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 statement. It's been just two months since we had a capital markets day where we gave an update on Shell's 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 businesses delivered strong results this quarter. Although the low oil prices do 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 there have been large movements in our figures for the BG purchase and consolidation, the restructuring charges, and the buildup 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. Altogether, this is a very complex period for the company. 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-$8 billion of asset sales this year, and that's part of the $30 billion divestment plan, and delivering profitable new projects. $10 billion a year of cash flow potential in 2018, and eight startups just in 2016. As you know, we segment the portfolio in a number of strategic themes. 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, then leave us with enough money to fund the future. Our growth priorities have a clear pathway towards delivering strong returns and free cash flow in the medium term.
Our future opportunities should provide us with material growth in cash flow per share in the next decade. Through all of this is our intention to be in fundamentally advantaged positions with resilience and running room. Asset sales have an important role to play in all of these strategic themes as we reshape the company. Now running through all of this, there's a great emphasis on uptime, on cost, and delivering profitable projects right across the company. The examples you see here are all from the upstream business. Lower unit costs, typically down 15%-20% from 2014 levels. Higher production overall. That's 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 on a 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. For Shell, our 12 months 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. Total shareholder return, which in the end is how you and of course we ourselves measure our performance, well, we've improved in the last 12 months from a low baseline. Overall, there's a lot to do here.
I believe that by doing a better job on delivering higher and more predictable returns and free cash flow per share, and underpinning all of 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, 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 averaged $46 per barrel in the quarter, at $16 a barrel lower. At the same time, the downstream industry margins were also lower, both in refining and in chemicals. These macro effects have dominated in the results this quarter, despite the strong progress that we're making on underlying costs. Excluding identified items, Shell's current cost of supply or CCS earnings were $1 billion. That's a 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, and I'd be quite happy to take any questions you have on that. In summary, at the group level, macro effects, oil and gas prices, and the downstream margin movements account for 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 result is a combination of higher depreciation charges and other effects such as taxes, with an uplift from volumes, lower exploration charges, and lower costs. That's comparing Shell plus BG this year against Shell alone a year ago. 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, 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. The 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 assets continues to ramp up well. In Australia, QCLNG and Queensland have both LNG trains running at full design rate of 4.25 million tons per annum. In Brazil, our deepwater production has reached around 200,000 barrels a day. The Petrobras-operated eighth FPSO, floating production storage unit, on Lula Central in the Santos Basin, has started production in the last few weeks, and the ninth FPSO, in the same basin, should be on stream later this year. On the synergies, no change to the guidance, $4.5 billion of annual synergies in 2018. We've already actioned the steps that will deliver around half that figure. These include office closures, the staff reduction, exploration savings, and reductions in our overhead. Turning to the financial framework.
This particular slide we used on Capital Markets Day last month summarizes the potential from the levers that we're 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, the reduction in cash flow that we've seen 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. The potential outcomes here reflect the actions by all of my colleagues in Shell, all 90,000. In practice, they reflect a reset of the way that we're doing business, particularly in terms of the underlying sustainable cost base. The levers we're pulling here are individually and collectively material. They will make a difference over time. 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's not just about managing the balance sheet. Up to 10% of our upstream oil and gas production is earmarked for sale. These include several country positions and a number of midstream assets for sale into our MLP, the Master Limited Partnership vehicle in the U.S., 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 of strategic intent. Asset sales in total are expected to reach $30 billion for three years, 2016 to 2018 combined. 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'd expect to see significant progress towards and including sales agreements on around $6 billion-$8 billion this calendar year. As we said before, we are not planning for asset sales at giveaway prices, and there's no reason today to think 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-$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 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. Capital investment, 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 number, but most of this has yet to be booked. It will come through in the second half of the year. There are, in addition, some decisions ahead of us on "idle rigs," unquote, which is committed spend, which may move between OpEx and CapEx, depending 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, 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. That's in addition, of course, to the fact that the exploration expense is also not deducted from the cash from operations. To operating costs, the third of the prime levers that we're 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're showing here adjusts for this.
Shell standalone costs reduced by $4 billion, around 10% between 2014 and 2015. We're 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. Hence you will have noted the identified item on redundancy and restructuring in the quarter. Overall, on costs, there's 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 start-ups 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. In the second half of 2016, we expect to see contributions from some major projects, including Stones in the Gulf of Mexico, the deep water, the Gorgon LNG project in Australia, and Kashagan oil project in Kazakhstan. These start-ups in 2016 should add more than 250,000 barrels oil equivalent per day, 3.9 million tons per annum of LNG for Shell shareholders once they're fully ramped up. We've also been reordering our priorities for growth projects in the next decade. The LNG Canada joint venture recently announced the postponement of final investment decision.
Today, we have updated that the Lake Charles in the U.S., 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 U.S. this year already. Looking a bit further out, we have had success with the drill bit this quarter. We're delighted to announce a new exploration discovery today in the deep water Gulf of Mexico. Initial estimated recoverable resources for the Fort Sumter well are more than 125 million barrels oil equivalent. This is a 100% Shell activity. Further appraisal drilling and planned wells in adjacent structures could considerably increase recoverable potential in the vicinity of this particular well.
That in itself builds on recent Norphlet, this is the Norphlet play, exploration success at Appomattox, the 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. 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. With that, I'll hand that back now to Ben.
Thanks very much, Simon. In many ways, 2016 is going to be a transition year for us. Low oil prices and therefore lower results coinciding with the bedding 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. I want to be very clear with you that we're on a pathway here for an ambitious transformation of the company. Higher returns, higher free cash flow, despite lower oil prices. There's a lot of energy and enthusiasm in the company to deliver all of this. 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. 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 I have the first question, please?
Thank you. We'll now begin the question answer session. People dialed in, if you have a question, please press star one. If you wish to be removed from the queue, please press star two. We'll take our first question from Oswald Clint from Bernstein. Please go ahead.
Yes, thank you very much. Maybe Ben, first off, just talking about Brazil and the progress you're having there. Obviously, as we look forward to the next phase of the growth that's coming from the replicant FPSOs in Brazil. I'm curious just to understand what you're seeing there, your comfort level with the progress of those FPSOs coming on stream starting in 2017 onwards. A particular update there would be quite useful. Simon, please, I'm just trying to get to as clean as a possible cash flow number for the second quarter if I get the $4.8, adding back working capital. If we start to add back the restructuring redundancy, onerous contracts, and maybe there's something for Canadian costs in the quarter for fires, just trying to get back to a cash flow number that might be as clean as possible for the quarter.
I'm just wondering if you could help us get there, please. Thank you.
Okay. Thanks, Oswald. Simon, you want to start with the cash flow?
Sure. Thanks, Oswald. Maybe a question of interest to everybody. We all know quarterly cash flow can be a noisy number, particularly when we're bringing the two companies together. There are some movements around working capital, et cetera. The 2.3 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. That is unique to the quarter. It's tax on a prior year divestment. There are one or two other moving pieces as well. Fundamentally, the last three quarters, taking into account some of the one-offs, 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 that also takes out some of the intra-quarter variances.
I'm not sure if that helps a great deal, going forward, of course, you're right that the provisions on severance and redundancy and idle rigs, et cetera, may flow into cash flow flowing out. Of course, that will be offset by delivery on the OpEx, the synergies, and most importantly, on the new projects, all other things being equal. It is running at a run rate of around $5 billion. Coming back up again from what essentially would be a low point in the first quarter.
On Brazil, Oswald. At the moment, we have 9 FPSOs on stream. Number 9 mentioned by Simon came on stream in Q2. If I look at 2017, there's 3 more, including the Libra extended well test FPSO. 2018, another 3, and then a further 3 in the 2020 plus timeframe. Can I have the next question please, operator?
The next question comes from Iain Reid from Macquarie.
Hi, Simon. Just a quick confirmation on your sensitivity data you gave us on page 10 of the earnings release on the upstream. When we're looking at this $3 billion per annum for every $10 movement in 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 kind of quarterly estimate of how these numbers are moving on an annual basis. Is that correct?
Yes. Although, of course, the volumes are moving as well. In the first instance, the simple answer is yes. I'll just put on record, I do not often have sympathy with you guys on the modeling, but just at the moment I do, on the grounds that 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 a $2 billion sensitivity within Integrated Gas, which is overall a $5 billion sensitivity. Of course, Integrated Gas has the added complexity of most of it being time lagged by four to six 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 a low, or at least in the recent trend, the gas prices would have been a low. We'll do what we can to help, Iain, but you're absolutely correct that it does include the BG volumes.
Thanks very much, Simon. Thanks, Iain. Can I have the next question please, operator?
The next question comes from Brendan Warn from BMO Capital Markets.
Yes. Thanks, gentlemen. I'll just keep to one question, I guess similar along the lines of what just Iain asked, just in terms of this transition period that you talk about, the deal effect, working capital and tax. If we just focus in on upstream, if I can think forward a year
Let's say 2Q 2017, and if we kept oil price out of it, what sort of benefits are we going to see in the upstream because of synergies? Just sort of trying to understand what would be a clean result projecting forward a year.
That's a tough question, Brendan, but let's see how much we can help you with it. Simon?
It may be too tough for me, Brendan, but let me try. I think you need to watch three things. The costs are coming down in pretty much a straight line. We said 40 for the total for the year. On an underlying basis by the end of the 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 cost, and that's across all the three businesses, in which the downstream is just below 50% of the total. The integrated gas is about a quarter. Integrated gas is more like about 15%, 12%-15%, depending on the quarter. That's an indication the synergies will kick in, for example, on exploration, almost all in the upstream.
Pretty much the $2 billion would be delivered by the end of this year on a run rate. 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 on stream by then and should have ramped up. Gorgon in the integrated gas business, of course, will have two trains hopefully working by then. Kashagan will be beginning to play through. The Shale focus at the moment in the U.S. is developing the Permian, so should be an improved performance from that. All of those things coming through should improve the revenue, all other things being equal.
What I will say on the earnings, though, is that early production from deep water, Stones, for example, comes with very high unit depreciation because of very low early proved reserve bookings until you've established a production record, in areas where you have no analogs. Stones and Appomattox, for that matter, are both in new areas where there are no reservoir analogs. Will both come with high unit depreciation. Average cash operating costs 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 a day and 3.9 million tons of LNG. 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'll try and update on the actual progress on a quarter-by-quarter basis. Thanks.
Sounds good. Thanks very much, Simon. Thanks, Brendan. Operator, can I have the next question?
We'll now take the next question from Lydia Rainforth from Barclays.
Thanks. Good afternoon. I'll stick to one question as well. I hate to come back to the upstream side again, just in terms of when you're looking at the results from the first half of the year. The question comes back to the idea of, are you happy with where you are on the cost side? 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, then maybe Simon wants to fill in on a bit more detail. I think, no, we are not happy on the cost take up where we 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 a underlying run rate of $40 billion per year. I think it is fair 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 on a longer cost journey. Of course, has never really had the comfort that a very profitable upstream business had where the focus was indeed on delivering value, even if it involved somewhat more marginal cost.
Integrated gas, of course, has a smaller cost base to start off with. Yes, the focus is very much on the upstream. If I just look at where we are right now, I now talk about the 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 a overall cost base, BG and Shell legacy combined, that is lower than what the Shell only costs were in the same quarter last year. There is a significant amount of momentum that has been established, but that momentum has not traveled to the endpoint in my mind, Lydia, there is probably more to come. 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, 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. Also rescoping projects so that they are actually costed and configured in terms of scope for oil price resilience rather than value maximization. What you see is that the unit capital cost is also coming down quite significantly there. That's one of the reasons why we actually managed to also significantly drive down our overall capital spending. It's not just only a matter of postponing 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? We're, I think, positively pleased or inclined about the pace at which reductions have come through so far, we are far from finished. There are severance or redundancy-related charges and restructuring, mostly office leases in the results, but pre-tax, 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've already announced the 12,500 people. There will be some ongoing noise as we go forward, because future reductions do have a little bit of cost up front. That will come through over the next couple of quarters. We'll also see potentially some noise from third quarter reviews on things like impairment, decommissioning, and restoration.
Fundamentally, we've just brought two companies together and we're still learning a bit on the underlying implications on short-term performance and the quarterly movement. While we'll do what we can to help you, it's 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.
Hi, 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. One area where, at least relative to our forecast, there seems to have been some differences is in terms of price realizations. The oil and gas prices that you report relative to what we expected based on benchmark crude and gas prices seemed quite low. On the one end you can say, Martijn, your model wasn't very good, at the other end, we weren't very different from what others were forecasting. 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? If so, is there anything that explains that?
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 to $75 billion. I know on the last call you said that the debt would continue to be on an upward slope for a bit. Would you still say that it will trend up from here on? Yeah, 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, do remember on price realizations, the North American gas prices that we quote, we're quite heavily exposed to Alberta AECO prices, which were lower than Henry Hub. We also take first of the month, which was lower than the average through the quarter. On global realized prices associated with the integrated gas business, there is that three, four months to six months lag. JCC was quite a bit lower relative to expectation than Brent headline. Those are both factors that have impacted price realization, possibly more so than the modeling would've thrown up. Let me just make a general statement on, I appreciate that three months is of interest to you and it helps you reset your model.
There is nothing in these results that has any impact on the 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'd be telling you about it. There are just a lot of, and there always is actually, $100 million, $200 million here or there, just that the net of them was quite negative this quarter as opposed to normally when they tend to wash out. I don't think there's 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 is what we said in the prospectus. At $46 a barrel, yeah, we are doing well, but it is a stretch to get earnings accretion out. That is what we said, and that was after delivery of quite a bit of synergy. Everything to do with the deal, on track to deliver value.
Debt.
On the debt, it may go up before it comes back down. 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. That is why the debt may go up before it goes down.
Thanks, Simon. Thanks, Martijn. Can I have the next question please, operator?
Next question comes from Jon Rigby from UBS.
Yeah, thank you. Two questions. The first is on upstream. Take your point that you can't infer too much the future from a quarter to quarter, but you have given sensitivities for your upstream business. If we look 1Q to 2Q, there seems almost no leverage to the $10 rise in the oil price in the upstream. Now, I know it's post-tax, I know there's some moving parts, but I'd just like to understand a little better what those moving parts might have been that would offset the nominally $750 million gain or improvement that perhaps we ought to have seen in that quarter sequential. Second, you mentioned the drop-downs into the MLP. Could you just go through the envisaged mechanism for that? Would that involve equity raises in the MLP rather than debt, so that you're not reconsolidating MLP debt?
Is that $800 million a net number? Obviously, it would be higher for the gross figure that's being dropped down. Thanks.
Thanks, Jon. Simon?
Just on the MLP equity first. It's new equity raised, Jon. If we raised debt, then it wouldn't show in what we comment upon. The entire MLP is consolidated. We actually own more than 50% of the LP units anyway, still.
Yep.
As long as we control the GP units, it will remain consolidated. It remains possible that we sell down LP units over time, and they potentially count as divestment as well. 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. It happens to be in the integrated gas results, but NAM, $100 million reduction between Q1 and Q2, simply because 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 and Auger, $50 million. Italy, Val d'Agri shutdown. That's known in the public domain. It's 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 sterling holding. They are all individually in the wrong direction from both your viewpoint and our viewpoint. None of those things I've just stated is relevant longer term, except I would actually like the cash in the back pocket today, but that's not how it is. Going forward, they won't get repeated. Sorry, there's no more I can say on that. It's just a long list of individual items that are different. 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 can't 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. 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 mind of many of you. Can I have the next question please, operator?
The next question will come from Thomas Adolff from Credit Suisse.
Hi, Ben. Hi, Simon. Hope you're well. I've got only questions for Simon this time. Simon, got a feeling that you might be, I'm probably the wrong person to say that you're being a bit conservative on the underlying cash flow during the quarter if you ex the restructuring charges. Cost savings cost money, they're, at the same time, structural in nature, at least a good chunk of it. I believe, or at least I think when you make these adjustments, ex the restructuring charges, actually cash flow was more than $5 billion. Should we be using that as a underlying cash flow of the business as it stands today? Following on from that, if you think about restructuring and redundancy charges, how much of that has already been cured or impacted?
How much has impacted your cash flow, and how much more is there to go? My final question on working capital in the first half of the year. If you ex out Iran, how much of that is reversible? Thank you.
That's good questions. We all had to smile at your first one because we have debated that one as well. Simon, why don't you take them?
If I did a similar breakdown of the smaller items, you're right, Thomas, it is above five for the quarter. I deliberately gave average over the last three quarters. It's a reasonable basis, there is an uptick, an underlying uptick in Q2. Although, as with the earnings, it's impacted by one or two one-off items as well. I'm generally not sure I can say too much more about that. Restructuring, how will they flow through? Quite a lot of those are not yet cash. There was about $1.5 billion associated with the redundancy and restructuring pre-tax, about half a billion on the idle rigs. Now some of that's 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.
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. Around a couple of billion 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 provisions. Once we are through some of the work in the third quarter around the D&R, the decommissioning, and you'll see some quite big movements on the pension liabilities as well. We'll probably be able to give you a better fix.
We are still working on bringing, remember, a $67 billion set of assets onto a $220 billion balance sheet, and working through some of the details. You're talking about relatively small movements, but on very large numbers.
Thanks, Thomas. Thanks, Simon. Can I have the next question please, operator?
The next question comes from Alastair Syme from Citi.
Hi. Thanks. Can I just quickly follow up on that last question, actually? All the restructuring charges you've taken being accrued, or are you putting anything straight through to cash flow, i.e., is there anything sort of bypassing working capital we need to think about? Secondly, can I just clarify, what you've done on Woodside? I just note in the statement you've reclassified the way you're accounting it. Thank you.
Yeah. Both questions for Simon.
All right. There is some cash effect from the restructuring, but it's 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 are certain office buildings that we will vacate before we can subcontract or otherwise deal with the lease. We're taking the payment there into the P&L, but not the cash payment. It will play out. Most of it will play out in the next six to nine months. It is likely, just to reiterate, that there will be further redundancy charges because we do not yet reflect all of the 12,500 changes that we've previously made. 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, we do not have the right to replace. We've gone effectively from two to one director. Therefore, the influence level has fallen below that at which we can recognize the investment as an equity associate. It is now held as an asset for sale. There will be quarterly volatility in the earnings that we see. Importantly, there is a production and a reserves impact because we no longer will recognize the 25,000 barrels a day of production. That is the 13% share equivalent. About 100 million barrels of reserves will be de-booked because we no longer have sufficient influence to continue booking them. There will be ongoing volatility until such time as we actually sell the asset.
It is, in accounting terms, regarded as an available-for-sale financial asset and marked to market in practice every quarter.
Okay. Thanks, Simon. Thanks, Alastair. Can I have the 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. Obviously, 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 obviously your disposal. Can you clarify on a like-on-like basis what is happening to your product sales? Is there any conclusions you can draw regarding trends in global demand, please? Thank you.
Yeah. Thanks, Irene. I'm sure Simon will have the precise numbers to hand in a moment. Of course it is the margin that we make on a product that is more important than the absolute number. What we have seen, 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 significant increase in gasoline and diesel sales. Also in places like China, but particularly also in markets like India, where we have reestablished the growth strategy.
If I look at how our retail business and our global commercial, so predominantly lubricants business, with some aspects of specialties and aviation in it as well, how they have been doing, they have been very stable and ratable, even at the sort of changes in volumes that you have been mentioning here. Quarter-to-quarter, that business hasn't really changed very much. Neither do I expect that to be the case. Simon, any specific details that you can add on some of the volumetric comments?
Sure. I just note that when you look at our total sales, need to split it into marketing to about two-thirds and non-marketing volume. Supply sales. Remember that we sell about six million barrels a day, but only refine just over three. 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 highlights, but also some of the specific to Shell issues where we may be growing in certain countries or have divested from others. Our non-marketing volumes are up around 3% percentage points, that is essentially taking advantage of market opportunity. They tend to be lower margin. Specialties or primarily lubricant sales were up, which is important because that, of course, is a high margin activity.
For completeness sake also, there have been a few divestments, of course, quarter to quarter that may impact the volumes as well, like Butagaz in France, our commodity lubricants business in China, Tongyi, 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 from me. I noticed 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 you have a number in mind? Thank you.
Chris. Simon?
We have a number in mind. The one reason we 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. As we go forward, it's not a clean view. It is, however, a small loss, and it's impacted by some of the one-off factors I spoke about earlier. Also note the comment on EPS accretion at $65 that was in the original. Step down from Q1 is one of the contributions to Q1, Q2 trends, 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, guys. I have two questions, one on Brazil and second on LNG. Ben, in Brazil, if pre-salt rules were relaxed, what would Shell's appetite be to double down in the country? That's on Brazil. On LNG, Simon, wondering if you could provide any early thoughts on second half integrated gas profitability relative to, say, a little below $2 billion in the first half. There will be some volume growth and appreciate the sensitivity comments, but it's a black box given trading. Any thoughts would be appreciated.
Okay, thanks, Asit. Let me take the Brazil one. Yeah, I think I've 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. 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 to ourselves. That we have been very clear on that. Going forward, no more than $30 billion of capital investment per year. 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've set, so closer to 25. If they really stay as they are today, we will go below 25.
The competition for capital would become, of course, more intense. There would have to be, of course, a more attractive propositions than some of the other things that we'll be competing. Believe me, if we hadn't 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 just mentioned. 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?
Sure. The first half, by definition, had contribution from pricing in Q4 2015 and Q1 2016. The second half had pricing from Q2 2016 and Q3 2016. All other things being equal, there'll be a slight improvement from price. We'll have volume from Gorgon. As long as Pearl GTL, the gas to liquids plant, stays at its current operating level, it will not have another maintenance turnaround, which it did have a significant turnaround activity in March and April. 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 was primarily unhedged, which is one of the issues our own team are now dealing with. I can't give a profit forecast, but those are the issues that are driving the gas performance as we go forward.
Remember that they are very oil price-linked, far more so than gas price, but roughly three-quarters of the earnings is with a lag as opposed to immediate Brent price linkage.
Okay. Thanks, Simon. Thanks, Asit. Can I have the next question please, operator?
The next question comes from Rob West from Redburn.
Hi there. Thanks very much for taking my questions. You've given us some really useful numbers today, that $5 billion cash flow per quarter, I think it's around $40 oil you mentioned, and we've got the long-term target of $20 billion-$25 billion of free cash flow by 2020. Obviously, this quarter, there's just been disruptions that have hit the cash flow. I was wondering, with those two numbers I just mentioned, what level of disruption due to that kind of just ongoing, inevitable disruption that happens in an oil business? What contingency is there in those numbers for that to continue? I'd be really interested if you could make a comment on that. Also in terms of some of the uncertainty arising from today, can you just comment on your attitudes towards giving a bit of nearer term cash flow guidance?
I think there's clearly an enormous amount of change underway at Shell, and we all understand that takes time, hence your free cash flow targets being 2020 targets. Maybe could you give us your attitude around giving a 2017 operating cash flow number of what you might expect? Even if just a very broad range. Thanks very much.
Thanks very much, Rob. Well, 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. It's very difficult to go off what should be indeed a quarter two to quarter two comparison. 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. It is unfortunate that they point more in one direction than the other direction, but there is no surprises in it, nor do they actually turf up surprises that we should be cautious of or be aware of going forward.
Therefore, I'm very, very confident to say that nothing in these results make me change any outlook statement that we have out there. 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 cost 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. All these numbers in principle 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.
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. 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.
Maybe if I may.
Yeah, sure.
Rob, thanks for the question. The $5 billion at 40, if you take that as a baseline, approximately at the moment, what we laid out for 2019 through 2021 was essentially to get to $11 billion-$12 billion a quarter, but at 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 sense of per quarter. The rest is essentially the delivery from the new projects coming on stream that are not necessarily included in the five. OpEx reductions or improvements will offset the decline in the underlying portfolio as well. This does hang together. It's not a set of data that is out of line or inconsistent with what we said three weeks ago in that context.
It does reiterate the importance of delivering the projects and the power of those projects as well. We are seeing some of that now, but obviously, there's only two quarters or five months worth of BG contribution here, and our own new projects haven't really kicked in. You'll start to see that hopefully in the second half of 2016. That, plus the OpEx being able to offset underlying decline, those are the drivers of cash generation. We need to reset the capital investment in roughly the $7 billion a quarter average level in cash terms or lower, if necessary.
Thanks, Simon. Operator, can I have the next question?
Yes, the next question comes from Biraj Borkhataria from Royal Bank of Canada.
Hi. Thanks for taking my question. I had a couple, please. The first one on pensions and on the balance sheet. You've got a fairly large pension deficit, and given the way bond yields have moved, that deficit seems to have widened further. I was wondering how we should think about that, and if I tie that into your 30% gearing limit, is there a scenario where net debt doesn't necessarily increase as much as you thought it might, but for mechanical purposes on the ratio that you might breach that 30% limit? That would be my first question. The second question is on commentary from the service companies recently has all focused on the fact that they're no longer offering 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 had 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 cost as well as our running cost in the upstream. That is one. Secondly, with quite a few service companies, we're also reworking the way we work together. It is genuine waste elimination, duplication of activities, that if you really work very hard together with our own well site staff and well site staff of service companies, you can find significant ways and means to reduce activity.
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. I don't see that effect that you describe, but I probably see it for the right reasons, which is that we actually take out activity and scope in addition to just applying the usual commercial pressure that is available to us now.
Pension?
Yep.
Thanks for the question, Biraj. Indeed, there's 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. It was around a $2.5 billion uptick in the quarter and over $4 billion in the year to date. 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. Fundamentally, the funded funds are funded, if that makes sense to you. You will see accounting movements that go through the other comprehensive income statement and on the balance sheet. The lower for longer interest rate scenario that we're effectively all looking at now may lead to further increases in the liabilities. The actual funds remain pretty solid.
The balance sheet impact and the impact on gearing, well, 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 the pensions, which is between $1.5 billion-$2 billion a year, typically. 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. It is a factor that impacts the way we think about cash flow over the balance sheet, but it's not directly related to the 28% gearing number that we state.
Thanks, Simon. Thanks, Biraj. Can I have the next question please, operator?
The next question comes from Anish Kapadia from TPH. Please go ahead, your line's open.
Hi. A few questions from me. Firstly, on the cash tax on disposals. I was wondering if you could just give us some guidance on what's remaining from previously announced disposals to be booked through the cash flow. Also, in terms of your $30 billion disposal target, what's your base case assumption in terms of cash tax that will be paid on those disposals? The second question on the Lake Charles postponement FID. As I understand it, you wouldn't be putting your own capital into that project. It would be ETE that would be putting the capital in.
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 that's supposed to be coming on stream, or is there something else? Just a very quick one on refining. If we see July refining margins persisting 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 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. We come off a second quarter 2015 that was pretty strong, then a drop off, then a recovery, and a drop off again now. In principle, we see the refining sector globally still being long.
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 capability 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. That's basically making the best out of an increasingly strengthening hand. Investing in refining going forward, we do not see as a strategically wise thing to do for our type of company. In Lake Charles, no, it's not just, or not necessarily, rather, a cooling of our interest in the LNG market.
You have to bear in mind, we have repositioned the integrated gas business from being a growth business to being a cash engine. It is all about free cash flow optimization. The general appetite that we have for new FIDs in quick succession has seriously reduced, of course. That is just with a change of strategic intent that we have for this business. It 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 is 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 that short-term volume. 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 the fossil fuels supply sources, the fastest growing one. We will remain an interest in taking investment decisions in that business, probably in the near term, a little bit more on market development, and as we see indeed, the demand uptick and the supply demand wedge opening up also more in supply. 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. On Lake Charles, by the way, there will be multiple ways by which we would be able to do that project.
If indeed we were to take a Lake Charles investment decision under the current construct, the commitment, of course, of the lease payments would still come onto our books. 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. It is therefore more an accounting aspect that you're referring to than really avoiding the capital altogether. In my mind, the decision goes back to fundamentals. We don't feel at this point in time in the cycle and at this point in time in our financial framework, it is prudent to make that level of commitment to the LNG business.
Just quickly on cash tax on disposals. This will always be a slight discrepancy between what we state on proceeds from disposals or anybody does for that matter. That's always a pre-tax figure, and any tax will then 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. Going forward, there is no carried 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 the $30 billion, there are different ways of assuming how that could be done.
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 non-zero, so close to the proceeds received. The actual effective tax rate on disposals is not likely to be a serious factor, but it is something we'll try and be a bit more transparent about as we go forward, if we identify and expect large one-off payments like we've just seen.
Thanks, Simon. Thanks, Anish. I think there's no more questions, operator?
That's correct. There's no further questions.
Okay. Well, let me then 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's all about consolidating BG. It's launching and executing a multi-year change program, which will, of course, still have to play out at the bottom line. Of course, all of this in the context of low oil prices as well. Again, the overwhelming driver for our lower result that you have seen is the macro environment. 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.
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, of course, scheduled for the 1st of 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.
Many thanks.
Thank you. That will conclude today's conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.