殼牌 (SHEL) 2014 Q2 法說會逐字稿

Welcome to the Royal Dutch Shell Q2 results announcement call.

(Operator Instructions)

I would like to introduce your host, Mr. Ben van Beurden.

Okay.

Thank you very much.

Good afternoon, ladies and gentlemen, and a very warm welcome to you all.

We've announced our second quarter results today, and Simon and I will run you through that.

And then we'll update you on the key portfolio strategy developments in the Company, as well, and then, of course, there will be plenty of time for your questions.

I have the disclaimer statement first, and then let me start by saying that the crash of Malaysia Airlines MH17 in the Ukraine is a real terrible tragedy for everyone involved.

And I'm very sad to say that in Shell we lost 12 people in this crash, staff, spouses, and also children.

Shell has staff and, of course, operations in Russia and the Ukraine and we are watching this very complicated and fast-moving security and political situation, of course, very closely.

And I'm sure that you will have questions for me later on this, but let me say now that I speak on behalf of everyone in Shell to say that our thoughts are with everyone affected by this very tragic event.

But I move to the 2013 priorities.

I believe we are making good progress with the priorities that are set out that the beginning of the year, just to balance growth and returns by focusing on better financial performance, enhanced capital efficiency, and a continued strong project delivery.

Now, Shell's strategy is founded on technological expertise, disciplined capital investment, integrated operations and large scale.

And this is underpinned by an unrelenting focus on safety.

We have to grow cash flow through the cycle and deliver competitive shareholder returns.

And our financial performance for the second quarter of 2014 was more robust than year-ago levels.

But I want to see more competitive results right across the Company, and particularly from our product and the North American resources plays.

We're taking firm actions to improve our capital efficiency by selling selected assets and making much tougher project decisions.

And we've continued to ramp up production at Mars B in the Gulf of Mexico, which is part of Shell's industry-leading deepwater portfolio.

And our exploration program is delivering with new finds in the Gulf of Mexico and Malaysia.

We've set clear priorities for 2014 and beyond, consistent with Shell's long-term strategy, and at the same time, we are sharpening up in a number of areas.

You should know we've implemented a series of new performance units in the Company for a more robust appraisal system.

There's about 150 of these, which are clusters of assets, markets or value chains such as integrated refineries or groups of oil and gas fields in similar geology and tax regimes.

And we continue to drive stronger alignment between the Company and the shareholders with increased shareholding requirements expected for the senior leaders in Shell beginning from 2015.

These new shareholding requirements will complement our existing remuneration programs, which include a Company-wide annual scorecard, individual performance assessment, and a long-term incentive plan with performance measures including total shareholder return relative to competition.

Now turning to the results, and Simon will give you a bit more detail in a moment.

Our second quarter 2014 underlying CCS earnings were $6.1 billion and cash flow from operations was $8.6 billion.

On a 12-month rolling basis, which for me is a more meaningful measure than a single quarter, we have delivered some $21 billion of underlying earnings and $39 billion of CFFO.

Free cash flow, which is the cash generation after investment, the money available for payout and debt pay down, has been on a rising trend in the last few quarters as our acquisitions and divestments turn to a net positive.

Our dividend for the second quarter of 2014 is a 4% increase on year-ago levels, and we are expecting over $30 billion of distributions to shareholders in the 2014-2015 period, dividends and buybacks.

And all of this, of course, underscores the Company's recent improved performance, as well as future potential.

Now let me update you on restructuring in our products and North American resources plays, which together represent about one-third of our capital employed and, as I've said before, have not been delivering acceptable returns.

Now let me start with oil products.

The downstream business generated 7% underlying return on average capital employed, and $7 billion of CFFO in the last 12 months.

And that's some 15% return in chemicals and 5% in oil products.

We are driving for a $10 billion CFFO target per year and 10% to 12% return for the downstream overall on a sustained basis.

And restructuring this segment included a $2.3 billion net impairment in the first quarter of 2014, which was some 14% of the refining asset base.

A strong drive on efficiency and cost [to try] a unit performance approach and [accept] from non-core portfolio in four countries, with $1.1 billion of disposals completed in the downstream in the first half of 2014.

So oil products earnings in the first half of this year run $2 billion was similar to a year ago levels, and that is despite a weaker industry environment in Asia and Europe.

So we are making progress.

There's a lot more to do.

Now turning to the North America resources plays, excluding divested assets, such as Eagle Ford, we have some 260,000 barrels of oil equivalent per day of production on stream.

Around 80% of this production base is gas.

This is a major long-term growth opportunity for Shell shareholders.

However, upstream, America's resources plays remained in loss for the first half of 2014, about $400 million loss.

And although this does represent a positive earnings swing of some $900 million on the first half to first-half basis, reflecting higher gas prices and the improvement plans that we have on the way.

We have updated our view on portfolio and strategy both for dry gas and liquids-rich shales.

Major divestments of non-core liquids-rich shales positions are now complete totaling some $800 million of proceeds in 2014.

And around 60% of our near-term resources plays investment in North America will continue to be directed at liquids-rich shales acreage.

And this will be in appraisal drilling and potentially material liquids-rich positions in the Permian and Western Canada.

In gas, our Western Canada acreage has the resources and potential to underpin a large-scale LNG project, and we have a 12 million-ton per annum scheme in front end engineering and design at Kitimat.

We're assessing the remaining potential for Shell in Lower 48 gas, including exploration, and as we work through the portfolio, there could be further asset sales and impairments there.

Okay.

So that's an update on some of the steps we are taking to improve our financial performance.

Turning then to the second priority of capital efficiency, Shell is opportunity rich and capital constrained and this is driving the hard choices in the portfolio.

So this involves moving ahead with growth projects such as LNG Canada and Appomattox in the Gulf of Mexico, where we are in front end engineering and design, and at the same time being more selective on new feeds with a routine in place now, where I review feeds with $500 million or greater cost implications with my colleagues on the executive committee.

The asset sales program is making good progress.

We have around $8 billion completed in the first half of the year.

So we've made a good start here against our plans for $15 billion of asset sales for 2014 and 2015 combined.

So we're having a busy year on asset sales.

In the longer term, I would expect to see around $5 billion a year of asset sales as the norm for Shell, as we apply rigorous portfolio management on a much more ongoing basis.

And there's no change in our guidance for around $35 billion of organic capital spending in 2014.

Turning then to the third priority of project delivery.

Mars B, which started up six months ahead of the original schedule in February of this year, is still on track to ramp up to its 100,000 barrels of oil equivalent per day plateau in 2016, and Mars B averaged around 38,000 barrels a day in the second quarter of 2014.

So our overall Gulf of Mexico production increased from some 177,000 to 231,000 barrels of oil equivalent a day on a Q2 2013 to Q2 2014 basis, an important profitability driver for us.

And if I look into the second half of this year, the Gumusut [Denshelec] platform and Cardamom tie-back are both on track for start-up later this year, much as planned.

Now let me update you then on conventional exploration, where we are spending around $4 billion in 2014.

So very long-term plays like Arctic and other Frontier basins could deliver really substantial new oil and gas fields.

But at the other end of the spectrum, near-field drilling can add high-value barrels in a short timeframe.

We expect to continue to add new discoveries in our Heartland basins, where basic geology and technical risks are well understood.

Regarding Alaska drilling, at the moment, as you know, we are blocked by the US courts and we are not prepared to commit to a drilling campaign there unless those issues are resolved.

However, we continue to work with local stakeholders on logistics and on permitting to keep the option to drill there safely in the future.

Near-field and Heartland activity is around half of our exploration spending and it's here that we've had some good well results recently.

And let me highlight two areas, the deepwater Gulf of Mexico and Malaysia.

So in the Gulf, the Rydberg discovery in a 2,300 meters of water is a third find in the Norphlet play, and Rydberg takes the [headline] discovery potential in the Appomattox area to 700 million barrels, and we are assessing if Rydberg will be developed as a tie back to Appomattox or as a standalone project.

And in Malaysia deepwater, the new Rosmari discovery is the latest in a series of new gas discoveries which could potentially feed into existing LNG schemes there.

And Rydberg and Rosmari are both examples of where Shell is adding value, material value, for shareholders with a drill bit in the Heartlands and looking into the second half of the year, we have some important wells coming up in Albania and, of course, the Libra field in Brazil subsalt.

And with that, Simon, over to you.

Thanks, Ben.

Good to talk to you all today.

I'll start with the earnings.

Our reported current cost of supply, or CCS, earnings included a negative $1 billion of identified items that included the impairments of some $2 billion predominantly related to the dry gas properties in the US, partly offset by divestment gains of $1.4 billion, mainly related to the sell-down of Woodside and Wheatstone, both in Australia.

The impairments in the US came primarily as a consequence of reduced intended development spending on the Lower 48 dry gas properties, and that leads in turn to reduced production and cash flow expectations in the near term.

Second quarter CCS earnings, excluding those identified items, were $6.1 billion.

Earnings per share increased by 33% from the second quarter last year.

We announced a $0.47 per share dividend for the second quarter of 2014, now that is 4% higher than year-ago levels.

The buybacks in the quarter to the [NG] and the $300 million, $1.6 billion to the end of June and $1.8 billion up to and including last night.

Turning now to the business in more detail, upstream clean earnings for second quarter 2014 were $4.7 billion.

That's an increase year-on-year of $1.2 billion, or 34%.

Integrated gas and upstream Americas both showed robust earnings momentum on a second quarter to second quarter basis.

Now I do need to flag, we had a positive year-on-year impact in the upstream from an increase in the deferred tax liability in Australia due to the stronger dollar there, $100 million positive effect in the quarter.

A year ago it was a negative $400 million.

On the flip side, recognition in the second quarter dividend to Shell from one of our LNG joint ventures slipped into Q3, paid early July, and that was around $200 million.

The headline oil and gas production for the second quarter was 3.1 millions of oil barely equivalent per day.

That's an underlying increase adjusting for divestments, et cetera, of 4%.

The volumes were supported by ongoing ramp-up of Mars B platform in the Gulf of Mexico and particularly in Majnoon in Iraq.

We also saw new volumes from revamping older fields in deepwater Brazil and the Gulf.

A year ago, production was reduced by high levels of maintenance compared with what we saw in the recent quarter.

Our LNG, liquefied natural gas, sales volumes were up 28% Q2 to Q2.

That was driven by the acquisition of Repsol's Atlantic and Peru LNG business, but also a much improved feed gas supply into the Nigeria LNG unit.

You'll see some pointers in the table here for the third quarter.

That covers production and some of the financial items that you can expect to see.

In the downstream, underlying earnings, $1.3 billion, that's $180 million or 15% higher than a year ago level, increases in both oil products and in chemicals.

In oil products, we delivered an increase in the refining results, and that was due to the combination of better operating performance and stronger Gulf Coast, US Gulf, margins.

And that overall result was delivered to despite the pressure on industry margins everywhere else in the world.

Our refinery availability averaged 94% in the second quarter.

That is an improved performance.

And our market and trading results declined slightly from year-ago levels.

Chemicals results were lifted by the improved base chemical industry conditions, primarily in North America.

You could also see on this slide some pointers for the third quarter in the downstream.

Let me flag that repairs at the Moerdijk chemical plant here in The Netherlands, where we did have an incident widely reported in the second quarter, those repairs will run through well into next year into 2015.

Turning now to cash flow and the balance sheet.

Cash generation on a 12-month rolling basis was some $39 billion, average run price $109 per barrel.

Free cash flow, that's cash generation less investment adjusted for divestments, that was nearly $8 billion in the quarter compared to an aggregate of $7 billion in the last 12 months.

So the gearing at the end of June sat at 13.4%.

Earlier this quarter, we announced that the scrip dividend would be canceled, so there will not be a scrip dividend from the Q2 payout and onwards thereafter.

Canceling the scrip underlines the confidence we have in our cash flow, and also in the growth in the free cash flow.

It means also that we are free to buy back the A shares or the B shares, whichever is the most commercially attractive option.

Buybacks for this year and 2015 combined should be in the range of $7 billion to $8 billion, of which $1.6 billion already in the bank, end of June.

Turning now to the financial framework, and just let me make some comments on how we think about our financial framework, how it integrates with the business strategy.

There is a little bit of misunderstanding here that's perhaps confused by the way some of our competitors talk.

We aim to add shareholder value with sustainable through-cycle growth in the dividend.

In financial terms, this means our ongoing operations, cash flow from Ops, must be able to finance both our organic investment and the growth in the dividend.

This chart shows the last decade of performance.

Seven to eight years ago, you recall, we lifted our investment levels as part of this strategy.

We knew we might face some headwinds along the way.

The spending would increase before we saw the benefits from increased cash flow.

The chart on the left of this slide shows the track record on organic free cash flow -- that's just deducting the organic capital investment -- and the dividend declared which you can see growing steadily over time.

Strategically, we will aim to ensure the cumulative surplus of these two trends upwards over the cycle.

If not, then we know we need to reconsider some of the key parameters, such as investment levels and priorities for that investment.

Since 2010, when the major new investments came on line, we have indeed trended upwards again on this line.

And our ongoing priority is to reinforce this rising trend, growing the cash flow from operations ahead of investment so that we earn before we spend.

The right hand chart on the slide here shows our track record on acquisitions and divestments.

The strategic intent here is to focus and high-grade the portfolio.

We expect a fairly regular flow of divestments, and you can see that here, typically over $5 billion a year, or 2% to 3% of the capital base.

Acquisitions and divestments have both been of a similar magnitude in recent years, although there has been a net surplus since 2005, you can see here.

There is not a precise target to balance these out, and the contribution made by these two elements is not an essential part of the financial framework.

We can, however, plan the balance sheet assuming a fairly regular contribution from divestment.

And we retain flexibility in the overall framework for acquisitions, which are inherently more opportunistic.

We do have other tools for the financial framework.

They are the gearing, the scrip, and the share buyback programs, and we have to look at all of the above in the context of the strong balance sheet.

So this next chart shows how all these elements have combined over time to drive the financial framework.

The yellow here is the cash payout to shareholders.

You can see the impact of both the global credit crisis and the investment choices that we've made through the cycle.

And we've used all the available levers in a prudent way throughout this period to meet financing needs.

Although we did reduce the cash distributions to shareholders in recent years, our investments have delivered underlying growth in cash flows, and we've begun again to increase cash distributions since 2012.

All of this supports our expectation, absent black swan events, of course, that we will distribute over $30 billion to shareholders in the two years 2014 to 2015.

Now moving on to competitive performance.

I'm aware some of you are concerned we don't have targets explicit in the market.

This chart records the key metrics on which we said: please judge us.

Track our progress on growth, both cash generation from operations and free cash flow, but also a move to more competitive returns on capital employed.

So we take a dashboard approach here, looking for a more competitive performance on a range of metrics over time, not single-point outcomes by a single date in the calendar.

Our cash flow from operations development has become more competitive in the sector.

You can see that here.

It's been a major strategic objective for Shell in the last few years to grow this figure.

But it's good to see the return on capital employed and the free cash flow trending higher this year, but as Ben laid out, we know that we need to do more here.

We have to drive these more sustainably through the cycle, and to take other metrics higher, as well.

There is no complacency.

Despite the more robust results we've seen in the last six months, there's still an awful lot to do.

So with that, Ben, back to you.

Thanks, Simon.

So we're making progress with the priorities that I set out at the beginning of the year to balance growth and returns by focusing on better financial performance, enhanced capital efficiency, and continued strong project delivery.

We are taking firm actions to improve our capital efficiency by selling selected assets and by making tougher project decisions, and we've continued to ramp up new production, and our exploration program is delivering with new finds in the Gulf of Mexico and in Malaysia.

So we have distributed more than $11.6 billion of dividends in the last 12 months.

And we're expecting distributions of over $30 billion for 2014 and 2015 combined.

All of this underlining our commitment to shareholder returns.

And with that, let's take your questions.

Please, could we have just one or two each, so that everybody has the opportunity to ask a question?

Operator, can you please poll for questions?

Thank you.

(Operator Instructions)

Theepan Jothilingam from Nomura International.

Yes, good afternoon, Ben, Simon.

Just two topics, please.

Firstly, just on the Arctic, do you think -- how do we go about thinking about the cost?

How long can you continue to have an expense in the Arctic without really having much activity or well results from that?

And I'm thinking, is there a possibility to turn down that spend in the context of overall exploration spend?

And, secondly, more strategically for the group, I think you've talked about reducing costs particularly in North America, but could you talk about now what the opportunities are, more wider corporate level?

Thank you.

Okay, thanks, Theepan.

Arctic first.

So what I said, we are very, very clear, we wanted to make sure that when we get into a drilling season, we want to be ready for it from, let's say, operational perspective.

We want to be able to do this completely flawlessly.

We, obviously, need all the permits in place and we need to be free of any legal issues or blockages.

We can't do it this year for reasons that are well known to you.

And let's see whether next year will be better.

In the meantime, of course, we do carry costs absolutely, and we can't do this indefinitely.

So there will be a moment where we will have to make up our mind but that is a position that we can continue to be in or not.

That moment has not been decided, but it will be before the next season.

Costs in North America, absolutely, you're right.

If I take North America here, as shorthand for unconventionals, we have, of course, been focusing very much on the cost take-out, take out overhead costs, take-out costs, very much equipment costs at the wellhead, gas processing.

Plant cost is the next phase that we are focusing on.

It's an absolute must for us to be cost competitive together with being in the sweet spot in order to be able to have a profitable business there.

That will continue to be a drive going forward.

Costs will continue to be, of course, a key focus area across the business.

And we have, certainly in downstream and upstream, had a good track record of taking out cost.

I've decided not to have an explicit target out there, but you will see the costs results, the cost take-out results come through in the results in the bottom line.

Thanks, Theepan.

Can I have the next question?

Thomas Adolff from Credit Suisse.

Good afternoon.

Thanks for taking my questions.

Two, please.

One on the buybacks, you said, over 2014 and 2015 at $7 billion to $8 billion.

Just wondered whether you can share the method around that number?

Just trying to figure out why, from your perspective, $7 billion and $8 billion is the right number for buybacks.

And the other question is on oil products.

Your target is to reach $10 billion in cash flow.

You generated $7 billion over the past 12 months.

Can you deliver on this purely from operational improvements, or do you actually need the macro to play also in your favor?

Thank you.

Thanks very much, Thomas.

Let me take the oil products question, Simon will talk to the buybacks.

Let me just correct you slightly.

It is actually the downstream as a whole you're talking about, so oil products and chemicals combined.

And we said we would indeed expect a $10 billion cash from operations and a 10% to 12% return.

That would be, again, the sort of macro conditions that we were seeing in 2013.

So there is an upside on that, of course, as macro conditions could also improve because we still consider 2013 to be not exactly a cycle average here.

A lot of it will be achieved by the initiatives that we've set in motion, so much more focus on the bottom line, a stronger margin orientation in the business in addition to a strong operational excellence orientation.

And you will have seen that the results can be quite material.

The results that we are seeing in this quarter, very, very strong operational performance, but matched with very high utilizations and much higher access to advantaged feedstocks and as a result, an improved refining performance.

We will continue to look at where some of our aspects in the portfolio simply cannot get there.

And, therefore, I don't rule out portfolio action in this somewhat weaker parts of our oil products portfolio.

The chemicals portfolio is pretty much where it needs to be in terms of robustness.

Simon?

On the buybacks?

Thanks, Ben.

I'd just note on the oil products cash generation, we're about $8 billion over the last 12 months.

$8 billion in previous years, as well.

But as you can see the actual performance is a little bit better this year.

So a lot of the improvement we're starting to see from the work that we're doing ourselves because the environment this year has not been any better than it was in earlier years.

And some of the buybacks, $7 billion to $8 billion, we've already completed as of last night $1.8 billion.

We're about 150 million shares short of offsetting the cumulative impact of the scrip, which is about 2% dilution.

And getting back that 2% dilution is the key target.

We always intended to do that within the four-year framework, we set out the financial framework to do.

We are acutely aware of the dilutive effect of the scrip.

And it was just a matter of time in terms of the confidence in the cash flow building out from the new projects that have been coming onstream before we effectively ramped up the net buyback impact.

Of course, canceling the scrip makes the net buyback impact that much more powerful, and means that we don't have to buy back at quite such a rate.

We can certainly accelerate that pending the generation of cash flow, the free cash flow.

We're in a pretty strong position on the balance sheet at the moment, but for now, the $7 billion to $8 billion, together with the expected dividend, as I said, absent black swan events, should mean a shareholder distribution over two years of $30 billion which we feel is appropriate given the spot we've had from shareholders in a period of high investment.

Okay, thanks, Simon.

Can I have the next question,, please?

Oswald Clint from Sanford Bernstein.

Yes, thank you very much, gentlemen.

Good afternoon.

First question was really maybe on your comments about long-term LNG ambitions in Canada using your unconventional portfolio and exporting it from there.

I just wanted to highlight those ambitions may or may not have changed given the Russian pipeline gas deal into China.

It could appear that a large part of the demand may just have been absorbed by that pipeline deal, and I wonder if that's affected your long-term views on Canadian LNG exports?

Second question was just on your comments in the release about improved well performance in the Gulf of Mexico, so over and above Mars B, what's going on with the well performance that you're seeing there?

It seems to have lifted the US liquids volumes quite strongly.

Thank you.

Okay, thanks, Oswald.

I'll take your first question.

I think our long-term LNG ambitions are just that.

Long-term LNG ambitions that haven't really changed.

Our LNG business is an incredibly important business for us.

It's a huge opportunity to continue to grow in a reliable way.

It's a very, very material business, as you know, already producing very, very strong returns.

And we will be looking at advantaged LNG projects to take the business further.

I think Canada LNG is an advantaged LNG project if you consider the fact that it's still aimed at what at this stage and in the future will remain to be an advantaged market, one of the strongest markets, the North Asian markets, as well as affected of course, Canadian gas is slightly more challenged to get to markets then gas in the Lower 48.

So, therefore, the risk in principal the largest value arbitrage available in the market.

Of course, the Chinese deal with Gazprom will take care of a significant amount of gas demand in China.

But if you look at the volumes, and if you look at the prospects for China to grow, bearing mind that gas demand in China is 5.8% of the energy mix at the moment, there is a huge amount of demand growth still available for us.

And no matter how we analyze it, we see there will be room for a number of LNG projects to get in there.

So, therefore, the prospect that we see for LNG Canada, possibly even for a follow-on investment, are still very strong and very much there.

And, therefore, we continue to move forward with it.

Would you take the second question, Simon?

Sure, thanks, Ben.

You're absolutely right, Clint, that the US liquids production has improved year-on-year, primarily driven by the deepwater performance.

We've also got an uptick in Brazil, I mentioned other projects, but both BC-10 and [Bidjibursalana] had new well activity come onstream this year, which has given some uptick in the upstream America result overall.

And the Gulf itself, Gulf of Mexico, we have 24,000 barrels a day ourselves, our share of Mars B. We have the Na Kika Phase 3 project coming onstream.

We have ramp-up in Perdido particularly.

Perdido is pretty much at capacity at the moment.

And a year ago, across Q2, Q3, we had quite a significant maintenance program, particularly across the Auger platform as we built some of the modifications to bring in future expansion there from the Cardamom development.

So the Auger platform is back onstream.

So you put that all together, Q2, Q3 last year were effectively the low point for our Gulf of Mexico production at around 170,000 barrels a day average over those two quarters.

In the recent quarter, 2014, we were at 230,000 barrels a day.

So like 60,000 barrels up on that low point from the middle of last year.

And, of course, Mars B is still ramping up.

Cardamom is still to come on.

So there's a fair bit more to come in the Gulf from that deepwater as we progress the investment program.

So it is a strong story, deliberate strategic choice.

Remember, these are high unit margin barrels, so overall, while we may not be entirely replacing the production that we are seeing there out of Abu Dhabi or elsewhere, we are certainly getting an uptick in earnings and cash generation per barrel.

Also I'll just take the chance to note that in September we'll be in the US talking a bit more with the investors about precisely this development, which is looking pretty strong at the moment.

Thanks.

Thanks, Simon.

Thanks, Clint.

Can I have the next question, please?

Jason Gammel from Jefferies.

Thanks very much.

I just wanted to follow-up on the comments that you made about the oil products business and enhancing the profitability there.

Two specific ones.

It seems to me that the low hanging fruit in the portfolio is potentially the Port Arthur refinery where you put in a lot of incremental investment, and not necessarily had fantastic results early on.

Can you talk about where you're at in terms of the overall economic capacity of Port Arthur and where there might be some more room for further profit enhancement there?

And then second, just on the European business, while Pernis might be an advantaged refinery within a pretty bad region, what solutions would you have if you decide that some of the other refineries in Europe are not going to be profitable?

Is there a real exit strategy there for you?

Okay, thanks, Jason.

First of all, Port Arthur, it's indeed, significant of amount of investment being put into Port Arthur.

As you know, of course, we've had some [teething] trouble starting it up.

We had some constraint at the time with the crude unit after we resolve some other [teasing] issues that have been resolved.

The focus now has moved from running it reliably to making sure that we maximize the yields that we can get out of it.

Some of it is taking advantage of the availability of advantaged crude and other feedstocks.

Of course, Port Arthur very much a heavy feedstock machine, so, therefore, not necessarily you could argue suited for the large crude that tends to be in abundance at the moment.

But, nevertheless, we can put in there some residues and other feedstock to make sure that we load up the units fully.

I think with the phase of getting the operational excellence piece right, and now focusing very much on sweating the asset from a margin perspective, you'll see that Motiva and Port Arthur, but certainly also in the other refineries, has moved to a much more intense game of utilizing all the assets for maximum margin delivery.

And in the process also finding out what logistics bottlenecks are there to get access to even more advantaged feedstock.

It's a practice, the same strategy that we follow throughout North America.

We have been pushing our entire system to be more equipped to deal with advantaged feedstocks, so feedstocks that are distressed in pricing, and what we see is that year-on-year we continue to make progress.

We hope to be at about 44% of advantaged feedstock capability for our entire refining system in North America.

I think the low hanging fruit in Motiva is still pretty much there in that respect.

And a lot of the improvement that you've heard us talk about is indeed Motiva improvement that we already flagged in the first quarter, which very much is in evidence and growing in the second quarter.

Europe, well, the way you have to look at refining, refining, particularly in Europe, but also in the Far East, is in our portfolio going to be concentrated in those areas that we have highly complex refineries in very deeply traded refining hubs, so that we can get access to a wide range of feedstocks and can place products in a wide variety of markets.

Then having refining operations, supply operations, and trading operations, very well integrated, which is basically the organizational business change that we made in the course of last year and implemented on the first of January, with improved that particular approach to what we call integrated hub refining.

And, therefore, I think Pernis will still be in an advantaged position compared to the rest of the market because it is after all one of the most complex refineries in the deepest liquid trading hub in Europe.

So we have to look at Pernis to making sure we can take advantage of niche crudes, niche markets, and by opening up the operating window to deal with more flexibility requirements that will be offered to us through market opportunities.

And I think, yes, it is a challenged environment at the moment, but Pernis is at the moment still in that sense the most advantaged in a challenged environment.

And if the market environment picks up, and as we indeed understand how to play this game better and debottleneck the refinery, you will see that this has the potential to still be a very strong asset.

Okay, thanks, Jason.

Can I have the next question, please?

Iain Reid from BMO.

Hi, gentlemen.

Just a question on the Lower 48 gas.

(inaudible) I'm just wondering what (poor audio).

Is there a macro side of that, presumably there is in terms of having changed your long-term Henry Hub assumption?

Or is there a more technical analysis required of the individual assets in order to make your mind up on that?

And the second question is, on your MLP, and I know you would say, now you've crossed the Rubicon of realizing you don't have to own all these utility star assets.

You've got a huge amount of resource of assets elsewhere in the world, particularly LNG production assets, et cetera.

Is it your intention to put this philosophy to work elsewhere in the world?

Thanks, Iain.

Simon will take the MLP question.

Let me start with the Lower 48.

The Lower 48 is pretty much concentrated at the moment on a significant position that we hold in Pennsylvania, the Marcellus and the Utica positions that we have there.

And then we have some other smaller positions around there.

So some of them will maybe give us opportunities for further concentration, further cleanup, but if I just focus at the Lower 48, sorry, at the Pennsylvania position, I think it's going to be first of all appraising that position further to really understand how good it is.

We still have some work to do there to really understand the full potential.

And then it's a matter of deciding whether that is indeed good enough to develop in its own right against the prevailing gas prices that we see, and whether we have the capital to dedicate to it, and whether that indeed is the best use of our capital, or whether we can find that this is better developed by somebody else and we basically get the value of the position at the gas prices that we would see going forward or better.

So there is -- it is going to be purely a value play, and, of course, very much a value play that has as a precondition that we need to understand a little bit better what is there.

There's still some appraisal activity to be carried out.

It is not part of a larger strategic integrated play, much like the Western Canadian position integrated with LNG Canada.

On the MLP, Simon, to you.

Thanks, Ben.

Just a reminder upfront, I can't actually say anything about the specific MLP program already launched because for legal reasons, I can only refer you to the prospectus.

But the question, I think, Iain, was about broader applicability of the same principal alternative forms of financing of the assets already in the portfolio today.

Essentially, an MLP structure takes advantage in the US of significant availability very large liquid pool of potential investment looking for a particular type of return in a tax advantaged manner.

And that type of return typically fits well with utility type returns from assets such as infrastructure.

Yes, we have assets of that nature around the world.

They are not necessarily in a place where we can attract such a liquid pool of investment.

Even if they were, it would become a question, it's essentially a financing issue, it's not a strategic issue.

So it becomes a question, what is the cost of that financing?

Remember, we are borrowing typically 5- to 10-year money, 3%, maybe less, pretax, tax deductible, so our incremental cost of finance is fairly low.

So to get equivalent types of returns, and then we have to think very carefully about how we would structure something.

The other issue is, of course, the MLP structures in and of themselves, particularly as we retain the general partnership, remain consolidated on the balance sheet.

So they don't impact the overall metric which you guys and we tend to look at in terms of capital employed and return on that capital employed.

Maybe there are other types of financing structures that would do so, but that's something, I think, for the future.

At the moment, our metrics, both in the equity market and the debt markets, are predicated on most effective financing being done either through equity or through accessing medium- to long-term debt at pretty attractive rates.

I do think, over time, we could sustain a greater level of access to debt type finance, but I think we have to prove we can make the basic books balance first sustainably and grow that organic cash flow.

A lot of other opportunities open up after that, I think, once we are pretty much sound on the basics.

Okay.

Thanks, Simon.

Can I have the next question, please?

Lydia Rainforth from Barclays.

Thanks, and good afternoon.

Two questions, if I could.

The first one, just a clarification, on the divestment proceeds, a number of $15 billion, 2014 to 2015, is that a cash in the bank by the end of 2015 number or is it [announced]?

And then the second one, with the equipment sold that Harry Brekelmans, Projects & Technology Director, is what you are looking for from that division changing given the increased focus on capital discipline?

Thanks.

Can you remind that last one, Lydia, what is changing?

So with the appointment of Sir Harry as Projects & Technology Director, is what you're looking for from that division within Shell changing, particularly given the focus on capital discipline?

Thanks.

Okay, thanks, Lydia.

Good questions.

The divestment of $15 billion in two years, pretax number, of course, it is, we will be looking at completing the deals, but it is no good, of course, to announce and not delever.

So that's why we also, when we talk about the delivery, what is that we have in the bank.

On P&T, let me first of all say that P&T, of course, very important and very crucial part of our organization.

The very fact that we have put that capability together, and have really high-graded it and made it a very prominent capability represented at the Executive Committee level has really helped us to make sure that we get very, very focused on the key things that I do, the [bell's] performance project delivery, hydrocarbon maturation, as well as a number of other things that fit in that technical IT, contracting and procurement, et cetera, et cetera.

Matthias has been incredibly successful in it, has had a very, very successful career.

Will be retiring, going back to Switzerland in October.

And really the trend that he has set, the agenda that he has, will be the agenda that Harry will take over.

So there will be no changes that will coincide with it.

I'm sure that Harry will have his own stamp on it, will have his own style in doing it, but very much the underlying philosophy that we want to have excellence in these skills that are core to the delivery of our business, that philosophy will remain and that focus will remain.

Thanks, Lydia.

Can I have the next question?

Jon Rigby from UBS.

Thank you for taking the questions.

Good afternoon.

Two questions, please.

The first is connecting two things that are on the presentation.

The first is your discussion around the Lower 48 and your ambitions around that.

And then, you talk around the conventional exploration budget of $4 billion.

So I'm thinking in terms of a Company that's producing a touch above 3 million barrels a day annually, if you're not going to be active in developing conventionals in North America, if you are restricting the boundary of what you want to do, is $4 billion a year of conventional exploration enough to keep filling the resource hopper moving forward?

The second question is just going back to the financial framework track record over time, the balance of free cash flow that you indicate through from 2005.

It occurs to me, if you go back to 2005, production was close to 20% higher and returns almost double what they are now.

So what other things have to be done other than just balancing cash in and cash out?

It seems to me that if anything, cash in and cash out balance is a managed decline of the business over that period.

Thanks, Jon.

Good questions.

Yes, on the Lower 48, or rather your $4 billion of conventional exploration, is that enough to replace the hopper?

No.

It's not.

We know that.

We will need a mix of finding hydrocarbons by the drill bit and getting them through to MBD activities that we will develop a good enough funnel to continue to replace and grow the business, give us enough opportunities to have a rich set of choices.

And then we can always balance these two if we have a very, very successful run of exploration results.

The pressure to do deals is less and vice versa.

If we run into very, very good opportunities, quite often you've seen us do this with Libra.

We will try and find the money for that in a sensible way out of our exploration budget without, of course, cannibalizing the opportunity set there.

But it will always be a two-legged strategy to make sure that our hopper, or our opportunity funnels for all the different investment themes are adequately filled.

And that's what we do.

We look at the individual investment themes very much of what is it that we have under operation?

Can we understand what is still very strong, attractive Brazilian business?

What do we have under development?

What's coming on?

What do we have in terms of opportunities that we can now start maturing?

And do we have enough very, very early opportunities, much more in exploration or acreage stage of the game, to continue to have that funnel grow?

You have to take a long-term view because particularly with things like deepwater we're looking at a 10-year maturation cycle.

So we don't necessarily bet on 100% exploration success.

We bet on the mix of the two.

Simon, will you take the financial framework question?

Sure.

Thanks, Jon.

It gives me a chance, I think, to maybe reiterate some messages I've said before.

Clearly, 10 years ago, the industry was in a different place.

It was, in my humble opinion, living off the fruits of the legacy.

In our case, we basically opened up one new province since the 1980s, I think, which is the deepwater Gulf of Mexico.

And we had as an industry been hugely under investing, that's why the oil price is $100 today, not $20 as it was 12 years ago.

And, of course, returns were higher, but that is not a sustainable situation.

You can see that for everybody.

Oil price rises, costs rise with it.

We made some choices, as I noted.

And I think you'll recall, partly because fundamentally, our portfolio was tired, relatively mature, and needed a major refresh with significant new positions that would become the legacy assets of the future.

We knew we had to invest.

We said at the time that we would do that, and over 10 years this has played out.

Over that period, we've opened up, for example, [tackling] activity, gas, refresh completely Australia North West Shelf, Brazil deepwater, completely refreshed again the Gulf of Mexico, and certainly built out the heavy oil position in Canada in a way that just creates 10, 20, 30 years of future investment, rather than nibbling around the edges, looking for 5 million barrels here or 20 million there, to sustain high returns in mature legacy asset areas.

So fundamentally there's been a shift.

Returns have come down.

As we've move now to a more balanced position, where we've got a core of legacy assets, we'd call it the upstream engine that we can certainly for the next 10 years still drive strong returns from but with strong cash flow.

We recycle that into the pure growth areas of integrated gas and deepwater, both of which have decades ahead of them of strong high return performance, competitive performance.

And we create through either exploration or the unconventional activities additional opportunities to build on, and we'll have the strength both financially, but also operationally and technologically to make choices around that portfolio.

So over the period, cash in, cash out, has been a challenge.

We knew it would be going forward.

I would suggest what we need to do with the cash is more an indicator of where the value both will come from and how we will distribute that value, whether that is back to the shareholders or whether we choose to reinvest for longer-term future growth.

There'll always be a balance between the two, of course, but our strategic aim was always to be the choice would be ours because of the strong performance, not that it would be forced upon us by events such as the credit crisis and us running out of cash.

We kept the investment going through that cycle, remember.

And that was a tough call to make given the change in the free cash flows that you can see there.

And I have to say, 8, 9, 10 years ago, golden age of refining.

There is a $2 billion or $3 billion step back in the downstream contribution since then.

We may not see that recover again.

But we can certainly revert back to the earlier conversation.

We can do better there, as well.

Of course, just staying still isn't good enough, but that's not the intent.

Okay, thanks, Simon.

Can I have the next question, please, operator?

Irene Himona from SG.

Thank you, good afternoon.

My first question concerns Russia.

You have about 5% of your production there.

I wonder if you could share your thoughts on the potential threat that the current sanctions being implemented, specific to the oil industry may pose to shareholders?

My second question is on LNG, a very good second quarter thanks to the Repsol acquisition, but actually, spot prices did collapse in the quarter.

We can see that in the numbers.

Was there an effect on your business, and what do you think drove such a dramatic decline?

Do you think it's sustainable or reversible, and what is the impact on the underlying Shell business?

And my final question, very briefly, Ben, you referred to the challenging refining environment in Europe.

Exxon has recently announced a fairly sizable upgrade in their European refinery.

Does that impact the Shell view of the challenges of European refining?

Thank you.

Okay, thanks, Irene.

Very good questions.

Let me take the first and last one, and Simon will talk to the LNG pricing.

So Russia, yes, I find it very hard to make definitive pronouncements on a day like today when there is so much still uncertain happening as we speak.

So we have, of course, a pretty good idea conceptually what sort of sanctions are being proposed.

But the devil will be in the detail here.

If you look at the oil and gas technology sanctions that are being proposed, you could look at it and say, well, it's very much oil targeted.

Of course, for reasons that also the EU wants to protect its own gas supply security from Russia.

So you could, on the one hand, argue that, of course, investments that we have in Sakhalin should be spared, if you like, from sanctions.

But at the same time, of course, we have to, in the end, see in detail what these sanctions will entail, particularly also the financial sanctions, which look like financial instrument sanctions, but there can be quite some devil in the detail on how that looks, as well.

So we are monitoring this intently.

We have, as you can imagine, teams not only in our Russian joint ventures, but also here to understand how it could affect us.

We are looking at what sort of contingencies do we need to have there?

Of course, we have every intention of obeying the sanctions.

That is without any doubt.

But it's very, very hard at this stage of the game to just say, well, this is how we see it play out.

This is how we are going to respond to it.

So I cannot sit here and say, listen, we are completely risk free when it comes to Russia based on our knowledge of sanctions.

The only thing is, well, you know our business as well as I do.

It is a profitable business.

It's very much focused, of course, in two upstream joint ventures that are possibly at risk, the Sakhalin Energy joint venture and Salym.

Of course, our downstream operations are very much domestically focused and, therefore, much less dependent on technology, financing tools, et cetera, from the outside.

So I'm afraid I can't give you any sort of definitive details other than what I said just now.

The refining environment in Europe, yes, it is, absolutely it is challenged.

And as I said earlier on to a response to Jason's question, it is in my mind, the last person standing strategy, with the strongest refining position very well integrated into very strong markets, both from a feedstock supply as product off-take perspective, and having the highest degree of flexibility in your refinery to indeed take advantage of transient pockets of value that will come by, that will be the strategy.

And if you will look back at what we have been doing over the last years is to basically concentrate our refining portfolio to those assets where the potential to play that game is really there.

Now I can't comment in detail on Exxon's investments that they announced in their Antwerp refinery, but they are pretty consistent, I would argue, with the sort of things that I've just said.

So getting higher complexity in your refining kit in areas where you have access to good [handling] markets, but also the Atlantic Basin at large seems a sensible strategy as it is the same strategy that we are following.

So that's probably all I can say about Exxon's investment.

But I do have the belief that in the end we will end up with a strong position in Europe as the industry further restructures, and as we continue to have a very strong capability, a margin capability focus in oil products business.

And let me also add, if we can't get to that point, then there will be no mercy also for those refineries.

We will not tolerate having structurally underperforming assets that cannot deliver or cannot punch their weight in the portfolio either.

Simon, will you take the LNG pricing?

Sure.

Just overall, the integrated gas results, very strong again.

The primary drivers year-on-year were actually gas to liquids, its highest ever capacity utilization to date.

And the total LNG volumes being quite a bit higher, 1 million tons higher in the quarter, three-quarters of which came as a result of the Repsol acquisition, most of the rest is Nigeria.

In pricing terms, first quarter we're seeing spot cargoes at $20.

In the second quarter, some at $12 or lower.

However, the vast majority of our sales are linked to long-term oil prices.

We had slightly fewer diverted cargoes which can mean, or linked to spot.

We had slightly fewer in the second quarter than we had in the first quarter.

But, overall, our exposure to that spot market remains limited.

The uptick is primarily GTL and the total volume.

Of course, going forward, the spot prices are very driven by short-term effects which include weather around the world.

Gas demand has been quite a bit lower because of the weather, but also some of the choices, particularly in Europe, made around the power, all of the constituents of the power mix.

So, therefore, more coal, less gas, and, therefore, more carbon dioxide seems to be the European energy policy and that does reduce the number of cargoes going into Europe.

Having said that, I'm not sure how sustainable that will be going forward.

We remain confident that not only will prices remain attractive, but that that long-term element linked to the original investment premise will pertain to support the current significant investments going into Gorgon, Prelude, Elba Island and the future potentially in Canada [rails] and Indonesia.

Okay.

Thanks, Simon, thanks Irene.

Can I have the next question, please?

Martijn Rats from Morgan Stanley.

Yes, good afternoon.

I've got two, if I may.

Looking back at 2013, one of the problems with 2013 was not just that the overall earnings and cash flows were lower, but they were also quite volatile.

And that made forecasting quite difficult.

We've now had two quarters in a row that feel much more robust and where the changes in the earnings follow factors that we can broadly foresee.

Now two quarters, of course, is a very short period from where we are sitting, but from where you are sitting, would you say that see the business slowly but surely moving into a regime where performance is more forecastable and more gradual again?

And the second thing I wanted to ask you relates to the $30 billion figure of combined dividends and buybacks over the two-year period, of course, this absolute amount is a pretty impressive figure.

I wouldn't imagine that you probably would feel as enthusiastic about doing so if you felt a bit worried about commodity prices.

Is there an embedded message in the $30 billion figure that your incrementally more comfortable that oil prices are going to stay broadly at the levels where they have been recently, at least over those two periods, rather than decline from here on?

Thanks, Martijn.

I'll have Simon talk to that first.

Thanks.

You're absolutely right, Martijn, 2013 volatility was a problem for us as much as you.

I think I'm on record as saying that before.

Yes, it has very much been the case in the last six months the kit has performed well.

People have picked up the challenge that Ben gave to them.

Let's make the most of what we have.

Let's bring the new projects on stream.

Let's do it in a much more predictable and manageable way, and things have worked reasonably well.

That's not to say I can project that out going forward because many of the things that have happened to create volatility in the past have not been under our control.

For example, Nigeria.

For example, the hurricane season.

We had a very, actually, a very easy or non-hurricane season last year.

That's not to say it will be the same this year in the Gulf of Mexico.

And those do have quite important impact on our quarter results.

But it is pleasing to see that our fundamental structural performance on issues such as refining availability, upstream time, turnaround activity and new projects coming on stream and ramping up has indeed over the last six months been more predictable.

The last cause of volatility last year was very much exploration where the write-off, particularly in the last half of the year, were quite substantial upticks and difficult for you and us to predict, of course.

The bottom line impact.

The performance this year in exploration overall has actually been better.

Ben talked about it.

Therefore, fewer write-offs.

I cannot predict there will be no further write-offs, but we're operating at a fairly transparent level of what we're spending, where we're spending it and updating the market, I think, much earlier, and more specifically, about what the results we actually see are.

On the $30 billion, fundamentally that's a combination of the dividend which takes us to, with neither reduction or increase, $23 billion-plus, add to that the $7 billion to $8 billion of buybacks, so the dividend is not linked to the commodity price.

The buybacks, we're pretty confident we are going to deliver sufficient free cash flow to support the $7 billion to $8 billion, therefore, we make that comment.

That is independent of commodity price.

Where commodity price does kick in, importantly, is more on that medium-term three- to four-year window organic cash generation against capital investment.

If we project and see a fall in prices, remember $10 is roughly $3 billion of cash generation per year, so a $10 move in the crude oil price.

If we see weakness there, we do need to think about investment levels at the margin, and also the impact that a fall in revenue or commodity prices usually has on capital costs.

The unit cost of capital as well as the total amount of activity, and negotiating effectively with suppliers around some level of flexibility in that.

And then we do have some of that in place in terms of contracts that adjust to changes in market rates.

So we have still more through cycle at the investment level if we start to worry about the commodity price.

Thanks, Simon.

Thanks, Martijn.

Could we have the next question, please?

Michele Della Vigna from Goldman Sachs.

Good afternoon.

Thank you for taking my question.

You have worked a lot on refocusing your share exploration over the past year, year-and-a-half.

I was wondering if you could give us an update on what level of resources or potential you see in your liquids-rich share portfolio in the Permian and in West Canada, and also if you could give us an update on your International share strategy?

Thank you.

Simon?

Thanks, Michele.

Resource level in the Permian and West Canada, we talked small number of billions.

It's still appraisal.

Still some exploration to do.

But we have quite large positions in both.

And we had hoped to see in liquids-rich shale development quite significant resource bases over time.

We've not yet pulled the trigger on a major development program, but we are seeing growth, for example, in the Permian where about 13,000 barrels a day shale share ahead of where we were on a year ago, and that's without actually pulling the trigger on a development program.

So we would hope to be able to build that portfolio into several billion barrels equivalent.

And around the world, the shale program, there are several countries, small countries, where we've looked, tried, and we're thinking about what's the long-term exposure in countries such as Indonesia and Turkey.

We have already stepped back in a couple of countries, onshore stepping back, for example, in Latin America.

So the major plays outside North America are now China and Argentina in terms of the activity that we are embarking on today.

China, as we said before, remains a geological challenge.

We can see the hydrocarbon, but actually producing economically.

We are still working on a couple of plays in Sichuan with our partners.

We're not at the point where we can define a development program there just yet.

And we are exploring and appraising acreage in the Vaca Muerta play in Neuquen Province in Argentina at the moment.

The other plays that I'm sure you're aware, we've been involved in Russia and Ukraine, I think I can add very little to Ben's earlier statements about the uncertainty going forward there, and the fact that we are effectively de facto temporarily suspended operations in the Ukraine.

Okay.

Thanks, Michele.

Thanks, Simon.

Can I have the next question, please?

Christopher Kuplent from Bank of America.

Thank you, good afternoon.

Just two questions.

Your announcement regarding the longer-term recycle rate of $5 billion annual disposals, are you announcing that today because given the success you had already this year in your asset disposal program, you want to make clear that we shouldn't wait for the next $20 billion disposal program announcement next year?

And, Simon, I know I'm only teasing you, but does that mean you also have a longer-term ambition of an annual $5 billion M&A budget?

Thank you.

Thanks very much, Chris.

As we said, the $5 billion is pretty much.

If you look at it, the average that we have been doing, and if you think of it, we have a portfolio, $220 billion of capital employed that has assets in them that will at some point in time become late life in the upstream, or assets that will lose their competitive strengths more in the downstream.

And, therefore, you will have to have a program in addition, of course, to keeping them as healthy as you can, you will have a program of basically termination where you prune the things that basically do not have the run length anymore or do not warrant the capital anymore to get the incremental future value out of it.

Therefore, almost statistically you have to say, think of $5 billion a year as a good outcome if you would expect to see this pruning systematically every time you review one of the strategic themes in our Company.

So we don't necessarily set targets for that.

We don't need this disposal for the financial framework.

We basically expect that this will be the outcome of good stewardship of our portfolio.

Now on the M&A piece, it's basically completely opportunity driven.

So we basically look around all the time.

Where are opportunities, smaller or larger opportunities that we cannot grow ourselves but we can acquire?

And do we see value in that?

Simon says over the longer run, probably you will see the two balance each other.

But we don't necessarily have to balance the books there every year.

If you want to do that, it's just too constraining because both of them are basically driven by different dynamics around the decision making.

I'd just add on that, the balance sheet is where you need to look if you want to think about what is available for acquisition opportunity.

The back end of last year, we have the BC-10, the Libra, and the Repsol opportunities all come along at the same time, all of them, so it didn't actually worry me too much, but in totality that was close to $9 billion.

That's what the balance sheet is for.

Actually, the divestment program is at least in part to offset that, but we can take our time over that, as well, to ensure that on both sides of the ledger, we are adding value.

Okay.

Thanks for that question, Chris.

Can I have the next one, please?

Thijs Berkhelder from ABN AMRO.

Yes, thank you.

Two questions from my side.

I heard the question on the divestments already, and your answers there, but you more or less announced already $12 billion of divestments with the target of $15 billion.

And with the $5 billion guided on disposals going forward, you more or less are saying that you almost have finalized already your restructuring program.

Is that right?

And is that the only way further indeed improving the operations of what you have, or is the there strategically more in the pipeline?

Second question relates not to LNG pricing but to European gas pricing.

European gas prices have been decoupled from the oil price and also your realized gas price in Europe is clearly lower than we've seen in the past.

What is that meaning in terms of strategy for you as a Company, looking at European gas assets?

Thanks, Thijs.

Simon will deal with the European gas pricing question.

Let me say a little bit about the divestment program.

Yes, $12 billion announced, $8 billion in the bank.

I think you should focus on the $8 billion in the bank, not on the $12 billion announced.

Because that's in the end what we want to do.

We want to deliver the cash, not announce future arrival.

So is it almost finalized?

I don't think that's necessarily the way to look at it.

So if I go back to my answer on Chris's question, we do restructuring because we're not comfortable or content with the quality of a particular business or the quality of the portfolio.

What comes out of it is a divestment number that is a result rather than a target.

And statistically you could say, $5 billion a year seems to be the right sort of number to expect from a Company that continuously reviews and prunes the portfolio.

So if we have announced $12 billion, have delivered $8 billion, and if you say, well, typically we should do $5 billion a year, you could argue that the $15 billion is eminently doable.

And let me just leave it at that.

But ultimately, again, it's not a target.

It is an expectation.

We will be restructuring portfolios.

We will be taking care of weaknesses in our portfolio to make the business healthy.

And if it takes more or deeper restructuring, or longer restructuring, we will not hesitate to do that.

And, again, the divestment number that flows from it will be a result rather than a target.

Thanks, Ben.

The opening gas price, indeed, the spot prices the, hub prices at the moment are probably at three, four-year low.

That has been partly driven by weather conditions which has both reduced demand, but also ensured that stocks remained high.

They are not necessarily related to the medium or longer-term supply/demand situation which is perhaps more driven by politics and the relative economics of gas as a source of fuel for the power sector.

The politics driving the current demand and, in practice, I think, any of you who follow the power sector, there is nearly 60 gigawatts of gas capacity in Europe currently not being used.

Two gigawatts is roughly equivalent to 6 million tons of carbon dioxide a year which ultimately is currently being replaced by coal.

So there's a massive disconnect at policy level which we can't see pertaining or sustaining, at least not with politicians retaining any level of credibility on the subject.

So gas demand, we do think will grow in Europe.

That will have an impact on price, but strategically, quite a few things have already happened.

Fundamentally, we've moved away from all linked pricing.

It's much more hub, spot and a little bit of oil now.

Some long-term contracts, but there has been a move towards shorter contracts.

We've reflected that in the amount of both trading activity, the amount of investment we make in new European production, and fundamentally, not looking, certainly, in the medium term to be making any investment or strategic push towards bringing LNG into Europe.

As of when the policy unwinds itself in a more rational fashion, then we will be well placed to do that, particularly given the additional LNG volumes that we now have in the Atlantic Basin.

But our focus primarily in gas markets is on North America and Asia-Pacific and developing new LNG markets in emerging economies such as Southeast Asia and Latin America.

Thanks, Simon.

Okay, can I have the next question, please?

Anish Kapadia from Tudor, Pickering, Holt & Company.

Good afternoon.

Couple of questions from me, as well, please.

Looking at the US on conventional position, just wondering if Shell can really be cost competitive in the forefront of technology relative to some of the more niche-focused independent players in the liquids-rich shales?

For example, Shell seems to have been left behind somewhat in the Permian, and thinking about market valuations in the Permian, I was just wondering why you don't look to monetize instead?

And then the second one is looking at exploration, you clearly had some good near field success in your exploration portfolio.

But I was wondering if you could review your exploration performance in more Frontier areas over the last few years?

And then just specifically, if you can comment on results of your Gabon pre-salt offshore wells this year?

Thank you.

Thanks very much, Anish.

Simon will take the exploration question.

US unconventionals can we be cost competitive?

That's really the key question.

I think it's probably more a question for dry gas where indeed, the price setting mechanism, particularly if you sell into the pipeline market, could very well be set by the marginal operator with the more advantaged cost structure.

No.

That doesn't mean that we don't need to be cost competitive in LRS.

And a lot of the things that we have been doing over the last 18 months or so has been very much targeted at improving our cost competitiveness.

So we've talked about this earlier.

We've taken about 40% of the headcount down, or rather that's in the process of being run down in 2014.

About half to contract the staff out.

We're focused very much on equipment standardization and better procurement channels for equipment, particularly on well site equipment where we are well on our way of realizing a 30% cost reduction.

We are now getting into the next phase of central processing plant cost reductions through standardization and advantaged procurement routes.

So I think all together we can get very, very close if not in some areas better than some of our competitors, also the more so-called nimble independent competitors.

And there is a high degree of transparency in this market because everybody joint ventures with everybody else, so the way we have approached our target setting on cost take-out in this business is pretty much to see individual categories of cost, what is the best operator?

So what should the cost be if you wanted to be at pacesetting level?

And the targets that we have set ourselves, the targets that we are very much going after and our meeting in quite a few categories.

So I just want to, I wouldn't say ignore it, but I want to put to one side the argument that we cannot be cost competitive.

Now, having said that, of course, the whole cost competitive question, as I said earlier on, is much more important in dry gas.

And in dry gas, of course, you also have to ask yourself question, how can I access more value because it's not necessarily a good game to just be the most competitive operator in a cutthroat market where supply is very, very long and pricing is being set in a very, very liquid market.

So, therefore, the focus on gas is very much bifurcated into two areas.

One is Western Canada, where I do think we do hold a very strong position.

Can be a very cost competitive operator, but we will integrate it with our Canadian LNG position to make sure that we maximize the integrated value and, therefore, look at for our dry gas position as part of that integrated value chain.

And the Lower 48, yes, we just have to have top acreage, and we have to be a top producer and a top operator.

And we have to see gas prices that will make it worthwhile to invest in it.

And if you can't see all of that, then these positions will be under review, will continue to be under review, or we will see whether somebody else with a different outlook or a different appetite will be a better owner of it.

And that's basically the strategy that we have chosen and that is playing out.

Exploration, Simon?

Thanks, Ben.

Thanks for the question, Anish.

Just a reflection, you asked about an interesting specific asset there, Permian.

That's precisely one where we operate entirely with Anadarko.

In fact, Anadarko does quite a lot of the activity.

We know we're cost competitive at the drill pad.

We have to get a bit more competitive back at the ranch in the office.

NFE success, yes, we do pretty well still around the basins that we know and close to the asset, bringing on within eight weeks in the recent case, for example, in The Netherlands.

And in, certainly in Oman and Egypt, we similar to three months hook and produce [tine] post exploration.

You then flip to Frontier, I'll go via Heartland.

In the areas, the basins, for example, Malaysia and the Gulf of Mexico where we have a long history.

We've been pretty successful the last 6, 12 months in adding material volumes that we can develop either through infrastructure, or even the potential to build out new infrastructure.

So that Heartland's activity has actually been the most value adding, if not the most immediately value adding which, obviously, comes from the near field.

On the Frontier program, we spent two to three years building up acreage program, two to three years drilling it out.

It has been statistically less successful than the Heartland program to date.

We've had success in Albania.

We have, it depends how you define, obviously, Libra in Brazil is a significant step out from where we were, and we've got a remaining several basins still to target from Nova Scotia through the Black Sea, South China Sea to New Zealand.

So still a lot of activity to come.

On the specific question on Gabon, this is a two-well program.

We drilled one, we've already spudded the second, the well's on the way down.

We really need to look at both wells before we can update and give a view on the success.

So as you probably are aware, this is sub-salt, new play for us.

And we do need to look at both wells together before we can give an indication.

Okay.

Thanks, Simon.

Can I have the last question, please?

Bertrand Hodee from Raymond James.

Yes, hello, gentlemen.

I have two questions.

Two very short ones.

Your cash flow generation was strong in [H] one, near $24 billion in working capital movement.

You lack a significant contributor to that given that you've reached commercial production and that you were able to recover very rapidly some costs.

And is this kind of cash flow from Iraq sustainable in the coming year?

And the second question is, you've had also good performance on Mars B, already reaching around 40,000 barrels, 40,000 equivalent per day.

Earlier comments from Simon, if I recall well, pointed to quite a slow ramp up at Mars B before reaching plateau of 100,000 barrels a day.

Do you still expect this plateau of 100,000 barrels a day to be reached by early 2016 or before that?

Okay, thanks, Bertrand.

Simon, will you take that?

Sure.

First one, within the first quarter, in the CFFO, is about $500 million contribution from Majnoon, small contribution from West Qurna.

How sustainable is that?

Well, you may understand how the contracts work in Iraq, but basically once we reached first commercial production in fourth quarter last year, we were entitled to recover cost.

That cost shows as cash generation, the CFFO, it also shows high depreciation so the actual earnings contribution is fairly small.

The current expectation is that we will recover the approximately $2 billion of investment there over the next 9 to 12 months.

So it's sustainable for a period, thereafter it will fall back to reflect the service fee on the ongoing production plus recovery of any ongoing investment.

Now there is still some ongoing investment there beyond the first commercial production, particularly looking at gas treatment, et cetera.

Yes, there will be sustainable cash flow, but not at the level that we've seen in the first half beyond effectively the second half of next year.

Mars B, slow ramp up, we've only got, I think, three wells, three wells on at the moment.

That's entirely normal for a facility of this scale and complexity.

We bring them on one at a time.

There is an element of water flow associated with the activity both on Mars B into the Mars A reservoir and vice versa.

So there's quite a complex interplay between the two platforms over time, and very important that we do this safely, reliably and in a way where we get to understand the reservoir as quickly as possible so that we can maximize the future production in the most reliable way.

So it's still effectively some time away, the full capacity.

I have to say, we brought it on six months before we expected and the ramp-up of the first two wells in particular was pretty trouble-free compared to what could have happened, but we cannot project, this is a subsurface, things happen.

We can't project really any differently than we previously had.

So it is 38,000, 100%, 24,000 is ours in second quarter.

So it's pretty good progress so far given this only came on stream in March.

But let's see where we get by the end of the year.

The next key milestone, by the way, is Cardamom, really.

Some time, depending on how the hurricane season, the weather plays out in the next three months, but certainly before the end of year, we should be bringing the first well onto the Auger platform.

So that's the next big milestone in the Gulf.

And we look forward to sharing with you, at the next conference call, how we're going on, and also as I mentioned, at the US investor event in September.

Okay.

Thanks very much, Simon.

Thanks, Bertrand.

And thanks to all of you for the questions and for joining in the call today.

And as Simon just said, we have the investor day in New York on September 5, and I really look forward to seeing many of you there again.

The other thing to put in your diary is that we will be releasing our third quarter results on October 30.

And Simon will talk to all of you then.

So can I wish you a very good day?

For those of you going on leave, very good leave, and come back well rested and safety.

Thank you very much.

Thank you, ladies and gentlemen.

That concludes today's Royal Dutch Shell Q2 results announcement conference call.

Thank you for your participation.

You may now disconnect.