殼牌 (SHEL) 2015 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 you to your host, Mr. Ben van Beurden.

Okay.

Thank you, operator.

Ladies and gentlemen, welcome to today's presentation.

So, we've announced our third-quarter results this morning.

And you will have seen some substantial headline losses on your screen this morning.

There are significant one-time charges in these figures, which are a consequence of actions that the Shell management team are taking on portfolio, as well as, of course, the impact of lower oil prices.

So, what I want to do is to update you on that.

And then, Simon will take you through the numbers.

And, of course, there's plenty of time for questions afterwards.

Before we start, of course, the disclaimer statement.

So, Shell current cost of supply earnings for the quarter were a loss of $6 billion.

And these results included $7.9 billion of identified items.

And around half of these charges, $3.7 billion to be precise, are primarily related to a revised oil and gas price outlook.

And the remainder, $4.2 billion, is a result of management actions on the longer-term portfolio.

Now, if you would exclude these impacts, on an underlying CCS basis, earnings were $1.8 billion, with $11 billion of cash flow and a $0.47 per share dividend declared.

And these results were underpinned by a strong downstream earnings and a strong performance on uptime, volumes, and costs across the Company.

The recommended combination with BG is on track, and we are expecting completion of this transaction, subject of course, to Shell and BG shareholder approvals, and also the satisfaction of the pre-conditions, in early 2016 -- pretty much as planned.

Now, let me take you on -- or let me update you on the portfolio actions that we have taken.

And, of course, some of this is flowing into the charges that we have taken in the quarter, alongside that reduction in oil and gas price assumptions that I mentioned.

But first here let me recap on the exploration in Alaska, where we had some drilling results in the quarter.

We've completed the 2015 drilling season.

And we drilled the Burger J well to its target depth.

This well was completed safely, was on schedule, in what is probably the most regulated and high-profile exploration province in the world.

But it was a dry hole, and we are currently in the process of safely demobilizing from Alaska.

And whilst Burger turned out to be uneconomic, there are of course, other potential prospects in our Chukchi leasehold, as well as other areas offshore of Alaska.

However, due to the high cost, and the challenging and unpredictable regulatory environment, we have decided to cease further exploration activity offshore of Alaska for the foreseeable future.

The leases that we have in Alaska expire between 2017 and 2020.

And the US government recently denied Shell's request for lease suspension, which would have extended their expiration dates.

And we are of the view that the US government should simplify and modernize the permit processes there, if there is any ambition to develop oil and gas in the offshore of Alaska.

So, how does this decision fit into our strategy overall?

We're moving forward with the preparation for the recommended combination with BG, and we are aiming to complete this deal in early 2016, as planned.

Transaction is important opportunity to create a simpler and a more profitable Shell; so, what we call grow to simplify.

And major elements of that refocus strategy are under way today as we review and reduce Shell's long-term option set.

Of course, we have Alaska; just mentioned that.

In heavy oil, we have decided to hold the development of the Carmon Creek project in Canada, an in situ oil project.

After careful review of the potential design options, updated costs, the Company's capital priorities, et cetera, we have taken the decision that this project simply does not generate suitable returns.

Elsewhere in these longer-term themes, portfolio restructuring is essentially complete.

In our shales businesses, we have retained attractive options in the Americas, and we've reduced pretty much elsewhere.

In Nigeria, we have reduced exposure with a $4.8 billion asset sales program in SPDC in the last five years, and we're also reviewing options in Iraq.

Overall, we are making changes to Shell's mix by reducing our longer-term upstream options worldwide, and managing affordability in the current world of lower oil prices.

And this is driving tough choices at Shell, and I hope this sets the context for the charges in the result that you have seen today.

Now, let's turn to the quarter.

Let me hand you over for that to Simon first.

Thanks, Ben.

Good afternoon.

Good morning.

I'll start with the macro.

Shell's liquids and natural gas realizations declined substantially this quarter compared to the third-quarter 2014.

The Brent crude oil prices were some 50% lower than a year ago, with similar declines in WTI and the other markers.

The realized gas prices were 18% lower than year-ago levels, with strong decline in gas prices seen in North America.

On the downstream, the refining margins around the world continue to be supported by the lower crude prices, but also by robust demand and industry refining downtime.

The industry base chemicals margins declined in North America, as ethylene prices fell with the crude.

Intermediates margins increased on the back of reduced feedstock and the energy costs, and improved market conditions.

Now, turning to the results, excluding identified items, Shell's current cost of supply, or CCS, earnings were $1.8 billion.

That's a 70% -- seven zero percent -- decrease in earnings per share from the third quarter of 2014.

Within that $1.8 billion figure, there was $1 billion of non-cash charge related to currency movement, which were not taken as an identified item.

On a Q3-to-Q3 basis, we saw significantly lower earnings in the upstream, and higher earnings in the downstream.

The return on average capital employed, excluding the identified items, was 5.5 percentage points.

Cash flow generated from operations was some $11 billion.

Our dividend distributed for the third quarter of 2015 is the same as the year ago, at $3 billion or $0.47 per share.

Turning to the business segments in a little more detail -- first, the upstream.

The earnings, excluding identified items, for the third quarter were a loss of $425 million.

The oil prices have halved from the year ago, and that, combined with gas price movements, together, reduced the upstream results by $4.4 billion.

The results this quarter did include a negative of $761 million of non-cash tax effects related to movements in the Brazilian reais and the Australian dollar.

They also included a higher level of well write-off.

Integrated gas results within the upstream figures were $824 million in the quarter, and that compares to $2.8 billion a year ago.

Again, the majority of that decline was oil and gas price related around $1.4 billion.

In addition, last year the Q3 results in integrated gas, included a catch-up dividend payment from an LNG joint venture around $200 million, which has not recurred this year.

And also this year the integrated gas results do include a $470 million non-cash tax impact for the movement in the Aussie dollar, and that's a negative movement, of course.

The results in the third quarter this year also exclude dividends from the Malaysia LNG Dua Joint Venture.

They were, a year ago, $195 million; that's the joint venture that we've now exited, so no contribution this year.

So, you can see there's quite a few moving parts in these upstream results, but I think it's important to note that our actual underlying upstream operating performance continues to improve.

The focus on reliability and uptime, and the project growth, is delivering, with an increase in production, decline in operating cost, and successful exploration appraisal wells at Kaikias and Power Nap, both in the Gulf of Mexico.

Now, the headline oil and gas production for the third quarter was 2.9 million barrels of oil equivalent per day.

That's 3% higher than last year.

However, the underlying volumes, like for like -- they increased by 9 percentage points.

This was driven by improvements in the operating performance, and we saw lower levels of unplanned maintenance compared with the same quarter last year.

The underlying volumes also strongly supported by the ongoing ramp up in deepwater fields in Nigeria and Malaysia and in the Gulf of Mexico, and that alone more than offset the impact of the field declines.

Our LNG sales volumes in the quarter were some 5.3 million tons.

That's down 6.5%, quote, Q3 on Q3.

That mainly reflects lower volumes as a result of the expiry of that Malaysian Dua Joint Venture.

Turning now to the downstream, the earnings for the quarter, excluding identified items, were $2.6 billion.

That's driven by high results in both oil products and chemicals.

Oil products -- we benefited from increased refining margins and lower costs.

Some offset from lower contributions from marketing, although that was mainly as a result of exchange rate movements and divestments.

Chemicals earnings were 15% higher than a year ago.

In turn, driven by improved market conditions and lower energy costs for intermediates, partly offset by the weaker base chemicals environment due to the falling ethylene prices and the outage at Moerdijk plant in Europe.

Overall, this was a strong quarter for the downstream.

So, return on capital on the clean CCS basis was 19.3% at the quarter end, with the downstream cash from operations generated around $16.5 billion over the last four quarters.

The cash flow for the group as a whole, on a 12-month rolling basis, were some $34 billion at an average Brent price of $60 a barrel.

Free cash flow -- that's after deducting the investments -- was $5.5 billion in the quarter, and $11 billion over the last 12 months.

Gearing, on the balance sheet, the debt divided by debt plus equity, was 12.7 percentage points.

That's essentially unchanged over the year, despite that significant downturn in the oil price.

Our returns to shareholders [versus] dividends declared plus the buybacks were $13 billion -- one three -- over the last 12 months.

Now, some of you have asked us about dividend affordability against the backdrop of low oil prices today.

So, let me just share with you how we think about this.

We plan the financial framework on a long-term, multi-year basis; not for any given year or quarter.

We aim to balance the cash in and cash out across the cycle, wherever the prices might be.

You can see on the chart here that Shell has delivered on this strategy both on a long term, up to five years, and a short term, over the last 12-month basis.

Our oil price cash break-even point, over the last 12 months, has been around $60 a barrel, or the same as the actual price.

And we have options to further reduce that going forward, such as asset sales and capital investment levels.

As an example, as we go forward, $5 billion of divestment proceeds in a given year approximately equates to a $10 movement in the oil price breakeven for any given year on a cash flow basis.

The combination with BG enhances Shell's free cash flow -- improves our dividend potential in any expected oil price environment.

And in the future, one of the key elements of the BG deal is moderated capital spending -- a higher rate of asset sales, and more of the shareholders' cash returned as share buybacks.

So, let me sum up.

Our integrated business and our performance drive are helping to mitigate the impact of low oil prices on the bottom line in what is, admittedly, a difficult environment for the industry today.

While our underlying performance in the quarter was strong, the headline numbers we report today, including the charges reflecting both the lower oil and gas price outlook, but also the firm steps that we've taken to review and reduce Shell's longer-term option set.

The BG deal itself -- that remains on track for completion in early 2016, and it will be a springboard to focus the Company into fewer and more profitable themes, especially, of course, deepwater and the integrated gas.

With that, I'd like to move to take your questions.

But also, just let me remind you that we're having a management day in London, next week on Tuesday, followed by a day in New York on Wednesday.

So, prefer if possible to keep the Q&A today to the quarter, and we can expand more next week.

And please could we also just keep ourselves to one or two questions each, so that we give everybody the chance to get in a question?

Thanks a lot in advance.

Operator, please could you poll for questions now?

Thank you.

(Operator Instructions)

Theepan Jothilingam, Nomura International.

Yes, hello.

Good afternoon, gentlemen.

Just two questions.

Firstly, you've discussed, sort of, a cost improvement target of around $4 billion earlier this year.

I was just wondering how much of that has filtered through into the Q3 numbers?

And, if you could break that down between upstream and downstream?

Secondly, and, I imagine you'll talk a little bit more about this next week.

But just, upstream Americas, remains a problem child and that's been exacerbated by lower liquid prices.

Was there anything in particular, outside, simply the operational gearing that we saw come through in Q3 that might reverse out if we look into 2016?

Thank you.

Thanks, Theepan.

Good afternoon.

The $4 billion cost reduction wasn't really a target.

It was an achievement.

We'd already done it.

So, yes, it's already there and we also said we expect to see further improvements.

It's roughly, split between upstream and downstream.

We're currently putting together our expectations for 2015, but certainly on a like-for-like basis, we would to see -- expect to see further improvements.

So, all of it's in there, year to date, effectively.

On the upstream Americas, remember there's a combination of businesses in there; Deepwater, Alaska, the heavy oil and the unconventionals in the shale business.

The -- there is a one-off charge around $300 million on the Brazilian deferred tax that is included in upstream Americas.

And, other than that, there's not too much one-off that really relates in the clean earnings.

Of course, quite a lot of the [abandoned] one-offs were indeed in the Americas.

So, the issue is really realized oil and gas prices.

And, while the costs are certainly coming down there, we are -- we will need to take more out in the current price environment to see a return to profitability.

The actual performance of the assets, both in the heavy oil and in the Gulf, was better than a year ago.

Underlying performance reliability up.

And, in the shale business, for quite a reduction in the capital investment, we are maintaining the production levels and targets that were originally deposited before we reduced the investment level.

So, in general, good progress.

But, not enough to see a big impact yet on the bottom line.

Okay.

Thanks for that.

Operator, can I have the next question please?

Oswald Clint, Sanford Bernstein.

Thank you, yes, thank you very much.

Intent, it's maybe, two questions on North America.

Sorry, the first question, I wanted to ask about the impairments in the upstream.

I think it's North America.

I think it's North American gas, potentially, Duvernay or Groundbirch.

Could you just talk about the gas price changes that have been incorporated into that exercise?

And also, does it imply anything about your appetite for, kind of, West Coast Canadian LNG exports?

That's the first question.

And then, secondly, maybe just on Carmon Creek.

I -- obviously, I heard your comments there.

I just want to know in addition, was there anything with respect to the technology or actually the reservoir in terms of the Carmon Creek that forced you to make this decision?

Thank you.

Okay, thanks very much, Oswald.

Good questions.

Let me take the first one.

Well actually, I will be happy to take them both.

The -- let me talk a little bit more broadly on our oil and gas price outlook changes.

The screening values that we have been talking about before, I think, ultimately ended up being characterized almost as central management tool.

Which, of course, they're not.

They also, some point in time, got characterized as a Shell forecast.

Which, of course, they're also not.

So, the reality is that we managed the Company differently.

We managed the Company on the fundamentals of the market and on the reality of the day, and, if you look at the fundamentals, be it oil or gas.

The point is, that industry will not invest trillions of dollars at the price and the costs are such that you can't make a profit.

And, if investment slows down, supply will quickly fall short of demand.

And, as a result of it, prices go up, costs will come down, or, a combination of the two.

The reality is, of course, that we don't know when this process plays out, how it plays out, at what level it stabilizes.

And, whether or not there will be, sort of, remaining volatility as a result of all of this.

So, the way we are looking at projects now, is not so much with, here is a screening value.

But, it's really, how can we make sure that all our projects that we are considering are resilient, are completely competitive in their class to a point that we are clearly ahead of the rest.

Because, if the industry needs to exist, it needs to make a profit and we want to be ahead of the curve, so to speak.

Now, the other part of the reality of the day is, that we have to live within our means and that means living within our means at today's oil and gas prices.

And, that essentially is, as you heard from Simon, what we are doing.

We live within our means at $60.

Which the oil -- where the oil price, on average, has been over the -- how many of, the last 12 months.

That's how we manage the business.

That's also how we want to talk about managing the business going forward.

So, yes indeed, if you look at where oil and gas prices might go in the future they will probably have a more conservative outlook than what we had before.

But, I do not want to characterize numbers here and then see them being used as management tools.

Which, as I said, they clearly are not.

Now, what does it mean for LNG Canada?

We are in the middle of the defeat for LNG Canada.

Of course, if you look at gas prices in North America, you can imagine a downward adjustment is actually going to improve the economics of a project that fundamentally takes a margin between US gas prices and North Asian gas prices.

But, at the same time that's not the only driver.

Again, I go back to my principles.

This project needs to be ahead of the pack.

It needs to deliver the most competitive LNG into the target market and we need to understand how resilient that is to the sort of volatility that we will, no doubt, continue to see in oil and gas markets in both sides of the Pacific.

That decision will come up later in the year.

I think, I -- I'll leave it that.

We'll take that discussion again when we are near a -- an investment decision point.

On Carmon Creek.

Yes, there were a lot of moving parts in Carmon Creek.

So many things have, sort of, continued to evolve since FID.

Costs escalation, evacuation routes that worked out differently and became rather uncertain.

Of course, the whole oil price environment, not just the global oil price environment, but the Canadian oil price dynamics.

And, the upshot of it is, again, the project turned into a project that was just not sufficiently resilient in today's environment.

So, we pose it, already, earlier in the year.

We had been working on cost and getting more certainty around evacuation options.

We got the costs back in control again, more or less, fully.

But, ultimately, we were looking at a project that's -- was just not resilient enough to go ahead under the affordability pressure that we have.

And, the only sensible going forward was to, basically, shelf it.

Incredibly tough decision to do, but also, simply necessary.

There was nothing in the technology, as such, that made that if you look at the sort of fundamental technology of steam injection in these types of reservoirs.

It was just the economic resilience and the affordability that just didn't make us comfortable to go ahead.

Thanks for these questions, Oswald.

Can I get the next one?

Brendan Warn, BMO Capital Markets.

Yes, thanks, gentlemen.

It's Brendan Warn from BMO Capital Markets.

Just two questions, if I may.

Just first, question, this, I guess, relates to the acquisition of BG.

And, just in terms of current oil price, and if we took the forward curve as given as an example, can you just talk around the share buyback?

And, the pressure that may be under the share buyback in terms of what trigger points you'd look at to buy back shares that you previously announced from 2017?

And then, I guess, just a second question, again, just relating back to Carmon Creek.

And, I -- if you could just talk around if this is a one-off in terms of post-sanction cancellations?

I appreciate it's a tough decision.

But, if we're still in this environment in -- certainly, in the next couple of quarters from here.

Just, sort of, what percentage of committed CapEx spend is at the edge of assessment in terms of cancellation please?

Yes, thanks, Brendan.

Let me take the Carmon Creek one and then Simon will talk about share buybacks.

Yes, I think Carmon Creek was a -- was quite a special case.

A challenging project because of the economic environment in which it had to operate.

As I said, not just cash, of course, but also the very difficult dynamic that we have in oil prices.

So, not just the bitumen price that we would see in Alberta; the bitumen netback, but, also the whole pricing dynamic around [biluence], the uncertainty around the evacuation route.

And, ultimately, it was just too many things coming together, conspiring against the project that made the project not just attractive enough.

But, also, not resilient enough to have the comfort to take it forward.

And, we had, of course, several billion dollars of investment still outstanding.

So, I think that is a relatively unique case.

Now, the other thing you have to bear in mind, of course, it's an onshore project.

It's somewhat easier to hold.

It -- you may argue that if, what comes close to something that is always on the cusp of, will we go ahead or will we hold back, is shales.

But, that, of course, is a less punishing type of decision because you can take it a little bit more -- the investment decision, you can take a little bit more a hand-to-mouth approach.

So, you will see us flexing that a little bit more, and simply, because we can without too much penalty.

But no, I would characterize this to be a -- an unusually tough decision to take.

And no, we don't expect that to be candidates in the current portfolio of projects that we are bringing on-stream.

Simon?

Thanks, Ben.

I'd also note, that on Carmon Creek it's 100% Shell.

So, something we have more control over to take a decision.

On the BG deal.

I'll, for the -- expand a little on the question, if I may.

The -- we're getting a lot of questions around pricing and the value of the deal.

So, just to be clear, the deal was deliberately structured back in April, with 70% equity, 30% cash.

The equity ratio, share-for-share, is fixed.

So, as oil price and therefore share prices, have varied, the deal offer varies as well.

So, on the day of the announcement, it was $70 billion for the common equity four weeks ago.

But, amount has readjusted to $56 billion; therefore a 20% reduction.

As of this week, it's in the low $60 billion, so, more than a 10% reduction.

The share prices both companies, under sector, tend to reflect the forward curve.

So, there is in essence, a natural hedge in the market as we go through the period.

And, that's precisely how the deal was structured.

It's working.

Now, that doesn't necessarily help with the -- and will the cash be available in the future to execute buybacks if the oil price stays at 50?

And, the forward curve, of course, doesn't actually extend out in any meaningful way as far as the buyback period 2018 through 2020.

It's -- it only actually reflects storage cost, either putting it in or taking it out.

It has nothing to do at all with the fundamental supply and demand characteristics of the market.

Having said that, if the oil price stays at a low level because the marginal cost gets set at such a low level, then the buyback program is going to be more challenging to execute.

But, the determination to do so over a period is completely unchanged.

It is an essential part of the offering to shareholders post the completion of the BG deal.

First, we address the debt characteristics, the rating.

And secondly, we return cash to shareholders.

And, that's a fundamental principle that will apply whatever the price happens to be as we go forward.

Okay.

Thanks for that, Simon.

Thanks for the questions, Brendan.

Operator, can I next one please?

Lydia Rainforth, Barclays.

Thank you and good afternoon.

Two questions to focus on the numbers if I could.

The first, just thinking about the cash flow from operations for the quarter.

Clearly, you could echo those numbers, the $11.3 billion includes a large working capital lease.

You've then got $5.3 billion, given in the statement as excluding working cap.

But, when I'm thinking about what is an underlying and ongoing, or, per divisible by cash flow number, if I ask about the inventory holding loss as it gets me about $6.6 billion.

Is that the right way to think about the cash generation over this quarter itself?

And then secondly, just a very quick one.

The write-downs in Oceania; did that relate to the Arrow project?

Thanks.

Simon?

Thanks, Lydia.

The working capital movement is always a bit volatile and not always representative of inventory.

Which actually went up in the quarter in volume terms.

Obviously, down in price.

It was a high movement.

There are movements in there that are driven by, the provisions for example, that we took relating to Carmon Creek and Alaska.

So, to be representative, the other way around.

Technically in earnings, add back the non-cash billion or so on currency and around $4.3 billion of depreciation per quarter.

So, we start with an EBITDA type number and, but then, take off effectively, the tax.

Because, the tax payments are not aligned either with the tax charge.

You get to a more representative figure.

Which is not that far off the figure you've had -- got, but a little bit higher.

So, between seven and eight is probably the underlying cash generation from ops.

Write-down in Oceania.

We've looked at, I think, clear lower oil and gas for longer.

There are implications from lower gas prices.

Henry Hub in North America explicitly noted, in Oceania we have multiple assets.

Most of which, although they're gas production, are ultimately exposed to oil prices because of the netbacks on Asian LNG.

So, wouldn't identify any one asset, but there are multiple assets down there.

Thanks, Lydia.

Thanks, Lydia.

Thanks, Simon.

Can I have the next question please, operator?

Irene Himona, Societe Generale.

Thank you.

Good afternoon.

Hello, Irene.

I had two questions.

Firstly, on the FX.

The $1 billion non-cash input on the P&L.

I mean, obviously, we have zero visibility on that.

And, normally, companies would take such a move through the balance sheet.

Can you just remind us of the logic of taking it through the P&L, please?

And then secondly, very quickly on CapEx.

You have spent $20 billion in the nine months, just under $7 billion a quarter; your guidance remains for 30.

Are you likely to undershoot, do you think, this year?

Or, are we going to see quite a step up in Q4 spending?

Thank you.

Thanks, Irene.

Simon, will you take them?

Thanks, Irene.

Indeed, there are three elements to the FX move this quarter.

That we have deferred tax assets in Brazil and Australia which are slightly complicated in terms of the way that the currency moves on it.

But, we have given sensitivities through the IR team on what they may be in there.

They basically reflect the exchange rates on the last day of the quarter.

There's no choice as to whether they go through the P&L or not.

They are not balance sheet items in terms of the way they translate.

This quarter, there are a few other currencies where we have loans, some of them into group, held in non-US dollar currency.

Because, that's the currency of operation in those activities.

Where the general strengthening of the dollar has also added some negatives.

So, if -- it's effectively $761 million in the upstream and couple hundred million in corporate and in the quarter.

The other question we're regularly asked is, why don't we identify them separately?

And, some companies definitely do, do this and some don't.

The primary reason is that we don't change our policies on what we report on a serendipitous basis.

It's a fair question; now it's become so material and so volatile with limited means at our disposal to actually reduce that volatility.

So, it may be something we think about going forward.

But, we typically don't make changes in the middle of the year.

The $7 billion a quarter capital investment.

There is some uptick in Q4 partly, and it's mainly in the downstream.

Partly, will be driven by turnarounds and partly, by the back end of the year at retail activity.

So, it's more marketing spend that tends to be later in the calendar year for a variety of reasons.

I can't really give a more accurate figure than that.

But, we said 30 or we'd be doing better.

The trend is exactly as you state.

We have quite a lot of tens of thousands of people working on this, not just Ben and I. So, the good news is that the right decisions are being taken in many different parts of the organization.

We have not given an indication for 2016, other than to say on completing the combination with BG, we'd expect the combined capital to be around 35.

That's no reason to change that statement today.

Yes.

Okay.

Good.

Thanks, Simon.

Can I have the next question please, operator?

Fred Lucas, JPMorgan.

Thank you.

Good afternoon, gentlemen.

Two questions if I may.

The first one on impairments.

Could you specify what price curve you've assumed for the Q3 impairments?

And, also, perhaps the sensitivity, where you to reduce that curve by $10 a barrel?

And, related to impairments.

The $60 billion, or thereabouts, that your deal for BG is currently valued at.

That implies quite a sizeable balance sheet uplift to the value of BG's assets, order of magnitude $25 billion to $30 billion.

I just wondered how safe that uplift would be to your current impairment test?

The second question is on exploration.

Obviously, you have good and bad quarters for Q3.

Perhaps, not a vintage one with [burkett shay] and it's discovery on Shell acreage in Egypt.

I just wonder whether you think the internal decision-making at Shell regarding what equity exposure you should take in blocks and when or when not to relinquish blocks is really fit for purpose?

Okay, thanks, Fred.

Let me take the next question -- the second question first and then, Simon will talk a bit about the impairments.

Yes, I think it's a fair question and a question that we have to address.

It -- the -- if you look at our last comp.

The only good news about our last guy is that it was a very conclusive result.

So, at least, we knew immediately what to do as a result of it.

But, of course, it's a very expensive dry hole.

And, it -- of course, we can rationalize that to a large extent by, sort of, pointing at the unbelievably complex regulatory environment that we were looking at.

Of course, generally, we -- you would expect exploring in this type of climate to be more expensive because of the weather and the remoteness and everything else.

And, you would, of course, only do that if there was a significant amount of barrels to be potentially discovered.

But, as it turned out, this one went bad on us.

I am not going to just say, well, that's exploration even though it is what it is.

We will have to look back and say, let's take a good view on how we got here.

And, without, sort of, rehashing the 2012 season, let's just try and learn from this as much as possible.

Also, on what sort of review points that we take and for the benefit of hindsight, should we have taken a different view and what can we learn from it?

I think it's an important moment, an important thing to do in cases like this.

Much, by the way, as we also have to learn from everything that did go well.

Because, it has been an exceptionally difficult campaign and we have operated, I think, exceptionally well.

And, it would be remiss of me not to also in a call like this, remind all of you how strong a performance the team there has delivered.

With lots of new capabilities, by the way, that has resulted from it.

That I'm sure we will use in other areas of the world where we have to deal with ice, or with very difficult conditions.

But, it -- let's do that work.

We will bring that back to the board as well.

As you can imagine.

First priority now, is to make sure that we safely demobilize from Alaska.

Simon.

Impairments.

We use a range of prices for all purposes in Shell.

Whether it's impairment, long-term decision making, short-term trading, or otherwise.

We don't use a single price deck.

We did come down the -- on the long-term assumptions for impairments.

We actually do the first screening at the lower end of the range and then look at a more representative expectation to do the actual calculation for impairment.

So, I can safely say, that if we brought the price down there wouldn't be anymore assets at risk.

While my argue that the actual impairments taken might be slightly higher.

But, not materially higher.

I don't think, in the sense as going forward whether we would do anything differently.

And, just to note, the biggest impact was the reduction in the Henry Hub price, not the oil price, and the impact that's had on gas assets in North America.

BG, it's a good question.

This is a little complex.

I'll take just a moment to explain for those who are maybe not as up to speed as Fred.

The assets for BG, when we bring them on to our balance sheet at the data completion, will be recorded first at fair market value.

That's a third party valuation, so it'll be partly based on what you guys think.

It will be above the current carry and book value of the BG assets.

For sure.

And, there will then be an ongoing amortization of that purchase price premium.

The amortization, we said back in April, could be up to $2 billion a year and that obviously pays in the earnings per share.

As of today, almost by definition, you would give a lower fair market value.

So, make your own choice on what that might actually do going forward.

Any remaining difference between that fair market value is then recorded as goodwill.

And, when I say difference, that means difference between fair market value and the equivalent of the offer based on the share price on the day the deal completes.

So again, it could be just about anything going from here to there.

Given the extreme volatility we see in the markets.

We do not know what the goodwill will be.

We have a reasonable idea where the fair market value will come out.

As of today, we don't see any reason to be concerned on its future impairment.

Of course, if you're -- the share price were to be excessively high with a large goodwill, that thing gets tested for impairment every year thereafter to ensure we still see the value from the totality of the BG assets within the combination.

Thanks for the question, Fred.

Yes, thanks, Simon.

Thanks, Fred.

Can I have the next question, operator?

Jon Rigby, UBS.

Oh, hello, hi.

Just one question.

It's about impairments, really, and a, sort of, broader perspective.

It seems there's, sort of, modern era of Shell as being periodically scarred by these events where you take very large impairment charges.

And, I think, in the context of the Company that is obviously deploying a lot of capital, a lot of CapEx annually.

Is there a problem there in terms of the process by which you go through thinking about how you deploy capital?

And, could that be tightened up?

The process be tightened up going forward?

Because, it would seem to me, that even though you've talked about a fairly sophisticated process and you've talked about the environment and the scenarios, is -- there is evidence that you periodically get it quite wrong.

Yes, that's good philosophical question, Jon.

And, it, of course, charges and if I characterize, for instance, what happened in -- lots kind of charges have come with it.

You will have them as a result of the nature of our industry.

But, I'm sure that's not exactly what you are referring to.

It's more impairments on assets, leaseholds, operating assets that we have on the balance sheet.

The only thing I can say is this has been, of course, a significant focus area over the last few years.

I'm not going to sit here and say, now impairments are actually good and healthy and we use it as a way to clean the cupboard out.

That would be the complete wrong way to characterize it.

I think we have to make sure that, in the main, you import impairments that can clearly be traced back to poor decision-making around capital investments and deals that we have done.

And, a lot of the focus, one of my key priorities from day one, has been, how can we improve decision-making around capital investments and deals?

And, how can we do that by making not only the decision process more robust, but, also make it much earlier in the cycle?

And ultimately, I think it is processes like this where we have better visibility, earlier visibility, clear enough, much clearer guidance on what we want to see in terms of resilience.

And, tying it into very well articulated strategic intents for each of the investment themes.

These are going to be the processes that need to get it right.

It is tough that you have to make decisions that lead to impairments.

Believe me, I don't like them at all.

But, you have to take them in the environment that we find ourselves with the legacy that we have in certain areas.

But, the processes we have in place are clearly designed to make the decision process and the resulting portfolio from it, much higher quality, much more predictable.

Okay, can I have the next question please, operator?

Martijn Rats, Morgan Stanley.

Hi, hello.

I just had a quick question about Slide number 6 in the short package.

You probably still -- at the bottom there's a comment on Kazakhstan.

The title of that page is actions taken and it refers Kashagan and BG asset potential.

I was just - I just wanted -- wondering what actions are taken in that area?

I'm -- wasn't quite sure what that bullet point referred to.

I think it's just an indication, what -- well, first of all, we always said, in the longer-term themes, we have also what we call INK, internally; Iraq, Nigeria, and Kazakhstan.

And, we have to take a view on how these are going to be long-term positions for us.

Because, they have unusual characteristics and different countries in that category have different types of characteristics that make them unusual.

I talked about Nigeria.

Which is basically, sort of, restructuring the portfolio.

I mentioned Iraq.

Which is basically referring -- reviewing Majnoon and looking at, what do we want to do with full field development?

How do we take into account the directives that we get from the Iraqi government to spend less?

And, what are the consequences of that particularly affect Majnoon, much less so, the Basrah Gas Company?

And then, yes, Kazakhstan, of course, has two things in it.

Kashagan, which, of course, we need to see how that will come on-stream exactly.

Hopefully, late next year or early 2017.

And, of course, what is the potential of the BG assets when they come in?

So, it was more mentioned for completeness sake.

We don't have a particular review that is going on, on Kazakhstan.

Other than to say that these two, of course, are very material positions if you have them together.

So, Kazakhstan will become quite an important country, but, also a country that has very, very long live assets.

So, I would not read anything else in it and just mentioning it for completeness sake.

Thanks, Martijn.

Can I have the next question, please?

Thomas Adolff, Credit Suisse.

Hi, Ben and Simon.

Two questions as well.

Just firstly, on the BG transaction.

I wondered how the two integration teams are working?

And, whether you have any interesting updates now that you had access to a bit more data, if you will?

Positively surprised or negatively surprised?

And secondly, just going back to this thing you call cultural change.

I think, generally, people have the perception that Shell will struggle to change culturally.

You are a very complex organization.

So, when you talk about this platform for cultural change, can you, perhaps, give some example that the entire organization is actually buying into your strategy?

And, maybe, some examples that are harder to see for an outsider like myself?

And, what this BG transaction will do to accelerate this thing you call cultural change?

Thank you.

Thanks, Thomas.

Simon, why don't you have a start and I will pick it up.

Many thanks.

I'll just talk about the integration, really.

Thanks for the question.

We have about 40 people working.

Roughly half and half from Shell and BG together.

Separate office, separate team, 19 defined work streams, and an environment, in which, it gives me great confidence that the two teams will be able to work together.

And, then more of a sense from we actually come together.

Great contribution, positive, from all of the BG people involved.

I think Helga's given a good steer that we're in this to create value and create a winning combination.

And so far, its been a very positive experience.

The -- as we work, there are limits to the amount of data we can share.

Particularly, as we're still competitors.

So, confidential information can't actually flow yet.

But, in general, where it can, I would say there are ups and downs.

Probably more positives than negatives.

I can't say anything more today in terms of quantitative.

Just that, the mood music and the way in which the teams are saying, hey, when we come together, these are the things we could do, do go beyond just what you might think from looking at the paperwork.

Yes, I think on the cultural change, let me say a few things, Thomas.

But then, also remind you that, actually, we -- when it comes through, the BG combination, we will, of course, be going into this a bit more completely next week.

So, I may reserve a few things for that as well.

There are, of course, areas where we believe BG is doing things very well that we want to make sure we learn from them.

We know that they have a very, very good exploration capability in certain areas.

We also know that they have a really first class management of non-operated ventures simply because that is the bulk of their portfolio.

We tend to have still a slightly more, sort of, Shell operated portfolio in the balance.

We know that they manage their integrated gas business through their GEMS organization in a way that is slightly different from ours because they came at this portfolio model from a different way.

We are both aggregators but they manage it in a slightly different way.

Everything becomes work processes, people capabilities, et cetera.

That are just very worthwhile to understand, how we pick the best from it.

So, we have identified these and other areas as areas that the integration team, called BG Magic, and we want to make sure that we, sort of, build them in to the combination going forward.

And, there's multiple different ways to do that.

You can imagine, has to do with processes, structures, and individuals.

And, that's exactly the three levers that we are using to make sure that this comes across very well.

The other thing when you talk about complexity, Thomas, it's -- of course, we are a large organization with many assets around the world.

And, we have a model that is matrix, which is pretty much what you have to do in a situation like this.

But, -- and that is not going to change going forward.

It -- we will make sure that it works very well with the BG assets coming in.

Make sure we have the same performance unit approach that we have in Shell also very much imprinted on the BG assets.

Which I think is actually going to be pretty straightforward.

But then, a lot of the other complexity that, maybe, comes from the breadth and the size of the portfolio.

We are going to take out, not so much through a culture program, if you like, but, through a portfolio upgrade program.

Which is very much at the heart of this growth to simplify mantra.

I'm making sure that we focus the organization down on those capabilities and investment themes where we have leadership.

And, that by making the Company not only more focused, but, with it, more predictable, more reliable.

But, also making it more profitable and more attractive for our shareholders.

Perhaps, easier to understand as well.

So, all of that sits together.

I think talking to the comments that Simon just made.

Both, actually, I shouldn't say both anymore.

The integration team is incredibly excited about making this work.

It -- I know that both our chairman have been recently at the dedicated integration office and both were struck by the fact that these people are working for the combination.

They're not two teams coming together trying to figure out what to do next and that's exactly the trajectory we want to be on.

We want to be absolutely ready for day 1 and we want to be ready also for day 30, 60 and 90 and that's what they are planning for.

Thanks for the questions, Thomas.

Can I please have the next question, operator?

Rob West, Redburn.

Hi there.

Thanks very much for taking my questions.

Simon, you asked, at your peril, about questions on the P&L, so I'm going to give you one.

I -- just looking at the production manufacturing expenses, which is the very real key cost line I always look at in the quarter.

So, if I think the 3Q this year versus Q3 last year, it's about $4.9 billion in both quarters.

And, if I look at the downstream, same line, it's about $2.6 billion this quarter and about $2.6 billion in 3Q last quarter.

I'm wondering, is that a little bit unfair to look at those and say the costs are broadly flat?

There are moving parts in there like restructuring effects that are effectively one-offs, but the underlying trend is going down a little bit more.

Get down a bit more.

Second question is on production.

Which I thought was good in the quarter.

There -- is there some, you alluded to this in the release, some higher uptime at your fields going into that effect.

So, I think you mentioned Gulf of Mexico on the call and Pearl GTL and Malaysia in the release.

But, is it a general theme that you finally can squeeze more oil out of these fields just across the entire Company?

I'm interested in that.

And, there attempts, maybe one's more on, just something you said a second ago.

Which was just that there's some consummate -- confidential information that isn't flowing between yourself and BG yet.

Would that include the terms of your LNG contracts?

Thanks.

(laughter) Thanks, Rob.

Probably I better take them all, yes?

The last one's easy.

Yes, it does, we can't -- because we can't talk about LNG commercial contracts until we are one Company.

There may be a point at which a clean team is established to ensure that on day one we can operate without competing with each other.

But, the -- that's for the future.

The -- can we squeeze more barrels out of the assets?

I'll take questions in reverse order.

The basic answer is yes.

Several years ago, we put quite some time and resource in what we call WRFM, well and reservoir facility monitoring.

Which, in essence, is how much more can you squeeze out from regular, but, small investments, sometimes as OpEx, sometimes as capital, from a reservoir?

So, upgrading, then monitoring of individual wells, pressure, performance, et cetera.

And, applying a bit of technology where appropriate; drilling extra wells, workovers.

And, over time, that has indeed, we believe, squeezed more out of the assets.

Our actual underlying decline rate this year has been around three percentage points.

Five years ago, that was usually 4.5% even 5%.

Now, there's a maturity of assets contribution as well.

But, by and large, we are taking probably 2%, 3% over the last couple of years.

More production out of the same asset than we would otherwise have expected.

The expenses, you have -- always look at the P&L at your peril.

In general, the right comparison is more the nine months than the three months.

The three months does include, in some of the expenses you note, the provisions made around Carmon Creek, in particular.

Because, they show up, not in exploration but in production, potentially, production manufacturing, or, SD&A expenses.

So, there are some one-offs in Q3.

But, the nine month comparisons, where, for example, the production manufacturing are down by $2 billion; SD&A down by $1.5 billion, is more representative of the reductions that we've actually made.

Okay, thanks, Simon.

I can't resist, actually, adding a comment on the second question.

It's -- so, on a quarterly basis, we come together.

The upstream teams, so, and the brown, I've got to note them, have a recommence together with a few other people in a war room here in the Hague, to just see how we are getting on with all the programs and all the assets.

And, what we are seeing as results and where we see where the uptake of some of the excellent initiatives are working out.

And, where we can do more.

I join it every now and then.

I just joined it a few weeks ago.

When we had another one of those.

Sort of, spend another three hours with them to see how things are picking up.

It's remarkable to see how that focus on production excellence.

So, WRFM, as it was mentioned by Simon, really is beginning to come true and is transforming the quality of the operations.

Reason why I am so interested it is because many of the concepts we have there are concepts in terms of asset management at their heart have worked very, very well in the downstream.

Have worked very well in our LNG plans.

But, reliability, of course is basically what you sell.

Reliability of supply.

And, of course, also in our GTL plants, where we have very, very complex assets.

That are very easily, of course, affected by unreliability.

So, I -- yes, I do think that we are making a lot of progress there and I do also think that it is sustainable.

Anyway, thanks very much for that question, Rob, and let's go to the next one, operator.

Aneek Haq, Exane BNP Paribas.

Hi, guys.

Thank you very much.

Just two questions, please, as well, for me.

The first one coming back to this point on CapEx flexibility.

I wondered if you could, maybe, I understand, obviously, you can't talk about Shell BG combined.

But, on Shell's standalone basis if we take that $30 billion number, and would just say, theoretically, to assume no sections over the next couple of years.

How much can you bring that down?

Or, how much of that roll off over the next two years?

Is it $5 billion or $10 billionish?

And then, the second point on downstream, actually.

I'm just interested if we take that $2.5 billionish CCS earnings you've done this quarter.

How much would you classify of that, say, is defensive?

And, I mean, lubricants, I mean, marketing, growing, et cetera, as well.

Thank you.

Thanks, Aneek.

CapEx flexibility.

We usually give numbers of something like 10, 30, 50 in terms of flexibility, looking forward at this time of year.

10% next year, 30% in 2017, and 50% in 2018.

While I have to say they were non-scientific when I first used them, they've stood the test of time.

So, that's not unrealistic as the terms of total flexibility that there may be.

That's neither a projection, nor, a forecast.

It's just a measure of the likely flexibility and we will take decisions going forward.

We have some interesting ones for example, in chemicals over the next year.

So, it's not just massive upstream projects like Browse and Canada LNG that we need to think about.

Is it possible just to repeat the second question?

Because.

I wasn't quite sure I understood it.

Yes, just in terms of downstream.

I'm just looking to understand how much of the earnings you would classify as defensive?

So, not exposed, necessarily, to refining margins.

Yes, right, I've got it, yes.

Understand, that I wasn't quite sure what defensive meant.

The -- we've said before and under the -- I wouldn't give too much of a preview.

But, there's a chance next week John Abbott will be presenting at the investment day.

So, talk to John further about this.

But, typically, we have businesses, marketing, chemicals, trading and supply, and manufacturing.

The first three are essentially what we term rateable income.

I -- it's consistent enough to raise that easily on it.

And, the manufacturing tends to go from a negative to a positive.

Of the two, six or the eight so far this year, more than half of it is what you term defensive.

We might term rateable.

And, the manufacturing is doing well.

And, I would note, that because of the way we changed, or, Ben changed the accountabilities for the value chain in the downstream.

Putting a much greater emphasis on the integrated value from customer back through to crude, using the trading and supply organization and different accountabilities to maximize.

We are capturing quite a lot more of the available margin than we would have done three to four years ago.

So, we're not just benefiting from better industry refining margins.

We're capturing more of them as well.

Okay, thanks very much.

Thanks for the question, Aneek.

Can I have the next question please, operator?

Anish Kapadia, TPH.

Hi, yes, a couple of questions for me as well.

Just getting back to the cash flow and looking back at the last 12 months.

It seems like you had a big contribution from working capital over that period.

I just wanted to, kind of, think about it more on an organic basis, pre any working capital impacts.

And, when I look at it like that, it seems like your organic cash flow, pre working capital, post interest, is around $15 billion or so less than organic CapEx and the dividend.

So, I was just wondering in terms of, kind of, adjusting for it's, kind of, $60 world.

Do you think you can organically meet the kind of cash flow?

And, so, meet the dividend and CapEx through cash flow over the next few years?

And then, just to, kind of, I was thinking Shell standalone.

And then, the second question, kind of, going back to Carmon Creek.

Just wondering the decision to halt that project.

Just wondering is there anything to be, kind of, read into that in terms of the new government coming in, in Canada, the potential for a carbon tax?

And, kind of, issues in terms of carbon going forward becoming a, kind of, bigger issue for Shell overall?

And, yes, could this be a precursor for Shell pulling out from oil sands altogether?

Thank you

Thanks, Anish.

Let me take the second question first and I'll ask Simon to take care of the first one.

No, the short answer to it is no.

It would be, if you want to take an investment decision on a project and decide the fate of the project knowing that it will have to live for 30, 40, maybe, in this case, more than 50 years.

You cannot let that decision be governed by the government of the day.

And, of course, when it comes to carbon tax.

Yes, we know that this is a -- an issue that we could face.

And, that's exactly the reason why we priced carbon into the economics of our projects.

Even if there is no carbon price at this point in time, or, there's no carbon tax, we basically burden all our projects with a carbon price in order to make them future proof for the scenario where a carbon price could materialize.

So, there is nothing else to be read in this.

In terms of oil sands, no update on the portfolio there other than to say the oil sands operations are actually pretty strong.

If you look at the mine, it -- again, significant cost take out, significant reduction in ongoing capital commitments, and a -- and altogether a cash cost of about $25 a barrel.

And, that is at this quarter's environment.

So, it is, actually, quite a, from a cash perspective, a very, very good contributor.

So, there is -- there's nothing much to -- much else to say about it.

Simon, on the organic cash flow argument?

Sure as I mentioned to Lydia earlier the working cap does have some issues in there that are not, what you might call working cap.

So, it's not a straight adjustment and we also have a knack of structurally reducing working capital, you'll see if you look over a longer period.

The -- just stepping back.

Our aim is to finance the dividend whatever the actual oil price is.

In the medium to long term we have flexibility around the investment level.

We always -- we've averaged $5 billion of divestment for quite some time now, probably, the best part of the decade per year.

There is, not to be forgotten, in terms of how we balance the books, we intend to do more than that.

Double that, in practice, in the three years following the combination with BG.

The other factor that we need to note is that investment level of capital investment intensity tend to be correlated with the oil price.

In fact the correlation R squared is 0.9 or 90% in correlation.

But, we know that investment levels in the industry and the unit cost will reset over time.

They don't reset in three months, but, they do in three years.

It is happening at the moment.

And, of course, how do we get from here to there?

You start with a strong balance sheet and our balance sheet is 12.7% gearing.

We've managed to cover the dividend over the past 12 months of $60.

Because, we thought that the actions some time ago that were necessary.

We are planning lower for longer.

You are aware of that.

And, our aim is to ensure that we protect that dividend whatever the actual prices turn out to be.

Okay.

Very good.

Thanks, Simon.

Operator, can I have the last question please?

Biraj Borkhataria, RBC

Hi, thanks for taking my question.

On the US resources business, I was wondering if you could give us a quick reminder on what you've done in the last six months in terms of activity levels?

And, assuming a $50 to $60 over the next year, or, whether you need to decrease activity levels further?

Thanks.

Simon.

Well, we've reduced investment below $3 billion.

In fact, it's close to $2.5 billion at the moment.

We're active in the Permian, in the Marcellus, throughout Utica and West Canada, and the Grand Birch, and in the Duverney liquids play, and in Argentina.

We're effectively running at to, sort of, care and maintain with the possible exception of some of the Permian activity at the moment.

If the operation stays where it is, we will benefit because we're taking cost out on almost a daily basis, particularly away from the well pad.

At the well pad, we are pretty competitive today.

And, in our evacuation costs getting the molecules to market we are reasonably competitive as well.

But, there is a cost away from there that we are still working to take down.

If the oil or gas prices were to recover, I'm not sure it will be top of our list of things to immediately spend more money on.

Okay.

Good.

Thanks for that, Simon, and thanks, Biraj, for that question.

So, that pretty much brings us to the end of this session.

Thank you very much for all your questions and for, of course, joining the call.

I'm very much aware that there is a number of calls going on, more or less, at the same time.

Just a final reminder.

We have our management day in London next week on Tuesday.

And then, on the 4 of November, so, the Wednesday, in New York.

And, I look forward to seeing many of you there.

Thank you very much.

This concludes the Royal Dutch Shell 3Q, Q3 results announcement call.

Thank you for your participation.