殼牌 (SHEL) 2013 Q1 法說會逐字稿

Welcome to the Royal Dutch Shell Q1 results announcement call.

There will be a presentation followed by a question-and-answer session.

(Operator Instructions)

I would like to introduce you to your host, Mr. Simon Henry.

Thank you very much, Darren.

Welcome to Royal Dutch Shell's first-quarter 2013 results presentation.

Let me give you a run-through on the quarter and I'm sure there will be plenty of time to take all of your questions.

First of all, I'd like to share the cautionary statement.

While we have this on the screen, I'm sure you have seen in the announcement this morning that our Chief Executive, Peter Voser, has decided to retire in the first half of 2014, and the Board has now started to look for his successor.

I'd just like to say here how much I've enjoyed working with Peter over the last 17 years as a colleague and a friend.

And of course, we'll continue to do so over the rest of his time here at Shell.

Let me move to the results.

Start with another cautionary statement you will have heard before -- quarterly results are important whether they're good or bad.

But they are only a snapshot of performance in a volatile industry, where we in Shell are implementing a long-term strategy, much longer than three months.

First-quarter earnings excluding identified items was $7.5 billion, and earnings per share were up 2% against Q1 2012.

We are investing for profitable growth while maintaining simultaneously strong capital discipline.

We're developing at the moment 13 new projects and maturing a series of further opportunities for future investment.

So far this year, we've seen the growth impact of recent startups with underlying volumes up 2%, and we've taken four additional final investment decisions during the quarter with new investments and [adds in] petrochemicals in Singapore, in deepwater in Nigeria, and in LNG for transport capacity in North America.

This should all add new value for shareholders.

We're managing the portfolio dynamically with that global thematic approach to capital allocation where asset sales improve our capital efficiency, add focus to the Company.

They enable us to bring in strategic partners, and with selective acquisitions we can add value for shareholders by refreshing the option set.

Over the last 12 months we've done or delivered around $5 billion of asset sales, matched by some $5 billion of acquisitions.

Over three years, that's $21 billion of divestments and $17 billion of acquisitions.

We've made further portfolio moves recently, such as the plans to sell down part of the Downstream portfolio for positions in Italy and Australia.

Of course we have the agreement by Repsol global LNG portfolio, which has LNG supplies in Latin America, in Trinidad and Peru.

Oil prices have fallen recently, and this kind of volatility is a fact of life in our industry, and we are implementing a long-term consistent strategy against what is and will continue to be a volatile backdrop.

Our financial growth allows us to invest for long-term shareholder value, increasing cash returns, and we have distributed $11 billion of dividends over the last year.

We've raised our dividend today, confirmed a 5% increase to $0.45 per share per quarter that we announced back in February.

We are committed to a share buyback program to offset the dilution from the scrip through cycle.

And we have recently stepped up the pace there.

As of last night, we were around $1.3 billion of share buybacks so far this year in 2013.

Let's just move on to the macro environment.

You can see just from the lines on the chart the volatility we face.

If you look at the macro picture compared to the first quarter 2012, the oil prices were lower than year ago.

And there was an increase in the differential between Brent and WTI to $18, and between Brent and West Canada Select or WCS, $45 per barrel discount.

Our global natural gas realizations increased from the first quarter a year ago.

That includes the higher Henry Hub price levels in North America.

On the Downstream side -- refining, marketing, and Chemicals margins -- they were higher year over year and we had better conditions for trading than a year ago.

Moving on to the earnings impact.

There were a number of accounting and presentation changes in the results today, and you'll find all the details in the results announcement in the supplementary materials.

IAS 19 is a change for pensions accounting.

And IFRS 11 moves some of our equity affiliates to proportionate consolidation.

There's no substantial impact on earnings and cash flow as a result of these changes, although the balance sheet will be more volatile in the future.

We've also refreshed how we define identified items, difference between headline and adjusted for identified items, clean earnings.

We got more clarity on definitions and we've removed the old $50 million threshold.

That's because that threshold did lead to sometimes rather binary outcomes and that was out of step with the peer group.

We're moving to be more easily comparative.

We don't expect this change to make a fundamental difference to clean earnings over time; maybe some minor variance on the quarter-by-quarter basis.

To give you an example for the quarter just concluded -- first quarter 2013 -- this change to identified items leads to underlying earnings that are $250 million higher than they would have been on the old basis for identified items.

CCS earnings for the quarter including the identified items were $8.0 billion.

Excluding the identified items, the earnings were $7.5 billion, and that's an earnings per share increase of 2% over the last year.

On a Q1-to-Q1 basis, that was lower earnings in Upstream, higher figures in the Downstream.

Upstream earnings, excluding identified items, was $5.7 billion in the first quarter and that's a decrease of 10% against the same quarter last year.

Earnings were impacted by lower liquids prices, higher operating costs, higher exploration expense, and higher depreciation.

Growth projects such as Pearl gas-to-liquids had a positive impact on the Q1-to-Q1 results, with some uplift from gas prices.

We also had positive year-over-year impact from tax from LNG trading and from inventory effects.

Our Upstream Americas business returned to profit in the first quarter, compared to the losses sustained in the second half of 2012.

This was driven by higher volumes, higher price realizations.

However, earnings were lower than one-year-ago levels, due to lower oil prices, higher costs, and the higher depreciation charge.

Our Downstream results, excluding identified items, and on a CCS basis, were $1.8 billion -- that's higher than year-ago levels and supported by higher oil products and chemicals results.

Refining had the largest Q1-to-Q1 uplift, where Shell was positioned better than the industry or better in the industry environment; and that's despite our lack of exposure to the advantaged inland pad 2, pad 3, particularly US refining margins.

We also had positive momentum from chemicals, oil products, marketing margins, and an increased contribution from trading.

So those are some comments on earnings.

Turning to cash flow.

Cash generation from the business on a 12-month rolling basis was some $49 billion, including $5 billion of disposals, and that was with an average Brent price of $110 per barrel.

Both Upstream and Downstream segments generated surplus cash flow after investment.

Free cash flow was $4 billion in the quarter and $13 billion over the last 12 months.

We paid out $10 billion of that cash in dividend and a share buyback over the last year, and that's less the cash surplus of $3 billion.

We manage this cash cycle very closely as we face that volatile macro environment.

So those are the comments on the financials.

Moving on to the underlying operating performance.

Headlines -- oil and gas production for the first quarter was 3.6 million barrels of oil equivalent per day; 2% up on an underlying basis.

Volumes were supported by growth from Pearl gas-to-liquids, and Pluto LNG project in Australia, and both of these effectively now fully ramped up.

And also supported from North America liquids-rich shale plays, where we produced 52,000 barrels oil equivalent per day.

That compares to only 7,000 barrels per day a year ago.

Maintenance -- especially in the North Sea, took around 30,000 barrels oil equivalent a day from production year on year, and the worsening security picture in Nigeria -- that reduced our share of SPDC volumes on-shore by 30,000 barrels oil equivalent per day.

That's, again, relative to last year.

LNG sales volumes globally were flat Q1 to Q1.

The growth from Pluto in Australia was offset by reduced load-ins in Nigeria where the feed gas supply was disrupted by attempted theft on the gas pipelines.

In the Downstream, the chemicals and refinery availability -- they were lower than a year ago.

But that was largely a result of planned maintenance in the US Gulf Coast and Germany.

Downstream sales and marketing volumes were impacted by accounting changes, and headline sales volumes in oil products went up, chemical sales product volumes went down as a result of the changes.

If you look at the underlying trends, we saw lower chemicals and oil product sales than one year ago.

Europe and North America oil products volumes declined.

We did see some growth, led by retail in Asia.

Now looking forward to the second quarter of 2013.

We are expecting, relative to last year 20,000 barrels oil equivalent per day of negative impact from the North Sea and Gulf of Mexico maintenance activities; and those of course are high-margin barrels.

Security conditions in Nigeria remain very challenging and we're also expecting heavier than normal maintenance program in LNG overall for the second quarter.

In chemicals, I need to flag that we're expecting higher maintenance in Q2 '13, availability around 85%.

That would compare with availability of 89% that we produced in the second quarter 2012.

It was a busy quarter for the portfolio, so let me give you a bit of oversight there.

A lot of development as we refresh the Company for future growth.

This chart shows how all these portfolio moves map out against the strategic themes that we talked about previously and that we're using in Shell to drive the strategy and the capital allocation.

We restarted production at Port Arthur's crude expansion project and the refinery in Texas in the Downstream.

In the Upstream, we started up the first of the oil sands debottlenecking projects in Canada.

We started up the Amal enhanced oil recovery project in Oman.

And we started yesterday operations in the Basrah Gas Company in Iraq, which will capture and commercialize the gas currently being flared in Southern Iraq.

We saw four new final investment decisions in the quarter -- 60,000-barrel oil equivalent per day in Nigeria deepwater on 100% basis that will be; and 0.5 million ton per annum of integrated gas in the gas-to-liquid fuels or transport fuels in North America.

We also launched new polyols and ethoxylation investments in chemicals at the Duran petrochemicals facility in Singapore.

We added new exploration acreage worldwide.

We found new gas reserves in Australia -- discovery.

And have continued near-field drilling success in our Upstream engines.

Now looking at new potential final investment decisions, we've had real progress in two areas in the last few days.

We're very pleased to be chosen by the Abu Dhabi National Oil Company to participate in a 30-year joint venture to develop the Bab sour gas field, with a 40% stake in that joint venture.

This could be up to 0.5 Bcf per day for sale gas, or around 90,000 barrels a day oil equivalent.

In Canada we've been granted regulatory approvals for the Carmon Creek in situ heavy oil project.

That could come to final investment decision in the next 12 months, and eventually be an 80,000 barrels a day project, and currently that's 100% Shell project.

Acquisitions and acreage purchases in the quarter totaled $0.6 billion.

That includes the increased stakes at Beryl and Schiehallion in the UK, where we already had an equity holding.

Divestments were also $0.6 billion, primarily proceeds from dilution of the Prelude floating LNG project in Australia to a strategic partner.

There's been quite a bit of progress on our integrated gas portfolio.

I'll just give you oversight there.

Firstly, in Australia, the operator of Browse LNG, the potential project; the operator is Woodside.

They announced that the project will not go ahead with the original onshore design that had been studied in feed, and it will not proceed due to the high expected cost level.

We fully support that decision and the operator will now assess alternatives, including floating LNG, which Shell believes is a viable economic alternative for this important resource.

16 Tcf of gas there -- so very potentially interesting resource for future development.

Elsewhere, we've taken FID on two new LNG for transport projects in North America; brings our total capacity there for transport LNG to 0.75 million tons per annum.

We also in the US formed a joint venture with Kinder Morgan for an LNG export facility at Elba Island in Georgia.

This is planned to be built using the same small-scale modular liquefaction facilities that we used in the gas for transport.

We'll build Elba Island in two phases for an expected total 2.5 million tons per annum, with Shell offtaking 100% -- all of the LNG gas.

We also reached an agreement in the quarter with Repsol to purchase their LNG business -- that's 7.2 million ton per annum of sale agreements, including the support from 4.2 million tons per annum of Latin America liquefaction capacity.

We're already a leading LNG trader, clearly, and we can add value to Repsol's position through that trading capability.

We see up to $1 billion per year of cash flow potential from these Repsol assets once the deal closes.

We expect that to be later this year or early 2014; a lot of details to work through.

So pretty good progress overall on the integrated gas portfolio.

I have to point out one important fact here for you.

The new positions -- Elba, gas for transport, Repsol LNG, and the Basrah Gas joint venture -- they'll all bring good future cash flows, growth, returns to Shell.

But collectively they don't add a single barrel to our reserves or production.

This is just symptomatic of, reflects our long-standing emphasis on value creation ahead of volumes.

Must reiterate -- any production target is only a proxy for financial growth; and you can see in this choice of projects precisely what that means.

Let me move on to the financial framework -- important messages as this takes shape and you can see the choices that we are making.

Our business strategy requires substantial levels of capital investment through the business cycle.

These are multiyear programs to maintain facilities that are onstream to build new growth projects and to explore for new opportunities.

The balance sheet underpins the financial framework, and we manage that in a conservative basis in order to be able to finance the strategy.

The business strategy itself is chosen to grow the cash generated sustainably through cycle.

While we see quarterly volatility, we look through this.

We target growing free cash flow -- that's the red line on this chart, just to be clear -- that exceeds the payouts to shareholders, as you can see on the top left here.

The growth in our cash flow underpins both the competitive dividend for shareholders and the investment program.

Our free cash flow has grown in the last few years from a negative position in 2009 to some $13 billion over the last four quarters.

At the same time, the balance sheet [gearing] has declined to 9.1%.

All of this is a result of the growth strategy and some recovery in the macro since 2009.

This increase in free cash flow gives us more flexibility in financial planning, and we have increased the dividend in 2013 in line with underlying growth in earnings and cash flow, and aligned with the policy; and we've also increased the pace of the share buyback program to offset the scrip.

And there is no precise formula for dividends and buybacks.

We have to take a long-term approach to capital allocation.

But I don't see the Company selling assets or raising debt to fund buybacks.

This is something we do from our cash flow generated from operations.

Dividends are our main route for returning cash to shareholders.

The scrip uptake in the fourth quarter was 31%.

And we will be offering scrip dividend again for the first quarter.

We increased the pace on the buyback program over -- now just under $1.3 billion on buybacks as of yesterday.

And if the current environment continues, I expect the share buyback to be somewhere in the range $4 billion to $5 billion this year.

The upper limit is dictated by the share price and trading restrictions in the London market.

And overall, of course, that should more than offset the impact of scrip shares that we issue this year in 2013.

We will sustain investment for long-term shareholder value.

That will enable much longer-term dividend growth.

But this financial strength we see at the moment enables us to, at the same time, optimize the near-term cash returns to investors.

Couple of words on competitive performance.

It is improving.

This chart looks at a range of financial and operating measures, and we see improving performance in all of these metrics.

I think there's more to come here.

Quarterly results are important, of course, but we've got to put these in the context of the longer-term strategy and performance.

We look at it three to five years.

Just let me summarize the key messages before moving to your questions.

Underlying earnings -- $7.5 billion for the quarter, 2% increase in earnings per share.

We're investing for profitable growth, while simultaneously maintaining a strong capital discipline.

The financial growth creates the flexibility in the Company to invest for long-term shareholder value and to increase cash returns to the shareholders.

We raised the dividend today 5%, stepping up the pace on the buybacks.

So we're making good progress against the targets to deliver a more competitive performance from Shell.

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

Please could I ask you, restrict yourself to just one or two each, so that we give everybody the opportunity to ask a question.

Darren, please could you poll now for questions?

Thank you.

Thank you.

(Operator Instructions)

The first question comes from Theepan Jothilingam from Nomura.

Please go ahead with your question.

Good afternoon.

Thanks for taking the question.

Two, please.

Just come back to Australia.

Could you just talk about the other options still in the Shell portfolio, particularly around Arrow LNG, and also the stake in Woodside on the latter, how you think that sort of adds value to the Shell Group.

Secondly, just on the CEO succession, I know Peter's not on the call, but I wanted to know whether the Board and Management had good line of sight on Peter's intentions to step down, whether it's something you've known for quite some time?

Secondly, whether the internal process has started and whether you have or will be part of that process.

Thank you.

Theepan, many thanks.

Australia first, other options.

We are, just a reminder, building in Gorgon.

We're a small shareholder in Wheatstone, and the Prelude project is taking nice shape, the floater in Korea.

We're already engaged in quite significant development.

The Arrow joint venture, 50/50 Shell, PetroChina, is developing the Upstream, looking potentially early sale of ramp-up gas to domestic or export customers.

We are preparing or progressing in parallel, both the greenfield LNG option and potential cooperation with the existing project, the three projects under construction there.

We deliberately delayed our own LNG project because of cost inflation.

There are three projects ongoing in a country which is basically short of welders.

You can see what the underlying impact is on the project.

We're not in any particular hurry to make a final decision.

We want to get the economics right.

We also have other floating LNG options, we've talked about Sunrise previously.

We have other discoveries on the Exmouth outer or the outer Exmouth shelf, and in Evans Shoal and we're still doing exploration.

We've got a big well going down, Shell only, 100% at the moment.

So very significant gas province, and it's important for us we develop the right projects at the right economics at the right time in terms of cost.

But Australia remains an attractive country in which to do business for LNG.

Woodside, as a result of all of the above, we said a couple of years ago that Woodside was no longer really a strategic necessity for Shell in terms of executing our LNG strategy in Australia, and we did sell down part of our share holding.

We still own around 24% of Woodside, and basically the statement still holds.

However, it may not be a strategic asset but it is a valuable asset.

It's a Company with good assets, good prospects.

We're not going to give it away just because it doesn't fit strategically.

So we're not in any particular hurry there either.

And on the CEO succession.

Board and Management.

Just let me share with you, just to take this once rather than multiple questions.

We're happy to describe this to the staff this morning.

He decided to retire from Shell after almost 10 years on the Board as CFO and obviously the last four years as CEO.

More than 25 years in the Company in total.

He's had a great career as an Executive but he's looking for a lifestyle change, more time, family.

This is a private and a personal decision.

He will still be engaged in the business community through limited number of non-Exec roles but not at Shell.

And he will continue with active participation in not-for-profit organizations.

That's just some background.

That's how Peter posed it.

The Board is in general well prepared with succession planning.

[Denonco] which is chaired by Jorma Ollila and a member [of Hansbi] is Joe Ackerman are well prepared in this process as we go forward, and I think it's probably inappropriate for me to say any more.

I don't have timing or knowledge of exactly how this will play out, other than that they have suggested that they will look at both internal and external candidates.

So I'm hoping that will cover off Peter's statement today and hopefully we can return to results and strategy.

Thanks, Theepan.

Move to the next question.

Thank you.

The next question comes from Martijn Rats from Morgan Stanley.

Please go ahead with your question.

Good afternoon.

I've got two if I may.

You mentioned that production from liquids-rich shales in the US had reached 52,000 barrels a day already, which is growing at a pretty decent clip.

I was wondering if you could give us a bit of an outlook for how this will progress over the next couple of quarters, what level of growth you still foresee.

And secondly, I notice from the cash flow statement that the line dividends received from equity accounted investments looked light compared to the last quarter and compared to the same quarter last year.

And I know there can be joint ventures where sometimes the timing from certain dividends can be sort of a little specific.

I was wondering if we are looking at a sort of normalized number or whether we're actually sort of missing well what could be as much as $1 billion also whether this line item given the accounting changes that you highlighted could be affected by that.

Thanks Martijn.

The liquids-rich shale in the US, 52,000 barrels oil equivalent per day at the moment, that's basically the Permian and the Eagle Ford.

We've got 12 rigs in both in the two in total.

We're also drilling out other liquids-rich opportunities in Canada in particular, there's right around 20 rigs at the moment on liquids-rich activity.

We won't see quite such a stepup as we've recently seen because the 52,000, about 50% of it is in the Permian, which was an acquisition in the fourth quarter.

But we do expect to see some growth over the rest of the year.

Just as a benchmark, the average on-shore shale production was about 260,000 through the totality of 2012 and we're at about 320,000 in Q1 2013.

So quite some stepup.

That's helped in the turnaround of the Upstream Americas results.

I can't give an absolute figure because it does depend on drilling results, and overall you may recall we've scaled back our absolute activity in the on-shore drilling for now just to get the right balance and the right capital discipline into the system.

And dividends received on the cash flow statement, well spotted, we are somewhat less in terms of receipts than actual earnings in the equity associate.

There are several factors here.

Some of the dividend reduction is timing.

Some of it is stepdown in share -- of production share in contracts reached for cost recovery, and some of it is accounting change, IFRS.

That one in particular doesn't come back and the cash flow is anyway shown elsewhere in the cash flow statement.

The last one applies to the Arrow joint venture in California, the heavy oil joint venture.

And that's several hundred million dollars.

That's transferred from the dividend line to elsewhere in the statement.

So three factors there.

About 50% of that difference comes back, the other 50% doesn't.

Hopefully that gives you some feel for where we are on that dividend statement.

Overall, the cash flow progression remains generally positive, but there's still some way to go.

I'm sure you'll have seen relative to the targets that we expect to achieve over the full-year period, 2012, 2015.

Thanks Martijn.

Okay, thank you.

The next question comes from Jon Rigby from UBS.

Please go ahead with your question.

Yes, hi.

Couple questions.

Firstly, you mentioned on the call that Pearl had effectively reached plateau on production volumes, but can you just talk about whether it's reached a sort of plateau contribution in terms of earnings and cash flows, or is it still more shakedown and startup costs to work their way out in terms of the contribution to the financials?

And secondly, just on the Canadian stuff, you referenced small expansion and debottlenecking and also talked about Carmon Creek.

As you look at your Canadian position, are you able to effectively run all the future potential production from the oil sands through Scotford and therefore sort of avoid to some degree some of the problems that the rest of the industry is having in terms of differentials?

Although clearly still affected to some degree.

Thanks.

Thanks, Jon.

And GTL, it's a plateau or close to plateau production at the moment.

The dollar contribution still continues to grow as the specialist product markets are developed, for example in lubricants and clean diesel.

There are maybe a few more dollars we can squeeze out.

Overall, we're -- the big three projects have been quite transparent and open about in the past as they've been ramping up, given they're all pretty much where they need to be now at -- no need to be very specific, other than to say over 440,000 barrel a day of production from the three which is about where we would expect it to be.

We always said about up to 450,000.

And we I think delivered over $5 billion of cash flow last year from these assets, while we obviously at current conditions we should do a little bit better this year.

Canada, debottlenecking is relatively small the first one, it's 6,000 barrels a day Shell share.

But remember, this is a series of relatively small projects that over time should get to 60,000 Shell share and Carmon Creek is 80,000 Shell share at the moment.

Can we run it all through Scotford?

I'm afraid the answer is no.

We would need to move some to Sarnia, some potentially to Puget Sound, and some to the Gulf Coast.

That is the intent, always was the intent.

Clearly will depend on access to appropriate pipeline capacity, and we can only really talk about that at the point at which it's established, particularly Keystone is an important indicator for the industry, although it's not the only way of moving heavy oil down out of Canada.

Just on -- just as a matter of interest, on the GTL plant.

Is the product slate that's now coming out of it pretty much what you had all planned or will that develop as you develop the markets?

Are you sort of selling the product you planned but in slightly distressed pricing or are you actually moving the product slate to meet what is currently the market?

I wouldn't say we were distressed at all.

The market's developing and evolving.

It's very clean middle distillate, and it has some surprising uses of high value.

I can't say too much more.

But it's developing nicely.

And the one thing I would point out is that there's an ethane stream currently not seeing to much value, because you can't actually stick it through the Fisher-Tropsch process, and that ethane stream is being allocated in future into the Chemicals projects that we're now working on with Qatar Petroleum, the Al-Karaana project.

So over time, additional investment helps add further value to the hydrocarbon streams in Qatar, and also we hope to spud shortly the new exploration well in Block D with partners PetroChina.

So Qatar remains an area of potential growth for us, looking good.

Thank you.

Thanks, Jon.

Thank you.

The next question comes from Robert Kessler from Tudor, Pickering.

Please go ahead with your question.

Your Downstream results were quite strong in the quarter, presumably with the help -- well, specifically referenced from the trading and marketing.

I'm assuming that contribution was towards the higher end of that $800 million to $1.1 billion range.

And then also related to the Downstream assuming Port Arthur with Motiva still in kind of expansion mode for the quarter.

Could you give a sense for the average throughput at that facility for 1Q, and how much of an uplift we might expect for the second quarter.

Thanks, Robert.

Your assumption is pretty much correct.

The marketing and trading we haven't given specific figures this quarter but refining, manufacturing was in a small profit, so the M&T, marketing and trading was indeed at the top end.

Just make the point that trading is not a volatile open position business.

It's adding the cents per barrel to all the molecules that flow through the system and optimizing the positions we have.

It's not something that comes and goes.

It's a pretty substantive, regular, robust contribution to the bottom line.

Throughput in Port Arthur, I don't have a specific number.

It's not 100% on the 320,000 new expansion project but it's close to 300,000.

Not a lot of earnings impact in the first quarter as we're still ironing out some of the product flows, but it's actually performing pretty well, it's about 80%, 90% of its capacity on the distillation unit.

It's looking good, but not making a big impact on the bottom line just yet.

Okay.

Hopefully that helps.

It does.

Can I ask, for refining overall you said Chemicals' availability will be lower in the second quarter.

Can I presume refining availability will be higher, particularly with the Motiva ramp?

It's about the same as it was last year.

Availability is high but there's still actual throughput, somewhat below ultimate capacity because of the actual economic opportunities in the market.

So it's not a constraining factor on us at the moment.

Thank you.

Thank you.

The next question comes from Irene Himona from SG.

Please go ahead with your question.

Hello Simon.

I had two questions please.

Firstly on gas and the Basrah Gas Company.

Can you comment on whether the economics of that project would be conditional on a future LNG export project, or whether you can actually deliver a return, an acceptable return selling the gas domestically to the power stations?

And then secondly on exploration, you're obviously investing substantial amounts this year, up to $7 billion.

What are the highest, the most exciting wells, the highest impact wells you have this year?

And importantly, do you intend to update investors?

Obviously you don't do it on a well-by-well basis.

Would it be on a [altoca] basis?

Thank you.

Thanks, Irene.

Basrah Gas started yesterday.

The economics are certainly not conditional on future LNG exports.

Almost the other way around.

The LNG economics would need to I suspect they'll require quite some work, both on the costs and the value chain piece.

The upfront activity is basically we collect the gas, we strip the liquids, we put dry gas back into power for which there's a fee, and there is some access to the NGL revenues that we take out and that's what underpins the returns.

They're reasonably attractive, better than the oil.

Exploration.

We've got $4 billion going into conventional exploration and $3 billion into unconventional.

So unconventional first, the most exciting is some of the LRS and liquids-rich shale in Canada, in Argentina.

And on the gas side we are first well in Ukraine, and we have 10 rigs operating in China, not all on exploration, some are in [Chan Bay] and China and Ukraine on the gas, Argentina and Canada on the liquids.

We will also hopefully have picked up the Gazprom Neft agreement where we're looking at opportunities in the [Bhasinov] shale in Russia which we would expect to be liquids-rich as well.

That could be of interest.

Whether we'll get to drill it this year or not, we do not know yet.

On the conventional side, we had hopes in French Guiana.

We still have hopes for French Guiana, unfortunately, the most recent well was not success.

I just mentioned Qatar, which is a gas prospect in the [pregulf] that we will spud shortly.

We have two wells in [Banin] and [Gubon], deepwater new plays.

We have the Australian well at the moment, [Pulta].

We're interestingly drilling in Albania on land for oil and we have a fair few wells in more mature areas, both the North Sea and Malaysia in particular that could be certainly of interest.

We go forward, there are quite a few other areas such as Nova Scotia, the other Guiana and Columbia deepwater and the Latin America trend, Greenland and New Zealand that we may get to drill in in 2014.

The next two years is quite interesting in terms of the major plays, and let's not forget the Gulf of Mexico.

We have five exploration wells this year, three of which we're in progress at the moment, on the Yucatan well currently in progress and the Queen well later this year, of potentially interest.

We update on quarters typically and we try to avoid individual press releases unless they're on large operated discoveries.

We always leave it to the operator to make an announcement.

As you've probably seen in the industry, some of the smaller operators feel more obliged because of the relative materiality to make announcement.

Sometimes it's not always easy to keep the cats herded.

But fundamentally, expect to hear on a quarterly basis.

It's a big program.

It's a multiyear program.

And a statistical outcome.

We will drill dry wells.

They will not all be dry.

Let's see how it progresses.

Some of the most exciting set of wells we've had in conventional exploration for a very long time, I think.

Thank you, Irene.

Thank you.

The next question comes from Jason Gammel from Macquarie.

Please go ahead with your question.

I think I'll restrict mine to one because it's multipart.

But it involves the Repsol transaction.

I was hoping you could elaborate on the uplift that you could expect to achieve and the cash flow from that business from your trading positions, given that a lot of those volumes were essentially point-to-point committed.

Within that, could you address how having incremental Pacific basin volumes from Peru will help your trading business in light of a lot of those volumes already being committed in [Manzania].

I guess really what I'm getting at is would you have other solutions for getting gas into Mexico that would allow you to reroute the Peruvian LNGs to other Pacific basin markets.

Jason, thank you.

You have obviously been doing your homework on the Repsol contracts.

The uplift that we would expect doesn't depend and extend on diversions.

Let me be clear.

There's some fundamental value in those contracts.

We're not dependent on trading capability for most of the value.

Most of the value is just embedded in the contracts as they stand today, plus the growth potential.

So the trading is essentially diversions and the ability to meet customer requirements from what is a broad and diverse set of portfolio options within Shell.

So whereas Repsol may not have had the alternatives to meet customer requirements, the barrels may be point to point today, but they're not necessarily hard wired in the contract.

So they can -- customer demand can be met from different sources and that's what we intend to do.

That will drive the uplift.

Just got to reiterate, first of all, we have to close the deal.

Something 20 odd contracts, major contracts, several antitrust, many partner support required, some project financing in there.

So we've got a lot of lawyers, a lot of people working hard to close that deal, and you may remember it's effective October 1, 2012.

So we continue to accumulate cash in a lock box that will be released and credited against the acquisition cost at the point of closure.

So looking good.

But still some way to go.

And I expect to see closure in the next quarter, that's for sure.

Thank you, Jason.

Take the next question, please.

Thank you.

The next question comes from Oswald Clint from Sanford Bernstein.

Please go ahead with your question.

Yes, thank you, Simon.

I just wanted to ask you again about refining.

Because I remember you painted a pretty pessimistic picture for refining margins at the end of January.

You've had some benefit here in the first quarter.

Just want to know if you could -- are you still seeing that pessimistic view or expect that to take place over 2013?

Or have some things changed to make you a bit more optimistic about refining margins?

Secondly, just looking at your kind of CapEx split here on your -- in terms of your [data] book, and year over year looking at the big delta, I think it's in Europe, being the biggest delta, despite that being quite a mature part of the business.

Is there anything in that European CapEx number?

I know you've added some equity in some North Sea fields.

I don't think the numbers were disclosed.

But is there anything else in terms of European CapEx?

Thanks, Oswald.

Refining, no real change to the general misery and pessimism on the market, particularly in Europe, and actually in the short term in Asia.

The fundamental issue is capacity exceeds demand and nobody will close a refinery in Europe, so although we are, we are working our bugs out of the system now and we announced potential sale or closure in Australia of Geelong.

The oil and new capacity coming on-stream, the Middle East and Asia in general more than offset any closures plus demand growth.

So there are good quarters, bad quarters.

North America has some interesting opportunities as they -- the whole balance of the refining system is being challenged with all the light sweet crude available inland, and moving it to large coastal refineries that were built to process heavy sour crude has created some short-term arbitrage opportunities.

And of course short of one itself, you have seen from some of the competitors, there are shutdowns planned and unplanned, because of various incidents that have sort of temporary one-off support in the North American markets in particular.

I'm afraid in April margins have remained rather weak.

There was a weaker trend during March and that's continued into April.

Our uplift was partly better performance and partly the fact that refinery configuration was reasonably well mapped for the opportunities available.

But it's not a business that is going to drive the results going forward.

The marketing and trading, however, performed extremely well, as did Chemicals in what are tough markets.

So we're particularly pleased with a pretty robust performance there.

CapEx in Europe, Europe is up.

The Beryl, Schiehallion acquisition is in there.

I think for around $500 million.

But the big driver over time at the moment is their Clair and Schiehallion projects.

We're also continuing to invest in Tempa Rossa, Val d'Agri in Italy and Corinth in Ireland.

But the step-up is on the Clair and Schiehallion projects which are significant.

And we're over 50% shareholder in Schiehallion now and 27% in Clair.

They will hopefully make nice contributions from 2016, 2017 onwards.

So mature as a region but all those projects attractive, four of them are oil projects, Clair, Schiehallion, Val d'Agri, and Tempa Rossa.

That's great, Simon.

Thank you.

Thank you.

The next question comes from Iain Reid from Jefferies.

Please go ahead with your question.

Hi.

Simon, good morning.

Ask a couple questions about Asia-Pacific LNG.

Firstly on Sakhalin, it looks like your partner there is interested in building its own LNG facility (inaudible) are talking about a facility in the region.

Does that effectively mean an expansion of Sakhalin, your Sakhalin plant is off the table for the moment?

And secondly, on Papua New Guinea, I think you mentioned last year that you were looking at the InterOil acreage there.

Could you kind of update us on what the plans are there.

I believe you've been running a process for selecting partners.

When are we likely to hear something from there?

Thanks, Iain.

Asia-Pacific LNG, Russia specifically as I mentioned hopefully you all picked up, the Gazprom Neft announcement on Bhasinov shale and Arctic opportunities together with Gazprom Neft.

Signed in the presence of the President and also Alexey Miller, the Chief Executive and Chairman of Gazprom.

The train 3 option at Sakhalin continues to be worked.

We have work ongoing in terms of the design.

It is one of the options available to Russia Inc and Gazprom in particular to expand and enhance their LNG market presence.

It's our view of course that it is both the cheapest and by far the quickest way of achieving that.

But still decisions ahead of us, so progress continues.

There is competition within the Russian system, but on straight economics and speed to market in an important window of opportunity as well, particularly when you look at the direct competition potentially coming out of the North American continent.

If Russia wishes to catch a market window before that arrives then Sakhalin is its only workable option we believe.

PNG, better be careful what I say because I was quoted out of context a year ago.

There is an InterOil process.

Clearly we've taken a look from a distance and I can't really comment any further, other than to say I think I started on the Australian project portfolio in LNG.

We are known to be working the Abadi floating LNG project with our partners, Inpex, who are also the operators of course in Indonesia.

We are working Canada LNG very actively at the moment and we announced the Elba Island export facility plus of course the Repsol volumes.

The whole LNG business is progressing at quite a rate at the moment for us, and any new opportunities would have to look pretty attractive to displace the ones that I've just talked about.

That's about all I can say, really.

You can't comment on whether you're actually part of InterOil process?

No, obviously not.

No is the answer.

All right.

Fair enough.

Thanks very much.

Regards to Peter please from me.

I will do.

Thank you very much.

And much appreciated.

Next question, please.

The next question comes from Lydia Rainforth from Barclays.

Please go ahead with your question.

If I could just ask around the cost base, there does seem to be a lot of volatility on a quarter-to-quarter basis.

So I'm just wondering what you're seeing underlying on the cost base.

And then secondly if I could on the US oil gas to transport section, how big do you eventually see that ending up being?

Thank you.

Thanks.

Good question.

The cost base, there's a one-off impact of the proportional consolidation, IFRS 11, maybe not quite so volatile as you might think.

The underlying trends are in the Downstream we are generally reducing it, it's partly driven by divestments, and part driven from just squeezing out cents on the dollar every day in everything that we do.

That's underpinning some of the robustness of the results that we see.

The Upstream, the international costs holding roughly flat with some upward pressure from new projects coming on-stream, and in the Americas they are going up as we execute more activity and there's more exploration expense as well in the quarter.

One of our challenges in the Americas is to ensure that the costs grow more slowly than the revenue, and that's ongoing work with the management team there.

So we are seeing FeasEx at a relatively high level.

Feasibility expenditure on new projects potential.

But generally the costs over the past few years have been held at $42 billion, $43 billion total over about four years now.

So costs not a major issue in terms of results progressions.

Gas to transport, good question.

When we started we may have had certain aspirations for this market.

What we're essentially doing is producing LNG in small scale and selling it to trucks, fleet operators, and to shipping.

Small fleet operators in shipping or large enough to justify the investment.

That market we saw may take some time to develop because we need original equipment manufacturers for both engines and the vehicles or the ships, and we need a distribution network and most importantly of all, we need the customers.

We have been surprised at how quickly this is coming together.

We have many manufacturers now looking at this, Cummins, Westport are the main ones in North America.

Just in China alone, I think there are around Guangdong 17,000 trucks and busses running now on LNG.

That's growing fast.

Chinese manufacturers we're seeing appetite for LNG barges running down the Rhine in Europe.

We acquired Gasnor, which is LNG for shipping provider in Norway last year.

So potential is multi-million ton per annum.

Much of this will not necessarily be provided from our own Upstream gas production.

It will depend basically on the logistics close by.

We see the take-up of the various parts of the value chain accelerating in an attractive way.

It's our challenge and opportunity is to ensure that we can find an offer for the customers, the right pricing, the right distribution that helps us develop a leading position there.

It could be very substantive globally over a period of time and we see North America and China in particular as growing this as a major part of the transport fuels mix.

That's very helpful.

Thank you.

Thanks, Lydia.

Thank you.

The next question comes from Peter Hutton from RBC.

Please go ahead with your question.

Good afternoon, Simon, just two quick questions.

Q1 marked a welcome return to profit in E&P Americas.

Q1 last year, the profitability there was much higher than it was for the rest of the year.

Were there any seasonal factors in Q1 on costs really such as BP mentioned, which also impacts Shell there?

And the second one is just coming back to your helpful discussion on shareholder buybacks.

Under what circumstances do you think this could become an option in your financial framework?

You mentioned not borrowing to do this, but a lot of your peers see this as effective way flexibly to return any surplus cash through to shareholders.

Is it just seeing specific issues on the mechanics for Shell of shareholder buybacks, or is there a view that the rate of return on your own internal projects still much better than buying your shares at present levels?

Thanks, Peter.

Couple of good hooks there.

The Americas profit, definitely up year on year, partly that is driven -- sorry, down year on year.

Partly that's driven by higher exploration expenses, stroke feasibility expenses, plus some of the issues -- we've acquired a lot, the Permian acquisition from Chesapeake was most obvious, but quite a few other smaller plays we're buying.

As we bring in and integrate that activity, introduce sort of different standards around things like safety, you do see some of the costs go up before they go down.

So that is year on year, all of those things are something of a factor.

You referred to I think Gulf of Mexico costs.

In practice, we don't see those going up at all really in project terms.

In fact, we're seeing very good progress on Mars B, Cardamom, and the BC-10 Brazilian project as they progress towards production next year.

Those contracts of course were put in place back in 2010, mostly while the market was lower and we're doing okay there.

We're currently progressing stones towards FID, which will be a floater, floating production storage unit.

That's a 3 billion-barrel resource remember as well in the lower tertiary.

So it won't be a major development upfront because it will be more an early production system, but that will be the next one and costs, that's not that much of an issue in the Gulf yet.

Could be if projects all take off of course.

And just back on the shales, costs actually on the drilling and the activity not too much inflation there at the moment.

It's more on the administration, how on earth do you manage across the 14 basins that we're in at the moment.

And you may recall I talked about the $28 billion on the balance sheet three months ago.

So we're still working our way through that.

We've rebalanced the drilling activities as I said before with most of it now on liquids-rich plays.

A lot of that is still exploration and appraisal.

So we need to work our way through that towards full-field development and projects that we can see and work out effectively how that $28 billion finds its way to the profit and loss statement.

And that's something that will play out and we'll talk about in quarters going forward.

Buyback, dividend, free cash flow.

We have a commitment to offset the script dividend at the moment and that is the -- that's a three-cycle commitment.

The script has been about $3 billion a year.

We're currently at 150 million shares behind offsetting that dilution.

At the current rate of buybacks, absent any other changes in the activity by early 2015, we should have offset the cumulative dilution this year.

If we do the $4 billion to $5 billion, then that will more than offset this year's dilution.

It will take similar rates of progress to offset the historical dilution.

That's the only mandate I currently have.

There is no need to have the discussion about any mandate to go further, particularly in uses of surplus cash.

Our surplus cash comes from operations, not portfolio activity.

And our fundamental business strategy is targeted to keep that free cash flow growing to enable first of all growth in -- sustainable growth in the dividend.

And secondly, enough capital investment to continue growing the cash flow to be in that position through cycle, whatever the macro price.

And in the short term, with high macro, you might see what you might call surplus cash, and were we in the position where we'd already offset the script, then that may be a discussion the Board would entertain.

But we are best part of two years away from that at this moment in time.

But we are determined to offset the dilution first.

So hopefully that gives you some feel for the way we look at it.

And for now, it is a lever in the toolbox that we will use as aggressively as we can.

Okay.

Thanks.

Thank you.

The next question comes from Alejandro Demichelis from Exane.

Please go ahead with your question.

Good afternoon, Simon.

Just one clarification, follow-up from the previous question.

In terms of the buyback, you mentioned in the $4 billion to $5 billion for this year, and clearly you're not prepared to increase that to meet this.

Should we assume that if for whatever reasons oil prices were to drop in the second half of the year, that $4 billion to $5 billion may not be there?

Fair question.

Looking more at what we've already delivered from free cash flow than what we're about to deliver from free cash flow.

The oil price dropped to $70 we may look at the buyback program but for now we don't see a problem with that.

Great.

Thank you.

Next question comes from Kim Fustier from Credit Suisse.

Please go ahead with your question.

Hi Simon.

Just two questions, please.

Firstly on Alaska, I was hoping you could give us some color on the drilling program there which was postponed I guess two months ago.

Basically what are the next steps, and any color as well on the accounting treatment of the cost for this year?

Secondly on Nigeria, was hoping you could provide some updates there, how much of the 30,000 barrels a day lost in Q1 do you expect to see coming back in the next few quarters?

In other words, how much of this sabotage and theft is endemic?

Thank you.

Thanks Kim.

Alaska program, we did the two top holes.

We will not drill this year.

We have both rigs are in the yards at the moment in Asia.

One is for repair, one is for potential upgrade.

We will not take a decision on when and how we drill in 2014 until we've been through some of the work with the repair yards.

But also it's very important I think that we get all the ducks in a row this year and that we're not left with a critical path depending on any one piece of equipment as we were last year, which essentially was permitting around the containment barge.

That containment barge just for information is now fully permitted and ready to roll.

So it's really the rigs and the permitting system, so we want to see both of those progress to a reasonable level of confidence this year.

We don't want to leave it until April, May next year before we can say more.

We won't know for a month or two really, I can't give a date as to the engineering work that needs to be done.

The accounting treatment is pretty much as I said still at the last quarter results.

We have now it's about $2.8 billion on the balance sheet, just under $1.8 billion of that is the remaining signature bonus that we are amortizing slowly over time.

According to the probability of success, which has not changed, we still expect to drill.

Therefore, the probability of overall success we have not changed.

If we felt we were not likely to drill then that may have an accounting impact.

But for now, that has not changed.

The same is essentially true of the remaining balance which relates about $700 million to the capitalized cost of the wells that we have drilled to date, and the rest is basically the capital cost of the containment barge and the Kulluk drilling rig, which obviously are ongoing valuable assets.

So at the moment, we expect to spend up to $1 billion this year on both the repairs and keeping some of the work going that we need to do.

Last year we spent about the same.

We're capitalizing about 80%.

This year it's more likely we capitalize only about 20%, i.e., expense 80% of what we spend.

I can't give you a full figure.

It could be as high as $1 billion.

We look to minimize, obviously.

Nigeria.

30,000 barrels a day was essentially comparison between Q1 last year and Q1 this year.

The absolute loss is higher, it's more like 60,000 barrels a day.

Similar fact in the first quarter, I mentioned was attempted theft from a gas line, which unfortunately you can't steal, and also took us down in the LNG volumes, so quite valuable production loss.

Going forward, we have in April closed the Nembe Creek Trunkline simply because the theft is so high and the environmental damage potentially so high, it's no longer sustainable.

We need to go and remove all of the theft points.

Of course, the thieves just move to the next pipeline.

I believe [E&I] have also shut down facilities in-country.

So it's quite a difficult situation.

It's not getting any better.

I don't have a figure other than that if both pipelines were to be shut down it's quite a significant materiality in earnings terms, maybe up to $100 million a month if both of the major pipelines were to be down.

One is running at the moment, one is taken down, out of service for repair work.

It's an uncertain environment.

So hopefully that helps give you the framework we operate in, but unfortunately I can't be more specific on the actual outcome.

That's great.

Thank you.

The next question comes from Fred Lucas from JPMorgan.

Please go ahead with your question.

Thank you.

Afternoon, Simon.

Another big diesel machine ramping up in the Middle East, it's Aramco's Jubail refinery, 400,000 there of which more than 50% the product is slated diesel.

What effect do you think that will have on the profitability of Pearl GTL over the coming months?

Second question is you mentioned that you do have a focus on free cash flow growth.

Indeed that's a target for the business and that's certainly a focus for the market.

Why don't you move your operating cash flow target to free cash flow target to help the market even further and to graft the nettle over the risk of rising CapEx.

If I could squeeze a third one in, it just need numerical answer.

Can you put a number to how much of your oil sands output doesn't make it into the Scotford upgrader, so for every 10 barrels per se, how much doesn't?

Okay.

Thanks, Fred.

I'll see if I can do it justice.

The first one's relatively easy.

Big diesel machine, GTL profitability is underpinned by base oils and special products and being purely clean diesel.

So unless the Saudis can produce completely clean and sulfur-free diesel from crude oil they will not be impacting the markets where we are seeing premium pricing.

Free cash flow target growth, good question about the way we think about things.

CFFO, cash flow from operations is a target for the people who operate our assets which is most people who work for Shell.

Free cash flow is the difference between that and what we choose to invest or divest.

Those choices are made by a very small number of people in Shell and are a completely different decision process.

Our focus on CFFO growth is deliver maximum cash flow from the assets in the businesses that's we currently operate today.

It's what we focus our people on.

It's what we deliver.

If we deliver that, it gives us the choices to make on both rewarding shareholders and reinvesting.

We know roughly what we need to reinvest to be able to sustain that growth.

And that figure can change over time as you need either more growth or the individual projects change.

But for now we know what that figure is.

If we set a free cash flow target either for the Company or for you, for our own people, sorry, we would just encourage people to sell stuff.

It's simple as that.

Or to invest less but invest less in the wrong things.

So it's a question of who gets to choose on those big decisions.

And fundamentally we want most of the organization focused on safely and reliably producing, selling products to customers.

We'll reserve the big decisions on portfolio investment and ceilings and capital allocation for a relatively few people.

You say you know the level of investment that you need to get to your growth targets.

Could you share that number with us?

It's net $33 billion this year and it's net $130 billion over the figures 2012 to 2015.

Out to 2017, '18 to get to the $4 million a day.

The $4 million a day I think those are a clue in what I said earlier that we will invest in at least four projects now that have no value volume associated with them at all but will lead to equivalent cash flow growth.

I doubt that the investment is going to reduce post 2015, but I certainly have no mandate to confirm that or to give an alternative figure.

So the $130 billion if you remember the arithmetic based on what we already invested, already acquired and sold, doesn't actually allow for Repsol, I will say.

All other things being equal, you'd expect mid-30%s growth CapEx for the next couple of years, so slightly higher than we are this year.

The numbers go around and lead to delivery of equivalent financial growth 2017, 2018.

And again, could give you any growth or cash flow I wanted merely by drilling shale out in North America.

We're only going to do that when it make sense to make competitive returns.

I need to manage that red line on the graph but I don't want 87,000 people thinking they're managing it, is basically the message.

Last point, oil sands production to Scotford, the upgraders basically will process everything out of the mines.

Some of the debottlenecking we're doing at the moment will increase the upgrading capacity.

We're not able to -- the upgraders of course only produce syn crude, they don't produce necessarily a lot of finished product.

Because we put that into the Scotford refinery.

The refinery is smaller than the upgraders.

So we're actually moving upgraded crude to for example Sarnia and the West Coast, some of it's going by rail to the West Coast, and ultimately it will be most likely some synthetic crude but also some just basically straight diluted bitumen that will go to the Gulf Coast.

But at the moment, everything can be upgraded bar the 10,000 barrel a day coming out of Peace River, which is not of a quality that can go through you the upgrader.

And in future we will not -- it's highly unlikely we'll build new upgraders if and when we grow the heavy oil production further.

Our aim will be to take it into our own refining network.

Okay.

Hopefully that covers it.

Thanks.

The next question comes from Guy Baber from Simmons & Company.

Please go ahead with your question.

Thanks for taking my question.

I was just hoping you could address the environment for asset divestitures right now but your guidance this year is I believe just $3 billion, which would be the lowest total in a couple of years for you all.

Last year you ended up doing a little bit more than twice what the original guidance was.

Just wondering why the lower expectation this year.

Is it reflective of broader market conditions or is it more specifically that you all are just more comfortable with your existing portfolio right now?

Then I had a follow-up too.

Okay.

I'll try and do justice.

We start every year $2 billion to $3 billion.

That's what we would expect the business always to be looking to upgrade off the bottom end.

Previously we had slightly higher targets because we had a major Downstream program in progress for about five years.

That major program is now basically running out and we talked about Italy and the refinery in Australia, et cetera.

But these are not major factors.

We'd expect $2 billion to $3 billion.

The reason we often do more is that sometimes opportunity knocks.

Literally.

It took us three weeks to define and close the Holstein divestment for $600 million last year.

We at this point in time, we don't actually see major transactions that would take us above the $3 billion in the calendar year of 2013.

That does not mean we are not looking at the potential for 2014 and beyond, and back to the earlier question on free cash flow, that is one of our major levers.

But we don't have a higher target.

We may deliver more, depending on opportunity.

I hope that gives you some feel for how we see this.

Yes, that's perfect.

You had another question?

My follow-up was on US gas production.

Production very strong this quarter, presumably on some Marcellus ramp.

But just hoping you could provide for us the framework for how you plan to manage production through the balance of the year, and activity levels in light of some of the major variables, so Marcellus, some of the improvement we've seen in spot gas pricing.

But also just considering how materially you've cut the capital budget there for gas this year.

Okay.

Most of the current gas activity's actually in west Canada in the Groundbirch more than Marcellus, we've got twice as many rigs there.

We're also producing some gas in the Eagle Ford along with the liquids.

That's helped some stronger gas production.

In practice going forward, we've taken about 25% of the rigs out in North America from this time last year, and that's partly because we reallocated the high level CapEx to other parts of the portfolio.

Prices now are $4.30 I think in gas terms, even at that price it's probably still more attractive to keep the rigs very much on the liquids-rich shale appraisal activity as much as production as well, and to ensure that we're drilling out for example the China, Ukraine exploration opportunities.

So we're not actually planning or aiming to ramp back up again in a material way in North American gas at this point in the market.

Okay.

Thanks for the comments.

Next question comes from Hootan Yazhari from Bank of America-Merrill Lynch.

Please go ahead with your question.

Thank you Simon.

Two questions please.

Starting with a very simple one.

How should we be thinking about the CapEx figure for this year all in with all the different portfolio activities you've conducted both on a gross and net level?

And then going forward, just to get a clear idea of you how you're thinking about project planning, et cetera, how are you looking at projects that add value to Downstream in the United States versus your growth targets for 2017 and '18?

Is there a case to start to push up the -- some of the potential LNG, GTL, GTT, et cetera, projects up the chain, and thereby displace some of the growth there?

Or do you feel that -- or would you be more willing to relever the balance sheet up and include everything?

Thank you.

Thanks Hootan.

CapEx for this year is fairly good question.

Actually the Board's asking that at the moment.

Other than $34 billion plus $2 billion which is the official statement plus Repsol.

I have no real change to make.

$34 billion organic, plus $2 billion acquisition, which is completing last year's Beryl, Schiehallion, Iraq, and less $3 billion divestment, net $33 billion, add back Repsol, which is effectively $4.4 billion of cash, less whatever we have in the lock box when we open it.

And Repsol might be next year in practice as it happens.

So a lot of the things I've talked about in portfolio terms were already allowed for in what I've just stated.

And won't really impact CapEx until future years.

We'll update as we go through the year with more detail.

Obviously as I answered the previous question on free cash flow, portfolio activities will be discussed and agreed from Board-level down with the free cash flow objective in mind.

And projects Downstream in the US.

Actually there are quite a few opportunities, everything ranging from buying rental cars to LPG exports to tweaking the refineries to process the crudes that are available, all being thought about and progressed, not just by others as well of course at the moment.

In absolute materiality terms, not yet that significant.

Will help to grow CFFO or protect current CFFO.

So very much part of the thinking as is the same thinking around gas, where will the gas get moved within the continent.

The big projects to monetize -- we've already talked about Elba and the gas to transport projects.

These are what we might call the medium size projects committed on those export LNG.

Big projects, Canada LNG's pretty much the highest priority.

That we do need to get moving because of the good partners we have there, getting that gas to Asian markets.

Gas to liquids, gas to chemicals, very much in the mix in terms of optionality.

Unlikely to see a whole lot of CapEx in that period up to 2015.

Could we accelerate?

Would be a challenge for engineering reasons more than anything else.

But they are more the projects we will invest in in the second half of the decade that will deliver the growth out beyond the '17, '18 period rather than for the '17, '18 period.

Hopefully that gives you some feel for the phasing.

That was very clear.

Thank you, Simon.

Thank you.

The next question comes from Jason Kenney from Santander.

Please go ahead with your question.

Hi Simon.

Thanks for taking the call.

It's been quite a long question and answer session for you, I understand.

I've got a query on the tax charge, the underlying tax charge, which I think was around 38% in the quarter versus perhaps a more normal 45%.

I did notice that there was the tax credit and resource of $730 million, which compares to the whole year 2012, $629 million.

So if you could just give me some detail around tax and that tax credit in particular.

And then maybe secondly on the gearing at 9.1%, have you got a view of where gearing might exit 2013 if Brent oil price stayed at $100.

Thanks Jason.

Tax charge, two things really.

Structurally the more the Downstream makes in proportion of the total, the lower the effective tax rate.

But there are some one-offs mentioned in the identified items, Australia, and there was one, a court judgment went in our favor in Europe.

So it's over $600 million effectively of tax credit and identified items.

The actual underlying clean effective tax rate was 42%, which compares with about 44% a year ago.

So it is going down, but that shift is mainly the Downstream being more high percentage of the earnings.

9% gearing, good place to be if we execute all of the buybacks and if we just stick to the net CapEx I've just talked about, plus paying for Repsol, then it's not going to go down further I don't think.

Having said that, there are quite a few things that could change between now and then.

Our range is zero to 30%.

My aim is to keep us at the lower half of that because our rating agency friends look at everything that's not on the balance sheet also, which actually make the effective gearing a bit higher than 9%.

Thanks, Jason.

Next question.

Thank you.

The next question comes from Lucas Herrmann from Deutsche Bank.

Please go ahead with your question.

Thanks very much.

Simon, afternoon.

Two if I can.

First, just Chemical, if you could talk a little bit more about the performance, doesn't seem the environment's changed dramatically but the profit performance certainly appears to have.

Secondly, a broader question.

Are you happy with the way that cash flow is developing, vis-a-vis your forecast?

And the question's simply the guidance broadly was the $100 over the four-year period, $200 billion or so -- yes, $200 billion or so of operating cash flow.

$46 last year, you're annualizing at $110 this year, somewhere near $44.

Kind of says $110 is what you'd need in '14, '15.

So are you happy with how things are developing?

Or are we really looking for -- are you really expecting of a step change as Gulf of Mexico barrels come on in '15 and Gordon comes on in '15, and those businesses start to make a material difference to the cash delivered?

Thanks, Lucas.

Good afternoon.

Chemicals performance is generally pretty solid around the world, even in Europe we had base Chemicals performance improving and seeing reasonable demand and margins.

In Asia-Pacific, good place to be in some of the more specialist products, the intermediate products, monoethylene glycol, MEG, and the ethylene oxide, so just generally well positioned business and benefits compared to, say, four, five years ago fundamentally from the switch to ethane feed in the United States.

So quite a robust performance, great outcome from Ben's time in charge.

The general CFFO developing, am I happy?

Lucas, I'm a CFO.

I'm paid not to be happy.

Clearly there are quite a few areas that I think we can improve on.

But strategically and structurally the big projects are either up and running or they're in place.

The growth you're absolutely right needs to continue from now to the end of 2015 to meet those overall expectations as to $175 billion to $200 billion over the four years, or to put it simply you have to get to $50 billion a year of cash flow and then push on from there towards $55 billion and beyond.

So first to get to $50 billion, there is improvement, underlying improvement whether it's cost and the unit margins we generate, the improved customer profitability, lots still to come, Downstream and to be honest Upstream and just doing things better in the business.

It's not big projects, it's the 87,000 people doing the right thing every day and doing it a bit better tomorrow.

There are some major projects coming through, clearly.

[Majanine, Cashighan], obviously Basrah will start to kick in.

We are seeing LRS kicking in.

Now Majanine and Cashighan will make little difference this year, hopefully see some performance next year.

You mentioned the deepwater projects.

Yes, Mars B, Cardamom, and BC-10, together with in '15 definitely we'd like to see Gorgon producing.

Those big projects will certainly make a difference, we're talking multiple billion uplift there.

But fundamentally the challenge today for the next 12 months is primarily steady progress Downstream and Upstream, taking the extra dollars out of the flow of the hydrocarbons that we're involved in.

We've always said these are ambitious targets and whatever way you do the arithmetic, we're a bit behind the curve, and some of that we can look at the macro, some of it is things that we ourselves work on.

I will only say that if you look at the competitive performance, we might behind the curve against our own aspirations.

We seem to be ahead of everybody else's curve.

I'll stop at that, Lucas.

Simon, I'll let you stop there.

Listen, thank you.

Thank you.

The next question comes from Stephen Simko from Morningstar Equity Research.

Please go ahead with your question.

Hi.

How are you doing?

Simon I just wanted to ask you.

I believe it was last quarter you kind of gave a sort of multi-quarter view of Upstream Americas and sort of how things would progress in terms of production coming online from liquids-rich shales and the profitability coming from your Gulf of Mexico projects that will be coming -- starting to come online next year.

I was just wondered if you could again for investors looking at just how profits are going to trend up from here.

Hello?

Can you hear me okay Simon.

Yes, I can hear you.

There's a little bit of background noise.

The Americas, I shy away from production forecasts.

But we are established now our 320,000 of production a day on-shore.

We're about 190,000 in the Gulf, the deepwater offshore.

That 190,000 was a bit below trend.

Some planned maintenance, some down time in the auger platform.

We're ramping up still production in Great White, Perdido.

So there are still production to return in the Gulf.

There is production to grow although not as quickly as we have done over the past three to four months over the rest of this year.

The oil sands was producing pretty much a potential in the first quarter, it was a good quarter performance.

The production growth should be steady and the income should come with it this year.

The major projects are next year, that's Mars B and Cardamom in particular, and when we report Upstream Americas we include Brazil.

So the BC-10, [Vigiperis Selama], both have additional production coming on next year.

So next year is where you'll see some of the step-up.

It's more a steady growth this year as we improve the effectively the availability and the on-shore production.

Great.

Thank you.

That was the last question.

Please continue with any points you'd like to raise.

Okay.

If that's the last question, thank you and it's been quite a tour around the world.

Thank you for your questions.

Thank you for your interest.

The second-quarter results will be released on August 1, and I hope that's not too late for you and your holiday plans.

I look forward to talking to you again then.

Thanks very much for listening.

Take care.

Thank you.

That concludes today's conference.

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