殼牌 (SHEL) 2014 Q3 法說會逐字稿

Welcome to the Royal Dutch Shell Q3 results announcement call.

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

(Operator Instructions)

I would now like to induce your host, Mr. Simon Henry.

Thank you very much.

Ladies and gentlemen a very warm welcome to you all today.

We announced our third quarter results earlier today and I will take you through them and, of course, there will be plenty of time for your questions.

However, first I think we must reflect on last week's tragic event in Moscow.

Christophe was a warm, unique, charismatic individual who touched thousands of people in our industry.

His thoughtful leadership and the huge impact he had will be sadly missed by us all.

Moving on, first, our disclaimer statement.

(technical difficulty)

Moving on, to the priorities and results today show we are delivering on the three priorities we set out at the start of this year: better financial performance, enhanced capital efficiency and continuing strong project delivery.

We aim to grow cash flow through the cycle and at the same time deliver competitive shareholder returns.

We are making good progress with restructuring in North American resource plays, essentially completing the asset sales program there, and we are continuing with the cost and the portfolio reductions in all products.

The recent decline in oil prices is very much part of the inherent volatility in our industry.

We planned the strategy around an expectation of such volatility; that portfolio needs to be attractive and resilient in a wide range of circumstances.

It underlines the importance of our drive for better performance management, to keep a hold on costs and spending, to improve the balance between growth and returns, and to improve capital efficiency.

Proceeds from asset sales so far this year total almost $12 billion, with further disposals ongoing.

The new projects are delivering benefits to the bottom line now.

Overall production volumes were lower, but margins are higher, as the strategy of investing in profitable projects with or without equity production paid off.

We have continued to mature new investment opportunities in the quarter.

We have added quite a few new barrels with the drill bit.

Turning to results starting with the macro, Shell's liquids and natural gas realizations declined from the third quarter 2013.

The Brent oil price was some $8 per barrel lower than year-ago levels, with similar differentials between Brent and WTI.

Of course, current prices today are still below this level, and are squeezing revenues further.

On the downstream, this was a quarter characterized by higher levels of industry refinery downtime, which led to year on year uptick in margins in all regions, although [technical] margins in Asia-Pacific in general remained in negative territory.

Industry base chemicals margins increased, on the back of reduced feedstock cost and tight supply conditions.

However, intermediate margins declined in challenging market conditions.

Now, turning to our earnings.

Excluding identified items, Shell's underlying current cost of supplies, or CCS, earnings were $5.8 billion for the quarter.

That's a 30% increase in earnings per share from the third quarter a year ago.

On a Q3 to Q3 basis, we saw higher earnings in both upstream and downstream.

Earnings was supported by a range of factors.

In the downstream, the industry margins were higher, and the operating performance and the capture of those margins improved.

In the upstream, we benefited from new higher margin production, lower exploration expenses, and higher integrated gas results.

Return on average capital employed, excluding identified items, was 10.1%.

Cash flow from operations, some $13 billion.

That's an increase of 23% year on year, supported, amongst other things, by higher dividends from joint ventures during this quarter.

Our dividend for third quarter 2014 is up 4% from year ago levels, and with $8.9 billion of dividends declared and over $3 billion of shares repurchased as of yesterday, we are on track for a program of over $30 billion with dividend distributions and buybacks for 2014 and 2015 combined.

Turning now to the businesses.

Excluding identified items, upstream earnings for third quarter 2014 were $4.3 billion.

That's an increase of almost $900 million or 25% compared to a year ago.

That figure includes a $400 million reduction in earnings due to the increase of a deferred tax liability, as a result of the weakening Australian dollar.

This was partly offset by a $200 million dividend receipt from an LNG joint venture which was delayed from the second quarter of 2014, and also offset by lower exploration charges overall.

The upstream Americas and integrated gas businesses both showed positive earnings momentum on a third quarter to third quarter basis.

We benefited from new, high-margin production, offsetting the effect of lower oil prices and lower volumes overall.

This is the result of a strategy to invest for profitability, not simply volumes, and not something simply started a year ago, something that was effectively a strategic choice seven or eight years ago.

And, of course, some of our recent projects, such as Iraq Gas and the Repsol LNG deal, came with financial up lift but no, zero, equity production volume.

Headline oil and gas production for the third quarter was 2.8 million barrels oil equivalent per day, an underlying increase of 2%, supported by the ongoing ramp up at Mars B in the Gulf of Mexico and Majnoon in Iraq.

We also saw some new volumes from existing drills in deepwater Brazil and the Gulf, and lower levels of maintenance compared to the third quarter a year ago.

The LNG sales volumes were up 16%, Q3 on Q3.

That's strong growth.

That's driven primarily by acquisition of Atlantic and Peru LNG.

You will see some pointers for the fourth quarter on this slide covering production, and some financial items.

Just let me note that some 65% of Shell's worldwide production revenue is linked to oil prices, and a $10 per barrel move in Brent equates to some $3.2 billion of earnings impact on an annual basis for 2014.

That sensitivity is likely going to grow, be higher, in 2015.

Let me also note, there is a four- to six-month time lag between LNG prices moving, or between spot oil prices moving and LNG prices, that's [oil pricing], moving after that.

Turning now to the downstream, underlying earnings were $1.8 billion.

That's effectively double year ago levels, driven by higher oil products results.

In that business, we delivered an increase in refining results due to a combination of better operating performance, stronger margin environment in all regions and, as I mentioned, better capture of that available margin.

The refinery availability averaged 94% in the third quarter, strong and improved performance.

Marketing and trading results, they increased from a year ago level.

Chemicals earnings are slightly lower.

Again, you will see some pointers for the fourth quarter on this slide.

So just let me flag, we have had operating issues and damage to the Moerdijk chemical site in the Netherlands in the last few months.

The financial impact was not too significant in the third quarter, but could be significant to chemicals earnings in the fourth quarter with most units out for the remainder of 2014, and this outage will extend on some units into 2015.

Turning to cash flow and the balance sheet, cash flow, or cash generation, on a 12-month rolling basis was some $41 billion, with an average Brent price in that period of $107 per barrel.

Free cash flow, that's after deducting capital investment and divestment, that's improved sharply, nearly $8.5 billion in the quarter alone, $14 billion in the last 12 months, and over $22 billion in the last 9 months of the year to date.

[Gearing] at the end of the quarter is therefore reduced to 11.7%, and returns to shareholders, that's dividends declared plus buybacks, were $15 billion over the last 12 months, pretty much in line with the $30 billion projected for 2014 and 2015.

I think you are all aware, we don't take a particular view on near term oil prices.

We have a strong balance sheet, and we take longer term view on financing and project economics.

But as you would expect from Shell, we are keeping the pressure on the spending and the operating costs, and the current environment may actually give us opportunities to get better value from the supply chain here.

So, that's a roundup on the results.

Just let me update you on the portfolio.

The asset sales program is making good progress, around $12 billion of proceeds in the bank so far this year.

Announcements we made over the summer on the lower 48 on-shore gas essentially marked the completion of the major portfolio reduction in North American resource or shale plays, and that's with around $3 billion of disposal proceeds announced 2013 and 2014.

Once these deals and license expiry effects have all been completed, we'll have exited around 11% of our 2013 oil and gas production and some 6% of refining capacity.

That means we enter 2015 with a more focused and efficient portfolio, and balance sheet, but of course there will be a reduction to headline production and reserves.

In all products, where our portfolio restructuring is a longer-term drive, we completed exit from bulk of Australia business in the third quarter with further assets such as Denmark on the market today.

And we are making good progress now with the US midstream Master Limited Partnership, or MLP.

This is called, or named, Shell Midstream Partners LP.

We formed this in the US earlier this year.

The MLP announced the pricing of its initial public offering of 40 million common units at $23 per common unit.

The common units began trading on the New York Stock Exchange yesterday, under the ticker symbol SHLX.

The underwriters of the offering have a 30-day option to purchase up to an additional 6 million of common units, and the offering is expected to close on or around 3 November, that's early next week.

That's subject, of course, to customary closing conditions.

Turning now to project delivery, we had a strong year in portfolio development.

We had first oil at Gumusut-Kakap in the quarter in Malaysia, and that completes the list of four Shell-operated deepwater startups that we planned this year, and it's great to see these fills all making an impact now on the bottom line.

There have been some well-publicized delays in some non-operated projects in our portfolio.

And this, combined with the 2014 divestment program and license expiries, collectively mean the headline production has been falling.

Looking to the longer term, we have a highly competitive set of fields under construction for startup, particularly in the 2016 through 2018 timeframe.

For example, Prelude Floating LNG, Stone's deepwater Gulf, Carmon Creek heavy oil in Canada, but we also have the non-operated developments such as Gorgon LNG Australia, [Clarence Gilead] in the UK North Sea, and eventually Kashagan in Kazakhstan.

And we have made a lot of progress in 2014 on maturing new opportunities, with front-end engineering design feed underway in some very substantial plays such as Appomattox and Vito, deepwater in the Gulf of Mexico, could drive production well into the next decade there.

And LNG in Canada, where we can leverage our leadership in integrated gas.

Also, now let me update you on exploration in the quarter.

We have announced four interesting new discoveries in the last few months, and also continued with a highly successful, this year, near field exploration program.

In the Gulf of Mexico, the Rydberg and Kaikias oil discoveries, they could add new barrels in the Appomattox and Mars Ursa areas, both with tie-back potential to existing or planned hubs.

In deepwater Malaysia, the Marjoram gas line is one of a series of new hubs and near field discoveries that could feed into existing LNG schemes.

And I am very pleased to confirm that we found gas in deepwater Gabon, with a sub-salt exploration well called Leopard-1.

Now, we are going to appraise this one with at least one more well potentially next year, and we're also assessing the further exploration potential in this area.

It is essentially a new play for us, and potentially the industry.

Let me just update you on the competitive position, slides you should be familiar with.

We take a dashboard approach here, looking to balance growth and returns.

We are looking for a more competitive performance on a range of metrics over time, not just a single point outcome.

We have been trending higher on our return on capital employed and the cash flow in 2014, with a pronounced uptick in the free cash flow.

And you can see the competitive position improving here, the other lines being our four main competitors.

However, there is no complacency here.

We know there is a lot more potential, and a lot more we still need to do to be correctly positioned in these ranges.

Just let me sum up, before we go to the Q&A.

Third quarter 2014 results reflect more robust levels of profitability.

However, we are in an industry seeing, currently and often, high volatility.

The priorities that we set out at the start of this year have not changed.

We are taking firm actions to improve capital efficiency: selling selective assets, making tougher project decisions.

We have continued to ramp up new production, and the exploration program really is now delivering with those new finds.

We have declared $15 billion of dividends and buybacks in the last 12 months.

We are expecting dividend distribution and buybacks over $30 billion, 2014 and 2015 combined.

All of this underlines our ongoing commitment to shareholder return.

So with that, I'd like to move to your questions.

Please, could we try to restrict ourselves to one or two each, so that everybody has the opportunity to ask a question.

Operator please could you poll for questions?

Thank you.

Thank you.

We will now begin the question and answer session.

(Operator Instructions)

Your first question comes from Lydia Rainforth from Barclays.

Please go ahead.

Thanks, and good afternoon Simon.

A couple of questions, just if I could.

The first one is just on the bigger macro environment.

I think you've always said that you are very well positioned, or Shell, with some of those sort of conditions.

Wondering where are you prepared to let gearing levels go to, if we stay at this sort of level for a little while?

And then secondly, and this is more on the numbers, in terms of the integrative gas line, given the Repsol acquisition.

How much of that actually comes from the upstream Americas these days as opposed to the international part of it?

Thank you.

Thanks Lydia.

On the macro, I think I have been saying two or three years now that the old price probably was defying gravity.

And that's perhaps coming through in the way that underlying supply/demand fundamentals would indicate at the moment.

The gearing range we say, we would expect to see us through such periods, such volatility as 0% to 30%, it is currently 11% -- just over 11%.

I am well aware that the rating agencies in particular, and quite possibly the equity markets too, would get a little nervous if we hit 20%, one of the reasons being the inclusion of off balance sheet liabilities as well.

And therefore, before we would get nervous another 10% gearing roughly $20 billion of additional net debt.

That's equivalent to, effectively, think about it $30 for a couple of years off the old price.

That's not a prediction that that's going to happen, but that's the range at which gearing, I think we would need to be looking quite seriously at our investment programs.

The reason we retain that wide range is fundamentally so we can complete what we started in terms of the capital program without taking value destroying decisions.

Clearly as we go forward we'll be taking a close look at where we think the macro will stay, as we look at new investment decisions but currently the intent is, you know, we finish what we started.

And, as far as the second question Lydia, the Repsol?

Yes.

It was just about the proportion of the expected gas business from the Americas.

Just to note that we stated on acquisition that we thought, with a fair wind behind us, we might be able to deliver a billion dollars of cash flow from the assets we acquired.

And that was aspirational over time after we embedded.

In practice, we may well be able to deliver that much this year.

It's been a very strong contributor, a very good deal, embedded in our day to day activities almost from week one.

The majority of it does show through in the upstream Americas and that is then the Integrated gas is a combination of the Americas and the upstream international piece.

I don't have a figure for the way we actually split it, but more than half is in the Americas.

By that the billion dollars is cash flow, not earnings.

The earnings is lower because of amortization of the premiums.

Thanks.

Thank you.

Thank you.

Our next question comes from Theepan Jothilingam from Nomura.

Please go ahead.

Hi, Simon.

Two questions please.

You talked about the Deepwater project, the [shallow] first started up and are operator up, and the 300 thousand platters.

I was just wondering, what the contribution of those four assets were in Q3?

And when you might expect to reach plateau?

And the second question is just following up on project delivery.

Could you give us an update on Corrib please?

Thank you.

Theepan, thank you.

The Deepwater, four big projects.

We've got a few smaller ones and some non-operating starting up again as well.

It's just in the Gulf alone in the US.

We hit the bottom at about 170,000 barrels a day, a year or so ago we were close to 220,000 this quarter, so roughly 50,000 barrels ahead of where we were a year ago.

The totality of the Deepwater, where in the quarter, this is including outside the Americas, we were at about 286,000 barrels a day in that third quarter.

So we are closing in on the 300,000.

Of course the third quarter had minimal contribution from Gumusut and in practice Cardamom only started up towards the end of the quarter.

Bonga North West came on in the quarter, so still hopefully some legs yet in that portfolio with the new projects but it is relatively high decline on the existing asset.

So on balance overall we are on track for the totality of the 300,000 in the deepwater activity.

Project delivery, Corrib, a bit of a forgotten project in some ways but we are essentially pretty much mechanically complete but we need to start moving into the commissioning phase which means going back to some wells which have been down for quite sometime, etc.

So we are not planning on any contribution really until towards the end of next year.

But the tunneling is done and most of the mechanical pieces are all in place.

Many thanks, Theepan.

Thank you.

Next question comes from Thomas Adolff from Credit Suisse.

Please go ahead.

Hi Simon, two questions as well please.

For a company like Shell which is exposed to in essence every type of up-stream projects and I am aware of what you said earlier on, on strategy and planning, but say we get to the stage where you have to manage your CapEx slightly differently.

Which area or areas are the most likely impacted first?

Is it shale, exploration, your base in terms of work overs and field drilling, deferral of operated projects?

In essence how is Shell's portfolio CapEx managed in a slightly low oil press environment?

The second one is just a quick one on Basrah gas.

It's a bit of a black box, if you can possibly quantify what sort of contribution you expect from the project?

Thank you.

Thanks Thomas.

I will start on Basrah gas first.

You may recall it's essentially processing wet gas stripping liquids, the dry gas goes back into effectively the Iraqi power chain for which Basrah gas receives a fee and can sell the liquid.

So no equity production, but we are now processing around getting close to 600 million standard cubic feet of raw gas at the moment, collected from it, is basically associated gas, it's a reduction of flaring.

So it's doing a great job there for the environment as well as the Iraqi power sector.

The actual contribution at the moment, relatively small but cash positive.

The next question for us is investing and expansion in some of the LPG handling and so far so good.

The operation is very well managed with 5,000 employees there, all Iraqi, and working well.

Over time it can be quite a material contributor.

I am not sure we are exposed to everything but we certainly do have a diverse portfolio of investment opportunities.

Going forward look at it in different [branches].

What are we spending on the big projects, the headline projects, which is only around a third of the total spend?

We will complete, finish, what we started there.

We will think carefully about the timing of big new decisions going forward, but we do as I mention in the speech, Appomattox, Vito, LNG Canada, there is some really quite interesting, exciting projects ahead even in Brazil, the early work there.

So that's the big projects.

We have probably, not dissimilar amount going into asset integrity.

Small projects type of activity as well, so the asset integrity comes first.

The small projects, clearly they are likely to be in practice either attractive or necessary to sustain the operation as it is today.

So, while there is some flexibility that's possible, there are consequences for cutting that back into short term.

We then have about a quarter in the longer term which essentially is the exploration and the unconventional spend, and if you like pre FID feasibility or late feed work.

That has been more flexibility.

That is something that we take a close look at, but not really willing to eat our own seed [cone], particularly when we have made some pretty important choices around portfolio priorities in the unconventional areas.

So we are not going to jump to any rapid decisions to stop, cut, or slash anything that, in the short term, will only destroy value.

Having said that, we are not immune to the environment and, I would like to think, there is a very constructive discussion about priorities phasing.

And in this environment we are looking again at the supply chain, and the way that we deal with our suppliers if we are facing a period of lower revenues.

So it's not a single outcome that we are looking for, quite a few levers that we need to balance.

Thank you very much.

Thanks Thomas.

Thank you.

Your next question comes from Alastair Syme from Citi.

Please go ahead sir.

Couple of questions.

I know Shell's moved away from talking about individual projects in the past, but can you give us some sort of view on Prelude given it's such a huge operating component of your growth?

And I say that with respect to, we are all sort of aware that the [art and career] has had issues with other operators that are using the yard.

And then secondly, just looking at slide 18 which I am intrigued in, the portfolio development to 2014.

It just strikes me about the projects and feed, how few there look to be.

And maybe if you can comment on where we stand on [brows] within that context?

Thanks, Alastair.

We have moved away from giving specific custom schedule outcomes for projects.

We love to talk about [them].

On track for [buddies] in schedule at FID and Prelude, but, you are right, there are yard issue is there.

We are about two-thirds complete in the mechanical completion.

We are about three years, plus or minus a few months depending on events, from seeing significant revenues from that project.

Those events include, amongst other things, weather in terms of the windows for moving the facility out and commissioning.

That would be ten years from original discovery which we think is pretty competitive given the nature of the project.

It's a challenging project but looking good in the yard.

We were there quite recently to visit and very confident that we'll have a great project there.

On the next wave of projects, the slide that only shows the feed decisions, this year really, has quite a few other projects.

The big projects at the moment that are through-feed, all of which are operated by LNG, Canada, Appomattox, and Vito in the Gulf, we have pretty much ready to pull the trigger on Bonga South West Deepwater in Nigeria as well.

But that actually needs quite a lot of broader stakeholder support as well.

On non-operated projects, remember Brands is not Shell operated, it's Woodside operated.

I would have to defer you to Woodside.

Clearly it's an interesting project and would be a very large project for Shell with the share holding we have, 26% or so.

But I can't really add anything to statements made by Woodside.

Thanks Alastair.

Thank you.

Thank you.

Your next question comes from Fred Lucas from JPMorgan.

Please go ahead sir.

Thank you.

Good afternoon Simon.

Simon, can you run us through what projects you expect to sanction in 2015 and which projects you expect to start up in 2015?

I guess the last of both operated and non-operated as well.

Secondly, on upstream depreciation it's very difficult to track it with impairments and assets leaving the portfolio.

Could you tell us where run rate is now for unit depreciation and where you would expect that to go to in 2015?

And, if I may, just a quick question around your application to suspend operations in North American [uptick].

If your request is denied by the Bureau of Safety and Environmental Enforcement, where does that leave you?

Do you see the acreage recycled and having to re-bid for it or do you cease operations there all together?

Thank you.

Thanks Fred.

I will start at the back end.

The application is to extend not suspend.

I think it got lost in translation when the NGO sent you all a letter.

The reasons for asking for the extension are pretty clear.

Macondo and the current litigation which is, remember, against the DOI not against Shell, plus live parts of the earlier litigation.

And the significant changes in regulation mostly as a result of Macondo that have added delays or events that we feel, justifiably, we can claim were not under our control.

In the event that we're unable to extend, I can't really speculate on where we would be left in those circumstances.

But it's just part of normal practice really, looking to extend the leases to enable us to drill when in fact it is really decisions taken down in Washington that have prevented us actually drilling to a date.

Also worth noting that 30 years ago we went and drilled several wells pretty quickly, no real issues in the theatre.

It's not that difficult to drill up there.

That was the basis of the original application, the original signature bonuses that were paid in 2005, 2007.

So all of that put together is what's driving position.

The clean DDNA, you are absolutely right, has gone up and down and another factor that is there this year, and will probably come down a bit next year, is Majnoon with a lot of the cost recovery effectively flows throws through as DDNA.

So the current clean DDNA is around 3.5 billion upstream per quarter or 14 billion for the year.

That will come down a bit with Majnoon reaching, sort of, full cost of recovery roughly end of this year, but will go back up a bit as effectively the deepwater production goes up because the unit DDNA there is pretty significant in the early phases of production.

Similarly, linking back to your first question on which projects FID start ups etc.

It's possible we start to ramp up some activity in, for example, the Permian and the west Canada liquids-rich shale next year.

That's one over which we may have some flexibility of course pending the oil price and that usually comes with pretty high early unit depreciation as well.

We will start up Corrib.

There are a series of small activities, but primarily the boost next year is coming from full year of operation of this year's start ups and, plus, the variety of small projects around the world.

The significant projects, the Gorgon, Prelude, Clair, Sakhalin, Tempa Rossa, Carmon Creek, Stones, they're all really contributing materially to revenue in the period 2017, 2018.

So the big projects are pushed a bit further out, and, of course, cash, again, hopefully will be coming back in that timeframe, too.

Therefore the visibility on headline delivery will be slightly lower in the next 18, 24 months.

So do you think that, overall, given these start-ups, but given the wave of ramp coming through from 2014 that we'll see any headline volume growth in 2015?

Well, the headline growth will be negative because of the impacted divestments, which just to be clear because don't give the exact figures, we are already down close to 300 but the totality is 244 thousand down in Q3 alone from divestments and the Abu Dhabi license expiring, 76 from divestments, the rest with Abu Dhabi.

The full-year impact of divestments already made and license expiry for next year is about 350 thousand barrels a day.

And of course we have ongoing the Nigerian divestment program which has capacity 80 thousand to 100 thousand Shell share, or actual production at the moment is a bit less than that.

So all of those flowing through will have quite an impact on volumes.

The underlying volume delivery will depend a bit most likely on the rate of progress on the unconventionals.

And so the underlying decline at the moment is actually about 3% year on year, which we are looking to offset.

So all of those factors combined, production will be lower.

We'll aim to keep unit margins up notwithstanding the movement in the oil price, and very much focus on the dollars, not the volumes.

Thanks.

Very helpful.

Just on the project sanctions, interested by your comments on potential supply chain efficiencies.

Wondering what sanctions you expect and whether it would actually make tactical sense to defer a few?

You might be right on the latter.

The big ones that most likely, we have Appomattox which is at 800 million barrel now Gulf of Mexico, deepwater.

A potential chemicals plant in Pennsylvania.

Let's not forget the downstream.

There are a couple of small ones as well in Singapore and Rotterdam in refining terms as well, but small relatively quick payback, few hundred million.

And the LNG Canada, maybe not next year, but let's see quite where we can get to.

I can't really comment on some of the non-operated such as Browse or Abadi.

I think in the environment they may get pushed further out.

That's very helpful.

Thanks Simon.

Cheers, Fred.

Thank you.

Next question comes from Oswald Clint.

Please go ahead.

I do beg your pardon.

It comes from even read Iain Reid.

(multiple speakers)

Hello, Simon.

Just listening to what you were saying about production, and just kind of taking a step back.

It wasn't very long ago that you were sitting there or standing there, I think, and telling us that Shell a target of 4 million barrels a day.

And I know you do not target production anymore.

But you are now down to about 2.8 million barrels a day and guiding low and I am wondering for a company the size of Shell, what sort of critical math you think you'd need to have in terms of volumes, if not to support all the earnings, but to support the infrastructure in terms of people, project teams, et cetera?

Because, the way you're going, you're going from second in the industry in terms of volumes to, if this continues, something like fifth.

I am just wondering how Shell senior management look at this in terms of shrinking this business quite so radically.

Thanks.

I think you will find whenever I talked about 4 million barrels it was followed by the words: this is a proxy for the growth you can expect in the business as a result of the high level of investment program.

It was a simple translation of the growth, not the, shall we say, volume driven decision-making that might, therefore, ensure if that was all we focused on.

The growth will be less than that, I think it's fair to say there has been a bigger divestment program.

And there have been one or two highly public delays in delivery such as Kashagan or Gorgon.

So all things being told, there is still an expectation of growth, obviously, back into the latter part of the decade.

And while it's some linkage to volumes, how we think about it is the robustness, the resilience, and the level of certainty around delivery of cash flow growth.

So our targets are cash flow growth, return on capital, and as an outcome of those, ultimately, the free cash flow that drives dividend sustainability and hopefully growth.

And essentially optionality within the strategy; if you are not delivering up free cash flow, then we'll always be victim of circumstance.

So that's what we are looking to get the right balance around, and the production that delivers that, ultimately, is just a bit of a-- I won't call it an incidental, but if it's something we target in its own right we all know we can get the wrong outcome.

Just anecdotally, of course, just compare the Abu Dhabi impact with the Gulf of Mexico impact.

And a few thousand barrels, tens of thousands is replacing 160 thousand with a net positive impact on the bottom line.

Repsol, Basrah gas likewise, so that's how we think about it.

It is really the certainly of the underlying growth.

And I think you will find, in terms of where the cash flow generation is, we very much still are second and over time let's hunt them down.

(Laughter)

One quick follow up.

On the refining impact you've given, does that include potential shutdown of a train in Singapore?

The refining impact of 6% I think is just the divestments.

We are looking at the distillation capacity in certain parts of the world, including Singapore.

There are three distillation units in Singapore, you may be aware.

Okay.

So this doesn't include them?

We have not made final decisions, but we are certainly looking at the --I will tell you, the one we did certainly look to close the base oil plant in Pernis, for lubricants.

As a means of improving flexibility of crude supply into the refinery, and we are already seeing early benefits from the lower crude cost that's enabling us to fulfill the demand for fuel throughout the value chain.

Could I just ask one final thing?

Are you bidding for the renewal of the Abu Dhabi license?

We are one of the companies that is interested, yes.

We have all made offers and, at the moment, it's with the government.

Thanks very much, Simon.

Thanks.

Thank you.

Our next question comes from Martijn Rats from Morgan Stanley.

Please go ahead, sir.

Just a few short ones.

I wanted to ask you about the downstream result which, of course, was a lot stronger than before and also stronger than, at least, we had forecast.

This of course an element of benchmark, mark of margin to it, but also underlying.

And I was wondering if you can say a bit about what part of the results that have uplift is the environment versus structural changes that you are putting in place?

Secondly, just a small one to clarify, yesterday's CapEx has been running a bit below the sort of guidance you have given for the full year.

But then typically, in the past, in the fourth quarter we got quite a sort of large amount of CapEx.

I just wanted to ask you if that is this a profile that we should expect this year as well?

I'll deal with the second one and then the first, Martijn.

The intent or expectation for CapEx was $37 billion of which $2 billion related to completion of acquisitions from previous years or minor acreage during 2014.

So, interesting, we are bang on target for 35 organic and 2 of acquisition.

It looks like-- and the 2 of course is not equally phased, so the run rate is pretty much on target.

Much closer than we usually are to an expectation for a given year.

The downstream result, we are up at 900 million.

We're up year to date quite significantly.

It's not easy to be very specific here about environment versus actual underlying structural improvements, because, ultimately, one of the improvements is capturing the opportunities from a volatile environment.

But it's about 50/50, Martijn.

The actual improvements are a combination of refinery operational performance.

It's been pretty good.

Our utilization has been higher, as well as availability.

And that's in part because of effectively taking advantage of margin opportunities that were there by looking at the full fuel values chain.

So the crude traders, the supply traders.

Remember we trade as much product out into the market as we market out into the market.

3 million barrels a day, roughly each, and we are taking cost out and we have upgraded the marketing product mix.

Higher proportion or better unit margin, high proportion of premium product.

So V-Power, Shell Helix, and just focusing on where we are getting best bang for the buck in the markets.

All of those have been levers that, essentially, Ben kicked off a year and a half ago, and John is now executing well and seeing some benefits.

Certainly we see-- first of all, it is hard work everywhere, everyday, by a lot of people.

And secondly, there is quite a lot more potential out there for us.

So we are in the middle of delivering it.

All right.

Thank you.

Thanks.

Thank you.

Our next question comes from Lucas Herrmann from Deutsche Bank.

Please go ahead.

Thank you, Mr. Herrmann.

Your line is open.

Sorry.

Simon, good afternoon.

Thanks very much for the opportunity.

A couple if I might.

Just going back to growth but maybe changing dynamic slightly and thinking about maybe a five-year view, you seem the perfect person to ask.

The objective is clearly to improve return, or amongst your objectives, one is clearly to improve return on capital employed at the present time.

How do you see the capital base growing over the next five years on the assumption that if my returns are improving and my capital is improving, I should expect to know an improvement in profitability and cash flow?

So rather than talking barrels, Simon, can you talk capital?

Did you have another question?

The second question is very simply exploration charge.

What should we be expecting for Q4?

Last year was what, 1.7 billion negative, which was a very big drag on the profitability of the business.

What are you anticipating as we move forward?

What guidance can you give us?

I would like to come back to you on Nigeria again as well, if I might afterwards.

Thanks, Lucas.

The growth-- that was one of the cleverer ways I have heard of trying to extract a target from me.

The CapEx is running at a higher level in the BDNA, fairly clearly.

So we are growing 6% 7% of capital employed a year over the current level of investment and if we continue that will likely continue.

When we have talked about return on capital improvement, it is to a competitive position but not necessarily an industry leading position, because we think there is a trade-off between grow and returns.

And obviously the actual return we achieve is to an extent oil price linked.

And are we happy with 10% return at $110?

No, of course not.

So we would expect to improve the returns by a few percentage points, but not necessarily deliver 20% returns at $110.

I am more interested in capital base, Simon.

You've got a view on what you are going to divesting, you have got a view on what you will be investing.

You have a base oil price.

You must be able to come up with some indication of what kind of capital growth one will see on five-year view?

6% to 7% a year is not bad going rate, [that] leaves you at 30% above where we are 220 at the moment.

I think it is something we'll probably come back [to] in Q4, because the divestment program paradoxically doesn't have a major impact on capital employed, the [effects] movements at the back end of the quarter had almost as much impact as the divestment program.

So it is something that we think about, not necessarily in totality for Shell but for the individual strategic themes that we've talked about.

If I said downstream, I would not expect that to increase but depends on what choice we make with chemicals it may at least stay at similar levels.

I expect Integrated gas and Deepwater in particular to grow strongly.

The rest of the portfolio, well let's see.

They will be choices based in part on capital and in part on returns, but very much also in part of what's the ongoing investment commitment and the potential growth.

And exploration charges, Q4, you're absolutely right.

Was 1.7 billion largely driven by high exploration write offs which unfortunately don't come along regularly.

I can say fortunately this year they haven't come along really.

We had more of our fair share last year.

On going rate is about 800 million to 900 million per quarter with a small number of contributions from write offs.

We have a couple of wells going down now.

I think there are one or two that may play though into the write offs.

I don't actually have a feel yet for the success rate likely in the quarter and which wells will reach TD.

In fact several of the big wells at the moment won't reach TD until first quarter.

There is not many have a big exposure in Q4 and may run over into 2015.

So, we would hope that the change was a bit lower year on year, Q4 to Q4 but it is just too soon to say.

Can't be any more specific than that I am afraid.

Okay.

Maybe you could encourage JJ, [or tell], let us know if it's going to be materially above [nor point $8 billion] come the start of the next quarter.

What we'll try and do is be clear about which wells achieved what outcome.

Please bear with us though, because if we are not the operator, that's not within our gift.

I am sorry Simon, just going back to Nigeria.

I did not quite understand or catch the comments you made around the level of barrels that you were effectively divesting.

And also can you just explain to me what is -- the proceeds have been talked about.

Are those just proceeds that relate to your interest, Total's interest, and Eni's interest?

I mean, in short, the news wires have been carrying a number of around 5 billion for your onshore divestments.

I don't know if that number is right or wrong, but what I would like to know is whether that number is just associated with the IOC's interest or what NTC is in there as well.

Sure.

I agree that it gets confusing because actually we said very little about this.

Just everybody has buyers, sellers, government, and banks.

So what the facts are, we have four onshore licenses and one related pipeline activity.

All the activity is basically oil, associated with an NB Creek trunkline environment, evacuated through the Bonny oil terminal.

The potential production in that space is 80 thousand to 100 thousand barrels a day Shell share, about 30% of it.

And current production is more like 30 to 40 because remember this is the area that is very subject to sabotage and theft.

So it's a big area.

It's got big reserves, and a bigger of 5 billion has been quoted, as strangely is approximately correct.

But that's for Shell, Eni's and Total's share, and MPC is not selling.

And in fact, actually has preemption rights on the sales, were they to choose to exercise that right.

We have signed SPA's for all four licenses, and the pipelines, so five SPA's.

The total proceeds to Shell are around $3 billion, but I can't give either specific numbers for specific transactions, nor can I give any indication of when we expect to conclude.

Because all remain subject to ministerial support and approval within Nigeria.

So we can really only update as the transactions are signed off and cash changes hands.

The offers are certainly for the other IOCs.

We have no reason to expect they won't accept the offer.

But to confirm that, you probably need to talk to Total and Eni as I think you well know.

(multiple speakers) We hold 30%, Total 10%, Eni 5%.

Where does that leave you with the rest of your onshore, by the way, which isn't gas?

My impression would be the prices you are able to command seem pretty attractive relative to the troubles that the positions entail.

Fundamentally, the remaining piece that is not gas is just to the east of the blocks that we're selling.

It includes well-known [Nagoni] block, although we don't operate within that particular area.

And is associated with the Trans Niger pipeline.

So there is another pipeline system associated with it.

In this particular process, this block is not actually included and that doesn't mean-- I wouldn't exclude necessarily future consideration.

But it is one step at a time.

To the west of these blocks is essentially the gas-producing acreage which we are investing at the moment to grow the production there, and ensure that both domestic gas and production grows.

And that we keep LNG plant full.

And we also have some shallow water offshore blocks which are operated by the joint venture as well.

It's still a major operation, in addition to gas and deepwater.

Hopefully that gives you a feel.

A lot of the oil reserves are associated with the blocks that are for sale, and that one particular big block in the Trans Niger pipeline area.

Simon.

That's great.

Thank you.

I'll leave it there.

Thanks, Lucas.

Thank you.

Our next question comes from Sir Jon Rigby from UBS.

Please go ahead.

Hi, Simon.

Can I ask just one question and one clarification?

Can you just update on what you're thinking around LNG Canada?

I noticed earlier this week, a competitive project was being backed up a little bit.

And I guess there is a process where you need projects to get shaken out, rather like we saw Australia.

So can you characterize where you stand on this project and where you think it is in terms of its maturation?

And then just back to the discussion around Nigeria and the onshore.

If I follow what you are saying, and I look at what SBDC was producing over the course of this year; I think 100 thousand barrels a day in the first two quarters and a little lower in the third.

Are you effectively saying that the remaining liquids production in SBDC, to you, will be on the order of about 60 thousand to 70 thousand barrels a day liquid?

Yes, well the last question is easy.

Yes.

(Laughter) Right.

Presuming that is mainly EA?

Is it?

It does actually include EA.

Yes, you are correct.

Which is shallow water offshore flows are not as familiar.

There is also further growth potential, shallow water offshore, by the way, but we are not growing there at the moment.

LNG Canada, I think there is 17 projects applied for permission to export it, even more crowded than the Gulf of Mexico at the moment in terms of notional projects.

If all the North America projects went ahead, by the way, it would be 400 million tons of export capacity which compares to today's entire market of 250.

We don't think they're all going to go ahead.

Let's put it that way.

To make these projects happen takes quite a long time, particularly the first in a greenfield environment, at least part of it greenfield, to bring to all the stakeholders.

We have been working extremely hard for the past two to three years to ensure that we have, not only the land to build, which is clearly in place now in Kitimat.

It's a brownfield site not greenfield, so we are already over quite a lot of the hurdles in what is an environmentally sensitive area.

We have great partners both for the midstream, but also the upstream gas production and downstream LNG market.

In our Chinese, Japanese, and Korean partners we have the best pipeline operator, TransCanada, contracted to build a pipeline from the Montney area and our Grand Birch gas development.

All the pieces of the value chain are in place.

We have been working very hard also with First Nations tribes, 28, 29 tribes, or peoples that are either at one end of the physical value chain as well.

Last but certainly not least, the British Columbian government, particularly in terms of the fiscal regime.

Now, we have seen positive progress for our project on most of these.

Some have made headlines in recent days.

It was good to see the government or the provincial government making the statements on the tax regime.

We are pretty confident we can bring all this together in a project which will make a lot of sense.

A two train, 6 million tonne per train, i.e.

12 million tonne total.

50% Shell share project.

It's in feed already.

FID would be a challenge to make it next year, but let's see.

But we do need all the stakeholder dominoes to be in a line before we can knock them down.

Many of the competitors, we have been interested to note, how many statements have been made before any, let alone all, of those elements are in place.

Therefore, it is not surprising they seem to go backwards and forwards.

So rather than speculating on any other competitor, I just think we like to think we have a solid project.

If we're not first to market, I think we will be one of the first to market, and we will have a very solid set of players with us to generate value over a long period of time.

And there is room for expansion on the site.

Right.

So if we are in those two trains, a third or fourth train, there is certainly room, and there is certainly gas available for that end and maybe more.

Consolidation, that's perhaps for the future, but we have learned both sides of Australia.

That's probably a good idea.

I was going to say, so you think industry can avoid the fiasco of Queensland?

Well one would hope so, yes.

(Laughter) I cannot guarantee to avoid on behalf of the industry, Jon.

Thanks, Simon.

Thank you.

Our next question comes from Irene Himona from SG.

Please go ahead.

Thank you.

Hello, Simon.

Two questions, if I may.

Firstly, upstream and Majnoon in Iraq, can you talk about the earnings impact and whether you're actually receiving any cash?

Are they paying invoices?

Secondly into downstream, obviously you mentioned that roughly half improvement was, let's say, self-help.

How much of that half was Motiva, please?

Thank you.

Thanks, Irene.

140 million, is the answer to the second question.

Of which, again, is roughly half and half, and although, in their case, it's more like 60/40 environment and operation.

Majnoon.

Good question.

We are one year into now production with remuneration.

We had to meet the original first commercial production target of 175 thousand barrels a day.

Remember this is the first greenfield bid or license that was on offer.

The previous fields, West Kelowna, Rumaila, et cetera, they were brownfields.

So we needed to take time to set up some of the processes and relationships, particularly with the government, on cost recovery, for example, for greenfield.

Which is one of the reasons we have been a bit later to hit first commercial production.

But having hit it, we are now averaging 210 thousand barrels a day there.

That's not our share.

That's the 100%.

And we are recovering our cash pretty quickly.

By the end of this year, we expect, give or take a few weeks, to recover the essential capital outlay.

That cash coming in is in this year's CFFO, and as soon as we have recovered, we drop back to just receiving the remuneration fee which is quite a bit smaller.

The actual overall earnings impact for Majnoon is pretty low.

Fundamentally, you build up a big asset and then depreciate it quickly and the asset equals the cost recovery bank.

The CFFO has been good this year, clearly over back end of last year, this year maybe a little bit will creep into next year.

You are talking a couple of billion or so coming back in.

And that will slow in early 2015.

We have not yet agreed a full-field development, either what the concept would be and the objective and the production levels.

If and when, we do so that would effectively add CapEx that is recovered typically within three months.

We have a very high cost recovery rate, close to 100%, having taken a lot of time up front to get agreement and build levels of trust that are required in a new environment.

A bit like Canada LNG we think in the longer term, the up front investment in stakeholders and the relationships, it does pay off.

We also have, of course, Basrah gas which is contributing, actually contributes a bit more than Majnoon even at the moment.

And certainly longer term, absent the decision to grow, Majnoon will do better.

I think that covers it.

Thanks, very much.

Move on to the next question, please.

Next question from Richard Davis from Canaccord Genuity.

Please go ahead.

Good afternoon, Simon.

I was intrigued by your comments about your liquid rich shale and whether you might or might not take decisions next year on the back of where we are on the oil price.

I was just wondering, do you see as cash breakeven from LRS from your point of view, but also from the industry point of view in North America?

And also, if possible, by basin?

I wish I knew Richard.

(laughter) That's one of the things that would drive the decision.

Because it's not independent to the oil price the costs do tend to adjust but maybe not enough.

We are into the middle to late stages of appraisal in Permian and West Canada.

We have seen some great wells.

We've had quite significant number of wells at the thousand barrel plus initial production rate, which is when you are talking sweet spots something that is going to work, clearly.

A thousand barrels a day and multiple million dollars of barrels when you are only spending somewhere between $5 million and $10 million to drill and complete a well.

Then, you are going to do okay.

What you need to know is what's the average going to be when you decide to drill 100 wells or 200 wells, across a particular rollout while you are building infrastructure, et cetera.

That's where it is too soon to say.

We are not that far away, but we may not pull trigger on development, what we call common value area, sooner rather than later as we take a view on what the oil price actually is.

Okay.

That's Shell's perspective.

We would hope to be able to develop oil prices with a breakeven below today's level.

I doubt we would take a positive decision if we couldn't do that.

For the industry, it's a great question.

We are watching what others say, people who have more direct experience.

But actually, the thing that is of interest to us is the fact that so much of the drilling, to date, has been financed by capital markets or the banks.

250 billion or so that we can see has been provided by debt, or from debt providers into that industry and very little of the drilling is being financed from own cash flow, and the way that one plays out with lower oil prices will be interesting to watch.

Okay.

That was backdrop to my curiosity.

Just one other thing, just confirmation.

The decline rate on those wells is up to about 80%?

Is that right?

Per annum?

First year, yes, not the second.

First year, yes, apologies.

They tend to-- it's not an exponential decline.

They tend to come down and then you get a relatively stable-- but comparatively low.

So, yes, that's one reason we haven't gone forward.

We've got wells with initial production.

What we don't have is where do they stabilize out at.

Thank you.

Okay.

Thanks.

Next question.

Next question comes from Christopher Kuplent from Bank of America Merrill Lynch.

Please go ahead.

Good afternoon.

Simon, I just wanted to ask about dividend growth.

You've got this $30 billion or more than $30 billion number in your press release.

You have had that for sometime now.

For this year and next year, I don't know whether my calculations are right, but I think you can get there without having to raise $0.47 quarterly rate.

Does that mean you are sort of leaving yourself a little bit of flexibility depending on CapEx budgets, oil prices?

How do we think about that term more than $30 billion, becoming $35 billion over the next few years?

Thanks.

Good question, Chris.

I will need to remain enigmatic about dividend growth because it's a decision for the board.

What we said is we aim for a strategy that enables sustainable growth in the dividend through the business cycle.

We have already demonstrated in the past five years that doesn't mean growth every year.

I think your figures are pretty accurate, but I wouldn't overinterpret the figures themselves.

There is a little bit of judgment as well as the specific outcome.

Clearly we grow in line with underlying growth in earnings and cash flow.

But we have to look at the balance sheet and we have to look at the oil price environment as we find it, rather than we might hope it to be.

We'll have that discussion of the board in January.

Okay.

Thanks.

That's great, Simon.

If I could one quick question for clarification, can you give us a delta in terms of CapEx budget for Alaska?

You know, whether you go ahead or not?

Thanks.

Thanks.

Unfortunately the later we leave a decision as to whether we go ahead or not, the smaller the delta for next year.

You may recall we need a smaller model to simulate just under 30 vessels to accompany the rigs.

We must take two rigs up, because we have to have a standby rig available for release, which goes back to earlier questions I have taken on Alaska.

So if we, as of today, said: No, we are not going to drill next year, we would still have quite significant outgoing with next year because both the rigs and some of that equipment is committed.

So we would only save a few hundred million.

Great.

Thank you.

Thank you.

Next question comes from Neil Morton from Investec.

Please go ahead.

Thank you.

Good afternoon, Simon.

A couple questions please.

Firstly on chemicals, you used to split out the result between the US and [Woeza], no longer.

And clearly the US is doing very well.

I just wonder, maybe talk about your chemical portfolio X the US.

And then, just secondly, on Abu Dhabi, it's held up by both you and others as a poster child for this value verses volume mantra, and yet everyone seems to be sort of fighting tooth and nail to get back in.

I am a little bit perplexed.

Why is that?

Is it simply a relationship issue?

Thank you.

Thanks, Neil.

Chemicals outside the US.

You are right, the US business is doing well basically because of low cost feedstock.

The business recently outside US has taken a bit of uptick because Naptha prices have fallen.

Partly linked to crude, and partly because demand hasn't fallen, but it's also not as strong as we might have hoped.

So the rest of margin is out there to play with.

So both Europe and Asia-Pacific have made money, but it's not as strong a performance as the Americas.

The Europe, I have to highlight the Moerdijk incidents, two incidents where we will take a hit in the fourth quarter there.

And that could persist into 2015.

We just do not know yet which units we can bring back and when we can bring them back.

So the European performance will certainly take quite a hit in the coming quarters.

In general, the chemicals industry is one in which, first of all, there is pretty strong growth globally.

A lot of growth and supply as well.

But in certain areas if you have either a location, a technology, or a cost advantage, it can be very attractive.

And that's why we have been looking at a variety of chemicals opportunities, including the one in Pennsylvania I referred to earlier as a means of taking advantage of being in the right place with the right feedstock and access to the right market.

Some of those could be also outside North America.

Abu Dhabi, interesting.

We are clearly interested in any opportunity where we invest a dollar, we return more than a dollar, and the risk associated with that is acceptable.

But then we compare Country X with Country Y because, clearly, adding up even the future projects we have talked about on this call, we have come up against a few limitations in terms of overall capital allocation.

Abu Dhabi needs to be in that.

It's easy to highlight it at the moment, particularly in our results, because it's year on year such a big factor.

And therefore you can see unit margin playing through.

We will only bid for Abu Dhabi or anywhere else if we think we can get a competitive return.

If that comes with barrels, fair enough.

If it doesn't come with barrels, also fair enough.

Why would we be interested?

There is an awful lot of hydrocarbon in Abu Dhabi and the Emirates, and the surrounding region.

Some of it is approaching the maturity where advanced technology, I think is well known.

We are also looking at project, the Sour Gas project on the Bab Field.

So there are other opportunities both in the Emirates and in the region where Shell technology, Shell ability to project manage, and to take product to market, could be able to create quite valuable good returns.

And if the extension of the ATCO contract forms part of that overall portfolio of activities, that will be a good outcome.

But we are still in progress on all of those opportunities.

But we won't be chasing it just for headline barrels.

We need a good return also.

Can I just ask one quick clarification, just following on from Chris's question on the dividend?

The board reserves the right to change the dividend at any point during the year, not just a Q1 effect anymore?

Well, in theory, yes.

In practice, we have only changed it in Q1.

In recent years?

The board actually considers the dividend every quarter, by definition, including yesterday for today.

It's unlikely to change in that context.

Whether it changes in terms of outcome, i.e.

we move away from just announcing in the first quarter remains to be seen.

Thanks, Neil.

Thank you.

Next question.

Next question comes from [Kuran Moula] from ING.

Please go ahead.

Hello, it is Simon from ING.

Two questions.

One is, of course, with regard to divestment program.

You're progressing so fast now, are you considering to raise the target there given the fact that you have $15 billion for 2015 or is that the end of the low hanging fruit now?

And second question is on Alaska.

We heard environmental players saying you were trying to get your license which, in my view, is quite logical.

Are you progressing there or is there something, a stand still at this moment in the discussion with the government on the license?

Okay.

Divestments we have done $12 billion.

You are correct.

Progressing perhaps a little bit quicker than might have expected against the $15 billion two-year target.

We have in progress and still to conclude the MLP is effectively a billion dollars.

We have conclusion of the Haynesville onshore gas asset, which is another $1 billion.

And we have the Nigerian deal, which is about $3 billion.

So about $5 billion in progress, plus a couple of smaller ones.

I would hope, just from that portfolio, we can get to the $15 billion.

Having said that, we are now going forward, looking at a much more difficult environment to divest.

So it's good that we have moved quickly and achieved good prices.

We are seeing some challenges in one or two smaller deals that we are looking at, as to whether buyers can finance and take through to conclusion the deal.

And I think you would probably be aware that the second phase of the Woodside deal didn't happen back in August, because the shareholders voted against it.

And the actual Woodside share price has fallen quite a lot since then, so our appetite to resurrect may have declined.

Looking forward, it may not be as easy, but we will have delivered what we said we would deliver anyway, I expect.

On Alaska, yes, of course, we are trying to extend the license.

And, yes, it is entirely normal do so, bearing in mind events that have transpired since we took the licenses.

At the moment, we are planning and hoping to drill next year, but we have not taken a decision do so.

Because it will depend both on ongoing litigation which is against the US government, not Shell.

And regulatory permits from the government to Shell that would enable us to drill.

I cannot say when we will get clarity, but we do not yet have clarity.

And we certainly retain the ability and right to not drill next year.

Thanks.

Thank you.

Next question, please.

Your next question comes from Oswald Clint from Sanford Bernstein.

Please go ahead.

Thank you, Simon.

Hello.

First question on the upstream per barrel kind of earnings.

Good to see America is picking back up again, but could you just talk about Europe in terms of net income per barrel?

Seems to be deviating away from the rest of the regions of the past four or five quarters.

Is that just oil barrels falling out of the mix, or is there something else happening there?

My second question was more macro.

Just in terms of your oil products sales volumes, a little bit lighter in the third quarter after being up strongly first quarter, second quarter.

Is that weakness just aligned with the kind of global demand slowdown we saw in the third quarter, and any indications of what you are seeing so far in the fourth quarter?

Thank you.

Thanks, Oswald.

By and large it's aligned with demand on the second question, but we also sold Australia.

So we lose Australian volumes.

And the earnings per barrel oil equivalent in Europe, quite a lot of what we do in Europe is gas.

We are seeing weaker European gas prices partly because it's been so warm, and we have seen decline in unit margins in Denmark which is partly higher costs.

Obviously, we are now seeing the oil price coming down, and I think we have spoken before about challenges on the operational performance in the United Kingdom, particularly on central North Sea assets.

Where asset integrity spend, maintenance cost, and declining production, or at the very least the availability, reliability of production, have all been challenges.

So it's a combination of all those factors in Europe.

And I think that probably is all I can say about that without speculating further.

Thanks, Oswald.

Next question.

Next question is from Bert Van Hoogenhuizen with [Strothe Lanburger].

Please go ahead.

Hello, Simon.

Thanks very much for the extensive answering of all the questions.

I have one major and one follow up question.

Major question is the gas pricing.

I believe it is both prices in the Far East about $13, Europe $6.

In the past you have once said that you had about 60% of contract and 40% on spot.

Is this still actual?

And how are you looking to going forward?

Would you sort of enlarge your spots to wait for better contract prices in the future when prices would go up again?

That's the first question.

A small corollary question is LNG volumes went up 60%, mainly Repsol.

What is the figure without Repsol?

What's autonomous growth in LNG volumes?

I don't have a specific number on the second question, although there is some growth because Nigeria LNG suffered operational challenges last year.

The most LNG plants run full.

I remember that as it's quite difficult to grow other than either buying or building.

The gas pricing, you are about right in terms of [West Pop] prices, have been they've picked up a bit in Europe, now they are at $9 or so in UK and BP.

We and the whole industry has shifted progressively in Europe in particular towards a much greater proportion that is spot linked.

Spot means that is usually a combination of the hub price and not just the UK, but Antwerp or elsewhere.

So we are doing better than $6 and then realized price is probably closer to the $9 at the moment.

But there are few new long term gas contracts that are directly and solely oil price linked.

Quite often, there is a bit of a mix.

Asia-Pacific, fundamentally our LNG, 90% or more of the volumes are on long-term contract which are all price linked one way or another.

70% of the actual contracts-- of those contracts in sales are directly linked to oil.

So the majority of our LNG business and probably around 40% of gas in total has some kind of oil price linkage.

I can't be too much more specific than that, because there are a lot of moving parts out there at the moment.

And, particularly in Europe, the evolution of the market has certainly been one way.

And the majority will not be solely oil linked going forward.

Right.

Thank you.

Of course.

Indeed, I was referring to the shifting landscape, especially in view of the rumors of the prices that the Chinese pay for Russian gas.

More in the order of $10 or $11.

I was wondering whether clients, indeed, are sort of trying to get away from long-term contacts, and preferring the actual lower prices.

Most of the long-term customers, remember that does not include very many in Europe as those in Asia-Pacific.

They are looking for a mix of pricing basis.

A little bit of Henry Hub, I am not sure about Russian border, but-- and some oil price linkage.

But also with some kind of S-curve in there to protect against both extremes at the bottom and the top of the price curve.

It is complex.

And price is not the only part of the negotiation as well.

The Russia-China gas price negotiations really only have an impact on China and Russia.

It is not really impacting over into the rest of the market at the moment.

Okay.

Thanks, Bert.

I think we have, was it, one last question.

Thank you.

Next question come from Anish Kapadia from PPH.

Please go ahead.

Good afternoon.

A couple of questions from me as well.

If I am right, your reports on exploration and appraisals stand in 2012, 2013 was around $8.5 billion dollars.

And I think guidance for 2014 was around $7 billion dollars.

Just wondering, are you going to be at that $7 billion dollar mark in 2014?

And, looking at the portfolio going forward--.

We just lost you, Anish.

One moment.

We are trying to reconnect.

Just let me confirm on the 2013 and 2014 figures.

I think he was quoting probably from our annual report, where in accounting convention terms, quite a bit of what we regard as development spend is actually accounted for as exploration.

So our real exploration spend of $7 billion is a combination of three conventional.

Somewhere between $0.5 billion and $1 billion in Alaska.

And the rest is in unconventional activities.

Basically, shale in North America, Argentina, and China.

So the $7 billion was the target for what we call real exploration and appraisal activity for both 2013 and 2014.

And that is about the level at which we are spending.

In 2014, it's probably shifted more to conventional than unconventional.

We have been having quite some success with the drilling as a result.

Not giving any figures for 2015, but reflecting on earlier question, that is one of the few areas over which we retain some, albeit limited, flexibility for 2015.

Thank you.

Your line is open.

Please carry on.

Thanks, Simon.

My second question was related to this oil price environment.

I was wondering if you believe that buying back shares is still best value than buying into, say, other assets or companies in this market, given you are seeing this pretty depressed pricing.

And it also seems like consensus is that it is a biased market.

You mentioned yourself it's a lot more difficult to get disposals away.

So is buying into assets a better alternative than buying your own shares?

Bit like equity markets, it's not easy to catch a falling knife.

So it moves from a seller's market to a buyer's market, but not smoothly or overnight.

There is a period where buyers and sellers look at each other and say: Who blinks first?

We are probably that period at the moment where the sellers haven't gotten desperate enough and buyers who have cash, which does include us, certainly aren't going to jump in and try and catch that knife.

So let's see where it goes.

Buying back our shares we said, we would offset number of shares that have been issued in the script dividend cumulatively.

That equates, roughly speaking, to the $7 billion to $8 billion buyback over 2014 and 2015.

Lower oil price makes our shares cheaper as well, so it doesn't affect our view of the inherent value either, of course.

So as long as our own shares offer an attractive alternative to buying assets, or other people's equity, then it will be one of the choices we look at.

But, of course, always in the broader framework of what cash is available, and how do we create most value for the shareholder balancing returns growth and the financial balance sheet as it is today.

So good point to end on.

I think we are now done.

Thank you very much.

Thank you, everybody, for questions.

It was quite a thorough examination of the situation and the results.

I thank you for that and the interest that you've shown.

Thanks for joining the call and the fourth quarter results are scheduled to be announced on January 29, 2015 and, of course, Ben will join me then to talk to you.

Thank you and have a good day.

Thank you.

That concludes the royal Dutch Shell Q3 results announcement call.

Thank you for participating.

You may now disconnect.