殼牌 (SHEL) 2013 Q2 法說會逐字稿

Welcome to the Royal Dutch Shell Q2 results announcement call.

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

(Operator Instructions)

I would like to introduce your host, Mr. Peter Voser.

Please go ahead.

Thank you, Operator.

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

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

We will update you on the key portfolio and strategy developments in the Company.

And of course, at the end, there will be plenty of time for your questions.

Let us start with the disclaimer first.

Firstly, on the results.

Our second quarter 2013 underlying CCS earnings were $4.6 billion, and cash flow from operations was $12.4 billion.

Higher costs, expiration charges, adverse exchange rate effects and challenges in Nigeria have hit our bottom line.

Now there are many factors driving these results; some of it the world around us, and some is our performance.

But the bottom line of all of this is that these figures are clearly disappointing for Shell and for myself.

Dividends are Shell's main route to return cash to shareholders, and we have distributed more than $11 billion of dividends in the last 12 months.

Our share buybacks are set to offset EPS dilution from scrip.

So far this year, we have repurchased more than $3 billion of shares and we're on track for $4 billion to $5 billion of buybacks in 2013, underlining our commitment to returns for shareholders.

Earnings volatility is a fact of life, and we're looking through that.

We have a long-term strategy making multi-year investment decisions, and we are delivering on that strategy, generating profitable growth for shareholders.

Now 2013 and '14 should see the start-up of a large number of new projects, of which the largest five should add over $4 billion to our 2015 cash flow, which is (inaudible) LNG and (inaudible).

We don't have oil and gas production targets.

We have retired our outlook statement on production today.

Our recent portfolio moves make a production target less and less relevant.

New place like Urepsol LNG and the Basar gas don't have any production entitlement, for example.

And overall, we are targeting financial performance at Shell.

We have built up substantial new options for the Company in the last few years, and the larger exploration portfolio.

We have reached critical mass with our 2015 plus option set, and there will be decisions to make on which options to take to final investment decisions.

We are entering a period where there will be a higher rate of asset sales; for example, in Nigeria and North American shares and in other parts of the portfolio, too, as we work through those choices.

Fundamentally, we are driving sustainable through cycle financial growth in the Company, measurable through our cash flow and we can achieve that growth through a number of pathways and production outcomes.

We are 18 months into the financial program we set out last year, and there is no change to those targets, $175 billion to $200 billion of cash flow from operations for 2012 to '15 combined, in $80 to $100 oil price scenarios, and we have delivered $70 billion of CFFO the first 18 months of that program.

Now before Simon takes you through the numbers, let me just make a few comments of Nigeria.

We have seen a marked escalation in security problems and theft in Nigeria in 2013.

The SPDC joint venture has had shuttings on major oil pipelines and the gas pipelines that feeds the Nigerian LNG plant, due to sabotage.

This has all been compounded by tax disputes between the Nigeria LNG joint venture and the Nigerian Maritime Administration and Safety Agency, which resulted in a blockade on exports from LNG for 23 days, ending on the 13th of July.

Oil theft and sabotage in Nigeria are resulting in substantial revenue loss for the Nigerian government and widespread environmental damage.

On an annual basis, this could actually be an earnings loss of $12 billion for the Nigerian government and society.

For Shell, we had a second quarter 2013 shortfall of around 100,000 barrels of oil equivalent per day, 150,000 tons of LNG, and at least $250 million of lost earnings as a result of all of this.

Now, Shell and our partners are all working with the government of Nigeria, as well as foreign governments on solutions to what seems to be an endemic issue.

Now we at Shell will play our part, but we cannot solve this on our own.

Now with that, let me hand over to Simon on the results; and I will then come back on portfolio and strategy.

Over to you, Simon.

Thanks, Peter, and good to talk today.

I will start with the macro environment.

If you look at the macro picture compared to second quarter 2012, Brent oil prices were $6 lower than a year ago, narrow differentials between Brent and the North American market.

Our own realized liquids prices declined by around $10 per barrel, Q2-to-Q2, so that's more than the markets; however, our natural gas realizations increased from a year ago.

On the downstream side, refining margins were weaker in Europe and the Gulf, slightly higher in Singapore, and about the same in the West Coast.

And North American margins were reduced by the narrower WTI differentials.

In Chemicals, margins declined from year-ago levels, thanks to weaker industry margins in Europe and turnarounds in our own operations.

Now quarterly results are important -- and this is a phrase you'll recognize after the first quarter -- whether they're high or low.

But they are really just a snapshot of performance in the volatile industry, and we are implementing a long-term, through-cycle strategy.

Second quarter CCS earnings, current cost of supply, excluding the identified items, were $4.6 billion.

Earnings per share decreased by 21% from second quarter 2012.

Our reported CCS earnings included $2.2 billion of identified items.

Now these are at Danstream in Italy, where we announced the intention to sell assets, but much more substantially in the upstream Americas business with an impairment at some of our liquids-rich shale positions.

That reflects the latest insights from drilling and production data.

In a lot of ways, this is similar to an expiration write-off.

The clean depreciation in the quarter was $3.9 billion.

Now that's some $2 billion higher on an annualized basis compared to 2012, due in part to IFRS-11 effects, but also new project ramp-ups and the amortization rates on the resource plays.

Now the ongoing depreciation will not be significantly impacted or decreased by the second quarter impairment, because we've also increased the amortization rate for the non-productive leases as we go forward in the North American resource plays.

This reflects increased subsurface uncertainty following the recent drilling results, and that effect offsets the reduction in depreciation on the impaired assets.

The second quarter 2013 DD&A also included an impact of $80 million for a catch-up effect in non-producing lease amortization, and that was not taken as an identified item.

We announced a $0.45 per share dividend for second quarter 2013.

That's 5% higher than a year ago.

The share buybacks in the quarter were $1.9 billion; and as of last night, we were at $3.2 billion year-to-date.

Remember, we're using those buybacks to offset the dilution from the scrip dividend.

So we've more than just offset the likely scrip dilution for the year.

Headline oil and gas production for the second quarter was 3.1 million barrels oil equivalent per day.

That's an underlying increase of 2%, excluding the impact from Nigeria, from PSC price effects and from divestments.

Volumes were supported by growth from Pearl Gasto liquids Pluto LNG project in Australia.

But the Nigeria security problems reduced production by some 65,000 barrels per day on a relative Q2-to-Q2 basis.

We had some 40,000 barrels a day of Q2-to-Q2 maintenance and performance impacts, that's negative, and that was spread across a number of assets, such as oil sands in Canada, the UK North Sea and the Brazilian deepwater.

Also, continued impacts in the Mars corridor for the Mars B hook up.

The Gulf of Mexico production overall was similar on a year-versus-year basis.

This quarter's production was also reduced by 30,000 barrels a day from a reclassification of royalty entitlements, and that impacts reported volumes on an ongoing basis and going forward, but has no impact on current or future earnings or cash flow.

LNG sales volumes were up 2% Q2-to-Q2, driven by the growth in Pluto in Australia, but partly offset by the Iran 150,000 tons a day lost in Nigeria, where the feed gas supply was disrupted by the security picture and also by the blockade that Peter mentioned.

In the downstream, chemicals and refinery availability are both similar to a year-ago.

The sales volumes were impacted by accounting changes and divestments, although the underlying sales volumes of oil products did decrease as a result of lower trade-in volumes, while the chemicals product sales decreased as a result of maintenance activity in Europe on our own efforts and expiring contracts.

Otiva in the US ramped up refinery production from new facilities at the [Gos Alvery] refinery.

And that's close to capacity now during the quarter, but we're still looking forward to a higher financial contribution there.

Now this chart shows you the main drivers of the results this quarter compared to 2012 Q2.

The macro environment overall was broadly neutral.

Looking at upstream and downstream margins, the uplift from the LNG joint venture dividend receipts.

So the results were impacted by a series of external environment factors that were in aggregate a $0.7 billion negative for shareholders.

That's the lost revenues in Nigeria due to the sabotage and the blockade of LNG; but also, an increase in the deferred tax liability, which is a foreign exchange effect, due to the weaker Australian dollar.

Growth projects and the portfolio mix made a positive year-over-year impact; obviously, with a strong contribution from QTL in Qatar.

The underlying depreciation and amortization increased by some 20%, driven by upstream project ramp-up, acquisitions, and expiration and abandonment provisions.

Expiration charges were $1.2 billion pre-tax, and increased in line with our higher expiration expending overall, and a higher level of well write-off in this particular quarter in Egypt, in North America, and in French Guyana.

Operating expenses increased by 9%, primarily in the upstream, and that's with increased costs for maintenance and for growth in the portfolio in general.

Feasibility study costs for the new options, such as carbon creek, gas monetizations options in the Americas, [Mashnoon] in Iraq, Abadi, Indonesia, and [Bonda] Southwest in Nigeria, they totaled around $400 million pre-tax in the quarter.

You might remember that the bulk of our Alaska spending is being expensed this year rather than capitalized, simply because we're not drilling.

This charge, around $90 million post tax this quarter, comes through as an operating cost.

You will see some pointers for the third quarter on this slide, too.

Let me highlight, in the upstream, we are expecting similar expiration charges to the second quarter of about $1.3 billion, under our continued impacts from the Nigeria security and LNG blockade.

We're expecting 35,000 barrels a day of higher margin maintenance and asset replacement impacts Q3 versus Q3.

These include the [Orga] platform in the Gulf of Mexico, where there's a hook-up underway for the [Cardamon] tieback, but also at the BC-10 project in Brazil, and several North Sea fields.

This is normal planned turnaround activity, but higher than last year.

In the downstream, refinery availability overall is expected to be in line with Q3, 2012, and that includes the turnaround at Scottford in Western Canada, and the chemical's availability is actually expected to increase.

So those are the comments on the earnings, and they're moving on to the cash flow.

Cash generation on a 12-month rolling basis was some $47 billion.

That includes $3 billion of disposal proceeds.

That's against an average Brent price for the 12-month period of $109 per barrel.

Both upstream and downstream generates its surplus cash flow, although the surplus for upstream has declined somewhat.

The free cash flow, that's cash generated less investment, was $3.3 billion in the quarter and $9.3 billion over the last 12 months.

For obvious reasons, we're managing this cash cycle very closely, particularly in the volatile macro that we see.

Now a number of you have asked us for more details on upstream America's financials.

This slide is a snapshot of the key metrics that hopefully will help.

On a Q2-to-Q2 basis, the underlying earnings fell from around $100 million of profit to some $300 million of loss.

We saw 30,000 barrels a day lower volumes from the highly profitable deepwater, around 10,000 barrels a day reduction in heavy oil, some 60,000 barrels per day higher production from the shales.

So the net result is higher volumes overall, but with growth in lower margin production.

In addition, there was a $750 million pre-tax increase in costs, DD&A, and well write-off.

Taking a longer-term and more strategic look at this, I think it's important to say that we're not -- we're managing these businesses, the three businesses there, in their own right, and we're not running the portfolio to drive a particular upstream America's P&L outcome.

The upstream Americas business did generate $5 billion of cash in the last 12 months, although with negative free cash flow after investment and earning slightly negative.

The deepwater business is making solid profits, and we have seen falling production there as a result of Macondo delays and the more recently, the downtime at [Marzen Orga], as we work on the hook-ups for the new projects.

So that's resulted in a shrinking contribution from the high margin deepwater field in the Gulf, where production in '09 was around 250,000 barrels oil equivalent a day, and was 177,000 barrels oil equivalent per day in this quarter.

The Gulf of Mexico volumes are likely to remain low in the second half of 2013; however, this trend should reverse during 2014 and '15, with the new growth from Mars B, then from Cardamon and later on from Stones.

The three projects alone are a total of around 170,000 barrels a day out peak for Shell, and this is an important earning and cash flow driver for us.

Looking at heavy oil, also currently profitable, but with less near-term top line growth.

The focus here is, as we said before, current operating performance, de-bottlenecking capacity and controlling the costs.

Resources plays, that's the shales, we are seeing the impact of low gas prices, but also, the start-up costs, the expiration charge and the effect of the higher lease amortization.

It's not unusual or unique to Shell to see this kind of financial profile in the growth business.

Feasibility cost category mainly covers pre-FID options, such as integrated gas projects and particularly, Alaska.

So these are basically the options for the future.

Under the current macro conditions, we expect the upstream America's business to remain in a loss for at least the second half of 2013, as resources plays losses and the ongoing fees ex- outweigh the profits we expect in the deepwater and the heavy oil.

At growth in the oil production, which should come from deepwater and from the liquids-rich shales, should drive a return to profit in 2014, although upstream Americas is in and will remain in a growth mode.

So this will fundamentally be a cash flow story for Shell, rather than earnings, for quite a while to come.

Let me update you on the progress of the portfolio in the quarter.

We made more progress with accessing new investment opportunities, and we're working the portfolio hard to drive capital efficiency.

In the upstream engine, we were selected to develop the Bab Sour gas fields in Abu Dhabi.

We're adding new options and equity in integrated gas, and we've made new discoveries and taken new FIDs in deepwater and in Nigeria this quarter.

In July, we announced the final investment decision for the BC-10 phase 3 deepwater project in Brazil and a redevelopment at [Bijupira Salema] in the same country.

Peter will give you more details in a moment, but we also have launched strategic reviews of our Nigeria onshore and our North America resources, or shale, portfolio, both of which should lead to more divestment income and more focused investment spending going forward.

Turning now to the financial framework, our business strategy aims to grow cash flow on a sustainable basis through the macro environment cycle.

We have clear targets for financial growth, underpinned by consistent and appropriate capital investment that is subject to strict investment hurdles.

All aim to add value for shareholders, and the balance sheet itself underpins this overall financial framework.

We've delivered $70 billion of cash in the last 18 months; $63 billion, excluding working cap.

And in the same period, we've invested $49 billion on a net basis.

You can see, chart on the left, the red line, the free cash flow has grown in the last few years from a negative position 2009, to $9 billion over the last four quarters.

The gearing is now down around 10%.

Let me just say a few words on capital spending.

So remember, we're in an 18-month program, or we're 18 months into a four-year program; and that requires us to invest up to $130 billion on a net basis.

And that's driving the cash flow growth.

Any given quarter, or indeed any given year, is only a snapshot of where we are in that longer-term trend.

We've taken on incremental new projects this year, where we see good opportunities above what were our base plans, and those include Elba Island LNG exports in the US, the gas to transport project, also in the US.

We're investing in projects offshore like Stones, which is effectively now in a 100% basis, rather than a lower percentage.

In addition, we're making good progress with the Repsol transaction, which could close in the second half of this year, and that's earlier than we had expected.

But putting all of this together, we are expecting net spending for 2013 to be around $40 billion.

This figure includes around $3 billion of non-cash items, such as FPSO and LNG ship leases.

Asset sales, divestments, could reach $3 billion this year, and that depends -- the actual figure will depend on the timing of one or two transactions we currently have in hand.

And as Peter told you, asset sales will increase in the 2014-15 period.

We don't have detailed guidance for you at this stage, but it's likely to be towards the top end of the asset sales range that we delivered in the last three years, and it's all part of managing the net spending around $130 billion in the '12-'15 period.

As you know, the dividends are our main route for returning cash to shareholders.

The scrip dividend uptake in the second quarter was 28%.

We'll be offering scrip dividend again for the Q2 dividend, but 28% is about the going rate, which is, on average, 30%.

We've increased the pace on the share buyback program this year, which is designed to offset the scrip through-cycle, and we've already spent $3.2 billion on buyback so far this year, so just about offset the likely scrip dilution for the year.

And we remain on track for the $4 billion to $5 billion buyback program that we previously announced.

With that, Peter, back to you.

Thanks, Simon.

Let us look at the strategy.

We are driving investment and innovation in Shell 's human resources, along with years of strategic themes.

Downstream and our mature upstream positions, we call them our engines, generate strong free cash flow for the Company today.

The growth priorities are in integrated gas, in deep water and in resources plays, shales.

And we have good positions in longer-term plays like heavy oil, Iraq, Kazakhstan and Nigeria.

We have built up new options, more choice for where to invest our dollars.

And by implementing hard capital ceilings, we are driving tough choices in the Company.

As I said before, Shell is capital constrained rather than opportunity constrained, and there will be choices to make as we take final investment decisions on some of these options and exit or dilute others.

Let me update you on progress in some of our strategic themes.

Let me start with deepwater in the Gulf of Mexico.

We took FID, final investment decision, on March 3 during the Macondo moratorium in 2010.

Because we saw a cost opportunity, our Mars B now is making great progress.

The tension lake platform was floated out to the field in July, and we are firmly on schedule and on budget here.

In May of this year, we took final investment decision on another deepwater field, which is Stones, and Simon has mentioned it.

This is Shell's second lower tertiary development in the Gulf, and our first FPSO there.

Stones has substantial upside potential from the application of innovative technology.

The field is estimated to contain more than 2 billion barrels of oil in place.

The first phase of development is for 50,000 barrels per day from more than 250 million barrels of recoverable resources.

Let me update on you the resources plays in North America shales.

We are making some important decisions on what I am convinced is going to be a success story for Shell.

Exploration in shales is a dynamic activity, with production at an early stage of the cycle.

We have built a substantial position here, with some $24 billion for North American resources plays on the balance sheet.

We are now entering a period of focusing our portfolio down to our best liquids plays, whilst maintaining key dry gas assets for longer-term integration value.

We have some nine operational theaters in North America.

I think you can take it that this will reduce to about half that number over time, as we focus down this portfolio by growing our business.

We expect to see a step-up in asset sales for North American resources plays in the next 18 months.

Now we have reduced spending overall in this theme, with less activity on dry gas and more in liquid switch plays.

There may be some further small acreage built around our core assets or areas to achieve our desired scale, but the major acreage deals are behind us now.

So let me turn to our long-term plays in Iraq, Nigeria, and Kazakhstan.

We are pleased to update that the Basra joint venture in Iraq is up and running.

This JV uses (inaudible) gas that would otherwise be flared from oil fields and converted to LPG and natural gas for local customers.

In Nigeria, this remains a complex and difficult environment for the international oil companies.

SBDC's new investment has been focused on pipeline upgrades to reduce sabotage and theft, flares and flares reductions, feed gas for LNG, and some selective oil projects.

SPDC has been divesting part of a joint venture portfolio, concentrating its operations into a smaller, more contiguous area, and supporting the government's policy of encouraging investment by indigenous companies.

Since 2010, Shell has sold its 37,000-barrels per day interest in eight SPDC licenses, for a total of $1.8 billion.

We have recently launched a review of Shell's interest in SBDC's licenses in the eastern part of the delta.

This could result to in divestments of some 80,000 to 100,000 barrels per day Shell share of production, as we continue to refocus the portfolio.

Let me turn to Kazakhstan.

We are expecting first oil production from the [Kashigan] field in the second half of '13.

This is a giant field, 3 billion BOEs are being developed in phase one.

This is a two-train development that will be ramped up over a two-year period to the design capacity, with an average 300,000 barrels per day production plateau.

KMG and Shell have been delegated to jointly manage production operations of all phases.

Handover of the assets to production operations will take place once stable production has been reached.

Kashigan is one of a series of large new start-ups in Shell in 2013 and '14.

The five largest of these projects, out of 17, you can see them on the slide, should ad between $0.5 billion to over $1 billion each to our cash flow, or over $4 billion in total, once they are fully on stream.

These five start-ups will mark another growth step for the Company, and we are entering an exciting delivery phase here.

Now with that, let me summarize for you.

Earnings volatility is a fact of life, and we are looking through that with a long-term strategy, making multi-year investment decisions.

We make capital allocations decisions on a global basis, investing in the best projects, taking a value chain approach, and redesigning or exiting from positions that don't meet our return and materiality thresholds.

We have distributed more than $11 billion of dividends the last 12 months, and we are on track for $4 billion to $5 billion of buybacks in 2013.

All of this underlines our commitment to shareholder returns.

With that, let's take your questions.

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

With that, Operator, please poll for questions, and Simon and I are happy to take them.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Let's do the first question.

Theepan Jothilingam, Nomura.

--talk about why the change in view, in terms of for 2014 and 2015.

And just a point of clarification on that, if the asset sales go up, does that mean then the investment number goes lower?

And then in that context, have you got a new target range on where you think capital not in use should be for the Shell group?

Thank you.

Okay.

I think you didn't come through at the begin, but I think we got the question.

It was all about the CapEx for 2014-2015 and the asset sale.

So I'll pass that on to Simon.

Thanks, Peter.

Thanks, Theepan.

The one target that we have outstanding, the CFFO delivery over four years and the net Cap Ex required to deliver that and future growth, remain unchanged, so $175 billion to $200 billion.

$80 to $100 oil price remains the expectation and the intent, and up to $130 billion net capital investment also remains the intent.

What we're seeing this year is extra projects coming in and ahead of dilution or divestment.

What you hear around the strategic reviews in North America and Nigeria is the expectation that the divestments will kick up above the divestment level.

But we previously stated we expected that the organic capital would be in the mid-30s; that would meet that overall balance financial framework and there's no real change to that guidance today.

This is a four-year program, through-cycle delivery, to have sufficient free cash flow to grow the dividend, to offset the dilution from the script.

But also to invest at a level that creates sustainable growth in the cash flow going forward for years to come, which will support continually growing dividends.

That's the structure and no change to the targets within there.

And there's no real point in talking about individual moving parts, Theepan, on the grounds that this is a four-year program to balance the cash in and out.

Thanks, Simon.

On to the next question.

Martijn Rats, Morgan Stanley.

Two questions for me.

First of all, looking at the delivery of operating cash flow so far, over the last -- excluding working capital, the last 12 months you've seen $40 billion already in cash flow delivered versus the $50 billion a year run rate implied by the $200 billion target.

I do appreciate that the Repsol deal will kicked in and that there are five projects, each delivering around about $1 billion, or even slightly more, of operating cash flow at some point.

But did the gaps between the last 12 months at $40 billion and the future at $50 billion still seems quite large, even in that context.

Can you provide a little bit more detail on how that will ultimately be bridged?

And the second question that I wanted to ask relates to the impairments in the US.

I was hoping you could a little specific on exactly which basins and what regions and what plays have led to the revision in the asset value.

I take the second one and Simon takes the first one.

Thanks, Peter.

Thanks, Martijn.

There's one specific issue, if you go to 12 months rather than 18 months, and that is the tax payments versus tax charges, some of which is related to the tax payment on divestments and some of which is just timing related to last year's profits, as opposed to current year profits.

So that's a $3.5 billion movement year-on-year in the quarter.

And working capital, of course, will remain flat or reducing from various structural activities and a more flat macro; and the real world, everything in, is $70 billion, six quarters.

We know we could have done better in some operational areas behind us, but there is a lot of growth to come ahead of us.

We talk about the 5 projects, that's 5 out of 17.

The overall project growth is expected to deliver with 74, $9 billion of cash flow growth, 2015 versus 2012, and there are performance improvements, as well, in addition to that.

So it was always a steady growth through the program, and that's what we remain on track to deliver, give or take some of the operational incidents we've talked about.

And Nigeria doesn't help, obviously, but it's a relatively small number compared to 200, and the ambitious target, we remain in place and that's the intent.

On your second question, let me first say in general, we are driving an expiration appraisal acreage on the LRS side, and therefore, it is normal at this stage that you focus on your best reservoir.

Perhaps you add, as we have done over the last two years, some new acreage and you actually move on when the plays are not as successful as you want them, and specifically, if they are not scalable to the extent we would like to have.

And that's really what we have done over the last few months looking at the portfolio result, the well results, which ones are working, which you have to scale, and then actually we have taken some write-offs.

But we are moving the portfolio down from 9 to 4 areas.

So some of the things will have to go.

That's where the asset sales come in.

We have had a very rapid growth, and therefore, we had a lot of new well results, and this has all led to this one.

Now I am not going go basin by basin what goes and what stays on.

I think you will understand this is commercially interesting for us to keep that to ourselves, and we will drive it that way.

But all in all, I think, we are seeing very positive areas for us.

We are driving those, and that's where the investments will go in.

Just to give you some investment numbers, we had $9.9 billion of CapEx last year.

This year, it's around $ 5.7 billion, and it's roughly 60% LRS and 40% is dry gas.

That's how we are driving the change from gas into LRS, quickly assessing, moving away when it is not to our scale and focusing on those which we want to keep.

I think I'll leave it at that.

Operator, next question.

Iain Reid, Jefferies.

Hello.

Good afternoon, guys.

I was wondering, given the focus you've got on cash flow rather than production, whether you're considering reducing your Cap Ex going forward, taking your foot off of the pedal perhaps.

And some of the options you were talking about, Peter, for 2015 onwards, and giving a hard ceiling, if you like, to Cap Ex or even reducing Cap Ex somewhat.

And I'm accepting the fact that perhaps future production might be a little bit lower.

Is that the kind of option you've thought about in the strategic delivery that you've been talking about here?

Thanks, Iain.

I think over the last few years, we have talked quite a bit about increasing our optionality in the funnel, so that we can actually drive harder choices in terms of returns.

But also when we do this actually through a hard capital ceiling, which we drive internally, Simon explained on how this all fits together with the financial framework.

And in that sense, we are driving the $130 billion next capital for the four years.

We are very careful of letting the right projects come through for the post- 2015 growth areas.

Now the one thing I've learned over the last four years to predict CapEx three, four years out, that is always a quite challenging thing to do, because it has a lot of macro and other impacts, and lower price and gas price impacts, et cetera.

I think I would just leave it at that stage, at this stage, that we are driving the return and the discipline very hard, and therefore, we are driving growth in cash flow.

And as you know, our production target in the past, we always called a proxy for cash flow growth.

Now in discussions with all of our shareholders, we have clearly come to the conclusion that working on our portfolio and getting some assets up for sale and actually dropping the production target and focus on the cash flow growth target is what is wanted by the shareholders, and that's what we are driving.

So I think what you will see going forward is a very hard focus on the right projects coming through, and others will go out, those will give us cash flow even today, because they are less profitable in going forward.

And that -- out of that, you will get as a consequence, you will get the capital numbers, which benefit into our financial framework.

I think I will leave it at that, rather than forecasting ups and downs on capital.

Because even three years ago, when we said we are coming out of our big projects, we never said we are going to reduce capital, because we see profitable growth.

And that's just about now to come again with our big projects and the cash flow growth.

So I'd rather have the discussion around that.

So thanks, Iain, for that.

Next question.

Irene Himona, SG.

Yes.

Good afternoon.

You signalled that North American upstream is likely to remain in losses, at least for the rest of the year.

You've also switched to financial targets only.

In the first half this year, return on capital is down.

I wonder if return on capital is a financial target, or whether we should anticipate that to continue to weaken.

And I also had a question on exploration, if I may.

Your budget is $7 billion a year.

We've had some disappointments in French Guyana.

Can you talk a little bit about exploration results in the first half and what high impact wells you're planning for the rest of the year?

Thank you.

Okay.

Thanks, Irene.

I think I give both to Simon.

But I take, on the first one, just from a strategic point of view, yes, returns is part of our financial target set, which we are driving internally.

We have been quite clear that we are on the path of increasing our returns.

You can measure those returns on average capital employed.

That's a medium long-term target which we have and we drive that, clearly inside.

It's not an external target, because I think the financial framework targets which we have, actually the ones which are driving our overall returns to the shareholders.

And with that, more details on the first one from Simon, but then also exploration.

Thanks, Peter, and thanks for the questions, Irene.

The returns growth balance is something that is easy to talk about in terms of strategic themes, and it is for Shell, overall.

Technically, we don't have an overall return target; we do have a cash flow growth target and we do have a capital investment constraint.

So for Shell as a corporate entity, if the cash flow growth is delivered and we only invest the program of the 130, then by definition, returns will go up by a couple of percentage points, whatever the macro environment is.

There is an imbedded returns target, but not an explicit returns target.

And there is a clear linkage.

ROICI is not an independent metric.

It would be the wrong thing to do make it so, either, because ROICI is essentially delivered by at least as much by portfolio choices, if not more by portfolio choices, than it is at the individual assets or project level.

Within the main strategic themes, clearly the upstream engine, the mature business, is a very high return business, the downstream is a returns focused business.

You've heard us say that before.

It will continue to be.

And returns are slowly beginning to adjust there.

The deepwater, the integrated gas, they're growth areas, but they already have good returns, 15% plus.

The aim there is to grow and maintain the returns at that level.

The future opportunities, the Iraq, Nigeria, Kazakhstan, heavy oil, at the moment the returns are relatively low there, but there is a program in place or projects coming on-stream that will make a difference there.

And just following up one of the earlier questions.

The capital not currently productive is about $65 billion.

In the next few -- couple of quarters, the projects that Peter talked about, the five projects, will bring over $15 billion into productive use that is currently on the balance sheet and not yet in production.

So over time, the delivery of one target leads to improvements in other metrics, and that's how we think about it.

And the exploration program, $7 billion per annum, is $4 billion on the conventional activity, $3 billion on the unconventional, of which about $2 billion is in North America, $1 billion is in, well primarily China, of the latter.

So unconventionals first.

China, we progress.

We can see, beginning to see line of sight to economic developments.

Requires costs to come down a bit.

Better knowledge of the production rates in the reservoirs and a clear view on the gas price.

But progress is positive.

In the North America itself, on the exploration side, you can tell from the results that we've produced that there have been some pluses and minuses.

Almost all that activity is actually on the liquids rigs side at the moment.

So some of it has not been successful, but some have.

And obviously, you'll see development there going forward.

On the conventional side, we've had successes so far.

We've talked about Australian gas in Vicksburg in the Gulf of Mexico, which will certainly help the economics of the Appomattox development.

Second half, coming up, we have Albania, where we're on production tests at the moment.

We're drilling in Basra for gas on the Queen and current wells in the Gulf of Mexico, they're both oil targets.

We are about to spud, I believe, in Benine deepwater, when the rig there will then move on to Gabon deepwater in the second half.

That's the subsalt prospect, West Africa.

Those are the key prospects with a potential high impact, as we are headed forward through the year.

There is more also in Australia and in both Brunei and Malaysia, and we've just taken new acreage in the North Sea.

So it's a very full program over the next couple of years that we look forward to sharing with you the outcome.

Thanks, Simon.

Thanks, Irene.

Next question, Operator.

Hootan Yazhari, Merrill Lynch.

Good afternoon, gentlemen.

I just wanted to focus on the North American business, if we may.

First of all, I wanted to understand whether there had been any price reviews in your impairments with regards to North America?

And given where we are with liquid-rich shales pricing, if you haven't looked at pricing, whether there are any risks when you have undertake any reviews there, for further impairments.

The second thing I wanted to see is really how the asset disposal program in the North American onshore business will interact vis-a-vis your onshore strategy in the downstream, i.e.

with regards to gas-to-transport, LNG and GTL, whether you're having to accelerate any decisions there to get more clarity in what assets you can sell and the like there.

Any clarity there would be much appreciated.

Thank you.

Thanks, Yaz, for the questions.

Simon takes the first one.

I take the second.

Thanks, Peter.

The pricing expectations for gas have changed, but mainly, that was an impact in 2012.

Q3, we took smaller impairments, by $600 million in Colorado and Louisiana that reflected a lower expectation for gas prices.

The recent impairments, the current impairments, they are driven more by understanding of the asset based on drilling results, both what it tells about the subsurface, but also the production rates that we've been seeing.

And where they've not mapped out to expectations, and that's had an impact on potential development projects.

Clearly, that also reflects the lower price that we reviewed last year, and our latest expectation for the realization of prices of liquids themselves, NGLs, condensate or whatever, within the North American continent.

So it's primarily driven by operational results, not price reviews this year.

What happens in the future?

Well, some of the portfolio remains exploration, with some appraisal to go.

We have done a soup-to-nuts review of the entire portfolio, almost molecule-by-molecule, over the last six months.

This reflects our best view, taking values either at the current value in use or the potential sales value.

Nothing is being written off to zero.

It's held at a value we see appropriate.

And as we go forward, we're still subject to exploration results on some parts of the portfolio.

But the $24 billion of remaining capital employed as of today, looking forward, has sound economic development prospects.

Peter.

On the second one, I think you need to distinguish in the divestment strategy between gas and LRS.

So we'll be announcing today is more focused on LRS rather than gas.

The integrated projects which we are pursuing, which is gas to chemicals, potentially gas to liquids, and gas in transport and also LNG exports, some of them are already under design construction, which is more on the LNG and the gas-to-transport side.

They continue as normal.

We're looking at, or moving forward on gas to chemicals and gas to liquids, at the normal pace, so no acceleration.

We just do that, which is by the way, one of the drivers of the higher feasibility expenditure which we have in the Americas.

Then once we take those integrated project decisions, then we will look at the gas molecules again, we'll decide how much is third-party, how much is owned gas molecules, which you will use.

And then we take it from there, in terms of upstream assets.

If nothing goes forward, then we will have another close look on what we do with our own gas assets in that sense.

That's pretty much our strategic theme at the moment, and we'll get -- we are moving forward on all of these for the time being, and we'll get to a decision points over the next 12 months to 18 months.

Thanks for the question.

Next one, Operator.

Peter Hutton, RBC.

Hello.

Thanks for the question.

Can I just ask on the status of two areas, really, Pearl, and that was ramping up and I think was at full capacity for the quarter.

Gas volumes in Mina were up 33%.

Now as we understand it, volumes -- those volumes of Mina gas are amongst the higher margins, particularly in Pearl, but we saw profits down.

Were there any specific costs relating to the final start-up of Pearl, or is this underlying profitability in Q2 as we would expect to see that going forward?

And the second question is can you give an update on the status of the repairs to the Kulluk rig in Korea?

I think you may need up to 12 minutes to get permit.

So for summer drilling in 2014, it's starting to get on the critical path.

So visibility on the availability of the Kulluk's coming more to the fall.

Thank you.

Okay.

Thanks for the question.

Start with the second one.

There is no update at this stage on Alaska, as I say, we are not drilling.

We are waiting for some of the reports out of the external and internal investigation in order to take the learnings.

The Kulluk is, as you say, over in Asia, like it's the disco, the discoverer, and this will be assessed in parallel in order to actually get to the right decision towards the end of the year.

The permitting of all of this will play a role, but remember that both were actually permitted previously, and therefore you have caught a certain advantage, because of that fact that they were permitted.

On Pearl, I think we are progressing well, but Simon may have some numbers there, as well, but I think we are ramping up.

It was a good second quarter; and from that point of view, I think we are satisfied that we are working ourselves up to the capacity rates.

But Simon may have some numbers on that.

Thank you, Peter.

We built on the gas out projects in Canada of over 400,000 barrels a day potential, and that's where we are, similar to the first quarter.

It was a good quarter, operationally.

The comparative quarter a year ago, unfortunately, we had quite a serious fire incident on one of the air separator units, you may remember, so we had relatively high downtime a year ago.

And that's one of the reasons for the step-up year-on-year.

But so far, the progress has been pretty reliable.

There is still more we can squeeze out of the margin in terms of availability, but we're on track for where we expected to be this quarter.

Thanks, Simon.

Next question, Operator.

Jon Rigby, UBS.

Yes.

Thank you.

Two questions, actually.

The first is on your cash flow targets that you've got now, can you perhaps just go back into them and tell me what needs to go right and what needs to go wrong.

Let's hear really around the risking going forward to meet what you need to do, i.e.

what big levers are still left.

And then second, just going back to the removal of the production target, you referenced the fact that you'd made choices, value choices, to go into things like Iraq and the Repsol LNG that didn't have production attaching to them, which is fine.

Can you maybe turn it around the other way and say what in the last 18 months have you chosen not to invest in the upstream that would have contributed to make that formerly [barrel] targets in 2017, 2018?

Thanks.

Thanks, Jon.

I'll start with the second one on the production target side.

I think apart from having invested in a few areas like you have mentioned, like Repsol, like gas, we also have, as you heard today, increased our potential divestments, which will have an impact in that, as well.

I think over the last 12 months, we have not made the choices which obviously would have put the target on the race, but we have clearly slowed down in a few areas.

But we have actually also accelerated in a few other areas.

But I think what comes to mind is we already took very tough positions on postponing or getting out of projects, like in Arrow.

We postponed, because of the high prices.

We took a slower kind of development in some of the North Sea projects.

For example, one in Norway and another one further down there.

So we have actually slowed down projects, in order to not spend into the high areas.

They would have had production, but we had other things coming through, which would have delivered the cash flow, because remember, we said it's a proxy for cash flow growth, quite clearly.

We have invested in LNG and transport, which we see as a long-term business, which again will give us mainly margin and cash flow, rather than the other things, like production volumes.

The last one I would like to mention is we have clearly taken the decision to move from gas to LRS.

And we made it very clear, therefore, we have deliberately slowed down the gas side, which would have delivered a lot of gas volumes over the years to come.

We switched into an exploration appraisal strategy on the LRS, and we have now taken even some further pace out of that by focusing more.

And that, obviously, also has an impact, and that was, again, was an economic choice behind it and the results are rationalization going on there.

So I think there are plenty of things which we have done over the last few years like postponing, refocusing strategy, investing in non-barrel producing type of deals, which have obviously given us, let's say, a good reason now to take that off the table.

But the major one is still that we have good discussions with shareholders.

And they clearly focusing on financial performance over the years to come is the preferred scenario, because there was a perception we are chasing revenue targets, and that's not what we are doing.

We are chasing value targets in the bottom line.

With that, over to Simon on the cash flow.

Good segway.

The financial targets.

Thanks, Jon.

It's best to give a full-year update, really, when we get to the end of the year and have some more clarity.

But some indicators, as you asked, hopefully will help.

First of all, the five projects that we noted.

The ramp-up there and the successful delivery over the 2014, 2015 period is quite key.

There are a bunch of other projects, as well, such as Maginine projects in Italy, Malaysia, et cetera, that will also come on.

But fundamentally, those are the bigger plays.

It would help to execute clearly this switch into the right development projects in the shales in North America, and ensure that we generate cash from those.

And that's again, what we filled today.

That's on the growth side.

Embedded in our targets are improvement in performance, underlying performance, particularly in the downstream.

Now there are some very strong signs in the performance.

Cash flow, excluding working cap, as we roll forward every 12 month period, the downstream is slowly but surely delivering those.

Although there's also an imbedded expectation of some up-tick on the refining margin environment, as well.

That ability to capture those additional refining margin opportunities is very much part of the delivery, what we need to deliver, particularly in North America and then through Motiva.

So a combination of improvements, a combination of right focus in the investment, but primarily, it's the deliveries safely and successfully of the projects that are already in late stages of completion and ramp-up of production, as expected.

Hopefully, that helps things to watch for.

We're not dependent at all, by the way, on any exploration success.

That's for the next period.

Thanks, Jon.

Next question.

Lydia Rainforth, Barclays.

Thank you, and good afternoon, gentlemen.

A couple of questions, if I could.

One, just a follow-up on Jon's question, really.

Are you now starting to look at there being an optimal size for production in terms of the Shell group?

And then secondly, just going back to the North America and the Nigeria divestments that you're looking at, can you give an indication of how long you think it will actually take to execute on that plan?

Thank you.

Okay.

I start with the second one.

I think I mentioned Nigeria and North American divestment, specifically, but I also said, and others.

So I think you should not actually just focus on those two, there is more in the pipeline, quite clearly.

And as we have to make choices and as we already made choices, they are now coming into the frame over the next two to three years.

So I think if you look forward, your divestments will be accelerated and higher in the time frame 2014 to 2016, and therefore, you have to look at those years.

Because as you know, you can predict a divestment, and then it comes, instead of the 20th of December, comes the 10th of January and you miss a year.

So we cannot plan it as exactly like that.

But over the next few years, you will see that acceleration, given the fact that we have a very long portfolio option pipeline now.

And we have got these projects coming on-stream.

So our cash flow visibility and the growth of it over the next few years.

And also, the outlook of post-2015 in terms of cash flow growth through the new project coming on-stream is now higher, and hence, we can actually take some tougher choices in terms of what stays in the portfolio and what doesn't stay in the portfolio.

On production, internally, production will still be a key figure, which we are looking at.

As I said, we are value-driven and not absolutely top-line driven, so I don't have kind of a matching production number.

That's not the way I look at this.

We will look at the best projects with the best MPVs, the highest IRRs, the best long-term type of returns you can expect.

And we slice it, as Simon said.

We look portfolio for portfolio, so the strategic themes like deepwater, integrated gas, and highly optimize those returns.

And then that will give you as an outcome then the production which we are managing.

I think I leave it at that, rather than to try to have a number here.

Thank you.

Next question.

Robert Kessler, Tudor, Pickering, Holt.

Good day, gentlemen.

And I'll try and make this fit as two questions.

The first one being clarification on North America shale write-down and the asset sales corresponding to that.

How much of this was triggered by moving assets to a held-for-sale categorization?

It seems like you need an event to trigger a broad-based review for a write-down, unless it's your annual review process.

How much of the write-down is in Canada versus the US, if any?

And then for the asset sales, how many -- how much that you're considering for sale might be in producing areas as opposed to just non-producing acreage?

Robert, thanks for the questions.

I think I give both of them to Simon There are some embedded accounting questions here, as well.

Thanks, Robert.

As you're probably aware, it's a fair question, because we normally hold our value erosion review, or test for impairment, in the third quarter of each year.

So what's triggered this, it is not moving assets to held for sale.

None of the assets are held for sale, although some of them have been impaired down to a fair market value.

The trigger is essentially, three years ago, we started building this portfolio.

Then we started drilling it.

Then we started producing it, and production takes nine, maybe more, months to really understand the production characteristics of what you have.

Which together with the GNG work, gives you a much better feel for the quality of the asset and the likely development cost.

And it's that cumulatively, which basically we've been talking about this with you for six months, since really the Q4 results.

And this triggered the bottom-up review, asset by asset, that you may also have appreciated, we changed our organizational characteristics and ran this activity at the same time, the beginning of the year.

So taking a fresh look, fresh pair of eyes, different look at the integrated value, right from exploration through to production.

And the cost level that we were able to achieve on drilling and facilities, which actually is improving very well and pretty competitive across the basins we operate in.

So it's not really cost driven, it's sub-surface driven, plus the production rates we've been driven.

So it's more a cumulative trigger than a single trigger.

We haven't given any indication of specific assets, and partly that's for commercial reasons.

There will be portfolio actions.

And it's not in our interest to talk about individual assets, but by and large, the Canadian assets, we said before, the gas FAs look in good shape.

This is not a gas play, and most of the LRS activity on the radar screen has been in the US.

So I can't say more than that really.

And yes, some of it might impact, as we go forward when we sell, it may impact product, which of course, would not only impact production, but might have an impact at the margin on cash generation.

But I would stress, it's probably going to be at the margin in the period that we're talking about.

Thanks, Simon.

Next question, Operator.

Michele Della Vigna, Goldman Sachs.

Good afternoon.

Thank you for taking my question.

With the Repsol LNG business and Basra gas, you have added upstream assets with no associated production.

I was wondering if you could quantify how much cash flow you expect from this businesses on a timeframe of three to five years?

Thanks, Michele.

We don't break out area per area.

I think the Repsol deal, for example, you have got good competitive information from the previous owner, or still owner, but passing it on to me.

We also said, actually, when we made the deal, that we expect $1 billion out of this one on an annual basis, so that gives you a good indication where this is going to end up.

Just to give you a reference on how cash accretive these deals are, especially in the Repsol deal, if you compare it to what we actually paid or are going to pay for the assets, if you exclude the leases for ships, which I think you should.

Thank you very much.

Next question, please.

Alastair Sim, Citi.

Good afternoon, Peter and Simon.

Can I ask firstly again about the CFFO delivery?

You're promising growth, but equally, you did promise growth in cash flow in the past.

And I think if you look at first half 2013, pre-working capital and disposal proceeds, you're running at about $5 billion lower than you did in the first half of 2011, in a very similar Brent oil price scenario.

So can you help me explain the difference, and particularly what you think has happened to the contribution from Pearl and Athabasca?

And secondly, just very quick question, has anyone approached you on assets in North America, or assets held for sale in North America?

I think on the second one, Simon just said we haven't put them actually, or treat them as assets held for sale.

But it's a very hot market, and I'm positive on this.

As I've said, these are not what you would call dry assets.

These are actually assets with flow rates, good flow rates, but may not meet our scale of economic development, which we won't, in order to actually fully take advantage of the cost advantages which we are building into our operational model, business model, in this whole area.

Now on your first question, I think I give you the number, and Simon can then actually give his views on the cash flow, as well.

But you specifically asked for Qatar and Adabascar.

Together, actually, excluding working capital in 2012, they delivered $5.4 billion of CFFO.

I think that gives you -- which is 12% of the total, and they actually have produced 370,000 barrels in 2012, which is 11% of our production.

So I think they are contributing exactly to what we said.

There are many moving parts.

I think when we talk about our targets, a lot of people always forget that we have sold significant assets over the last three years.

We sold $7 billion every year.

There was quite a bit of production involved in that, as well, and quite a bit of cash flow.

So I think you need to take the totality into account.

And we are moving towards our cash flow targets, and I think Simon has explained that very well on how this goes on.

And we have never promised we will have four times 50.

We are working on the projects to increase our cash flow, and specifically, as we always said from the beginning, they're back-end loaded, the 17 projects, of which the 5 we have talked a lot about today come on-stream.

With a little bit of help on the downstream side, we are on the journey for our cash flow targets.

So I think you always need to look at the whole package and not just the pure comparison.

Anything to add, Simon?

Maybe just some of the mechanics.

Let me first point, Alastair, the answer is not when we started this call, but as it's now daytime in Central US, who knows whether there have been any inquiries by the end of the call.

The CFFO delivery, I mentioned the taxes, about $3.5 billion year-on-year is one factor for sure, half year on half year.

And we are at the low point in terms of the Gulf of Mexico production and actually the UK North Sea production, in terms of the liquids, the oil.

And they will get better going forward, anyway, irrespective of the large projects that should be on-stream by next year.

So quite a significant factor there.

And the final factor, obviously, is Nigeria.

It's not producing the same cash flow this year as it did last year, and we've been through the reasons there.

So there are both operational and one or two timing of payment issues.

But reiterate the more general track and the point I made to Jon's question about the triggers or the indicators of whether we will deliver going forward.

Thank you, Alastair.

Next question.

Fred Lucas, JPMorgan.

Thanks.

Two questions, guys.

First of all, can you step us through the moving parts that get you from a net Cap Ex this year of $33 billion to a figure of $40 billion.

Can you break down all the increments, positive and negative?

And can you explain why, if you're accelerating divestments -- and Peter, you said you will see high divestments in 2014 and 2015, i.e.

within the four-year program period.

Why, if you've great investments and you're shedding assets, which will presumably also shed some CapEx obligation, the net CapEx figure of $130 billion for 2013-2015 is not coming down?

Thanks, Fred.

I think on the first one, there are a lot of moving parts.

But the simplest way to look at this is $33 billion didn't include actually the Repsol deal, which has a $6-plus billion ticket against it, of which some is cash and some is not cash.

That's an easy way to get close to your $40 billion.

And we have said there are a few moving parts around new projects which have come in, like the Elba and the gas-to-transport, and I think that's the rest of it.

To be very transparent, we don't know yet how much the Repsol deal will be at the end, so we'll see that.

But I think we said around the net $40 billion, and it's -- that's the right number to take.

We started the year, when we announced the deal, we more or less said it's most probably going to be early next year.

Now we have changed our views, because it's progressing well and it goes into this year.

I think all the other $30 billion net, that's the target which you have, which corresponds to the financial framework.

Again, over 4 years, we're 18 months into it.

There are a lot of moving parts.

Yes, we do accelerate our divestments.

We also made some acquisitions last year, which we have just absorbed in those targets.

Like we bought the Permian, we bought some other things.

So I think overall, we are on the right track on the capital side.

And I think, as I said, there are a lot of moving parts around there and we will manage this to this number quite clearly.

And we see that we have more choices now to make, which we have made now to accelerate some of the investments.

If you talk about more investments in 2014, 2015, that's going to come, and we'll see what impact that all has at the end.

Next question, please.

Jason Gammel, Macquarie.

Thank you.

Two more on LRS, if I could, please.

First of all, I appreciate the analogy you're trying to make to exploration with the LRS.

But the primary cost that you would have so far would really be related to acreage acquisition.

And what you've written down here would be, at best, hundreds of thousands of acres.

So I suppose the question is, do you think that you simply moved too quickly in acquisition, in an effort to catch up with industry?

And then my second question is really more related to specific acreage positions in the Delaware basin, Wolf Camp and the Eagle Ford, which appear to be two of the blocks on your map.

Your acreage does appear to be outside of what the industry has defined as the core of those plays thus far.

So are you prepared today to say that you have any LRS plays that you're confident will be both scalable and economic?

Thank you.

I look toward Simon, as well, if he has got the number of wells which we have drilled over the last one or two years.

But in the meantime, I would not say that we have moved too far in.

We made it very clear last year, and actually the year before, that we're moving to exploration and appraisal.

We don't move into the, let's say, producing areas, with one exception, and that works well, which is the Permian, which we have done last year.

And that's where we have taken advantage over a special situation of one of the competitors and bought this one.

So we took the risk of moving in there, and as you know, for me, this is exploration.

If it works, and we have done so where it works, we have quietly added actually more acreage before the whole thing becomes a hype.

So that's where we are now going to focus on those areas where we have added acreage, and some of the other stuff which is showing good flow rates and we will just get out of it.

Because we cannot afford, and I don't want to really give green light to spend the capital, because we have other options, as well.

So it needs really to meet our hurdle criterias, otherwise it goes out.

And I think Simon said it very well, and that we have got acreage in the portfolio which is actually prospective.

But we just don't want to develop it ourselves and use our own capital for it.

And I think that's the way we are moving.

I'm looking at Simon, if he has got some numbers there.

If not, then we can always deliver that later on, because I think it's important that you're not just writing off acreage, that we actually have done the work, so --

Thanks, Peter.

We drilled about 150 LRS wells last year, and we're about the same track this year.

But obviously, focusing on the more attractive prospects now, as we see and identify what they are.

And in practice, I would say 30% of this year's wells have had initial production rates that are very attractive.

There is quite a significant demand of potential in the prospects that we see.

Can't be more specific than that, but yes, we see successful LRS developments ahead of us.

Okay.

Thanks, Simon.

Thanks for the question.

We need to speed up a little bit.

So two, the last two.

Operator, next question.

Alejandro Demichelis, Exane.

Yes.

Good afternoon, gentlemen.

Just one question.

In terms of the reposition of the LRS portfolio, when is it that you're expecting this to be on a break-even position, either from a cash flow perspective or from an earnings perspective, on the new perimeter?

Okay.

Thanks for the question.

But I think you need to let us work this through first, before we give any further insights.

I think we will be clear in the quarterly or the half yearly calls going forward on where we are.

We have got very good performance in some areas like the Permian, et cetera.

But let us work it first, and before we get too specific on setting a quasi-target for this.

Thanks.

Next question.

Jason Kenney, Santander.

Just one question, going back to an earlier theme.

If possible, on your non-barrel producing positions, and particularly Iraq Basra gas, is there a risk here that these positions become kind a black box financial modeling exercise.

And by implication, could get missed in you corporate valuation without guidance or a concerted effort to try to be transparent on the potential contribution?

Jason, thanks for the question.

I hand over the black box to Simon.

That's a good question, Jason.

And the potential answer is yes.

But the good news for you all is, it won't make much difference in the next one or two years, not Basra gas, nor the other gas-to-transport, or monetization options that we talked about.

So the only thing I can say is that as we go forward and we bring them on-stream and they start to have a material impact, we will need to find a way that will help transparently to understand where the value is being created.

A lot of it will show up in the integrated gas, and I expect that you see the of earnings today.

But your point is well-made, and we will need to think about that as we go forward.

But it isn't going to make a big difference in the next year or two.

Thanks, Simon.

And also, from me, Jason, I think we have shown over the last few years that we have been rather transparent on these types of things, and I think you have seen it today again in the presentation.

We get quite a number of details on these various moving parts, but also in the long-term cashflow outlooks.

And I'm sure that that will continue, in order to actually make sure that our numbers are fully understood.

I think with that, I am closing the call.

So thanks for all your questions, and thanks for joining the call today.

The third quarter results will be released on the 31st of October, and Simon will take your questions there and will talk to you.

Summarizing from my side, a complex quarter to explain, not too happy about it.

I normally like other quarters.

But it's a snapshot, the underlying journey we are on is positive.

We are moving towards a lot of choices to be made as we have growth outlook.

I am pleased with $12 billion cash flow in the quarter, which I think if I look around us, is a very competitive cash flow, and the $70 billion over the last 18 months, as well.

And with all of that, have a great day and hope to see you soon again.

Thank you.

We close the call, Operator.

Thank you.

This concludes the Royal Dutch Shell Q2 results announcement call.

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