殼牌 (SHEL) 2012 Q3 法說會逐字稿

Welcome to the Royal Dutch Shell Q3 results announcement call.

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

(Operator Instructions).

I would like to introduce our host, Mr. Simon Henry.

Thank you, operator.

Good afternoon, good morning, wherever you may be.

Welcome to the Royal Dutch Shell third quarter 2012 results presentation.

I'll give you a summary of the performance over the last few months and then take your questions.

First of all, for those on the web, the cautionary statement.

Shell is pursuing and delivering on a long-term and consistent strategy against a backdrop of a very volatile energy market.

Any one quarter's results are, simply, a snapshot of the delivery against this long-term strategy.

Third quarter underlying earnings were $6.6 billion.

Earnings per share declined by 6% from the third quarter a year ago.

We have announced around $6 billion of asset sales so far this year, part of the overall capital efficiency drive.

Our growth projects continue to ramp up well.

We've launched a couple of new projects, oil and gas developments, in Italy and the United Kingdom, and we've been adding new positions for future growth out towards the back end of the decade.

Now let me give you more details and I'll start with the macro environment.

If you look at the macro picture here, compared with the third quarter of 2011, liquids and gas realizations both declined from a year ago, but within that mix, I'd highlight the discount of WTI to Brent and the discount of Western Canada Select, or WCS, to Brent -- and that, of course, is important for our heavy oil business in Canada.

All these discounts remain wide by historical standards, a $17 discount of WTI to Brent and a $33 discount of WCS to Brent.

On the gas side, oil -- natural gas realizations increased year over year and you can see the uplift in our integrated gas results.

However, by contrast, the spot gas prices in North America declined sharply from last year, by 38%.

In the downstream, industry refining margins increased sharply from year-ago levels in all our regions, and it's been quite a while since we've been able to make such positive comments on the downstream macro.

However, I do want to temper the enthusiasm here.

We believe this rally is being driven primarily by capacity outages, such as the PDVSA fire in Venezuela, and hurricanes on the Gulf Coast, rather than by stronger underlying demand conditions.

In fact, to the contrary, we're seeing increasing evidence of the weak economy all around us in our downstream marketing and our chemicals businesses.

So, we believe the downstream rally could be short-lived.

Overall, we're seeing a complex macro picture this year, all playing into our cash flow.

We have the high headline oil prices, big discounts on North American oil market, weak downstream conditions and the low gas prices in both North America and in Europe.

So, for those of you who are modeling our financials, we give guidance that a $10 increase in Brent prices, the sort of step we've seen in recent years, would, in theory, add over $3 billion to annual earnings.

However, in practice, we're seeing about half of that uplift in our numbers, because the oil price since '09 has come against a backdrop of that weak downstream, low regional gas prices, and the discounts in North American crude.

So, only half of the price upside is there.

Overall, however, despite all this background complexity, we're making good progress against the medium-term targets we set out at the start of this year, and, as communicated earlier, we are delivering on the strategic milestones.

Turning now to earnings, excluding identified items, the CCS earnings were $6.6 billion.

Earnings per share 6%.

On a Q3-to-Q3 basis, we saw lower earnings in the upstream and broadly similar results in the downstream.

The cash flow generated from operations was $9.5 billion.

The dividends in the quarter were $2.8 billion, of which $800 million was settled with new shares rather than cash, under the scrip dividend program.

And we are offering that scrip program again for the third quarter.

We are continuing our share buyback program to offset the dilution from scrip, and we achieved just over $1 billion of share buybacks in the first nine months of this year.

Moving on to the business performance, firstly in the upstream.

Excluding identified items, the upstream earnings were $4.9 billion in the third quarter 2012.

That's a decrease of 10% against same quarter in 2011.

The earnings were impacted by the lower oil and gas prices, with a strong financial performance from integrated gas, both -- that's LNG and GTL -- but also high results from gas trading.

We saw slight losses in our upstream Americas business.

That's a combination of a loss in the onshore gas business more than offsetting the profits in the heavy oil and the deepwater.

The drivers here are primarily low gas prices, Henry Hub, higher depreciation in upstream Americas, which has increased from $0.7 billion to $0.9 billion on a net income basis Q3 to Q3, and that reflects the buildup in both new production and the amortization of non-productive leases.

Now, headline global oil and gas production in the third quarter was around 3 million barrels of oil equivalent per day.

On a Q3-to-Q3 basis, we saw a series of volume impacts, impacting the differential.

We saw divestments of 36,000 barrels a day, the Gulf of Mexico hurricane impact was around 20,000 barrels a day, Q-on-Q, the exit from Syria around 14,000 barrels a day, and Nigeria security impacts, 9,000 barrels a day -- all of those figures more negative in 2012 than 2011.

So, excluding these effects, underlying production increased by just over 1%.

Hurricane Isaac in the quarter itself led to a production hit of 26,000 barrels a day.

Our LNG sales volumes increased by 4% year on year, and let me just update on the Pearl gas-to-liquids facility in Qatar.

The last few days, we've been running the total facility at a utilization rate of over 85% of capacity.

Each of the two trains has run over 95% of capacity at some point in the last few months.

The overall complex is on track to finish ramping up in the fourth quarter and we're nearly there.

This will be an important strategic milestone for the Company and, of course, financially.

Our three large ramp-ups -- Pearl, Qatargas 4, and the Athabasca oil sands expansion project -- produced some 340,000 barrels a day in the third quarter.

That compares with 275,000 barrels a year ago, and, of course, the capacity of 450,000.

With Pearl ramping up to designed range during the fourth quarter, we should see the full impact of these projects next year.

For fourth quarter 2012, I should just highlight that the oil sands project in Canada will have upgrade or maintenance impacts of around 10,000 barrels a day for Shell, compared with the current quarter, the current third quarter in 2012, and that will increase the proportion of oil sands production that's sold as discounted, heavy synthetic crude.

In addition, we're seeing a combination of flooding and increasing security issues in Nigeria onshore, which could reduce production by 20,000 barrels of oil equivalent per day from the third quarter to the fourth quarter.

That's a sequential movement.

So, overall on production, we're running about 100,000 barrels a day below the outlook we gave back in February, which was for around 3.4 million barrels a day this year.

It's primarily driven by our own active portfolio management to generate long-term returns for shareholders.

We've sold producing assets this year.

We've slowed down North American dry gas drilling and we've switched the focus there to exploration and appraisal activity on the liquids-rich shale.

We've also had, unfortunately, sabotage impacts in Nigeria, and, of course, the oil price impact in production-sharing contracts is quite significant, as well.

So, we are making good progress on underlying growth, and we'll give more details on these 2012 movements when the year's actually closed.

Moving, now, to the downstream, excluding the identified items, the downstream earnings were broadly similar to year-ago levels at $1.7 billion, built up from softer chemicals figures and higher earnings from oil products.

In chemicals, we saw weaker Q3-to-Q3 margins in Europe and a broadly similar picture in Asia, where margins remained weak.

In contrast to this, the oil products earnings increased and we were boosted here, of course, by strong industry refining margins, albeit that is against a backdrop of pretty difficult demand conditions overall around the world, and, therefore, we saw some decline in marketing and trading results, although they still remain competitive, and, we believe, strong.

We are expecting refinery availability for the fourth quarter to be below fourth quarter 2011 levels due to a heavy plant maintenance schedule.

The chemicals availability, though, should be slightly higher.

Repairs to the crude distillation unit and the Port Arthur refinery expansion, they are going well, and we're on track for a restart in 2013, as planned.

These repairs, overall, are expected to cost some $100 million on a post-tax basis for Shell.

I think that's far less than some of the headlines I've actually read.

So, those were the earnings.

Turning now to the portfolio, where we've been pretty busy.

We've got more than 20 new projects under construction in Shell.

In deepwater, tight gas, liquids-rich shale, integrated gas, and in more traditional activities.

These are the projects that will drive the growth into the middle of the decade and beyond.

So, highlights in the quarter.

Firstly, we've taken final investment decision, or FID, on three new projects -- carbon capture and storage in Canada -- that will reduce emissions at the Scotford upgrader plant by 35% -- and two new upstream oil and gas projects in Italy and the United Kingdom, which are expected to add peak production around 22,000 barrels a day for Shell.

In China, we updated the contract terms at the Changbei gas field, which will allow drilling and development of new reservoirs there within the license.

And in Qatar, we've launched the front-end engineering design work feed on a new gas-to-chemicals plant, which would use ethane from Pearl GTL.

You will have seen in the results an after-tax $354 million impairment charge for North American tight gas properties.

This charge is against the higher operating cost positions in the Pinedale and in Haynesville.

We use a $4 gas screening price for our impairment calculation, which, of course, is the lower end of our planning range for economic decision making.

In North America, the onshore rig count is about flat, 37 to 36 rigs Q3 to Q3, but we've been refocusing within that all the drilling into liquid-rich plays.

At the end of Q3, that was 21 of the total, compared to 6 a year ago, and we'd reduced dry gas rigs down to -- from 31 down to 15.

Now, during October, that ratio has shifted further where now about three-quarters of the rigs are working on liquid-rich plays.

The gas drilling that we're doing is primarily in the -- basically the lowest-breakeven-price acreage in Western Canada and the Marcellus play in Pennsylvania.

Production from liquids-rich shales, or LRS, in the third quarter was 16,000 barrels of oil equivalent per day.

We recently started up one of a series of new processing facilities in the Eagle Ford formation in Texas, and the LRS production including the new assets in the Permian basin, that should reach around 50,000 barrels of oil equivalent per day by the year end.

It's a great platform for growth going into 2013.

In Iraq, the South Gas Company is gathering around 300 million cubic feet of gas per day, as we work towards the startup of the joint venture and the first Shell revenues in 2013.

Turning now to exploration, we had two good discoveries in the quarter, gas both of them, one in Australia and one in Malaysia, and we had a successful oil appraisal in the Gulf of Mexico.

We've made progress with our Alaska exploration program.

The industry, of course, continues to assess the offshore potential there.

Our own program is a multi-year exploration program.

It was always 5 wells over several years, and our ability this year has demonstrated, I think, our commitment both to setting and operating to high standards on sustainable development, and safe and reliable and responsible operations.

We are taking a very measured approach here, of course.

We're successful in drilling two top holes this season, one in Beaufort, one in the Chukchi, both down to around 1,400 feet.

We've learned a lot this year.

We're reviewing those lessons and we'll take all of them on board, developing the plans for 2013.

We've also been busy with acquisitions and divestments, accessing new growth opportunities, but also keeping a sharp focus on that overall capital efficiency.

For the year to date, we've announced already $6 billion of acquisitions, $6 billion of divestments.

We haven't booked all of these yet.

In the third quarter we actually booked $1.3 billion of acquisitions, and that's $2.2 billion for the year to date, and, on the divestment side, $0.8 billion in Q3, 45 billion recognized in the first nine months.

So, more to come.

There have been quite a few portfolio moves in the second half of the year.

Expect to see them booked in coming months.

We've announced increases in our equity in fields where we can add more value, such as Australia and the North Sea.

We've bought new LRS positions in the Permian Basin in the US, and we continue to build new exploration positions, such as in China offshore and the Ukraine.

At the same time, we're reducing exposure in other areas to share the risks and enhance capital efficiency -- for example, in West Africa.

You see this is all about dynamic portfolio management on a strategic and a thematic basis, and a global basis, aiming overall to optimize both capital efficiency and growth potential.

Moving on, then, to the cash flow and the balance sheet.

Cash generation on a rolling basis was $47 billion, including $6 billion of disposal proceeds, and that was against an average Brent price of $112 per barrel.

Both the upstream and the downstream segments generated surplus cash flow, after investment, and we've taken advantage of attractive market rates during the quarter to add $2.5 billion of new long-term, some of it very long-term, debt to the balance sheet.

So, the gearing at the end of the quarter sat at 8.6%.

That's similar to the second quarter, relative low in the 0% to 30% expected range, as, of course, you would expect in strong oil-price conditions.

We could see a slightly higher gearing level by year end, since we've got several transactions, that $3 billion headline, announced but not yet closed, that could come in the fourth quarter.

And we also typically pay out higher cash taxes in the fourth quarter versus the first three quarters of the year.

So, just let me summarize before we go for your questions.

We are pursuing and delivering on a long-term and consistent strategy against a backdrop, both in the recent past and, we expect, for the future, of volatile energy markets.

Third quarter earnings -- $6.6 billion.

We've announced the $6 billion of divestments this year, and we've been adding those new positions for future growth.

We've added new resource positions with the drill bit.

We've launched new oil and gas developments, and a series of small acquisitions.

New projects are coming on stream.

We are maturing new investments for medium-term growth.

We are making good progress to deliver a more competitive performance from Shell, and there is more to come.

With that, let me take your questions.

Please, could I ask that we have just one or two each, so that everyone actually has the opportunity to ask a question.

Operator, please, could you poll for questions?

Thank you, sir.

(Operator Instructions).

The first question comes from Martijn Rats from Morgan Stanley.

Please go ahead.

Yes, hi.

Good afternoon.

I'll ask two questions.

First of all, I was hoping you could elaborate a bit on the loss in the Americas, also specifically when you would -- when would you expect us to see an improvement there?

How structural are these losses?

And secondly, I wanted to ask about the refining results, which benefited, of course, from stronger margins, but even compared to the margins, our assessment was that it was a pretty robust result.

So, I was wondering if there was also another element of improved operating efficiency, or something along those lines to that result that could, perhaps, be a bit more structural?

Thanks, Martijn.

Clearly, those of you who delve into the detail will notice the loss in the upstream Americas, around $100 million, and that compares to about $700 million of profit a year ago.

Firstly, strategically, the Americas is a very significant growth area for Shell.

We've around $50 billion of capital employed there.

We're investing something like $12 billion, $13 billion per year in the upstream business.

As we invest, we expected a reduction in profitability as we see two things, structurally.

There are higher upfront depreciation charges, partly as we amortize non-producing leases, but also partly as we see high depreciation in early production of the onshore.

And we also have quite a high level of feasibility and exploration expense as we investigate possibilities for, for example, LNG or GTL projects in future.

So, there are two structural high levels of spend there.

We have also seen, if we go year on year, much lower gas prices.

We've also got those much lower Canadian oil realizations, so if you look year on year the costs for these explorations, costing around $300 million, year on year, and the price effect is around $200 million, year on year.

I mentioned the downtime in Hurricane Isaac.

That's about $100 million impact in the quarter, and a variety of other, smaller, issues.

There's no real issue, other than the ones I've talked about in terms of cost and the reliability of deepwater and oil sands of the heavy oil activity has been very good.

The final factor and structural this year, but positive going forward is we've deliberately slowed down the onshore gas activity.

We've switched the rigs.

It is now, actually 29 in liquids and 11 on gas, as we take on the Permian activity.

That has meant we've invested some $700 million than originally intended on gas, which has significantly reduced production, and we've switched it into what has primarily been exploration and appraisal activity on the liquids, which, of course, ultimately, will drive the growth that we expect on the LRS.

So, if we exit the year on 50,000 of production from the LRS activities, we have a platform for growth there that, actually, is likely to be more remunerative than the gas.

So, that one is, although structurally lower gas production, we would expect structurally better performance.

The last point I'd make, on the upstream Americas, we're still generating over $1 billion of cash each quarter, excluding working cap, and we should -- the rolling 12 months is over $6 billion.

So, quite a few of the impacts I've just stated are non-cash items.

So, still a strong underlying gas generation from that business, and it is a growing business.

Comment on downstream and refining margins.

I will just -- compared to the market we are -- or, maybe, some of the competitors, but generally the market, we're less exposed in the mid-continent and the West Coast than some competitors.

Therefore, we don't get quite the same proportion of benefit, because our refineries are typically on the Gulf Coast in North America.

We are well exposed in Europe.

So, we did see manufacturing and supply making quite a healthy profit in the quarter, the first one for quite some time, which has basically offset losses carried in the first six months in that activity.

I can't comment on how it compares with your estimates, because I can't look at your estimates.

The only sort of underlying help we see is an overall foreign exchange impact, which is basically an accounting impact between timing -- on timing of recognizing and paying for crude of about $200 million net positive in the downstream.

Right, thanks.

One other thing, actually, Martijn.

The actual operating performance was probably the best we've had in terms of no deferred, or very little, downtime, unplanned, in the refineries.

It was around 3% for the quarter, and world-class performance is typically about 4%.

So, it was one of our better performances, but that has a relatively small impact.

Okay?

All right, thank you.

Thanks for that, Martijn.

Next question?

Thank you.

Our next question comes from Jon Rigby from UBS.

Please go ahead.

Yes, hello, Simon.

Quick questions on the gas or the North American side, again, just to return to that.

Can you -- are you able to estimate at what point the current portfolio onshore turns positive?

And also, the degree to which your volume sensitivity starts to change, i.e., when do you start to raise gas production again?

And, I guess, circling back on to what your existing production is, what do you think the production is that you've foregone by taking the economic decision not to produce from that portfolio?

And then just lastly, can you just remind me why are you depreciating on a straight-line basis on those licenses rather than holding them back to depreciation them on a UOP basis when they come into production?

Thanks.

Thanks, Jon.

The onshore turning positive, a $5 Henry Hub would help.

Our sensitivity is $1 Henry Hub is about $100 million per quarter.

So, that would certainly help.

I don't -- we don't give, effectively, a bottom-line income for onshore gas on the grounds that there are significant allocate-able expenses which confuses the situation, but I will say the total depreciation is around $3 billion per year, at the moment.

So, when does it turn positive?

Difficult to say.

When does the potential liquids volume offset the volume loss in gas?

Well, Marvin tells me he thinks he can catch up by the end of 2014, in volume terms.

Of course, at the current gas/oil price arbitrate opportunity, that means the cash generation and the earnings performance probably gets better than the end of 2014.

That will depend, of course, on ongoing drilling rates and that's something that we need to assess ourselves, at what rate we pursue both.

And why do we depreciate?

Our general approach to signature bonuses, for example, is to amortize over the life of the lease.

So, in Alaska, for example, it's being amortized over 10 years.

And where we are assigning purchase price premium where we've acquired assets at a premium, we also do amortize some of that over what we see as the early lifetime of the asset.

So, I would say we're aggressive in depreciation and conservative, therefore, in earnings.

Right.

Sorry, and the gas production foregone, do you think there's an estimate?

Maybe what you'd been if we were running at somewhere in the middle of your planning price?

Well, compared to what we might have expected to deliver this year, we're probably about 30,000 short by the back end of the year.

Right.

But that -- it's -- it would have probably attracted -- because it would attract more OPM depreciation, it would merely have attracted more losses, had we done it.

Yes.

No, and that's the figure that Marvin's saying you can catch up in liquid terms by end 2014.

In volume terms.

In a couple of years' time, we should have offset the lower -- the lower gas production by higher liquids.

By higher liquids, yes.

Great.

Thanks, Simon.

Thanks, Jon.

Next question?

Thank you.

Our next question comes from Michele della Vigna from Goldman Sachs.

Please go ahead.

Hi.

It's Michele, here.

Thank you for the presentation.

Hi, Michele.

I had two quick questions.

The first one is, on the big -- the three big projects, and the 450,000 barrels per day of capacity there, should we expect to get full utilization of that capacity, let's say, next year?

Or should we assume that your average utilization there is always going to be somewhere below 100% due to maintenance et cetera?

So, should we assume something around 90% there?

And my second question would be on your dry gas activity in the US and whether there is a specific level of gas price above which you would actually start to ramp up that activity again?

Thanks, Michele.

The big projects, first, the 450,000 you wouldn't expect to average 450,000, necessarily, in any given year, particularly not the first year.

And on the oil sands piece, in particular, we're actually working our way for the next year or so through some of the not-quite-so-rich oil base, as well.

So, what we would hope to do is demonstrate we can operate sustainably and reliable at capacity in all the assets.

Already done that, by the way, in LNG and, in practice, in the oil sands in terms of tonnage of rock moved.

We hope to get the GTL, as well.

So, one step at a time.

We would like to get everything up and running.

I'm sure we can keep it there by the end of this year, but I don't think we would run, on average, at the 450,000 for the full year.

As we get more experience, we tend to de-bottleneck, and, yes, we would expect to see higher production.

On the gas price, what price would make it attractive?

Well, economic breakeven in West Canada and Marcellus is about $3, but that wouldn't mean that anything above $3 we would ramp up.

We essentially need to look at our total operating capability and the number -- basically, the number of rigs we can operate safely and reliably, and decide where we want to apply that.

And I think it's fair to say the focus will be on opportunities like the Eagle Ford, like the Permian.

We will continue to drill the Marcellus, and then in Groundbirch in Canada.

But that may be targeted, really, at the capacity that we already have in place for aggregation pipelines, et cetera, making sure we fill the capacity.

So, I think for the next year or so, you'll certainly see the focus being on the liquids-rich.

Thank you.

Thanks.

Next question?

Thank you.

Our next question comes from Theepan Jothilingam from Nomura International.

Please go ahead.

Afternoon, Simon.

Two quick questions.

Firstly, just, I mean, coming back to volumes, I just wanted to get a sense of whether you -- there was any other sort of significant planned maintenance next year, whether you were in a position to give a more explicit outlook at the Group level for 2013?

And then secondly, I just wanted to revisit the buyback.

I just wanted to understand whether you're still sort of hamstrung in terms of how much you can buy back in the market?

Any sort of progress in terms of the discussions with the Dutch authorities?

Thank you.

Thanks, Theepan.

I don't think we can give a forecast or projection ahead for 2013 just yet.

We'll probably do that with the Q4 results.

I will say there are clearly very -- quite a few moving parts.

We're suffering theft of 50,000 barrels a day in Nigeria, direct from trunk lines, and we can't measure how much from everywhere else in the system, plus the sabotage impact, and that remains very material in terms of its impact.

The -- what I can say, positively, is we do have that oil -- the LRS ramp-up to come.

We have the ramp-ups of the projects that we've just talked about, the three big projects.

We have -- hopefully, we will see Kashagan come on stream.

Hopefully, we will get the first commercial production in Iraq.

And, generally speaking, a fairly robust portfolio.

Our decline rate in the quarter was 130,000 barrels a day.

That's shading down a bit over the past couple of years from the 150,000 level, partly because of the introduction of the longer-lived projects.

So, it's a reasonably robust outlook.

Remember, of course, that our -- our actual expectation over the next three years is a cash flow target, not a production target.

So, $100 barrel should give us $200 billion of cash generation, and that's what we're focused on delivering.

The barrels will be what they will be.

Buyback constraints -- unfortunately, as you're probably aware, there is a new Dutch government.

Well, fortunately, there's a new Dutch government.

Unfortunately, the changes that we've seen, plus the fact that the government actually fell on budget considerations, there's been no real opportunity to have the discussion around some of the constraints we face, which are essentially fiscal constraints.

Therefore, no real move on that, no real discussions.

We are, in practice, limited to 25% of the daily trade in RDSB shares on the London market, which works out roughly at $25 million to $30 million, maximum, per day.

And that's what we've been doing when we've been in the market.

Great.

So, just coming back, I mean, no significant planned turnarounds in any of the large assets for next year, just announcing?

I just want to confirm that?

For next year?

Yes.

There will be some, I imagine.

I don't actually have the program in front of me.

The planned turnarounds in upstream is typically about 150,000 barrels a day, on average, but it does vary quite materially quarter on quarter, and I don't have anything in hand to suggest that it's more or less than that next year.

Okay.

Ask me again in February.

That's fair, thank you.

Thanks, Theepan.

Next question?

Thank you.

Our next question comes from Oswald Clint from Sanford Bernstein.

Please go ahead.

Yes, good afternoon, Simon.

Thank you.

Could you just update us on your Gulf of Mexico performance here in terms of where the volumes are heading, impact of adding new rigs into the offshore, et cetera?

And then also, secondly, just on -- what are your thoughts on NGL pricing, especially as you talk about these LRS growth platforms?

What's the NGL impact, if it stays depressed on kind of unit margins from that growth?

Thank you.

Thanks, Oswald.

The current performance is just under 170,000 barrels a day in terms of Gulf production.

We now have 8 rigs operating, 6 deepwater.

Some of that activity -- 6 floaters and 2 off the platform.

Some of that activity is focused on exploration and, therefore, has minimal impact in terms of short-term production.

Some of it is associated with Perdido and, ultimately, moving on to Mars B drilling ahead of that project coming on stream in 2014.

We are, hopefully, seeing pretty much the bottom of the production, the decline that we've seen post the moratorium.

Turn that around, Perdido is growing well.

We will have, in fact, 11 rigs up and running by early next year as we ramp up the activity.

We only had 8, pre-Macondo, so we're actually returning to a higher level.

Again, by 2014, back end of, we should have sort of brought our Gulf of Mexico production back to where it otherwise would have been if there had been no moratorium, and that's where when we should also the impact of the two new projects, Cardamom and Mars B.

They are both doing well, both on track, but I can't really say more about the actual production between now and that time, that late 2014.

NGL pricing -- clearly, there are volatility in the market at the moment.

We are in the process of reversing a pipeline that should help Eagle Ford and Permian production get down to the Gulf rather than going through Cushing, which should help relieve some of the volatility or the bottlenecks.

Now, that should be up and running earlier next year.

We are, also, as a chemicals -- a major chemicals producer on the Gulf Coast, a beneficiary of low NGL prices, as well as a victim of them as a producer.

So, in practice, we're reasonably well hedged against the short-term, from our viewpoint.

So, I think, structurally, there will be logistical changes that will remove some of those short-term anomalies in the market, but it does help to be a consumer, as well as a producer of NGLs.

So, I wouldn't like to guesstimate the net impact on Shell, but there is something of a hedge in our portfolio, overall.

That's very useful.

Thank you.

Many thanks.

Next question?

Thank you.

Our next question comes from Iain Reid from Jefferies.

Please go ahead.

Hi, Simon.

Two questions.

Hi, Iain.

Just before that, did you say earlier that you're losing 50,000 barrels a day due to theft in Nigeria?

Straight from the pipelines.

That's 100% SPDC.

We're 30% of that.

Okay.

That's on an industrial scale, this theft.

It's about 150,000 a day, in total, we believe, and that -- the 50,000 is only what we can measure down the trunk lines.

The 150,000 is across the whole industry, as well.

It's just impossible to measure.

So, I think industrial scale is an accurate description.

The finance minister in country has made the -- drawn the obvious conclusion.

That's $5 billion to $7 billion a year of theft.

Amazing.

Anyway, look, I had two quick questions.

Firstly, you talked about the ramp-up of the big three projects.

Is it possible to say what sort of cash flow per quarter or per annum we can expect from that at, say, current oil prices, $100?

And secondly, on your write-downs in the US, I was surprised that you didn't impair your Western Canada assets, given the fact you paid quite a lot of money for them when gas prices were significantly higher.

Was there a reason for that?

Are you assuming LNG export pricing in the future?

Does that offset the negatives on domestic pricing?

Thanks, Iain.

First, the three big projects.

Typically, quarterly, they've been doing just over $1 billion of cash flow per quarter and earnings is just under $1 billion.

So, the aggregate cash flow in nine months is about $4 billion from the three projects.

So, that's great growth, and, obviously, there's more to come there.

And that is, obviously, at current oil prices.

Impairing west Canada assets.

Impairments -- I mentioned $4 -- are a function of two things -- how much you paid for the assets in the first place, and how good the assets are, and, I guess, also, the costs, your own development and operational costs.

Neither in West Canada nor Marcellus, where we acquired big positions, are we in danger of impairment.

No, it's not assuming LNG prices.

We would not be able to do that.

Of course, the -- we look at cash-generating units, and in both cases, not only did we make the large headline acquisitions, but we picked up significant amounts of acreage at a much lower price.

The resources in the Groundbirch play alone have doubled relative to the original Duvernay acquisition.

We're at 12 TCF now relative to the 6 TCF at the original acquisition.

So, the quality of the assets, the fact that we're producing at low cost, low development costs, great drilling performance, great efficiencies, is the reason for no impairment, even carrying the premium that we paid on the acquisition.

So, it was good quality assets, low cost of production.

Okay, thanks very much.

Thanks, Iain.

Next question?

Thank you.

Our next question comes from Jason Gammel from Macquarie.

Please go ahead.

Thank you.

Simon, I wanted to ask a question on the LNG business and future strategy.

You've done quite a bit this year to increase the optionality that you have in future LNG supply, between what you've done in Canada and Australia, and then, potentially signing on for US offtake in the future.

Can you talk about, and I realize that getting optionality gives you the option-making decisions in the future, but where each of those would rank in your current development queue?

And then secondly, how this would affect your appetite for obtaining equity in Mozambique?

Thank you very much, Jason.

Good questions, very important strategy -- strategic area.

Just refer back to the $2.6 billion in the quarter integrated gases, not only an area of future growth and value, it is an area driving today's results.

The future strategy, we're working or we're building 7 million tonnes of further capacity on top of the 21 that we currently participate in.

That's, basically, all in Australia.

And we are investigating over 15 million tonnes of potential additional capacity, some of which is in Australia, and, as you point out, Canada, Indonesia, and, potentially, in the United States on the Gulf Coast are a part of that.

Difficult to say how they individually rank.

Clearly, floating LNG we're currently constructing in Korea for Australia looks good, particularly if we could take the costs down the learning curve as we build and learn from the first -- the number one license plate.

So, the Indonesia project, although that's operated by INPEX, initially that will be floating, so we'll transfer some of the experience there.

So, we'll see how that looks.

Australia, we have the Arrow project, Brass, and Sunrise on the to-do list.

The onshore developments in Australia currently do suffer some inflation, as I'm sure you're aware.

Canada -- we are putting together the full value chain from the molecules, through to the market, with our three Asian partners.

We need to secure the pipeline, the LNG opportunity, and put the permits together.

That's -- so, it's going to take some time to put all of those different elements together, but with the low cost of gas supply and the very abundant gas and the very solid partnerships, Canada looks reasonable, as well.

Gulf Coast depends almost entirely on at what price could you access capacity and ensure that you get the permit.

So, I can't give you a ranking, but they're all currently in progress.

What does that do for Mozambique?

Well, Mozambique is, clearly, a big play, maybe a very big play, but big plays come with big price tags and significant operational challenges.

We bid for Cove at a price we were comfortable with.

We pulled out, because we felt the process would take us to a price we're not comfortable with.

And when you're talking, potentially, $150 billion or more of investment in that country, given the gas resource, and it's not something that you pay a lot upfront or too much upfront to get involved in.

If you've got that kind of follow-on challenge, together with the -- clearly, developing infrastructure, ports, roads, railways, and domestic capacity capability and consumption.

So, it looks like a good resource, but we're not going to overpay to enter it.

Thank you.

Move on to the next question.

Thank you.

Our next question comes from Kim Fustier from Credit Suisse.

Please go ahead.

Hi, good afternoon, Simon.

Hi, Kim.

Just two questions, if I may.

Firstly, on your portfolio strategy, going back to North American gas, you've talked about trying to match acquisitions and disposals broadly by geography or asset type.

So, I can see you've spent $2 billion this quarter buying acreage in the Permian.

You've added many other positions in the last 12 months, but I've not really seen any specific announcements on asset disposals recently in North America.

So, I was wondering whether you're still very much in acquisition mode, still making net additions to the North American portfolio, and if so, when you're start selling positions to effectively high-grade the portfolio?

My second question is on Iraq.

There's been some noise recently around Shell not being able to meet its production target at Majnoon by the end of this year.

I was hoping you could clarify this point and, perhaps more generally, share your thoughts on the key challenges in Iraq, such as infrastructure, export capacity, and security?

Thanks, Kim.

Good point on Iraq.

North American gas -- typically, what we said before was when Marvin wanted to buy something, we requested he sell something to pay for it.

That wasn't necessarily a strategic move to always match geography and the divestments and the acquisitions.

Right now, it's a buyer's market for gas.

It may be a buyer's market for LRS, as well, in the right basins, on the grounds that many of the players holding acreage a bit of a cash flow challenge.

We -- therefore, we're not necessarily a seller, either, into a soft market.

What we are in -- we're focusing the gas assets in Western Canada and Marcellus.

We are in the Haynesville and Pinedale.

They're clearly, from the impairments, the less-attractive basins, but probably that means it's not the right time to be selling.

We did sell Holstein, of course, offshore, for a nice price, in the quarter.

But that is -- clearly, it's a deepwater activity.

So, at the moment we are -- we're just looking for the assets that are at the right price in the right basin with the right potential development cost.

We're actually in double-digit number of potential liquid basins across North America.

Some of these we will not develop, either because we don't see the potential or because somebody -- it fits somebody else's portfolio better.

That's why we're doing the exploration and appraisal now.

But -- and it's looking good in Eagle Ford and the Permian, the Utica, and the West Canadian basins, Mississippi Lime.

One or two of the others, maybe not quite so attractive.

So, we'll work that portfolio out over time.

Iraq -- we are in three activities in Iraq.

In the sense of the general question about developing there, all three fall in the same category.

Just quickly, the West Quma, we're the minority partner with Exxon in their activity on that brown field development, which is producing revenues, albeit as a minority partner, not significant ones for us at this current time.

Majnoon is a greenfield development.

It is targeted at 175,000 barrels a day for first commercial production.

We would expect to achieve that next year, not this year.

What we have learned over the past 18 months has been extraordinarily valuable.

It has been slower than we might have wished for, but we have been working with the authorities in Baghdad and Basra.

We've been working with local communities, and, very much, with Iraqi contractors and suppliers to develop what we think has become a robust way of doing things, a robust modus operandi for the country.

Just as an example, we've been through the cost of recovery audit, which is always important in such activities.

We got 99%-plus cost acceptance and agreement on the first year of operations there.

We are now into the ongoing process of importing equipment, after some initial delays and challenges on the way the law was being interpreted.

We are drilling.

We've got 4 rigs drilling in Majnoon.

And on the gas side, the joint venture itself is scheduled to actually be formally started up next year, early next year, and we're already collecting gas, as I mentioned in the speech, from some pre-investment that we, Shell, already -- have already done.

So, we've learned how to operate.

We've learned how to work with a wide range of stakeholders.

It's just taken us a bit longer than we would originally have wished.

But it's now a good platform going forward.

So, we would hope to see both production in Majnoon and revenues from both Majnoon and South Gas during 2013.

So, there's some good potential growth for us.

Remember, we don't get any production volume in the gas activity, but we will get revenue.

That's great.

Thank you.

I hope that gives you a good oversight.

Next question?

Thank you.

Our next question comes from Doug Terreson from ISI.

Please go ahead.

Hi, Simon.

My question's on the downstream and, specifically, your commentary suggests that the intermediate-term outlook for global refining may be challenged, and on this point, I had a couple of questions.

First, given your global perspective, I wanted to see if you could provide more color on some of the global demand trends that you highlighted and that Shell is seeing globally.

And then second, on Shell, specifically, while the downstream was strong this quarter, the returns on capital have really not improved this year, as has been the case with some of your peers.

And so I wanted to see if you could provide an update on the scale and scope of some of the return enhancements that are underway in the downstream at the Company?

Thanks, Doug.

Long time, no speak.

It's good to hear we've got US listeners on the call.

I hope that you're all managing to get through some of the problems with the recent hurricane.

Thank you.

The global refining -- we still see it as challenged.

It's 7 million barrels a day of excess capacity in the world, probably rising to 8 or even 9 over the next couple of years, depending on how demand progresses.

We saw demand for crude up, maybe, by half a million barrels a day this year, maybe less.

Again, what was a 1 million to 2 million barrels a day growth trajectory, on which the basis of new refineries was, I think, the investment case.

We see some mismatches in product slate, as well, with much higher demand for diesel than gasoline in quite a few parts of the world.

So, Europe is chronically over-supplied.

And while in the short term the occasional bankruptcy or maintenance turnaround helps margins, it's not going to get any easier.

The US is benefiting, obviously, at the moment, from both shutdowns in the US and elsewhere, as, for example, Venezuela, but also this WTI disconnect from Brent.

And how long will that last?

Well, we don't see demand that strong, particularly on retail at the moment.

Overall, always difficult to read a trend.

The US, industrial and commercially, seems to be in a better place than Europe.

What we don't know is how sustainable that may be.

Perhaps we'll wait 'til after the election.

Okay.

The emerging markets -- doing well, still growing.

A bit of an interregnum in China in the past six months, but that may well come back.

But, of course, refineries are being built.

So, there are still new refineries, many new refineries, coming on in the Middle East, in Asia, including China.

So, we don't actually see it getting any better, on average, around the world, as we go forward.

Okay.

Return on capital in downstream -- we're still probably below where we might like to be.

Okay.

But we are improving.

The chemicals is now doing well, and we see suggestions that the current cyclical decline may have bottomed out and we're still solidly profitable there.

The issue is partly the refining base, and partly the fact that we carry a great deal more capital in our business than some of our competitors, for example, just from FIFO stock accounting.

So, there are cost improvements that are ongoing, internal process improvements.

There are portfolio improvements, all in progress, although a lot of the portfolio work is coming to an end, the major moves, that are squeezing out the cents per barrel.

There's no real big move, but it's the cents per barrel around costs, which have come out and stayed out.

The costs are not coming back in downstream, but we need to be working, maybe some of the processes that we have in place with customers and optimizing the value chain around the refineries.

They need more work.

Okay.

There is more to come.

Okay, great, Simon.

Thanks a lot.

Thanks, Doug.

Next question?

Thank you.

Our next question comes from Irene Himona from Societe Generale.

Please go ahead.

I had a couple of questions, please.

So, firstly, in oil products, is it possible to say how much came from Brazil from the Raizen JV this quarter, and, perhaps, what the comparable was last year?

And then, secondly, if you can give us an update, please, on plans for Arctic drilling, I suppose in the next season now?

Thank you.

Thanks, Irene.

The JV, Raizen, doing well.

Definitely learning to squeeze more out and expand on the capacity that we have.

It's around $100 million contribution, slightly better than last year.

It's also got, obviously, the downstream contribution, the marketing contribution, as well as the ethanol.

But so far, very successful collaboration, very well placed, despite what is, actually, a difficult ethanol market, a bit distorted by some gasoline subsidies in country.

Arctic drilling -- just to -- it's a very important question.

Just to go back to the context, our exploration plan, which is multi-year, and always was several years, finds exploration wells across Chukchi and Beaufort Seas.

We planned, originally, to drill two of them this year, one in each.

And we aim to have the facilities or the capability of two rigs plus over 20 support vessels.

We did achieve that, barring one vessel.

The vessel that was missing was the containment barge, which is the fourth barrier against a potential blowout and spill incident.

A lot of our effort has been projected or targeted at avoiding a blowout, in the first place, but in the event -- very unlikely -- that that were to happen, the drilling mud, the blow preventers, drill shear rams, the capping stack, would all come into operation, all fully tested, before we would need the containment barge.

However, the absence of the containment barge meant that this year we were only able to drill two top holes, and I think I mentioned down, both, to 1,400 feet.

We've pulled off there, both of them, as of yesterday, and the fleet is moving south, I think it's fair to say now, for the winter.

We intend, obviously, next year, to go back to those two wells.

We would hope to be able to complete the holes into the reservoir.

I cannot say any more than that, that we would plan.

The 5-well exploration plan remains valid.

It is valid for several years.

Obviously, wells three and four will depend a little bit on the results of wells one and two.

But, we are, we believe, very well placed, very positive outcome this year in terms of the regulatory environment, which we now think there's much more clarity on, so that we can go forward with more certainty next year.

Good, constructive discussions with the regulators, both at the federal and the state level, and we look forward to a positive outcome in 2013.

Hopefully, that covers the Arctic, and thank you for the question.

Thank you.

Next question?

Thank you.

Thank you.

Our next question comes from Lucas Herrmann from Deutsche Bank.

Please go ahead.

Simon, hi, afternoon.

Hi, Lucas.

Two or three, if I might.

I wondered if you might talk a little bit more about the buildout of your tight oil positions.

Clearly, a lot of capital is going in.

What one can't see, or there's little transparency at the moment, is the extent to which production has built and is expected to build over the medium term, what are objectives?

Secondly, just on the downstream, your fourth quarter historically, or certainly the last three years, has been somewhat astray from the performance through the previous three.

Are there reasons why we should expect a better performance in the fourth quarter of this year relative to the past?

And thirdly, I just wondered if you could comment at all on what's happening with GTL, V-Power, the extent to which you're finding you're able to expand market and consequently cement the value from that product?

Well, thanks, Lucas.

I'll try and be quick on this.

The LRS positions will have invested about $1 billion in development this year, including building facilities in Eagle Ford.

We should have, I mentioned, one facility coming on line.

The second facility in the near future.

We, therefore, have around 40,000 barrels a day in Eagle Ford capacity, and we're doing the drilling to start to fill it.

We'll be around about 20,000 or so by the end of the year there.

Added to the Permian and a couple of other basins, that backs the 50,000 barrel a day exit rate in North America.

We now have -- well, we picked up 7 rigs in the Permian, so we've now got 29 operating on LRS positions, of which, in practice just over half are on development, and the other half are on, still, exploration and appraisal activity.

We're still aiming to answer your question, I think, is the short answer, as to what is the appropriate level of development next year.

Certainly, as we take on new acreage, particularly if it's coming off directly from others, we need to ensure that we're moving to our own standards on safety and operations, and sometimes that puts a slight slowdown on before we can ramp up.

But let's see.

We start the year at 50,000.

Let's hope we can end the year considerably higher.

Fourth quarter downstream -- apologies to confirm that you have been right on that over the past couple of years.

No, I was grievously wrong, Simon.

That's the problem, but --

There is no reason that I'm aware of why the fourth quarter should be particularly difficult this year.

We have had good operational performance.

We do have some shutdown activity planned in Europe, but that's not necessarily a big hit.

I think the one thing we do see in Q4 is that it's usually a less volatile trading environment, therefore, less likely to make money.

I suspect that's because most traders spend the quarter doing things other than trading, because they all think they've met their bonus for the year.

But that is just a personal insight.

So, it's a flat quarter for trading, rather than a particularly attractive one, normally.

The demand we see is weak everywhere in our major markets.

All OECD markets are down, but your third question, does have -- point to some mitigation for Shell.

Our market share, in almost every large market we look at, has gone up.

Our unit margins are sustained by the V-Power diesel, whether or not it's based on GTL.

I would say we're still not fully ramped up, in terms of total premium for the GTL product, but we are making steady progress against the plans we expected, including clean diesel, including base oils for lubricants, and including more specialist chemical products.

Our -- we are also growing, of course, in areas like the UK.

We acquired sites last year.

We're growing in, well, Brazilian retail, obviously, I mentioned earlier.

China, we expect our thousandth site, Shell-branded site, shortly.

So, we are actually still growing in the marketing, and there's no obvious reason why the fourth quarter should be particularly worse than we've seen in second and third quarters.

However, I'll reserve judgment until February.

Okay.

Simon, one other, by the way, just -- your license to export oil from the US, can you comment on that, at all?

Intend, hope, et cetera?

Not really.

It's just putting in place the option to do it, to the extent we need to do it.

Clearly, there is a lot of product export from the US at the moment, and there are some mismatches between crude supplies, refining, geographical locations, and, in practice, we are -- we're taking optional positions that we will move product around, as and when it's most efficient and effective to do so.

Okay.

Thanks very much.

Many thanks, Lucas.

Next question?

Thank you.

Our next question comes from Alastair Syme from Citi.

Please go ahead.

Hi, Simon.

You'll have to excuse my lost voice.

Can I come back to your comments on the sensitivities?

You talked about the $10 a barrel move at the beginning.

Yes.

Is that some sort of reminder around the $200 billion cash flow framework?

I just wanted to clarify that, and sort of what sort of assumptions are built into that framework on those spreads, et cetera, you talk about in the US.

And I wonder, secondly, if you could just talk about what level of capital employed was exposed on the write-downs you took in the US?

In other words, how much capital is remaining in the Pinedale and Haynesville?

Thank you.

Thanks, Alastair.

The comment on sensitivities was more about this year than the next four, to be honest.

It's -- effectively, what I'm saying is that the headline Brent price sensitivity is, obviously, upwards, but about half of it is being offset by the refining and gas prices that we see.

If you look at the four-year, 2012-'15 period, then that -- the half that disappears will be less, because we've got, effectively, lower expectations in, for example, European gas prices.

But the full-year cash flow generation is based on a $5 gas.

So, that is one impact and we'll see where European prices go.

We probably don't expect refinery margins where they have been for the last three months, but we would expect them better than they were for the previous three-four years, on average, over the four years.

So, the comment was mainly about the 2012 performance.

Capital exposed -- relatively low.

There's still some capital on the balance sheet, but he majority of the -- we talked about putting $17 billion into acquiring positions in North America in the past.

We've also, obviously, invested at quite a heavy level, but we're also depreciating relatively heavy level.

The majority of the investment has, in fact, been in Western Canada and Pennsylvania.

So, I can't give you a figure.

I don't actually have one, but it's not a -- it wasn't a huge amount that was exposed, and there is a remaining balance.

We've not written it all off.

Could I just come back to the first part, the target framework?

What are you assuming on those forward forecasts in terms of WTI-Brent and Western Canadian crude?

A reversion back more to the mean.

It's not today's $17 to $20, but, certainly, the first couple of years, we would expect there to be some discount.

We do think that there will be logistical solutions.

Remember, historically, WTI has traded at a premium to Brent, not a discount.

So, it will move in that direction, but I wouldn't want to get into too many moving parts.

What we actually deliver in the environment we find ourselves in will be the most important thing.

Okay, thank you.

Okay, thanks.

Next question?

Thank you.

Our next question comes from Robert Kessler from Tudor, Pickering, Holt.

Please go ahead.

Hi, good afternoon, Simon.

Hi, Robert.

Your pessimistic view of refining expressed in no uncertain terms several times today doesn't exactly present a bullish picture for near-term refining capacity expansions on the Gulf Coast.

So, it kind of makes me wonder whether you budget any income contribution at all from the Port Arthur expansion, or whether the expansion will bring down the market, net to Shell, more than the market share increase would benefit Shell.

Thoughts on your budget for income contribution there?

Thank you, Robert.

I need to be careful about not being too unequivocal, I suspect.

The refinery pessimism is global and general.

The winners can only be large, complex refineries in the right geographical locations, able to process a flexible crude slate, and access markets with a level of certainty.

And Port Arthur, and most of our other refining assets, meet that criteria.

It is advantaged in terms of the heavy crudes that can be processed.

It is advantaged in terms of its geographical location, either to trade into the very significant US marketing, or for further export back into South American, Latin American markets.

So, we would expect a positive contribution from Motiva overall, not just from Port Arthur, as we go forward.

It's big, but I'm not sure it's big enough to move the market, in and of itself, but even if it does, the net benefit to us, because we've got the better kit, should be positive.

Thank you, then.

And that's the best I can say.

Another quick one for me.

On gas trading, cited as a positive variance in the quarter, can you quantify that, year on year and sequentially?

Not really.

It's not a figure we give out separately.

It's difficult to separate it from the underlying LNG, but it's one of a series of factors and the biggest factor, year on year, really, is the GTL and the integrated gas, plus the overall LNG volume uptick, which is partly Pluto coming on stream, and partly better utilization, for example, at Sakhalin.

Sure.

All right.

Thanks very much.

Next question?

Thank you.

Our next question comes from Peter Hutton from ARBC Capital Markets.

Please go ahead.

Hi.

It's Peter Hutton from RBC.

Can you just talk about the integrated gas business?

There's record profits this quarter.

You mentioned that volumes were up 4%, but could you just sort of give a little bit of background on the sort of near-term, medium-term outlook, maybe a year out?

Given the comments that you're making on the caution in the refining and the downstream, as well as sort of generally industry-related, any implications there on LNG?

Or are you still seeing that as a very robust market in the near term?

And the second one is more of the big picture stuff in terms of the financial framework and the dividend policy.

I think you were saying before that you'd look at the dividend when you'd had sort of six solid months running of the new projects.

And with Pearl up and coming next quarter and Port Arthur not far away, how close are we now from the clock starting to tick, and when does that translate into the timing of when that dividend review would really get into action?

Many thanks, Peter.

Integrated gas -- we're up 4% in volumes.

We see a very tight market for the next four to five years, as through 2016, '17, before major new production comes on stream.

Thereafter, a lot of the new production is, actually, already spoken for in terms of re-gas capacity, whether it be China, Japan, India, or elsewhere.

So, even for most of the rest of the decade, it's a reasonably balanced market after the tightness is relaxed a little.

Spot market very robust at the moment, and our challenge, if anything, is ensuring we have enough supply to meet that obvious market demand.

We will have an Investor Day in London and -- on the 14th of November, and on the 15th in New York, where we'll talk in quite a bit more detail and context of the gas demand framework, particularly in Asia-Pacific, on which we're premising the strategy.

So, hopefully, you'll be able to follow us in that event or those events, one or the other.

Okay.

Dividend policy -- the policy is, of course, to grow in line with earnings and cash flow through cycle, sustainably.

That's what our investors tell us they like, and to do that in measured, affordable steps.

We increased the dividend back in February, first time in three years, as we were able to demonstrate the cash flow growth.

We've now, as you rightly point out, we're seeing further quarters of underlying cash flow growth and $36 billion in nine months.

Let's remember back in 2009, when we froze the dividend, our baseline for cash flow was $24 billion.

So, in nine months we're 50% higher than we were only three years ago.

And I know there's an oil and gas price effect in there, but there is substantive underlying growth in the cash flow.

We won't be jumping into quarterly or unexpected dividend announcements.

We, of course, will need to be looking at this as we go into next year, because by then, hopefully, we will have seen the underlying, sustainable performance from the big projects.

So, my own logic takes me to having to consider a dividend increase in next year.

But we're seeing good progress on the underlying metrics that will make that affordable and in line with the strategy and the policy.

Thank you.

Very clear.

Many thanks, Peter.

Next question?

Thank you.

Our next question comes from Hootan Yazhari from Bank of America.

Please go ahead.

Hi there, Simon.

Just a quick question regarding your realization in the US, in the North American onshore business.

You've alluded to weakness in price realizations.

Capacity is ramping up throughout the country.

I just wanted to think how much the downstream side is now factoring in to your future plans, not just, obviously, refining, but things like expanding chemicals capacity, expanding GTL capacity, cracker capacity, et cetera, to be able to really benefit from the massive amounts of CapEx you're putting in the upstream to grow the onshore business in the US?

Good question.

In the short term, the main downstream investment is actually in LNG inter-transport.

So, we're looking at -- we're already investing in Canada and looking at US, both with travel centers in, say, the trucking market, but also shipping market in the Great Lakes and on the Gulf Coast.

The -- we will, or, I should say, we are looking at almost all the opportunities you just suggested.

Gas to chemicals, particularly in Pennsylvania area.

We are looking at ethane supply, and some of this is not just the chemicals.

It requires aggregation of supply and the treatment there.

So, there are some strategic control points we need to consider where they might be, and whether we can make the overall value chain work into an area where we do see something of a resurgence in the chemicals and manufacturing industry is possible on the basis of relatively low-cost feedstock and energy.

The gas to liquids, we are -- I think it's known we are looking at opportunities on the Gulf Coast.

It will take some time to run this through feasibility, design, and we're several years away from any investment decision, but at this point in time, both the chemicals and the gas to liquids look feasible.

And you're right, that in the long term, structurally, there is a value opportunity there for companies that can go through the full value chain and actually turn gas molecules into either liquids or chemical price exposure.

That's what we're looking to do.

It will be, as I say, on both cases, probably several years before we can get to an investment decision, and significant capital will be involved.

So, we may need to look at some phasing of the investment, as well.

But overall, it actually looks quite attractive at the moment for a long-term investment.

So, thank you for the question.

Thanks, Simon.

Next question?

Thank you.

Our next question comes from Bertrand Hodee from Raymond James.

Please go ahead.

Hi, Simon.

Hi, Bertrand.

I wanted to follow up in Australia.

Among your very big list of projects in Australia -- Arrow, Brass, Sunrise, Pluto 2, or even Gorgon expansion -- when do you think you will get a new FID, and on which project do you think is the closest to FID, and when do you think this could happen, 2013, 2014?

Can you give us an update on those projects' ongoing status?

Unfortunately, I'll give you an update on the status, but I can't answer the question as to when we expect a new FID.

We're not actually the operator in several of those areas, so for Brass or Gorgon, train four, we're not the operator.

So, the ones that we are operator, Arrow, essentially, is the prime one.

We are already in feed, but Australia, overall, is subject to cost inflation.

We only make money in LNG if you get your capital costs in the right place, and have access to premium markets.

While we know we can get into the markets, we need to make sure that the costs are in the right place.

In addition to the ones that you raise, we're also in the Indonesian Abadi floating LNG, which could have certainly attractive potential, and the Sakhalin project expansion to the third train there would also look to be attractive.

So, we're balancing all of these and maybe we don't want to max out on any one country exposure, as well.

So, it's important that we don't rush ahead of ourselves, just to meet any notional targets.

So, I can't give you a date for any investment decisions.

All right, thank you.

Thank you very much.

Next question?

Thank you.

Our next question comes from Colin Smith from VTB Capital.

Please go ahead.

Thank you.

Good afternoon, Simon.

Can we go back to Nigeria?

You've obviously warned about problems with production in the fourth quarter, but your numbers have held up pretty robustly through the course of the year, and I just wondered if you could give us a view as to whether the problems you're seeing now are just a blip or whether they're presage of something a bit more serious?

And could you also comment on where you think things are with the PIB and how you are thinking about further investments in Nigeria?

Thank you.

Yes, Colin.

Good question.

Not an easy one to answer.

At the moment, the issue is more floods, which, essentially, is more of a humanitarian issue than the long-term sabotage.

So, hopefully, we'll be able to get back running there now.

The theft -- the industrial scale of theft, and the associated spillage, is structural, endemic, and there is a limit to what a commercial energy company can do in these circumstances.

Production is holding up well there, primarily because of gas.

We are, effectively, a major gas producer, and a lot of it's going into NLNG.

It's more difficult to steal gas, of course.

Our offshore activity remains operating well, but we've not taken any sort of major investment decisions there.

We're just trying to keep the facilities full, with the main reason being the PIB being in progress.

Now, it has been in progress since 2008.

So, we need to put the comments, any comments, in that context.

The government and the president are currently very committed to relief.

It's our view -- I think we've made this public, that the bill, the latest draft that we've seen, although it does change on quite a regular basis, is that offshore and onshore gas development would be severely compromised by the bill.

They just would not be economic.

Onshore oil looks -- because it's already taxed at 85%, anyway -- is probably less impacted.

The onshore gas developments and anything offshore looks very challenged.

So, we would hope that there will be, perhaps, a more pragmatic outcome.

And I think not just Shell, but the whole industry has been delaying or deferring investment decisions, waiting for a bit more certainty.

But it is -- as you're probably aware, having followed this for a few years, Colin -- that we always talk about we're not quite sure what will happen next in Nigeria.

And I'm afraid in much of a better position at the moment.

Our current business operates, to the extent it can, very well, very responsibly, and in a very professional manner, in what can be quite difficult circumstances.

So, we're very proud of what our people are able to achieve there, and their operational and safety record is exemplary.

Probably worth saying, as well, just while I'm on the subject, our current investments are, actually, limited to some onshore gas and infrastructure investments, which are helping take the flares out.

We're already less than 20% of total flaring in Nigeria, and the current investments that we're putting in should help reduce that figure even further.

So, many thanks.

I think we're out of questions now.

Many thanks for listening today.

Thank you very much for all your questions.

Just to repeat what I said, we are planning to host shareholder engagement, which will focus on the global gas, both market and our overall strategy, but specifically looking at Asia-Pacific, in London on the 14th of November, and in New York on the 15th of November.

And I hope that some of you will be able to join us for one or other of those events.

The fourth quarter results will be released on the 31st of January -- 2013, of course.

Peter and I will both be available to talk to you then.

I look forward to that opportunity, and wish you all a safe and successful conclusion to 2012.

Thank you very much.

This concludes the Royal Dutch Shell Q3 results announcement call.

Thank you for participating.

You may now disconnect.