殼牌 (SHEL) 2016 Q2 法說會逐字稿

Welcome to the Royal Dutch Shell 2016 Q2 results announcement. There will be a presentation, followed by a Q&A session.

(Operator Instructions)

I would like to introduce the first speaker, Mr. Ben van Beurden. Please go ahead.

Thank you very much, operator. Ladies and gentlemen welcome to Shell's second-quarter 2016 results call.

Let's start as usual with the disclaimer statements, and then it has been just two months since we had a capital markets day where we gave an update on Shells' transformation strategy, which is to create a world-class investment case for shareholders. What I want to do is recap on that a bit and then Simon will take you through the results and the progress that we are making with the financial framework.

Let me say that our downstream and our integrated gas business has delivered strong results this quarter. Although the low oil prices due continue to be a significant challenge across the business and particularly of course in the upstream.

I think overall when we look at Shell's results, we are in a transitional stage in 2016, where we -- there have been large movements in our figures for the BG purchase and consolidation, the restructuring charges, and the build up of [debt] amplified of course, by lower oil prices. All of this comes in a period where we have substantial cost savings, spending reduction programs underway, combined with a large divestment program and a strong development pipeline.

So altogether, this is a very complex period for the company. But as these actions all come together in the next several years, we are reshaping the company to create a world-class investment case for shareholders.

We are firmly on track for $40 billion underlying operating cost run rate at the end of 2016. We are delivering on a lower and a more predictable investment plan around $29 billion this year, of which some $3 billion by the way is non-cash. We are progressing $6 billion to $8 billion of asset sales this year, and that's part of the $30 billion divestment plan and delivering profitable new projects of $10 billion a year of cash flow potential in 2018 and eight startups just in 2016.

As you know we segment the portfolio and a number of strategic things, we have our cash engines that need to deliver strong and stable returns, a strong and stable free cash flow that can cover the dividend and buybacks throughout the macro cycle, and then leave us with enough money to fund the future. Our growth priorities have a clear pathway toward delivering strong returns and free cash flow in the medium term. And our future opportunities should provide us with material growth and cash flow per share in the next decade. Through all of this, is our attention to be in fundamentally advantaged positions with resilience and running room. And asset sales have an important role to play in all of these strategic themes as we reshape the company.

By running through all of this, there's a great emphasis on uptime, on cost, and delivering profitable projects right across the company. And examples you see here are all from the upstream business, so lower unit costs, typically down 15% to 20% from 2014 levels. And higher production overall, that is a combination of more effective maintenance programs and the successful delivery of attractive growth projects. An example, our underlying oil and gas volumes increased by 2% Q2 to Q2 all part of the drive to further improve efficiency as well as uptime.

Let me update you in the competitive position. Gearing has increased with the BG transaction and we want to reduce that level over time, of course.

Returns and free cash flow are now in decline for the industry due to the oil price downturn and for Shell, our 12 month rolling free cash flow of some negative $13 billion includes the BG purchase price and is running at some $6 billion negative free cash flow on an organic basis. And total shareholder return, which in the end is how you and of course we ourselves measure our performance, well we have improved in the last 12 months from a low baseline.

But overall there is a lot to do here. But I believe that by doing a better job on delivering higher and more predictable returns and free cash flow per share, and underpinning all that with a conservative financial framework, then we can create a better investment case. Indeed a world-class investment case.

Simon will next update you on the levers as well as the results that we have announced today. Simon, over to you.

Thanks Ben and good afternoon to all. First, on the financial highlights we've seen a sharp decline in oil and gas prices compared to a year ago, reflecting primarily the OPEC policy change and Brent [out] reached $46 per barrel in the quarter, $16 a barrel lower. At the same time, the downstream industry margins were also lower both in refining and in chemicals. And these macro effects have dominated in the results this quarter despite the strong progress we are making on underlying costs.

Excluding identified items, Shell's current cost of supply or CCS earnings were $1 billion, that's 78% decrease in earnings per share from the second quarter 2015. On a Q2 to Q2 basis, we saw an increased loss in the upstream and lower earnings in integrated gas and in the downstream.

The return on average capital employed was 2.5%, excluding the identified items and the cash flow generated from operations was around $2.3 billion or $4.8 billion excluding working capital. Our dividends distributed in the second quarter were $3.7 billion or $0.47 per share, of which $1.2 billion was settled under the Scrip Program.

You'll find more detailed waterfall charts that show the movements in earnings for each business as an appendix to this presentation. And some guidance for the third quarter, I would be quite happy to take any questions you have on that.

But in summary, at the group level, macro effects, oil and gas prices, and the downstream margin movements against the nearly $3 billion reduction in our earnings, excluding identified items compared to a year ago. These environmental impacts are the dominant feature of the results. The remainder of the results is a combination of higher depreciation charges and the other effects such as taxes with an uplift from volumes, lower expiration charges, and lower costs. And that is comparing Shell plus BG this year against Shell alone a year ago.

And turning to the balance sheet and the cash position, the cash flow generated from operations on a 12 month rolling basis was some $19.6 billion (technical difficulty). And that was at an average Brent oil price of around $43 per barrel. The gearing at the end of the quarter was 28%. This is a slight increase compared to the end of the first quarter, as we had expected, and priorities for cash have not changed. First, debt reduction followed by dividends, then by decisions on capital investments, and/or share buybacks.

Looking at the integration contribution from BG, the production from the key legacy BG growth asset continues to ramp up well. In Australia QCLNG in Queensland have both LNG trains running at full design rates of 4.25 billion tonnes per annum. In Brazil, our deepwater production has reached around 200,000 barrels a day. The Petrobras operated eight FPSO, floating, production, and storage units on Lula Central in the Santos Basin, have started production in the last few weeks and the ninth FPSO in the same basin should be onstream later this year.

On the synergies, no change to the guidance, $4.5 billion of annual synergies in 2018. And we have already actioned the steps that will deliver around half that figure. These include office closures, the staff reduction, expiration savings, and reductions in our overhead.

Returning to the financial framework, this particular slide we used on capital markets day last month, summarizes the potential from the levers that we are pulling to manage the financial framework in the downcycle. There is no doubt, 2016 is a challenging year and will continue to be so. Because it includes all the deal effects, reduction in cash flow that we've see in the first half from oil prices, and the negative working capital effects that are generated, at least in part, as the oil price is recovering somewhat.

Now the potential outcomes here reflect the actions by all of my colleagues in Shell, all 90,000. And in practice they reflect a reset of the way that we are doing business, particularly in terms of the underlying sustainable cost base. The levers we are pulling here are individually and collectively material, they will make a difference over time.

Now just looking at each in turn. Firstly, the asset sales. We are using asset sales as an important element of the strategy to reshape the company. It is not just about managing the balance sheet. Up to10% percent of our upstream oil and gas production is earmarked to sell. These include several country positions and a number of midstream assets for sale into our MLP, the Master Limited Partnership vehicle in the United States but also downstream positions. This is a value driven, not time or schedule driven, divestment program and is an integral element of the overall portfolio improvement plan in support a strategic intent.

Asset sales in total are expected to reach $30 billion for three years 2016 to 2018 combined. And to keep it in perspective, although a large number, this $30 billion is about 10% of our total balance sheet. We have currently some $3 billion of transactions underway, of which, $1.5 billion already completed and we would expect to see significant progress towards, and including sales agreements, on around $6 billion to $8 billion this calendar year. As we've said before, we are not planning for asset sales at giveaway prices. And there is no reason today to think that the $30 billion figure will not be achieved.

Looking now at the capital spending, our capital investment is being managed in the range, $25 billion to $30 billion per year through to 2020. This is as we improve the capital efficiency and develop a more predictable flow of new projects. At the end of the second quarter, the rolling average capital investment was $31 billion, including the full four quarters of the BG investment. We are firmly on track for the prior guidance of $29 billion this year, which is some 38% lower than the pro forma Shell plus BG levels back in 2014.

Our capital investments of course does include some non-cash items, such as, and primarily, the finance leases for FPSOs. 2016 is an unusual year here, as the total leases should be around some $3 billion. This is included in the capital investment guidance, the $29 billion number but most of this has yet to be booked. It will come through in the second half of the year. And there are, in addition, some decisions ahead of us on idle rigs, unquote, which is committed spend, which may move between OpEx and CapEx spending on how we choose to utilize the rig. I would encourage you all to take a look at the cash investment element of capital investment, that is shown in the cash flow statement. As well as looking at the headline capital investment that we quote on an all-in basis.

The chart here shows the cash spending as well. At which you can pick directly from that cash flow statement. The difference between the two, to reiterate, expected to be around $3 billion in 2016. And that's in addition of course, to the fact that the expiration expense is also not deducted from the cash from operations.

So to operating costs, the third of the prime levers we are pulling. We are delivering major reductions here already and more to come. In the statements that you can see today, the costs shown do include identified items. This particular slide we are showing here adjusts for this. Shell's stand alone costs reduced by $4 billion, around 10% between 2014 and 2015. And we are seeing pretty much the same 10% reduction on a Shell plus BG basis in the 12 months to June.

We are firmly on track for our previous guidance of a 20% reduction between 2014 and the end of 2016 on a combined basis, therefore reaching a $40 billion underlying run rate at the end of this year. Just as a reminder, some 40% of our operating costs are actually direct staff costs. Significant reduction programs underway here, and perhaps you will have noted the identified item on redundancy in restructuring in the quarter. So overall on costs, this clearly remaining potential for multi billion-dollar per year savings on an after-tax basis.

The fourth and final lever of course, is delivering profitable new projects that turn prior investments into future free cash flow. By 2018 the startup since 2014 in the combined portfolios, should be producing more than 1 million barrels a day. Primarily high margin barrels, with cash operating costs around $15 a barrel and a 35% statutory tax rate. By end of second half of 2016, we expect to see contributions from some major products, including Stones in the Gulf of Mexico, the deepwater, the Gorgon LNG project in Australia and Kashagan oil project in Kazakhstan. These startups in 2016 should add more than 2,015 -- oh sorry, 250,000 barrels oil equivalent per day, $3.9 million tonnes per annum of LNG for Shell shareholders once they are fully ramped up.

We have also been reordering our priorities for growth projects in the next decade. The LNG Canada joint venture recently announced the postponement of final investment division. Today, we have updated the Lake Charles in United States, the LNG final investment decision there is also being delayed out of 2016. On the growth side, we have launched new petrochemicals investments, with final investment decision in China and in the US this year already.

Looking a bit further out, we have had success with the drill bit this quarter. We are delighted to announce a new exploration discovery today in the deepwater Gulf of Mexico. Initial estimated recoverable resources for the Fort Sumter well of more than 125 million barrels oil equivalent, and this is 100% Shell activity. Further appraisal drilling, planned wells and adjacent structures, could considerably increased recoverable potential in the vicinity of this particular well, but that in itself builds on recent Norphlet, this is the Norphlet play [exploration] success at Appomattox first in 2010, Vicksburg in 2013, and Rydberg in 2014, bringing the total resources added by exploration in the Gulf for Shell since 2010 to over 1.3 billion BOE.

And of course all of the discoveries noted on this chart potentially, will be able to produce through the Appomattox project which is already under construction. Well with that I will hand that back now to Ben.

Thanks very much, Simon. So in many ways 2016 is going to be a transition year for us. Low oil prices and therefore lower results coinciding with a betting down of the BG deal that we are doing now, and coming to a large extent ahead of the delivery of cost savings, asset sales, and project growth.

But I want to be very clear with you that we are on a pathway here or an ambitious transformation of the company. So higher returns, higher free cash flow, despite lower oil prices. And has a lot of energy and enthusiasm in the company to deliver all of this. And BG of course, is a fantastic opportunity and it's a natural way for us at Shell to align on what needs to be done.

And with that, let's go for your questions. Can I please have one or two of you each so that everyone has the opportunity to ask a question in the time that we have. Operator, can have the first question please?

(Operator Instructions)

We'll take our first question from Oswald Clint from Bernstein.

Thank you very much.

Ben, first off, talking about Brazil and the progress you are having there, obviously as we look forward to the next years of the growth that's coming from the Replicant FPSOs in Brazil, I'm curious just to understand what you are seeing there, your comfort level with the progress of those FPSOs coming onstream starting in 2017 onwards. I think an update there would be quite useful.

And then, Simon, please, trying to get to as clean as possible a cash flow number for the second quarter, as I get the $4.8 billion adding back working capital. But if we start to add back the restructuring redundancy onerous contracts and maybe there is something for Canadian costs in the quarter for fires, trying to get back to a cash flow number that might be as clean as possible for the quarter. I'm wondering if you can help us get there, please. Thank you.

Okay, thanks, Oswald.

Simon, you want to start with the cash flow?

Thanks, Oswald. Maybe a question of interest to everybody.

We all know quarterly cash flow can be a noisy number. Particularly when we are bringing the two companies together, there is movement around working capital et cetera. The $2.3 billion headline can be adjusted clearly for working capital, $2.5 billion. We would probably adjust slightly downwards then for the cost of sales adjustment, but back up again for a $700 million charge tax on divestments. As that is unique to the quarter as tax on a prior-year divestment.

And there are one or two other moving pieces as well. But fundamentally, the last three quarters taking into account some of the one-off's, have all been around $5 billion. That's taking into account an oil price not much higher than $40 on average. And therefore that's reasonably representative, if you also take out some of the intra-quarter variances. I'm not sure if that helps a great deal.

But going forward of course, you are right, that the provisions on severance and redundancy and idle rigs, et cetera, may flow into cash flow flowing out. But of course that would be offset by delivery on the OpEx for synergies, and most importantly on the new projects, all other things being equal. It is running at a run rate of around $5 billion, but coming back up again, up from what essentially would be a low point in the first quarter.

On Brazil, Oswald, at the moment we have nine FPSOs onstream. Number nine, mentioned by Simon, came onstream in Q2.

If I look at 2017, there are three more, including the Libra extended well test FPSO; 2018, another three; and then a further three in the 2020-plus timeframe.

Can I have the next question, please, Operator?

The next question comes from Iain Reid from Macquarie.

Hello. Simon, just a quick confirmation on your sensitivity data you gave us on page 10 of the earnings release on the upstream. When we are looking at this $3 billion per annum for every $10 move within Brent on a year-on-year basis, I presume we have to include in that comparison the BG earnings from the year previously when we're trying to do a quarterly estimate of how these numbers are really going on an annual basis; is that correct?

Yes, well, of course the volumes are moving as well. But in the first instance, the simple answer is, yes.

I will put on record, I do not often have sympathy with you on the modeling. But just at the moment I do, on the grounds there are quite a lot of moving parts; and this indeed is one of them.

We've tried to help around the $3 billion -- you're absolutely accurate on the upstream -- and also $2 billion sensitivity within integrated gas, which is overall a $5 billion sensitivity. But of course integrated gas has the added complexity of most of it being time lags by 4 to 6 months on average.

Just to reiterate, in Q2 our gas price variance was impacted more by Q1 oil prices than by Q2 oil prices. It was probably at the low or at least in the recent trend that gas prices would have been a low.

We'll do what we can to help, Iain. But you are absolutely correct that it does include the BG volumes. Thanks very much, Iain.

Can I have the next question, please, Operator?

The next question comes from Brendan Warn from BMO Capital Markets.

Thanks, gentlemen, I will keep it to one question.

Similar, along the lines of what Iain asked, in terms of the transition period that you talk about, the deal affects working capital and tax. And if we just focus in on upstream, if I think for a year -- lets say, Q2 2017 -- and if we kept oil price out of it, what sort benefits are we going see in the upstream because of synergies? I'm trying to understand what would be a clean result projecting for the year.

That's a tough question, Brendan; but let's see how much we can help you with it.

Simon?

It might too tough for me, Brendan; but let me try.

I think you need to watch three things. The costs are coming down in a straight line. We've have had $40 billion for total for the full year. On an underlying basis by the end of year, they'll probably come down a little bit in absolute terms, next year as well. It's going at a run rate of around 10% on the costs. And that's across all the three businesses in which the downstream is just below 50% of the total.

And I guess in integrated gas, it is about 25%. I'm sorry; integrated gas is more like about 12% to 15%, depending on the quarter. So that's an indication.

The synergies will kick in, for example, on expiration almost all in the upstream. And pretty much, the $2 billion would delivered by the end of this year on a run rate. So there's a significant contribution there relative to -- you go back to the 2014 timeframe.

Important factors for the upstream will be the new projects, where Stones will be onstream by then and should have ramped up. Gorgon, in the integrated gas business, will have two trains hopefully working by then. Kashagan will be beginning to play through. And the Shell focus at the moment in the US is developing the Permian. There should be improved performance from that. But all of those things coming through should include the revenue, all other things being equal.

What I will say on the earnings though is that early production from deepwater, Stones for example, comes with very high unit depreciation because of very low early proved-reserved bookings until you have established production record in areas where you have no analogues. Stones and Appomattox, for that matter, are both the new areas where there are no at-reservoir analogues, so will both come with high unit depreciation. Average cash operating cost, to reiterate, $15 a barrel.

The only thing I could add is to repeat what I just said in the speech. Effectively, the startups this year will eventually get to 250,000 barrels today and 3.9 million tons of LNG. But both Kashagan and Gorgon have quite long ramp up periods. I know that doesn't quite answer the question, but those are the basic factors to watch. And we will try and update on the actual progress on a quarter-by-quarter basis. Thanks.

Thanks, Brendan.

Operator, can I have the next question?

We'll now take the next question from Lydia Rainforth from Barclays.

Thanks and good afternoon. I will stick to one question as well.

And I hate to come back to the upstream side again. But just in terms of when you are looking at the results from the first half of the year, a question comes up with the idea of are you happy with where you are on the cost side? Or are you looking at those results and going, actually, maybe, we need to go back to the beginning and see if we can take out even more than we have done already -- that we need to have another look at how we're doing things? Thanks.

Thanks, Lydia. Let me make a few general comments, and then maybe Simon wants to fill in on a bit more detail. No, we are not happy on the cost takeout where are at the moment. We are on a journey of cost takeout that will take us, as I said, by the end of the year to an underlying run rate of $40 billion per year. I think it is sad to say that we have made a lot of progress in all areas. Probably in upstream, we have made, relatively speaking, most of the progress. The downstream has been a longer cost journey, and of course has never really had the comforts that a very profitable upstream business has. where the focus was indeed on delivering value, even if it involves somewhat more marginal cost.

And integrated gas of course has a smaller cost base to start off with. So, yes, the focus is very much on the upstream. But if I just look at where we are right now -- and I'll now talk about total number -- but you can imagine with most of the progress being made, how the total number is actually different if you were to look at upstream only.

We are now running the Company with an overall cost base, BG and Shell legacy combined, that is lower than what the Shell-only costs were in the same quarter last year. So there is a significant amount of momentum that has been established, but this momentum has not traveled to the end point in my mind, Lydia. So there's probably more to come. And of course here we talk about operating costs.

We haven't spoken about capital costs yet. In capital costs, there is a similar thing going on. A combination of the general cost deflation that we see in the industry, that we are doing everything with our supply chain to either help bring about or capitalize on. But also, re-scoping projects so that they are actually costed and configured, in terms of scope, for oil price resilience rather than volume maximization. So what you see is that the unit capital cost is also coming down quite significantly there.

And that is one of the reasons why we actually managed to also significantly drive down our overall capital spending. If not just only a matter of expounding or canceling projects; it's also making sure that we get more bang for the buck because of the improvements in capital intensity.

Simon?

Thanks, Lydia.

Are we happy? I think positively pleased or inclined about the pace at which reductions have come through so far, but we are far from finished.

There are severance or redundancy-related chargers and restructuring, mostly obviously in the results, but pretax close to $1.5 billion. This will not be the end of that story because this does not yet reflect all of the reductions in employee numbers that we have already announced -- the 12,500 people. There will some ongoing noise as we go forward because future reductions do have a little bit cost upfront. And that we'll come through over the next couple of quarters.

We also see potentially some noise from third-quarter reviews on things like impairment, decommissioning and restoration. But fundamentally, we have just brought two companies together. And we are still learning a bit on the underlying implications on short-term performance and the quarterly movement.

So while we'll do what we can to help you, it is still going to be a bit of volatility, seen from your perspective, for a couple of quarters yet. The aim is to be as one Company, clean as possible, as of next year, starting with the first quarter.

Thanks, Simon.

Thanks, Lydia.

Can I have the next question, please, Operator?

The next question comes from Martijn Rats from Morgan Stanley.

Hello, good afternoon. I wanted to ask you two things.

First, I'm still trying to figure out why the results were so weak as they were. And one area, where at least relative to our forecast, there seems to have been some differences is in terms of price realizations. So the oil and gas prices that you report, relative to what we expected based on benchmark crude and gas prices, seems quite low.

Now, on the one end you could say, Martijn, your model wasn't very good. But at the other end, we weren't very different from what others were forecasting. So perhaps there is a more general point to it. Would you say that conclusion is correct -- that price realizations were relatively low relative to benchmarks? And if so, is there anything that explains that?

And the second question I wanted to ask relates to the debt because the debt did increase by a decent amount during the quarter, from $69 billion to $75 billion. And I know on the last call you said that the debt would continue to be on an upward slope for a bit. But would you still say that it will trend up from here on? Those are the two questions.

Thanks Martijn.

Simon, why don't you take them?

Obviously, I can't comment on either individual or aggregate models. But do remember on price realizations the North American gas prices that we quote were quite heavily exposed to Alberta eco prices, which were lower than Henry Hub. And we also take first of the month, which was lower than the average through the quarter.

Global-realized prices associated with the integrated gas business, there is that three-four month to six-month lag. And JCC was quite a bit lower, relative to expectation, then Brent headline. Those are both factors that impacted price realization, possibly more than the modeling when have thrown up.

But let me just make a general statement. I appreciate that three-month is of interest to you, and it helps you reset your models. There is nothing in these results that has any impact on longer-term, medium-term, intent for both improved performance and that strategic delivery that we talked about 2019 through 2021.

There is a lot of underlying noise. If there was a one big single factor and it was pertinent to the longer-term, we would be telling you about it. There's just a lot of -- and there always is actually -- $100 million, $200 million, here/there. It's just that the math of them was quite negative this quarter, as opposed to normally when they tend to washout. So I don't think there is too much point in going on further about the quarter. It is not that relevant in terms of the longer term.

Also just one reminder, in the prospectus for the BG deal, we said earnings-per-share accretion in 2017 at $65 a barrel. That's what we said in the prospectus. At $46 a barrel, we are doing well; but it is a stretch to get earnings accretion out. That is what we said, and that was after delivery quite a bit of synergy.

And the deal -- everything to do with deal -- on track to deliver value. And on the debt, it may go up before it comes back down; and the major factor is the oil price.

The second factor is the divestments. The divestments, I spoke about earlier -- in practice, the contribution this year to the bottom line is likely to be limited. And that's why the debt may go up before it goes down.

Thanks, Simon.

Thanks, Martijn.

Can I have the next question, please, Operator?

The next question comes from Jon Rigby from UBS.

Yes, thank you. Two questions.

The first is on upstream. I take your point that you can't infer too much of the future from a quarter to quarter. But you have given sensitivities for your upstream business. And if we look Q1 to Q2, there seems almost no leverage to the $10 rise in the oil price in the upstream now.

I know it's post-tax, and I know there's some moving parts. But I would just like to understand a little better what those moving parts might have been that would offset the phenomenally $750 million gain or improvement that perhaps we ought to have seen in that quarter, sequential.

Second, you mentioned the dropdowns into the MLP. Could you go through the (inaudible) mechanism for that. Would that involve equity raises in the MLP rather than debt so that you are not re-consolidating MLP debt? And is that $800 million a net number -- so obviously it would be higher for the gross figure that is being dropped down? Thanks.

Thanks, Jon.

Simon?

On the MLP equities first, it is new equity raised, Jon. If we raised that, then it wouldn't show in what we comment upon. But the entire MLP is consolidated. We actually have more than 50% of the MLP units anyway still. But as long as we control the GP units, it will remain consolidated. It remains possible that we sell down MLP units over time. And they potentially count as divestments as well.

And on the upstream Q1, Q2, let me try. We reclassified Woodside; therefore, it's held available for sale. Its price went down. There's $100 million negative; that happens to be in the integrated gas results. And $100 million reduction between Q1 and Q2, simply because of lower production.

Fires in oil sands, $70 million; we all know that happened. Majnoon, we spend less money -- reduces the earnings in Majnoon from a drilling effect. We had a planned shutdown, Mars in Orga, $50 million. Italy, Val d'Agri, shutdown; that is known in the public domain; it has been known, $50 million. It's a very long list, Jon. And there are at least four others, several hundred million in total associated with BG.

There's an FX movement on a not entirely hedged still in holding. It's just they are all individually in the wrong direction from both your view point and our view point. None of those things I just stated are relevant longer term, except I would actually like the cash in the back pocket today. But that is not how it is. Going forward, it won't get repeated.

Sorry, I can't -- there is no more I can say on that. It is just a long list of individual items that are different. And just to repeat what I think the guys and I have been saying, sequentially is not always a good basis to look at Shell. Although I do fully appreciate that you cannot go back to last year and easily translate BG.

The one thing I would just reiterate is that the PPA step-up on the depreciation remains $300 million a quarter, so $100 million a month. And that is a factor that you won't get if you just add Shell and BG.

Okay. Thanks for that, Simon.

Thanks very much, Jon. I'm sure a question that was on the minds of many of you.

Can I have been next question, please, Operator?

The next question will come from Thomas Adolff from Credit Suisse.

Only a question is for Simon this time.

Simon, I have a feeling that you might be -- I am probably the wrong person to say that -- you are being a bit conservative on the underlying cash flow during the quarter if you ex out the restructuring charges. Yes, cost savings cost money. But they're, at the same time, structural in nature -- at least a good chunk of it.

So I believe, at least I think, when you make these adjustments, ex the restructuring charges, actually cash flow is more $5 billion. And should we be using that as an underlying cash flow of the business as it stands today?

And following on from that, if you think about restructuring and redundancy charges, how much has already been cured or impacted; how much has impacted your cash flow; and how much more is there to go? And my final question on working capital in the first half of the year. If you ex out Iran, how much of it is reversible? Thank you.

Good questions. We all had to smile at your first one because it's we have debated that one as well.

Simon, why don't you take them?

I did a similar break down of the smaller items. You are right, Thomas; it is above $5 billion for the quarter. But I deliberately gave average over the last three quarters. They are reasonable.

It is a reasonable basis. But where there is an underlying uptick in Q2 -- although, as with the earnings, it is impacted by one or two one-off items as well. I am generally not sure I can say too much more about that.

Restructuring, how will they flow through? Well, quite a lot of those are not yet cash. There's about $1.5 billion associated with the redundancy and restructuring pretax. About $0.5 billion on the idle rigs. And some of that is in, but most of that is still to flow through the cash line.

The working capital in Q1 had $2 billion out for the payment to the National Iranian Oil Company. But over the two quarters as a whole, there is a stock build -- an inventory build, as well as a price movement, that has impacted working capital. We would expect about half of the inventory build to come back, so a couple of billion dollars to come back, over the rest of the year. Much of that inventory build was in the trading business and is revenue generating, but around a couple billion dollars should come back.

The rest is essentially price-driven. And there are one or two -- should we say, not easy to explain -- movements around the longer-term provision. And once we are through some of the work in the third quarter and the DNR, the decommissioning, you will see some quite big movements on the pension liabilities as well. We'll probably be able to give better fix.

We're still working on bringing, remember, a $67 billion set of assets onto a $220 billion balance sheet, and working through some of the details. Now, you are talking about relatively small movements, but on very large numbers.

Thank you, Thomas.

Thanks, Simon.

Can I have the next question, please, Operator?

The next question comes from Alastair Syme from Citi.

Thanks, can I quickly follow-up on the last question actually?

So all the restructuring charges you've taken, being accrued -- or are you putting anything straight through to cash flow? Is there anything sort of bypassing working capital we need to think about?

And secondly, can I clarify what you have done on Woodside? There's a note in the statement you've reclassified the way you are counting it. Thank you.

Yeah, both the questions are for Simon.

There is some cash effect from the restructuring, but it is relatively small. I only picked the two items, the idle rig and what essentially is redundancy payments and restructuring for the office leases. Where there a certain office buildings that we will vacate before we can subcontract or otherwise deal with the lease. But we are taking payment there into the P&L but not the cash payment.

So it will play out. Most of it will play out in the next six to nine months. But it is likely, to reiterate, that there will be further redundancy charges because we do not yet reflect all of the 12.5 thousand changes that we've previously made.

At Woodside, the shareholding is 13%, give or take. It has long been there effectively as an asset, with not a long-term strategic intent to hold. We have recently seen one of the Shell-appointed directors retire, and we do not have the right to replace. So we have gone effectively from two to one director. Therefore the influence level has fallen below that of which we can recognize the investment as an equity associate.

It is now held as an asset for sale, so there will be quarterly volatility in the earnings that we see. But importantly, there is a production and a reserve impact because we no longer will recognize the 25,000 barrels per day of production; that is the 13% share equivalent. And then perhaps a 100 million barrels of reserves will be de-booked because we no longer have sufficient influence to continue booking them.

So there will be ongoing volatility until such a time as we actually sell the asset. But it is, in accounting terms, regarded as an available-for-sale financial asset and mark-to-market in practice every quarter.

Thanks, Simon.

Thanks, Alastair.

Can have been next question, please, Operator?

The next question comes from Irene Himona from Societe Generale.

Good afternoon, gentlemen. Just one question, please, concerning marketing product sales.

The recent oil price weakness has been driven by concerns about demand. You are the largest marketer in the world. Your product sales show some quite sharp declines year on year, but some of that is your disposal. Can you clarify, on a like-on-like basis, what is happening to your product sales? And are there any conclusions you can draw regarding trending in global demand, please? Thank you.

Thanks, Irene. I'm sure Simon will have the precise numbers to hand in a moment. But of course it is the margin that we make on the part that is more important than the actual number.

What we are seeing, if I just decompose your question to two parts, first of all, we still see total oil demand robustly grow this year. As a matter of fact, in quite a few of the markets where we are ourselves pursuing a growth strategy, we have seen very, very significant increases in gasoline and diesel sales. Also in places like China, but particularly also in markets like India, where we have reestablished a growth strategy.

And if I look at how retail business and global commercial -- so predominately lubricants business, with some aspects of specialities in aviation as well -- how they have been doing, they have been very, very stable and ratable. Even at the changes in volumes that you have been mentioning here. So quarter to quarter, that business hasn't really changed very much, and neither do I expect that to be the case.

Simon, any specific details you can add on the volume metric comments?

Sure.

I'd just note that when you look at our total sales, you need to split it into marketing -- so about two-thirds -- and nonmarket in volume, so supply sales. And remember, we sell about 6 million barrels a day but only refine just over 3 million. Therefore, we can increase supply sales just from the trading activity.

The marketing sales are up about 0.3%. And they reflect both the market developments that Ben highlighted, but also some specific-to-Shell issues, where we may be growing in certain countries or have divested from others. Our nonmarketing volumes are up around 3 percentage points. That is essentially taking advantage of market opportunity, so they tend to be lower margins.

Of specialities, or primarily lubricant sales, sales were up which is important because that of course is a high-margin activity.

For completeness sake, also, Irene, there have been a few divestments of course quarter to quarter that may impact the volume as well. Like (inaudible) in France, our commodity lubricants business in China, et cetera. Thanks very much.

Let's go to the next question, Operator?

The next question comes from Christopher Kuplent from Bank of America.

Thank you. Very quick one for me. Last quarter, you actually gave us the earnings contribution from BG on a pro forma basis. I can't find that comment anywhere this quarter. Do have a number in mind? Thank you.

Simon?

We have a number in mind. The reason didn't share is it's becoming blurred at the edges, or more than the edges now because, in particular, the trading activity has already moved over into Shell and Shell volumes. So as we go forward, it is not a clean view. It is, however, a small loss; and it's impacted by the one-off factors I spoke about earlier.

And also note the comment on EPS accretion at $65 million, that was in the original. So step down from Q1 is one of the contributions of the Q1/Q2 trend, but nothing particularly significant in value terms.

Thanks, Chris.

Thanks, Simon.

Next question, please, Operator.

The next question will come from Asit Sen from CLSA.

Thanks, good afternoon. I have two questions -- one on Brazil and the second on LNG.

Ben, in Brazil if participation rules were relaxed, what would Shell's appetite be to double down in the country? So that's on Brazil.

And on LNG, Simon, wondering if you could provide any early thoughts on second-half integrated gas profitability related to, say, a little below $2 billion in the first half? There will be some volume growth, and I appreciate the sensitivity comments; but it is a black box, given trading. So any thoughts would be appreciated.

Okay, thanks, let me take the Brazil one.

I think I have said it before. If we see a relaxation of the participation rules in Brazil, so relaxing the 30% ownership, the operatorship rules, I think, yes, we would take a look at it. But at the same time, of course, you have to bear in mind we would have to make sure that whatever we do in Brazil stays within the capital constraints that we have set for ourselves. We have been very, very clear on that. Going forward, no more than $30 billion of capital investment for a year.

And if oil prices stay at the level that we are seeing today, we will be actually ramping that number further down towards the bottom of the range that we set, so closer to $25 billion. And if they really stay as they are today we will go below $25 billion. So the competition for capital would become of course more intense.

So there would have to be of course more attractive propositions than some of the other things that we will be completing. Because, believe me, if we had not put that ceiling in place, there would be a whole lot more to spend in the minds of our upstream development and integrated gas development folks than the range that I had just mentioned.

But in principle, I think we are not maxed out to the exposure that we would like to see in Brazil, particularly given the attractiveness of the acreage that is available there in principle.

On LNG, Simon, would you like to take it?

The first half, by definition, had contribution from pricing in Q4 2015 and Q1 2016. So the second half had pricing from Q2, 2016 and Q3 2016. So all other things being equal, there will be a slight improvement from price.

We'll have volume from Gorgon. And as long as Pearl GTL -- the gas to liquid -- plant stays at its current operating level, it will not have a maintenance turnaround, which it did have a significant turnaround activity in March and April. So all those factors are to the upside.

To the downside is potentially hedges running off on LNG pricing as we go forward. The BG portfolio is primarily unhedged, which is one of the issues that our own team are dealing with. So I cannot give a profit forecast, but those are the issues that are driving the gas performance as we go forward.

I think, remember that they are very all price-linked, more so, far more so, than gas price. But roughly three-quarters of the earnings is with a lag as opposed to immediate Brent price linkage.

Thanks, Simon.

Thanks, Asit.

Can I have the next question, please, Operator?

The next question comes from Rob West from Redburn.

Thanks very much for taking my questions.

You have given us some useful numbers today -- that $5 billion cash flow per quarter and that's around $40 oil you mentioned. And we have the long term target of $20 billion to $25 billion of free cash flow by 2020. Obviously, this quarter there has been disruptions that have hit the cash flow. But I was wondering with those two numbers I just mentioned, what level of disruption due to that is ongoing inevitable disruption that happens in the oil business?

What contingency is there in those numbers for that to continue? I would be really interested if you can make a comment on that.

And then also in terms of some of the uncertainties arising from today, if you could comment on your attitude towards giving a bit of nearer-term cash flow guidance. I think there's an enormous amount of change underway at Shell, and we all understand that takes time, hence your free cash flow targets being 2020 targets. But maybe could you give us your attitude around giving a 2017 operating cash flow number of what you might expect? Give us just a very, very broad range. Thanks very much.

Thanks very much, Rob.

Let me just reiterate what Simon said a little bit earlier on. First of all, I also understand that this is a very difficult quarter for you to reconcile the numbers to get your estimates right. And it's very difficult to go off what should be in a Q2 to Q2 comparison, so I can imagine that it has not been an easy process.

Let me also say that while there is indeed a long list of points that Simon mentioned, there are no fundamental surprises in there. So it is unfortunate that it points more in one direction than the other direction, but there are no surprises. Nor do they actually turf up surprises that we should be cautious of or be aware of going forward.

Therefore, I am very, very confident to say that nothing in these results made me change any outlooks that we have out. Of course, not on capital for this year, not on the capital range that we have mentioned, not on the point where we bring the operating costs to, but also not on what we believe is going to be the range of free cash flow, organic free cash flow, in the end of the decade period. So all of these numbers and principles still stand.

In terms of nearer-term guidance, we have not put anything out there. I hear what you are saying, Rob. I think we will probably come out with an update a little bit later in the year.

Let me not give any prognosis what that will be, but I understand that we have to get to a point that our earnings and our cash flow becomes more easy to understand, more transparent for you to see. And in that respect 2016 will indeed be a difficult year to work through, with so many moving parts that we have now that we bring the two companies together.

(multiple speakers). Rob, thanks for the questions.

The $5 billion at $40, if you take that as a baseline, approximately at the moment, what we laid for 2019 through 2021 was essentially to get the $11 billion, $12 billion a quarter; but there is a higher oil price, clearly, at $60. To fill the gap, effectively the oil price is going to do somewhere close to $3 billion with that kind of sensitivity a quarter. And the rest is essentially the delivery from the new projects coming onstream that are not necessarily included in the $5 billion.

And OpEx reductions or improvements will offset the decline in the underlying portfolio as well. So this does hang together. It's not excessive date that is out of line or inconsistent with what we said three weeks ago in that context. But it does reiterate the importance of delivering the projects and the power of those projects as well.

And we are seeing some of that now, but obviously there is only two quarters or five month worth of BG contribution here. And our own new projects haven't really kicked in. We start to see that hopefully in the second half of 2016. So that, plus the OpEx being able to offset underlying decline, those are the drivers of cash generation. And we need to reset the capital investments in the roughly the $7 billion a quarter average level in cash terms. Or lower if necessary.

Thanks, Simon.

Operator, could have the next question?

The next question comes from Biraj Borkhataria from Royal Bank of Canada.

Thanks for taking my question. I had a couple things, the first one on pensions.

On the balance sheet, you have a fairly large pension deficit. And given the way bond yields have moved, that deficit seems to have widened further. I was wondering the how we should think about that. And if I tie that into your 30% gearing limit, is there a scenario where gearing or net debt doesn't necessarily increase as much as you thought they might, but for mechanical purposes on the ratio that you might breach that 30% limit? That would be my first question.

And the second question is on commentary from the service companies recently is all focused on the fact that they are no longer offer discounts. And they're trying to push back on contracts. And it doesn't really tie in with the continued cost-reduction story for the majors. I was wondering if you have any comments on that or maybe recent conversations and how that relationship is going? Thanks.

Thanks, Biraj, let me tackle the second one; and Simon will take the pension deficit point.

No, I think we still see a continued cost takeout, both in terms of capital costs, as well as our running cost in the upstream. Some of it is indeed through the competitive pressure that exists in a supply chain that sees just lower activity levels. So that is one.

Secondly, with quite a few service companies, we are also reworking the way we work together. So it is genuine waste elimination, duplication of activities, that if you really work very hard together, with our own well side staff and well side staff of service companies, you can find significant ways and means to reduce activity.

And in terms of capital projects, also significant ways to either simplify, apply more common standards, or actually scope down some of the activities or some of the aspects of projects that we would not do in a world where we believed in higher oil prices to stay forever. So I don't see that effect that you describe, but I probably see it for the right reasons. Which is that we actually take our activity in scope, in addition to just applying the usual commercial pressure that is available to us now.

Thanks for the question, Biraj. Indeed there has been a significant increase in the accounting version of liabilities as a result of the reduction in bond rates and, therefore, the discount rate that we apply to the liabilities. There was around a $2.5 billion uptick in the quarter and over $4 billion in the year-to-date.

Of course pension funds, mostly they are funded; there are a couple of unfunded funds out there in Germany and some of the post-retirement medical benefits in North America. But fundamentally the funded funds are funded, if that makes sense to you.

But you will see accounting movements that go through the other comprehensive income statements and on the balance sheet. And the lower for longer interest rates scenario that we are effectively all looking at now, may lead to further increases in the liabilities. But the actual funds remain pretty solid.

The balance sheet impact and the impact on gearing, when I quote 28.1%, it does not include the pension fund liability. When the rating agencies and ourselves look at it, we look very much at the liability. We look at the actual cash cost of servicing pensions, which is between $1.5 billion and $2 billion a year, typically. And we look at the P&L charge and how this all hangs together in terms of the ratios, and effectively adjust the credit rating agency ratios accordingly.

So it is a factor that impacts the way we think about cash flow over the balance sheet. It is not directly related to the 28% gearing number that we state.

Thanks, Simon.

Thanks, Biraj.

Can I have the next question, please, Operator?

Yes, the next question comes from Anish Kapadia from TPH.

Hello, a few questions for me.

Firstly, on the cash tax on disposals. I was wondering if you could give us some guidance on what is remaining from previously-announced disposals to be booked through the cash flow. And also in terms of your $30 billion disposal target, what's your best case assumption in terms of cash tax that would be paid on those disposals?

And then second question on the Lake Charles postponed FID, as I understand, you wouldn't be putting your own capital into that project. It would be ETP that would be putting the capital in. So I'm just wondering the rationale for not going ahead with that project? Is it more that you're not as keen on the LNG market when those are supposed to be coming onstream, or is there something else?

And then a very quick went on refining. If we see July refining margins for 2016 for the rest of this quarter, would it be reasonable to assume a loss of the net income line in refining? Thank you.

Okay thanks very much, Anish. I think making predictions on the future income and refining is something I would like to stay away from. Refining is indeed a very cyclical business. We do, or rather we have seen of course, quite a few cycles already in the last 12 months or so. Looking at second-quarter 2015, it was pretty strong, then a drop-off, then a recovery, and a drop-off again.

Now, so in principle, we see the refining sector globally still being long. Therefore, we really have a strategy of shrinking our refining sector back to a strong core, where we will indeed continue to invest in the remaining portfolio of refineries. So that we not only have strong intrinsic margin capabilities because of refining complexity, can deal with lower-cost feedstocks, and can also integrate our refining operations better with our trading operations so that we can create more, shall we say, extrinsic value to it.

But that's basically making the best out of an increasingly strengthening hand. Investing and refining going forward, we do not see as a strategically wise thing to do for our type of company.

Now in Lake Charles, no, it is not necessarily a cooling of our interest in the LNG market. Although you have to bear in mind, we have repositioned the integrated gas business from being a growth business to being a cash engine. So it is all about free cash flow optimization. So therefore, the general appetite that we have for new FIDs in quick succession, has seriously reduced of course. That is just a little change of strategic intent that we have for this business.

t is also fair to say, of course, that at the moment we see quite a bit of length in the market. The market is well-supplied. There are still uncommitted volumes that are going to be placed. Some of these volumes we buy and then we place ourselves, so we make money off the short-term value. But we see the markets getting tighter again and more balanced, probably only in the early part of the next decade.

We also still believe fundamentally the LNG business will be a growing business. It will be, of a fossil fuels supply sources, the fastest-growing one. So therefore we will remain an interest in taking investment decisions in that business. Probably in the near term, a little more on market development and as we see indeed the demand uptick and the supply demand retro opening up also more in supply.

But the prime reason for not taking a final investment decision on both LNG Canada and Lake Charles is driven by affordability reasons this year. We have not stated when we will revisit that decision, so therefore there is no new date to look forward to.

And on Lake Charles, by the way, there would be multiple ways by which we would be able to do that project. And if indeed we were to take Lake Charles investment decision under the current construct, the commitment of course of the lease payments would still come onto our books. So therefore it's not just a matter of somebody else build and we will lift whenever we can. This would come, of course, with a back-to-back long-term commitment.

So it is therefore more an accounting aspect that you are referring to than really avoiding the capital altogether. So in my mind, the decision goes back to fundamentals. We don't feel, at this point in time in the cycle, at this point in our financial framework, it is prudent to make that level of commitment to the LNG business.

Quickly on cash tax on disposals, this will always be a slight discrepancy between what we state on proceeds from disposals -- or anyone else for that matter. That's always a pretax figure, and any tax will then the flow-through the CFFO as if it were a normal item.

The item in Q2 was actually on sale in Nigeria some time ago. So the tax usually follows a year or so later than the transaction, $700 million or so. And going forward, there is no carry-forward expectation of deals that have been done with a major tax impact. We haven't done major deals for quite some months anyway.

As we then go forward with $30 billion, there are different ways of achieving how that could be done. And in many of them, either transactions are not subject to tax or the taxable base of the assets being sold would be close to or certainly nonzero, so close to the proceeds received. So the actual effective tax rate on disposals is not likely to be a serious factor, but it is something we will try to be a little bit more transparent about as we go forward if we identify and expect large one-off payments like we have just seen.

Thanks, Simon.

Thanks, Anish.

Well, let me say thank you very much for being with us today and for the many good questions that you have asked. I again would like to, before closing, reiterate what we have both said before, that 2016 will be a transition year for us.

It is all about consolidating BG. It is launching and executing a multi-year change program, which will of course still have to play out at the bottom line. And then of course all of this in the context of lower prices as well.

So again, the overwhelming driver for our lower result that you have seen is the macro environment, so the $3 billion compared to the same quarter last year that is the result of lower oil prices, lower gas prices, as well as lower refining and chemical margins. And I think therefore the guidance that we have given, the commitments that we have made, the outlook that we have for the end of the decade that we made a bit over a month ago, is still all very much exactly the same.

Let me remind you also that we will have third-quarter results scheduled for 1 November in 2016, and Simon will be there to talk to you then. For now, many thanks for your attention and have a good day.

Thank you. That will conclude today's conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.