a preferred partner because of the capability they want to bring into the country, large project developers, people who can develop markets and local capability.

So yes, we've had discussions with PNG government.

We've had discussions with InterOil from time to time.

And I can't say too much about where those discussions are at the moment.

Yes, we are interested in a project.

Yes, it must meet exactly the criteria that Peter laid out to compete with other LNG options.

We don't actually know yet whether that will be the case.

There is a new government election process in progress at that moment in the country.

As they come out of that, confirmation of fiscal opportunity and where InterOil fits and the government thinking will enable potentially a project to go ahead there.

It's very difficult for us to say more because it is still quite uncertain at the moment.

It's an attractive play and the same effective geological trend that we are in in Australia and now in Indonesia, so it is one we think we can add a lot of value to provided the other conditions are right.

Okay.

I think I will take one from the web and then I will ask one in the room.

So we'll have more than one hand, so I'll have to decide.

Let's go to the Web.

[Ken Menager], Market Securities.

Yes, hi.

Can we have an update on the (inaudible)?

Sorry, could you repeat the question?

May we have an update on the matter of the [A and the B shares], please?

Yes, I will leave that to Simon.

It is quite a quick update.

I think I indicated earlier this is really an issue in the first instance between ourselves and the Dutch government.

Its fiscal constraints as a result of how the Company came together in the first place.

Unfortunately, I think since we last stood here, the Dutch government is no more.

They are in that period of taking six months to arrange an election and last time, it took six months to arrange a government after the election.

So we are not actually expecting productive discussions on this and the rest of the year.

A slightly flippant answer.

I think, to be honest, the Dutch government has more serious issues to consider at the current time whichever of the parties happens to be in power.

So it's difficult to see us getting the priority and they are doing a pretty good job in the circumstances.

Okay.

I take two in the room and then we stop.

There is one here and there was a hand there up.

Okay.

Go ahead.

Sorry.

Good afternoon.

Richard Griffith from Oriel Securities.

Just coming back to your 4 million barrels a day target you talked about by 2017/2018.

Throughout the course of the afternoon in the Q&A you have mentioned quite often issues of cost, whether it is Australia, reconsidering the FID of some of those big projects.

You have mentioned costs around the Gulf of Mexico.

You have mentioned rig availability.

So at what point does these issues accumulate to a point where your project FIDs then effectively push your target out or it becomes eroded?

And the second one is just coming back to the downstream issue and the improvements on the operational side of it.

How much of this is related to say a structural issue or an age-related issue and how much are you going to have to spend to get those 1% improvements and availability?

Yes, I think the second one is a very good question and it is really where you -- where the machines are -- where they are, in which zone and these are obviously historical decisions you have to do.

We are very much looking at your point, so the target is not to get every refinery to the first quartile or across all the benchmarks.

You get them actually there where the current configuration does actually make sense to get to because you cannot just drive everybody up there because in between, there might be $1 billion of investment and you would never do that.

So you expect some underperformance in that sense, but because you want to have it from an integrated away, you want to have it for your marketing assets, you want to have some coverage of volume, you accept actually that machine.

So I think there is a very sophisticated way, the way we look into it and how we actually approve gross -- we call it gross CapEx in the refining system and that has a very high -- a much higher profitability requirement than most of the other areas which we have actually in the system compared for some to Upstream etc.

So that is the way we are trying to steer that.

Now on the 4 million, I think it goes a little bit back -- I always said 4 million is a long-term target that I can mobilize and drive the organization for growth.

But we are not chasing just the absolute number of barrels.

We are chasing the best returns and the cash flow growth.

Having said that, we are very keen to have enough options in the pipeline that we can achieve our targets which we have and that we have flexibility if costs go up in Australia and in -- let's assume for a moment in Canada again -- that you have got other areas where you actually can push things in.

If you go back to the chart which we have in here, where we are actually doing the exploration work at the moment, you see a vast variety of different countries and different regions which should help us to offset some of that.

But you can be really sure that we are chasing the cash flow growth, but in order to catch your engineers out of [breath], you also need to a little bit have a volume growth but you need to steer it in the right direction.

Good afternoon.

It's Rahim Karim from Barclays.

Just a quick question on the game changer that is Alaska.

A few headlines suggesting that obviously with the ice that drilling might be delayed there and then also a few more inspections required before drilling is allowed to start.

I was hoping you could just give us a sense of when the ultimate deadline is if things don't start to go that actually we don't see any activity going ahead in Alaska, whether that is actually an opportunity or not?

And just perhaps, how long it will take for the first couple of wells to be drilled, when we could expect some results?

And if worse comes to worse, you aren't able to drill this year, what your action plan will be and how we might take that forward?

Okay.

Let's start with the ice.

That is the one thing which we don't control too much.

Normal drilling season would starts mid-July in Alaska.

This year it is late, so we expect the ice to be gone most probably within the next two weeks.

On the permitting side, on the -- there is some certification of the containment system, which we are working at the moment, so that's together with the Coast Guard.

This has more to do that this is a containment system which is barrier number 4 or 5 and it is the first of its kind which has been built into earth which stretches also the Coast Guard a little bit from a permitting certification point of view, and we are working together there.

So I think we are working our way through that.

So as that is delayed, you have got that time.

Then I think typically the window would be -- it's a little bit shorter on the (inaudible) because the ice comes earlier back in that sense compared to the Beaufort.

That's one thing to consider.

And then there is also on the Beaufort, we have to stop drilling somewhere for when the whale hunting is ongoing, but that is a concession which we made with the local communities.

So having said all of this, we are aiming for the two wells to be drilled and maybe some others to be prepared for next year.

We have already applied for more, so that we can actually continue next year to drill so we should not go through the same permitting process because we already have applied and some of the permits you need to review yearly.

So I think we are on the right track.

We have done everything, [great] corporation resolved the regulatory bodies and we are now just getting to the end of the certification and all the rest of the vehicles and I always say to Marvin, he is now also the captain of an armada out there because they has more than 30 ships up there, and in order to actually drill the two wells, which are, as you know, there is shallow water, low pressure, it's actually not the most difficult thing to do, but fine.

We have all of that prepared, and so I think that's how it is working at the moment.

Drill this year and should drill next year in that sense.

It is to the thickest ice which we have had for the last 10 years and that has delayed it somewhat now, but otherwise it is going okay.

Good.

That's it I think.

It's all okay?

Good.

So thank you very much for coming here.

The first-quarter results will be announced on the first of November.

Now for the analysts in all of this, we are hosting a shareholder engagement covering global gas and especially Asia Pacific on the 14th of November in London and on the 15th of November in actually New York and I hope you will be able to join me and some of my team for one of those two events.

And two weeks earlier, Simon will tell you what happened in the third quarter.

Thanks for turning out.

I wish you a great Olympic fever over the next two weeks and I hope traffic is acceptable for you.

So thank you very much.

Thanks for the Web as well for listening in.