Many thanks. Ladies and gentlemen, welcome to today's presentation. We announced our first-quarter results this morning. These results included 2 months of contribution from BG, following the completion of the acquisition on February 15th. We've taken the opportunity to enhance our financial disclosure across the company today, and I hope you will find the new figures useful, although I do appreciate some of the modeling challenges it may now bring. Let me give you a summary, and then, of course, there'll be plenty of time for your questions. Before we start, just let me highlight the disclaimer. Shell's integrated activities from the wellhead through to the customer do differentiate us with our downstream and integrated gas businesses delivering good results, underpinning our financial performance despite the continued low oil and gas prices at $34 average Brent for the quarter.
We delivered $1.6 billion of underlying current cost of supply or CCS earnings-
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this quarter, $9.3 billion of similar earnings over the last 12 months. We're already seeing positive effects from our acquisition of BG. BG delivered strong production growth in this quarter and some $200 million straight to the bottom line. We're off to a good start with the integration, building on 6 months of detailed planning before the deal was closed. At the same time, continuing to reduce costs and spending overall across both portfolios, with material opportunities to do exactly this in the downcycle. It's early days, but we're extremely pleased with what we're seeing so far from the acquisition. Turning to the results, and I'll start with the macro. We've seen a sharp decline in oil and gas prices compared with a year ago, reflecting primarily the OPEC policy change. Brent oil prices were some 37% lower than year-ago levels. Similar declines in WTI and the other crude markets.
The realized gas prices were some 36% lower than one year ago, with a strong decline in gas prices seen in all the markets. We appreciate there has been a recent recovery in oil prices during April, but this does relate to the fundamentals of supply and demand. It is far too soon to be calling a break in the weaker environment. On the downstream side, the refining margins were significantly lower in all regions, driven by oversupply, higher inventory, and a relatively mild winter in the U.S. and in Northern Europe. Chemicals, the industry cracker margin strengthened in Europe and in Asia compared to the same quarter last year. As was stripped by the further reduction in naphtha feedstock cost due to the decline in crude. U.S. gas cracker margins also declined as ethylene prices continued to fall over and above the decline in the gas prices.
You will, I hope, have seen the enhanced financial disclosures from the company this quarter. We now report integrated gas earnings separately from the upstream rather than the subset, and in more detail than in the past. In downstream, we've given an earnings split formally for the combination of refining and trading, obviously separate from marketing. Also taken on board some comments around the exchange rate impacts, which have been a bit noisy over the past couple of years in terms of quarterly impact. We're now treating non-cash foreign currency impacts in Australia and Brazil, specifically on the deferred tax assets. We now treat them as identified items. You'll see a restatement of that in the results tables today, both explicitly and also implicitly in the businesses.
As this effect was large and positive this quarter, had we reported on the prior basis, the underlying earnings would have been higher by some $570 million. Excluding identified items, Shell CCS earnings were $1.6 billion. That's a 63% decrease in earnings per share from the first quarter last year. That EPS figure for Q1 uses the weighted average number of shares in the quarter, and clearly that changed during the quarter. Much lower opening balance, $1.5 billion shares, roughly higher by the end of the second quarter due to the acquisition of BG. On a Q1 to Q1 basis, we saw an increase in the loss in the upstream and lower earnings in both integrated gas and in downstream. Return on the average capital employed was 3.8%, excluding identified items. The cash flow from ops was around $650 million or $4.6 billion, excluding working capital movements.
Dividends distributed in the first quarter were $3.7 billion, or $0.47 a share, of which $1.5 billion was settled under the scrip program. Turning to the business segments in a little more detail. Upstream earnings, excluding identified items for first quarter 2016, were a loss of $1.4 billion, but with $2 billion of positive cash generation excluding working capital. Low oil prices dominated these earnings, and that's a $1.4 billion effect compared to a year ago. However, I think it's very important to point out that the actual operating performance continues to improve The focus on margins, reliability, and uptime, it is delivering. You can see the increase in underlying production contributing, and we also have a decline in the operating costs. Turning now to integrated gas. Earnings there were $1.0 billion in the quarter. That compares with $1.5 billion a year ago.
Lower oil and gas prices reduced these results by some $700 million. Results also exclude the dividends from the Malaysia LNG Dua joint venture, which last year were $90 million in the first quarter. We exited that joint venture in May last year. Uplift from BG increased the contribution from trading and lower well write-offs. They all combined to deliver a profitable quarter despite the lower oil price. The headline oil and gas production for the first quarter was 3.7 million barrels oil equivalent per day, 16% higher than the first quarter last year. The uplift from the BG acquisition accounts for the majority of that increase. Let me also note, we're seeing the benefits of Shell's actions to improve the uptime. Less maintenance than a year ago, better reliability and uptime, for example, in the U.K. and in Malaysia. All good to see.
LNG volumes were also higher, mainly reflecting higher volumes as a result of the BG combination. Turning now to the downstream. Earnings there for the quarter, excluding identified items, were $2 billion, mainly due to lower results in oil products. In oil products, the refining and trading results were lower than in the same quarter last year. That reflected the weaker global refining conditions across the board and also reduced availability due to downtime, particularly in the Bukom refinery in Singapore. Marketing delivered strong underlying performance for the quarter, results at the same level as last year, in fact, driven by higher unit margins and lower costs. Chemicals earnings were 8% lower than a year ago. That was due to the lower margins in the U.S.-based chemicals, external margins, and the downtime again at the Bukom refinery in Singapore.
This was partly offset by lower costs and the recovery in production at the Moerdijk site in the Netherlands. Overall, another good quarter for the downstream. Return on average capital on a clean CCS basis was 18.8% at the end of the quarter on the 12-month basis, and the downstream CFFO, cash from ops, was around $11 billion over that same 12-month period. We made several announcements on the downstream portfolio during the quarter. In the U.S., Shell and Saudi Aramco decided to end the Motiva joint venture on the Gulf Coast. We're dividing the refining and the marketing assets portfolio between us. We've recently completed the sale of the Denmark marketing business for around $300 million. We also delivered a $400 million MLP equity offer in the midstream pipeline company in the United States.
We expect to complete the Showa Shell investment in Japan and the sale of shares in the refinement company in Malaysia this year. Taken together, the Showa Shell, Malaysia, Denmark, and the typical MLP yearly deals should result in around $3 billion of disposal proceeds this year. Together with potential contribution from the Motiva dissolution, that's a pretty good start for the year. Turning now to the cash position. Cash from ops on a 12-month rolling basis was $23 billion at an average Brent price of around $48 per barrel. That's pretty close to today's spot. Cash portion of the BG deal was $19 billion. That resulted in a negative free cash flow position in total for the quarter. The net debt position, which is around $69 billion, now reflects the total BG balance sheet and of course, the purchase price paid for that.
Gearing at the end of the quarter was 26.1%. We have recognized certain operating leases from BG as finance leases. These include FPSOs, some of the shipping vessels, and one LNG facility. Overall, the BG deal added 9%, or 9 percentage points, to our gearing, and 2 percentage points of that is as a result of effectively the finance lease changes. Priorities for cash have not changed. First, debt reduction, then dividends, then capital investments and share buybacks compete for the margin. Dividends declared were $12.7 billion over the last 12 months. More specifically on the BG consolidation, it's quite a significant one-off impact. The final transaction price for the BG acquisition was $54 billion, or GBP 37 billion. We'll find details of the accounting impacts to BG in the results announcement, the headline goodwill was $9 billion.
This is an accounting definition, an artifact, if you like. Goodwill is the balancing number between the fair value as seen by market participants and the purchase consideration, the $54 billion. Under the accounting standards, fair value is calculated using forward price curves as at the day of completion for the first 2 years, and then analyst macro forecasts thereafter. Just a reminder, the oil price on the 15th of February was around $33 a barrel. The forward curve was fairly low, and this did impact a lower fair value and therefore a higher goodwill. The profit and loss account going forward will include annually a $1.2 billion after-tax depreciation charge for the purchase price premium. That's basically $100 million a month. We had a $200 million impact the first quarter of 2016. It'll be $300 million in quarters going forward.
Let me now just move on to the ex-BG assets and their performance. We will, of course, talk about this somewhat in more detail at the capital markets day we're having in London on the 7th of June. It's great to see that the former BG asset growth really is coming through now in this quarter. The oil and gas production from these assets averaged around 800,000 barrels oil equivalent a day in the first quarter. That's 25% higher than a year ago, and it's a third higher than the production that was in the public domain when we negotiated and announced the bid. The production in 2014 was 600,000 barrels a day. In the first quarter accounts for Shell this year, we've booked only two-thirds of this amount, 522,000 barrels a day oil equivalent to be precise. Obviously, that reflects just 2 months of contribution.
The growth actually comes from the ramp-up of Queensland Gas in Australia and also the sixth and seventh non-operated FPSOs in deepwater Brazil. BG's assets overall added around $200 million to Shell's earnings in the quarter and approximately $800 million of cash flow from ops. Still early days, the synergies program is on track, but actually more than on track. You will have seen some announcements recently to reduce our U.K. office presence. Based on the excellent progress that we made in the detailed integration planning, we are likely to see delivery of the synergy targets much earlier than planned and at a lower than expected implementation cost. Overall, great start with the integration and obviously a lot more to come there. Before I close, a few words on spending. We continue to reduce capital spending and operating costs.
We're reducing those costs across the board, redesign, postpone new options. Earlier this year, a few months ago, we provided capital investment guidance for 2016 as $33 billion, potential to reduce that figure further because, of course, we hadn't actually got under the hood of the BG portfolio at that point. Now, capital investment for 2016, looking at the actual results, is clearly trending towards $30 billion. We look in detail at the BG portfolio. We continue to drive more capital efficiency in our own opportunity funnel. In practice, we're taking costs out of projects and projects out of the funnel. The $30 billion figure, just to be clear, in 2014, before acquisition, before we started either company working on reductions, the combined capital in 2014 was $47 billion. This $30 billion figure is 35% below that level.
It actually includes well over $1 billion of non-cash items for finance leases still to come this year, a couple of FPSOs in Brazil and Vito in the Gulf of Mexico. On operating costs, similarly, the underlying operating costs are trending downwards to a run rate of around $40 billion by the end of the year. During the year, we'll take a few one-off costs, most likely associated with the transaction, which is why we don't give a full-year figure. That $40 billion compares, again, go back to 2014, with something, $52 billion-$53 billion, 20% lower than the 2014 combined levels. In simple terms, we were saying all through last year, judge us on what we do, not what we say we're going to do. We're effectively taking $17 billion out of the CapEx and $13 billion out of the OpEx.
That's $30 billion out of the spend between 2014 and 2016. In very simple terms, we are expecting to absorb the entirety of BG's activity, OpEx, and CapEx, and keep the spend level in both cases at the same level it was for Shell alone in 2015. That's all a result of what I would humbly suggest is a world-class integration process that has been running since July last year and has really hit the ground running for both teams, BG and Shell. Just to summarize again then, integrated activities, well ahead through the customer, new differentiators, downstream integrated gas, both delivering good results underpinning financial performance despite $34 oil and $2 Henry Hub. We're already seeing the positive effects from BG. We're very busy now combining the two companies, looking to add yet more value for shareholders.
At the same time, we're continuing across the board reduction of costs and spending. Lots of material opportunities out there in the down cycle. Early days, very pleased with what we're seeing so far from the acquisition. With that, let's take your questions. I sort of raised this earlier, but I do acknowledge for all of you out there, we have changed some of the reporting segmentation, and this may be making some of the modeling quite difficult. Can I suggest that we don't cover those on the call and that we can follow up with the IR team primarily? I'll do what I can to help, but it may be a distraction for the main points in the call. Also a reminder, we have the Capital Markets Day in London on June the 7th, when hopefully everybody on the call will be able to join us.
Please could we move to questions, just one or two each, so that everybody has the opportunity. Operator, please could we poll for questions? Thanks.
Thank you, sir. We will now begin the question and 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. Our first question comes from Oswald Clint from Bernstein. Please go ahead, your line is open.
Thank you very much. Yes, Simon. Thanks. Two questions. First one, just on the upstream business itself, you spoke about the reduction in the OpEx, which I can see. Obviously on a country basis, we see here in the segmental that you're loss-making in every geographical business this quarter for the first time. OpEx has fallen, your uptime is good, reliability is good. Is there more you can do here to get the upstream across these geographies back into the black? Is that going to be sufficient for 2Q? Maybe if you could just talk about further cost reduction across the geographies. Second question, just on the CapEx trending towards 30, I think. I'm pretty sure investors are going to find that a little bit vague. I'm wondering, does that mean you feel confident about 30? Will it be above that?
Is there a chance it could fall below that? Just a bit more clarity around that CapEx number, please. Thank you.
Thanks, Oswald. The primary driver of the upstream number is a $34 oil price, plus the fact that even where we're producing gas, there is a linkage to the oil price, with some lag in some cases. That fundamentally is the difference. At today's oil price, $45 when I last looked, we'd be roughly $1 billion better off across the board, which moves some of the regions back into play. The fundamental reaction, though, you're absolutely right, is cost. We've made clear to the organization some time ago, and we are seeing the bottom line results coming then. In thinking about cost, the combination of BG and the $40 world is a fantastic opportunity to take cost out forever, as long as you think about the price being low forever and ensuring that costs don't come back again when they go back up.
Very strong focus on cost. That will come through. It's difficult to do $1 billion in a quarter, but it is certainly progressing in the right direction and there's more to come. There will be asset sales. We'll see that. We've been looking very closely at some of the more difficult areas, shall we say, of cost, such as the North Sea, and therefore working hard in that. As we go forward, you are going to see some new production coming on in places like Gorgon, all where that's an integrated gas, of course. Then in Kazakhstan and in Stones in the deepwater. We will see the BG synergies kicking in. Although quite a lot of that in the first year is on lower levels of exploration. All of those things contribute, each in their own small way.
The biggest short-term factor is clearly the oil price. Trending towards $30, what does it mean? Well, firstly, we genuinely only have now 10 weeks under the hood in BG and looking at the actual CapEx program. Before that, we did have 6 constructive months where we were limited in what we could share for legal reasons, but extremely constructive process during integration, or the planning for integration. We do have a reasonable view about what some of the choices are. The actual CapEx in quarter one was $6.5 billion. That's rounded up to include the January spend in BG. Multiply that by 4, you come up with a number less than $30 billion. If you look at the 12-month number, it's slightly above $30 billion, if you include BG. We're heading directly for $30 billion, and we're making basically decisions as we go along at the margin.
I would expect we'll hit $30 billion or below as we go through for the total for the year, because that's what the trend is telling us. We're finalizing that really over the next month or so ahead of the Capital Markets Day. There is an issue around rig commitments in terms of potentially idle rigs and what we choose to do with them has some noise impact. It could appear in OpEx, it could appear in ExEx, it could appear in CapEx. Which is why I'm slightly reluctant to commit to a very specific number. It'll be $30 billion or thereabouts, I think. 90% already committed. Hopefully that helps, Oswald. A longer answer, but I think it's a question that quite a lot of people have been looking to hear the answer to. Thank you very much. Can I move to the next question, please?
Our next question comes from Lydia Rainforth from Barclays. Please go ahead. Your line is open.
Thanks. Good afternoon, Simon. Two questions, if I could. The first one was, can I come back to focus on the OpEx side? If I look at the chart that you show, the move from 2015 to 2016 seems to imply about $8 billion reduction, which is clearly more than the $3 billion standalone guidance for Shell cost reductions and the $2 billion synergies. Is that the right way of looking at it, that you're actually doing more on the cost savings than you might have expected coming through? That partly links to the second question of, are you able to give what you think is now the cash flow breakeven to cover CapEx and dividends in terms of an oil price, either be it for this year or next year? Thanks.
The reduction between 2015 and 2016 that we're seeing, effectively, here using a rule of A, it's not necessarily $8 billion because we're trending towards a run rate of $ 40 billion. We might end up with slightly more than $ 40 billion in the year because of one-off items in the first part of the year. Broadly speaking, it's $ 47 billion down to a run rate of $ 40 billion in the year. Yes, we are seeing more opportunity than we'd originally expected. We previously stated $ 38 billion for Shell and add on a bit for BG, which is not necessarily all being accounted for on the same basis. All told, all integrated, we should be at a run rate of $ 40 billion by the end of the year.
This is coming from a variety of places, but One big help is synergies basically emerging much more quickly than we had originally planned for or expected. That's both on the exploration side, which we've been working at now for six to eight months, but also on the OpEx side, where it's clear we can absorb in quite a lot of areas, whether it's at the corporate function level or in one or two countries. The activities with no net increase in staff or cost. That has been a big driver. Plus, I think momentum, we talked last year about lots of, not small, but for you as observers, probably not that material, but $100 million here, a few hundred million there. Quite a few ongoing initiatives which are continuing. They took costs out last year, and They're taking more out this year.
It's aggregation of the contributions from many people, the 90,000, as I often say, in Shell, and not just something that Ben or I are exhorting people to do. Could be further room as we go forward as well. I expect, obviously, with the oil price being where it is, that's very much the direction we will head. Does that cover everything, Lydia? Next question.
Next question comes from Christopher Kuplent from Bank of America Merrill Lynch. Please go ahead. Your line is open.
Hi, thanks. Good afternoon. Simon, just two quick ones. I just wanted to check. I think you've now got almost $70 billion under your definition of financial net debt. The free cash flow, obviously, is still negative in Q1. I guess will remain negative this year. Just wanted to check how worried you are on the gearing side of things and whether that $70 billion number is causing alarm bells as well to ring. Secondly, just wanted to get my hand round again the $40 billion OpEx, whether you could give us a bit more detail where that OpEx actually sits, what you include in there, how much you would define as structural costs that are not coming back should the oil price recover into the next three years? Or indeed, how much of those savings are purely pricing and cyclical? Thank you.
Okay, I'll try on the second one. The first one is a really important point. $69 billion of net debt. Yes, it is something that I might lose sleep about, but not just yet. 26.1% gearing. Free cash flow negative in the first quarter, obviously driven by the BG deal and the working capital, the $4 billion. It's $15 billion there that impacts the free cash flow. A $34 oil price didn't help either. Going forward, in the short term, at $45, with the current level of spend, the gearing and the net debt is likely to go up before it goes down, even at $45. What brings it down? It's the continued reduction in OpEx. It's the continued reduction in investment level. Importantly, it's the coming on stream of new projects. None of these are easy fixes.
I'm confident, very confident, that the right things are being done. What we need to do is do them at pace and ensure that we are delivering sooner rather than later. It's great to see the BG synergies coming in as we do. The gearing figure of 26.1% is a couple of percentage points higher than previous advice and is driven entirely by the treatment of the leases as financial leases rather than operating leases. This has no impact or little impact on the credit rating because the rating agencies look through that. It does mean that any statements made around gearing, you have to sort of add two percentage points onto any previous statements of expectation. That figure will also be impacted going forward by new FPSOs as well, of course.
A manageable situation, but not one that has any easy fixes, but I think all the right things are being done. The credit rating agencies have taken a close look, and Moody's has brought most of the industry down. We came down to double A with Moody's. S&P, we're at an A plus rating at the moment, and that is still with a negative outlook. We are looking at effectively how our future performance benchmarks against those metrics as a key performance parameter for the management. Both debt reduction and increased cash flow generation are required to get those metrics back into the right place. The $40 billion OpEx, here's the high level breakdown. It's half and half upstream, downstream. Billion dollars is only the downstream. The $20 billion upstream is split two-thirds, one-third between upstream and IG.
That's after allocating everything to the businesses. Round about $10 billion of the 40 is what you might think of as corporate type cost, finance, IT, real estate, HR, et cetera. The reductions that we've talked about are coming across the board. Many are linked directly to reductions in the number of people by changing the way we do things or changing where we do the work. Different relationship with, for example, suppliers, not just on unit rates, but fundamentally changing the way we deal. Standardized design, different way of handling IT, et cetera. It's not something we started three months ago. It's something that we started three to five years ago, depending on the area we're looking at. We're pretty confident most of what we're doing will stay out, if the oil price does recover at some point in the future.
Clearly, at the margin where we're in the third party services are being supplied to us, there is exposure if oil price comes back. To be honest, a lot of the savings that we've seen so far have been in, for example, areas like drilling. It's been better performance as much as it has been low unit rates, or it's been in areas of activity such as the North Sea, where reducing costs is not a nice to have, it's an imperative, or facilities will be closed in. Some very significant changes in the way of doing things that will not be reversed in the event that oil prices go back up. We're quite pleased with what we've been seeing so far, and let's see how much further there is to go. Many thanks, Chris.
Hopefully again, both questions quite relevant to most of the audience. Next question, please.
Our next question comes from Jon Rigby from UBS. Please go ahead. Your line is open.
Thank you. Hello, Simon. Two questions. Could I just ask a question on LNG? I think you said that there's about a $200 million contribution from BG. Can you confirm or discuss a little more about what you're seeing in terms of optimizing cargos? Are you able to see the kind of trading, and optimization earnings that BG was able to generate? Is that starting to spread into the Shell business as well, the bigger Shell business? Maybe some color around that would be really useful. Secondly, just on chemicals. Obviously, Moerdijk coming back, but I think you referenced Bukom down. Is it fair to say chemicals is under-earning against where you'd expect it to be, all things equal? Maybe are you able to sort of calculate or indicate what you think the delta might be if everything was running rather more smoothly? Thanks.
Thanks, Jon. You're right on chemicals. I'll take that first. It's $200, $300 million. It's Bukom. Moerdijk came back. Essentially, the ethylene cracker in Bukom has been down. Should come back in the middle of the year, plus or minus the end of Q2. You are talking a few hundred million dollars, if you like, left on the table compared to everything running smoothly. LNG optimization. Still a bit early days. I don't say too much with some commercial sensitivity here, but I think we're seeing just as much flexibility and optimization in the Shell portfolio as there is in the BG portfolio. It's a great opportunity to learn from both sides how to optimize not just in the short term, but the medium and the long term. In very simple terms, Shell's traditional approach was supply-driven, and BG's traditional approach was market-driven.
As the two meet in the middle, you may be aware that Steve Hill, who used to run the GEMS business for BG, is now running basically the same business, but twice the size for Shell plus BG. Having Steve there, plus the guys who've worked on our portfolio is indeed identifying further opportunities. Certainly in the short term, interestingly, optimization is just as positive from the Shell portfolio as BG. One has to say, at this particular point in time, neither of them is as lucrative as they have been in the past. It's a great point for the future, opportunity for the future. I'll just take this opportunity to note, we've now got two volumes in for LNG.
We're showing effectively the share of equity production, which is about seven million tons in the quarter. You're looking at over 30 million tons on an annualized basis. We've also shown the Shell share of effectively the sales Because in BG's portfolio and increasingly in Shell's portfolio, we're lifting other people's production and selling it. Our share of sales is actually 12 million tons in the quarter, and therefore fully annualized, you're talking around 50 million tons or 20% of the world market in terms of Shell equity molecules. It gives you a feel of the scale and the opportunity. Thanks, John, and good luck against Brighton on Saturday. Next question.
Your next question comes from Biraj Borkhataria from RBC. Please go ahead. Your line is open.
Hi, Simon. Thanks for taking my question. I had a couple. The first one in looking at upstream Americas or North America now as stated, CapEx was down quite sharply Q on Q by about $1 billion. I was wondering if you'd talk about the unconventionals business specifically and post the departure of management there, and how that fits into your overall portfolio, as well as how much capital that business will get for 2016 and going forward. The second question was more of a clarification, really. I noticed the Oceania gas realizations were particularly weak in the quarter versus the run rate. I was wondering if you could give a bit more color on what's going on there. Thanks.
Sure. Thanks, Biraj. The unconventionals business in North America and Argentina together is getting about $2 billion of capital allocation this year. That's quite a lot down on previous years. We're getting a lot more for it as it happens, because they keep coming in ahead of target. About 70% of the wells are coming in with a 1,000 barrel a day initial production or better. We're seeing costs continue to be down sort of 20%-30% like-to-like year-over-year. The majority of the activity still remains exploration and appraisal. We've rarely, if at all, pulled the trigger on major developments for obvious reasons, $2 gas and $34 oil is not the time to be doing major development. It's a bit in a holding pattern. Strategically, we're in a good place.
We've got now in terms of resource potential, you're talking up to 12 billion barrels of oil equivalent resource potential across Canada, U.S., and Argentina. Around three quarters or 70% or so of that is gas. We have the balance sheet value is just under $15 billion. You've got massive resource, just over $1 a barrel. I think over time, this is going to be great value to develop. In the short and the medium term, it'll be on a pretty much a care and maintain capital allocation. The Oceania gas realization, and ultimately this is driven in part because what you see is a net back. It's a net back both in Queensland and in Western Australia, and therefore the realization, a net back to the LNG price. It's linked almost directly to the LNG price.
Once you've deducted effectively the way Queensland gas is being structured with tolling agreements and pipeline tolling. Once you've deducted the costs of taking the gas from the wellhead, liquefying it and getting it to market, that has basically driven down the average realization price. All of the price upside gets shown in the upstream rather than the midstream in practice. That's just the nature of the BG setup in Queensland. It's also not dissimilar in Western Australia, at least in terms of the realizations that we would recognize. Okay. Many thanks. Next question, please.
Your next question comes from Irene Himona from SG. Please go ahead. Your line is open.
Thank you. Hello, Simon. My first question is on volumes, if I may. You highlighted the contribution of BG to Q1 production and LNG. Are you able to provide some guidance on the new group's production in full year 2016 and 2017, given all the moving parts of the puzzle? Secondly, going back to the $ 40 billion. Effectively, you're talking about faster near term OpEx reductions, as I understand it. How does that relate to the $ 3.5 billion synergies from BG by 2018? Is it the same number happening earlier? Are you able to raise that? Is there anything you can say at this stage on the question of value synergies over and above that number, which I understand had to be strictly sort of audited? Thank you.
Thanks, Irene. Volumes, if we had three months of BG rather than two months, we'd have been about 3.95 million barrels oil equivalent a day. Quite a step up. As we go forward, I cannot give you guidance simply because it literally is not on my radar screen, the production, because we're spending all the time on cash. What are we spending? What are we earning? Where are the priorities? Production, to be brutally honest, apart from needing to be safe and reliable, is an outcome. It will obviously be impacted not just by divestments, but also new projects coming on stream as well.
I do think fundamentally at the moment, we're putting together The asset level detail, the maintenance, and the underlying spend programs. We are aiming to put together a much firmer and clearer collective unified plan by the back end of this year. During this year, quite a lot of what we say remains a little bit provisional, although it will be accurate. The targets for the individuals will be set in the back end of this year. I can't give further guidance on the volumes. The $40 billion, how does it relate to the $ 3.5 billion? The $ 3.5 billion by 2018 was, if you recall, $1.5 billion of exploration and $2 billion of OpEx. The $1.5 billion of exploration is something that we will almost certainly deliver early, quite early.
I don't know if we'll actually get there this year, but we'll get probably close this year. Of the $2 billion of OpEx, it is a bit harder work, but actually we're finding we're doing that much more quickly. I can't say because, again, don't actually have the exact figures, but a lot more than I originally expected when we did the prospectus will be delivered this year, and it will also cost us less. We had said in the prospectus that $1.2 billion would be the total expected one-off cost of the acquisition. It should be lower than that, and we will also most likely try and ensure that that cost is incurred all in 2016 and doesn't spill over into 2017. Those are the moving parts. Are we in a position to raise the number?
Clearly, there are indications that there are opportunities from what I've just said. I think it's something we'll probably revisit in a month or so. It's time for capital market spend. At the moment, the focus is on achieving the synergies, not necessarily extending them. We're seeing some great progress. The same is true on value synergies. What we are seeing is a combination of factors. We need to understand not only the numbers in the BG plans, but also the psychology behind them. How optimistic or conservative are they, and how are they comparing with what's actually being delivered? The actual asset performance is extremely good against the original BG plans to date, I must say. Therefore, that might actually throw up, yes, there are some value synergies that we can bank earlier rather than later.
We're definitely seeing lower costs in one or two areas, crucially in both Brazil and Australia. That is helpful indeed, because they are, by the definition, the two most valuable assets in the portfolio. So far so good, but I can't be more specific than that. Thanks, Irene. Next question, please.
Next question comes from Martijn Rats from Morgan Stanley. Please go ahead. Your line is open.
Yeah. Hi, good afternoon. I wanted to ask you two things. I listened to part of the media call this morning, and in there you sort of invoked the spirit of Mario Draghi by saying, "We will do whatever it takes to balance our financial framework over the cycle." I was wondering if you could elaborate on that. It sounded like you potentially had something specific in mind. Also, how far does the balance sheet gearing need to rise before sort of whatever it takes sort of really kicks in? The second question I wanted to ask is with regards to operating cash flow in the quarter.
Even taking into account low oil prices, the sort of the $4.6 billion working capital looks a little light. I was wondering if some of the one-off costs related to the acquisition, some of the sort of $1.2 billion figure that you also just mentioned might already have been in there while not taken as an identified item.
Thanks, Martijn. What I actually said this morning was in response to a question, what's your break-even price in cash terms? So far this afternoon, you've all been kind enough not to ask the same question, you probably would have got the same answer. We don't have one, was the answer, I would paraphrase Mario Draghi, we will do whatever it takes to balance the cash flow through the cycle. Actually there isn't an alternative, if you want to quote somebody else. Importantly, it's through the cycle. The aim is not to achieve any given break-even point in any given year. I also quoted going backwards. The previous 12 months is $ 61 million. The 12 months of 2015, break-even was $ 55 million or around $ 70 million, excluding divestments.
Clearly that needs to come down a little bit, if we are to stay in business. Therefore, we will do whatever it takes. That means reduce OpEx, reduce investment further, ensure that we deliver projects, keep them up and running, maximize the margins, and divest assets. The biggest short-term factor will remain the oil price. The second biggest is, in practice, divestment. That's one we can't control, the other we can. After that, it's investment and OpEx, we've already talked about that. You can see we're doing whatever it takes in those areas. How far does gearing need to go before in that situation? We're in that now. We always knew we would be post BG, but the credit rating metrics I referred to earlier, the actual numbers today would not necessarily mechanically support the ratings that we currently carry.
We need to improve the ratings. That is clearly stated by the rating agencies. We need to start to reduce the debt. It's simple. That's priority number one. We are in that situation now. $4.6 billion of working capital looks a little weak as a premise. Yes, perhaps. Yes, it's got some one-offs in. It's got, for example, the stamp duty in paying for the deal. At present, $ 300 million or so to George Osborne in terms of the cost of the deal, but that's less than $500 million in total in the quarter in cash terms. There's always a few one-offs, but by and large, the big factor was the working capital and the cost of sales adjustment, which ultimately some of those are one-off, some of those will reverse over time.
I can't recall whether I mentioned it earlier, but there is a trading inventory. It's basically a contango effect as well. That is reversible. The payment to the Iranians for their crude liftings a few years ago is not reversible, but it is one-off. Those things will play through, and it's always difficult to look at one quarter alone to see FFO. Let's see how that goes going forward. Okay. Next question, please.
Next question comes from Thomas Adolff from Credit Suisse. Please go ahead. Your line is open.
Hi, Simon. Two questions as well, please. First one on CapEx, and I guess there's no such thing as an apples to apples comparison when we look at the reported CapEx guidings amongst the super majors. If we look at the $ 30 billion or so that you talk about, is that the right balance for short-term cash and returns and the longer-term health of the business? I'm kind of asking this question based on, obviously, today's cost environment, and it's clearly further cost reduction to come outside of shale. The second question on the Lower 48. Obviously, Marvin left. The Lower 48 is now part of Andy's portfolio again. I think back in November, you said we're going to try to run it independently.
I think when I spoke to Marvin, he said, I haven't quite figured it out, whether it's the XTO type management or whether it's the BP type management, which is truly independent. Have you figured it out yet? Thank you.
Thanks, Thomas. I shall have words with Marvin. On CapEx, is $30 billion the right number in the current price environment? Well, probably not, because look where we're coming from. We spent $47 billion two years ago, so massive reductions. Even of what we spent today, some of that was committed in an oil price environment a lot higher than today. The unit rate of completing projects, think of Gorgon, Prelude, Stones, et cetera. Kashagan for that matter, Clair, Schiehallion. Those costs reflect a higher oil price environment, not today's oil price environment. The stay in business and maybe invest a little bit for the long-term health of the business is probably lower than $30. At today's unit rate, the costs that we would expect to see. Again, no specifics, it's just less than $30 is what I would say. Could be several billion dollars less.
On the Lower 48, there certainly are two models out there, sort of the reverse integration into an XTO type model or the UBI internally. That could be conceived in practice. The team running the onshore shale business today is the same team that was reporting to Marvin. They just now report to Andy. What they have done is take huge amounts of cost out on the asset in drilling and to the extent they're able to do in the aggregation and other facilities. What they and we are working on is basically the above asset costs, and how we deal with that will determine the answer to your question. It is coming down. It's coming down across the board, part of the $40 billion. It's not yet decided the specific answer to your question or whether there's a hybrid version.
What I would like to think is if lower levels of above asset costs are feasible for the shale business, then they should be feasible everywhere else in Shell. Let's use that as the pilot to identify where we can go further, faster elsewhere. Both of those are in progress at the moment. I think Andy will be with us on the capital markets day, and I know he was in the U.S. last week, so it's a good question to ask him. Next question, please.
Next question comes from Alastair Syme, from Citi. Please go ahead. Your line is open.
Thanks. Hi, Simon. Two quick questions. One on OpEx. You gave the 2014 reference pro forma. Can you give the 2015, by any chance? Secondly, appreciate the integrated gas and upstream from an accounting standpoint, but does that distinction apply wholly internally? I know Martin and Andy are running the businesses, but are people allocated to these different businesses distinctly?
On the latter, yes. I mean, they are being basically run as separate businesses. Although we reported externally an IG segment, which is basically the same asset previously, the reporting lines were not unified, so to say. Martin is now directly accountable for activities such as Trinidad and Peru and all of the trading that is done through Steve Hill in Singapore. That's effectively how that works. On the OpEx 2015 pro forma, it was basically interpolate between the two at somewhere around $46, give or take. The reason I'm not slightly more specific is there are some differences in definitions and accounting treatment. It's close enough, straight line between the $52, $53 in 2014 and the $40 by the end of 2016. Unfortunately, I don't think you can quite extrapolate that rate of improvement, but hopefully there's some improvement to come thereafter as well. Next question, please.
Our next question comes from Lucas Herrmann from Deutsche Bank. Please go ahead. Your line is open.
Simon, hi. Thanks for the time, and by the way, thanks for the added disclosure, which is useful, even though it will require a lot more spreadsheeting. Three brief questions, if I might. Firstly, hard choices, given where you're at. Do you want to say anything around the Pennsylvania cracker timing, if at all? Secondly, just on cash flow, deferred tax and other provisions, and this is not the deferred tax adjustment you had been making quarterly, but the deferred tax negative that's been running through your cash flow statement. Can you talk through that in a little more detail? The number has become increasingly large and just sits there as a big negative with no real explanation. Thirdly, if I might, the operating cash flow in the upstream business, which has clearly sunk over the course of the last four years.
Can you give us any indication, through last year or into this year, what proportion of that comes from the deepwater? Not the collapse, but the absolute today. What proportion is the deepwater that you suggest to us will deliver $15 billion-$20 billion of operating cash flow, back end of this decade? What proportion is the traditional upstream engines business? That's it, Simon. Thank you.
Thanks, Herrmann. Apologies-
You can call me Lucas.
We have the same problem, by the way. The hard choices, there are three or four big projects. The first on the list is, in fact, the one that you relate to, the chemicals in Pennsylvania. The others being Lake Charles, Gulf Coast, LNG Canada, British Columbia, and Vito Deepwater, Gulf of Mexico. They're the sort of the big four greenfields over which we could take a final investment decision in the next, well, less than 12 months. It's highly unlikely that more than, I would say, two, maybe only one, that will actually go ahead in that timeframe. Basically, it's a choice of what's the best way of retaining or maximizing value from that set of opportunities. The chemicals plant is probably the first one because of the timing of certain commitments that are already in place. It's an excellent project.
It's got a diverse set of market exposures and risks associated with it, therefore provides quite some portfolio resilience relative to the rest of the opportunities. Not just the big ones, but the small ones as well. We've had quite a lot of discussion. Not yet pulled the trigger on it one way or the other. It's not a free option, of course. There are costs of keeping the option open. Not a decision yet, but it actually is looking, if it were not a $40 world, it would be probably a very easy decision. It's a very strong and robust project. Deferred tax and other provisions. I will try not to go into too much detail here. We just added a $6 billion liability as a result of the PPA calculation.
Effectively, the tax benefit of the step-up in fair market value of an asset has to be added back in, and that increases the deferred tax liability by $6 billion. Elsewhere, we have deferred tax assets as a result of making losses in countries such as the U.S. and the U.K. We have deferred tax liabilities, such as benefiting from capital allowances in countries such as the U.K. and elsewhere. There's quite a complicated set of moving parts behind this. The biggest issue for us and for analysts is, are these tax assets recoverable? Which by definition, if they're on the balance sheet, they are seen to be. The deferred tax liabilities will play out over time as the earnings come through from the assets to which they're associated. Which the step up of $6 billion that I just mentioned is virtually all in Brazil.
Therefore, you can envisage, as you see Brazil produce and perform, that you will see the liability reduce. Deepwater production, I'm just looking. It's around 400,000 barrels a day at the moment, which basically is a combination of Brazil, U.S., and Nigeria. That would be the Shell number. You can have that on BG. BG is approaching now 200,000 barrels a day, effectively in Brazil. You're seeing over half a million barrels a day. It's highly price sensitive. Almost by definition, all of those areas have excellent exposure to higher oil prices. At $34, that was a contributor to the negative. It's probably the most price-sensitive element within the upstream business. Therefore, it's also the piece that's grown. It's the big driver of the future, but it's not helping today. Okay.
I think that's probably as much as I can say on that. Probably something we'll need to follow up as we do the capital markets day work. Next question, please.
Our next question comes from Anish Kapadia from TPH. Please go ahead, your line is open.
Good afternoon, Simon. Couple of questions from me as well, please. Just following up on a couple of things. The first one was on cash flow. Looking at Q1, if we take the cash flow from ops, ex-working capital, and post interest, it seems like about $4 billion. If you take a full quarter of BG, feels more like $4.5 billion, or $18 billion annualized. Is that a good basis to estimate cash flow off for this year using your sensitivities or are there any other kind of incremental factors, incremental cash flow that we should think of for the remainder of this year? The second one on taxes, following on from your last point. You have seen a substantial increase in your deferred tax asset, and also your unrecognized tax losses.
I'm just wondering, with BG coming into the business, is there an opportunity to accelerate the use of these tax losses with some of BG's key profit centers such as Brazil and Australia?
Thanks, Guy. The simple answer on the second one is yes. I can't go into too much further detail about that. We need to be both clear about the best way of doing it and making sure that it's agreed with the relevant authorities. Bringing together effectively income-generating assets and tax losses in a given country is an opportunity in at least two or three countries I'm aware of. The cash flow estimate for the year, will four times Q1 suffice? Well, yes and no. It's not any one-off factors, minor Q1 factors get multiplied by four, positive or negative. It's not the best way to look at it. Maybe look at the four quarters going backwards, which were actually at an average of $48 cash flow 23. Add a bit for BG is just as good as going four times Q1.
That in itself is not to be taken as a projection. It is just a little help with modeling because there is always noise in the cash flow statement. Remember that as we go forward, if oil prices do continue to rise as they did in April, we will increase working capital and therefore there will be a working capital outflow. At the end of the day, we work on the levers that we can, such as inventory levels and OpEx, then the actual number, to an extent, will be an outcome. Many thanks. Move on to the next question, please.
Our next question comes from Guy Baber from Simmons. Please go ahead. Your line is open.
Thank you very much for taking my question. Simon, a couple from me. You referenced the improved reliability in the upstream. Is there any way you can elaborate on that comment or perhaps quantify the extent to which reliability in the upstream is improving your production performance? I am curious, in an environment where you are attempting to reduce spending and take out costs and there is a focus on integration, is there a risk that you may begin to lose some of those reliability improvements, and how do you mitigate that? Secondly, in balancing the cash inflows and outflows, you mentioned spending costs and divestments. You did not mention the scrip dividend. Just wanted to get latest thoughts and comments around the extension of that scrip program into 2017 or beyond, and just what your most recent thoughts are around that program.
Thanks. Good point. The reliability year-on-year, our production performance was about 110,000 barrels a day better than it was a year ago just as a result of better reliability and availability. Our big drivers there in the U.K. and Malaysia, but also the Gulf and one or two other countries. That is a very material uptick. It also coming off not the best of quarters a year ago. That gives you some feel of the volume impact. Of course, the margin impact does vary. It actually more than offsets the decline, the underlying decline in the assets overall across the portfolio. This is just better reliability. In practice, one of the approaches coming out of the improved programs on maintenance is the timing and the scheduling of maintenance turnarounds.
Looking at them in the same way in the upstream as we do in the downstream. A typical downstream turnaround period is three or four years. Typical period in the upstream was a lot shorter than that, in fact, one year in many places. Every year there'd be some turnaround for maintenance. Just taking best practice within the group and improving the way we do the work, working better with contractors, managing the logistics offshore, for example, making sure the parts are available when you need them. These are all hard yards, but when you're doing them, and we're actually managing through a production excellence program in quite a different way across the asset base now driven by Andy.
We've seen that really start to deliver to the bottom line, and this was one of our better quarters, no question, with that more than 100,000 barrel a day uptick. You're absolutely right that taking costs out at the same time, if we are too indiscriminate, creates a risk, which is precisely why we've not stood up before and not really standing up today either and saying, "We will take $5 billion out of cost." What we have said is we have taken or we are taking, not that in some macho manner, we will take X billion dollars out because it's that type of statement that creates the risk and exposure when everybody tries to do the right thing even though they sort of have the concern about the risk you highlight. It is an ever-present risk in our business. Safety comes first, always has done, always will do.
Safety and reliability are very closely correlated. Scrip dividend. It's great question. What we have said is priority for cash flow, just a reminder, first of all, debt reduction, then dividend, then combination of investments and buybacks. The scrip is inherently linked to the buybacks. It's highly unlikely we would start buybacks before switching off the scrip. It's also highly unlikely we'd switch off the scrip and cut the dividend. We will and must reduce the debt first. We need, and what I stated before, just to be clear, is that we need to see the debt and the credit metrics returning to the point where they support the current ratings and a strong credit rating. The proxy for that was a 20% gearing. We needed either to be at 20 or line of sight to 20 and below.
That figure is now probably low twenties because of the point I made earlier about finance leases. We have to turn the debt around, take the gearing down. When we get to that point with clear line of sight of how are we going to ensure that the metrics are in a robust place for a credit rating, and are not going to slip backwards, then we move to the next set of priorities, which in the first instance, would be almost certainly stopping the scrip. That is unlikely to happen this year, looking at where the oil price is, and one of the big drivers will be where does the oil price go in terms of timing. The oil price is not the long-term driver. The sequence of events I've just stated and the logic will apply.
It just may take longer if the oil price stays lower for much longer. Some recovery of oil price, together with delivery of everything that I probably already talked about in terms of improving the cash flows and reducing the debt, should, within the next two to three years, lead to switching off the scrip. At that point, considering what we do at buybacks. These things may be sequential. Therefore, we do need to see the gearing down in the low 20s and still trending lower before we have that discussion. Many thanks. Could I move to the next question, please?
Our next question comes from Rob West at Redburn. Please go ahead. Your line is open.
Hi, Simon. I'm chomping at the bit to ask questions about your integrated gas split out, I'll keep them high level and save the really nerdy detail ones. My main question for you is why can't we have more disclosures, specifically around the things we'd really want to know? Like the average realized LNG price or the cash contribution from Pearl, which is a very unique asset in that portfolio. Can you say what those are? Is there a reason why you specifically can't say what those are? Then my second question is just on the divestment targets. I think you mentioned $3 billion coming in from Shell Malaysia, MLPs, and Denmark. Can you tell us what is the annual cash generation from those assets? How do you think about the annual cash flow you'd be willing to divest in that $30 billion divestment target?
Thank you.
Thanks, Rob. Disclosure, I appreciate the interest. I would like to think we're probably as transparent as anybody of our scale and size. If we were a two-asset company, then we maybe need to give more disclosure around key assets. Pearl remains one of the most valuable assets in the portfolio, if not the most valuable single asset. It's also a confidential one in terms of the agreements between ourselves and the Qataris. It's a very strong cash flow, even in today's oil price environment. Because it's essentially, it's not production sharing, it's a revenue-sharing agreement. It's been a great cash generator both for Shell and for the Qatari government. The average realized LNG price, I don't have a pushback reason why we're not giving it. I'll take that one away and think about it.
I just know for sure it will be actually quite difficult to calculate at the moment because we're still working on the systems. I did mention in the press conference this morning that the fact we even have these results at all is the result of an enormous amount of effort by two teams Primarily in Reading and here in The Hague to actually take two sets of accounts and bring them together. Point taken, we'll think about it. $3 billion asset. Well, any asset we sell, we're selling the associated cash flow, and that's what's being valued by the purchaser.
It's not easy to explain what you might think of in terms of modeling, there's probably, on average, because we're selling quite a lot of assets, what we sell is probably cash flow, same return on what we sell it at as the average cash flow on capital employed in service in the business. Capital employed in service in the business is probably not far short of $200 billion. Yes, we lose cash flow, it's not that major, it's probably not that different from the average in the portfolio once you look across.
We are at the stage of re-looking, I think, fundamentally, at the cash flow generation characteristics of the assets we've acquired and how they play in, not just in terms of the next six months, but the longevity, the risk profile, and which of those assets really form the part of the strategic intent, the long-term portfolio that we're trying to create. That is very much the sort of discussion that we'll address under the strategy discussion on the 7th of June. I won't go any further on IG disclosure, thanks for the question and the suggestion. Next question, please.
Next question comes from Jason Gammel from Jefferies. Please go ahead. Your line is open.
Thanks very much, Simon. I just had a couple questions around Motiva, actually. First of all, it was hoping that you could address some of the factors that led you to decide to dissolve that joint venture. Second, if I look at the assets that you have elected to retain, it would seem to indicate a preference for gasoline manufacturing capacity and light cracking capacity in preference over diesel manufacturing capacity and being able to crack the heavy barrel. Have I gotten that right? Finally, I'll take a futile one here. Do you have an order of magnitude in the amount of cash that you think you might take out of the transaction?
Thanks, Jason. I have to be careful here because some of this is still commercially sensitive and under negotiation as to how we finalize the deal. Why dissolve? The original joint venture was 1998 for 20 years. There was a, I would call it a prenup, but there was an opportunity to look at do we want to continue? Do we still have the same sort of level of strategic alignment to believe that we can create more value together than we can apart? Yes, we can create value together, but we said, well, if we do split the assets, is there a way in which we can allocate them where we're both more comfortable that we can manage the value chain? That's ultimately how it ended up.
Yes, we could have taken one or other set of assets, but at the end of the day, a negotiated deal is what people will accept. A balancing payment is likely to be made, but it may be made in terms of taking on debt or otherwise, you might not see cash actually flow. The way the assets are structured, that balancing payment, per se, is clearly going to be ours, not in the other direction. Likelihood is it will contribute to the divestment proceeds. It just may not show that way in accounting terms. It is most likely that Motiva will move from being an equity associate. Something where we only see cash flows when dividends are paid out. It will move to a fully consolidated basis, but only half or just less than half as much.
There will be some changes as and when we conclude the deal. First of all, we have to conclude it, and we'll try and be as transparent and helpful as we can because it's a big piece of kit and the numbers are non-trivial, and it will impact everything I said about OpEx and CapEx, for example. Thank you. Next question. Please.
Our next question comes from Anik Ghosh from Exane BNP Paribas. Please go ahead. Your line is open.
Thank you. Afternoon, Simon. Just two questions please, if I can. One, you talk about the urgency of the debt. Obviously there's a big focus on simplifying that upstream portfolio, which if I think about the buckets you laid out, deepwater, integrated gas, I think I might even be a bit light here, but there's at least about 1 million barrels a day, which is in some way sort of non-core. I just wondered, or at least why would you not consider a spin-off or an IPO, potentially if that becomes the best option in terms of disposals and maybe even get the debt down that way? My second question, that $30 billion guidance, just in terms of can you just help me bring that number capital invested back to capital expenditures in terms of the cash flows?
It seems as though it's sort of trending around GBP 27 billion. I just wanted to get that cash flow equivalent number based on that guidance, please, if possible.
Thanks, Anik. I may need to ask you to clarify the second question. The first one, the focus on simplifying the upstream. Why not IPO part of it or otherwise? Yes. Why not? The primary reason is it's $45 oil. How attractive would it be in the market? There are no prima facie reasons why we wouldn't look at such a monetization route if that were the best way to create value. It's not obvious that in today's market it would be. The teams we have looking at monetizing assets are looking at a very wide range of assets that if we were to divest all of them, it would be considerably more than $30 billion coming in. It's a variety of types of transactions. Motiva being one of them, for example, a split. There are other transactions which could involve markets.
We did actually create the MLP, the IPO in the U.S. It should be clear that not only are we open to it in innovation and idea terms, but we are able to deliver such complicated deals, and execute over a period of time. That's very much on the agenda, but all of it is subject to what will the market take at any given point in time.
Makes sense.
Just on the second question, I'll try and answer and then see if it's correct. When I talk of $30 billion capital investment, that isn't all cash in any given year. The two main factors that differ are finance leases. When we bring an FPSO onstream, exploration expenses, which actually pass through the CFFO, and not through the cash used in investing on the cash flow statement. $ 30 billion of capital investment may well indeed translate to something this year around $ 27 billion of cash used in investing on the cash flow statement. Indeed, there is a bit better free cash flow position than you might otherwise expect. You can see some of that in Q1 where the capital investment was $6.1 billion, but the cash flow in CapEx was somewhat less than that, if you look at the cash flow statement.
Does that cover your second question, or was there a more specific point to it?
No, that's exactly it. That's perfect. Thank you.
Great. Many thanks. Next question.
Our next question comes from Tjibbe Berkelder from ABN AMRO. Please go ahead. Your line is open.
Yeah. Good afternoon, Henry. Two questions on Integrated Gas and the BG contribution. Can you maybe tell what the BG contribution is in the Integrated Gas segment? Secondly, looking at especially the production costs in Integrated Gas, can you tell me why they're so much higher than they used to be? Is that only BG for one and a half months?
First question, about $200 million generated in IG from the BG assets, which would include the trading contribution as well. The production cost, I'm not sure I have a response for you, to be brutally honest. The production cost, if I were to think about it, would include Queensland, which by definition are relatively high compared to our average because many of our Integrated Gas assets are associate companies, and we don't show operating expense per se. They're accounted for as associates. The operating cost is primarily in Pearl and then maybe one or two other operated assets, but it's not shown as high. Whereas Queensland Gas, a bit as I mentioned earlier, the Upstream bears the cost of effectively the tolling cost of running through the LNG and the midstream assets. That may be one of the drivers.
There are no special factors in there?
Yes, although they will persist. If I'm right that it is in fact Queensland Gas, that will happen. It's also true, by the way, that Pearl GTL had a big major shutdown that ran over the quarter end, and the plant has just come back online in the last couple of days. That major shutdown and also much lower production was also a factor at the back end of the first quarter. Okay, next question, please.
Our next question comes from Asit Sen from CLSA. Please go ahead. Your line is open.
Thanks. Good afternoon, Simon. Two questions, please. First on Brazil and second on LNG. On Brazil, could you quantify production, or current production or production in the quarter? Since it looks like one FPSO started there, particularly since Brazil is such an important part of the story. Any color? Second on LNG, could you explain or help us understand the impact of Sabine Pass LNG exports on Shell's financials since there's a fixed liquefaction charge? Ramp-up is expected to be fairly substantial. Wondering if you could help us frame for us the potential impact on a broader Shell portfolio, please.
Thanks, Asit. On Sabine Pass, you're right, it's fixed liquefaction on top of effectively we put the gas in the Henry Hub and lift. We haven't really lifted much gas yet. It's still early stages, and we've not been the lifter, I believe. Most of the volume I think in that first trade does come our way, but it's not yet had a major impact. Yes, we will need to ensure that we are able to sell the gas to cover the liquefaction cost. The good news is, in our view, that's the lowest cost LNG that is available from the North American content, including all the other projects that so far passed FID. Which is a good place to be in. In fact, Henry Hub is low, also makes it potentially attractive to take the gas over to either to Latin America or to Europe.
Brazil production, absolutely right, major factor. We're running around 200,000 barrels a day Shell share at the moment, in Brazil, of which our own legacy is around about 30,000. The BG contribution around 175,000 barrels a day. It is ramping up all the time. We're seeing great well performance. We're talking 40,000 barrels a day on some of the wells, if we open up completely. That's one of the reasons that we're seeing lower costs than we'd originally envisaged. Two further FPSOs to come on stream this year, we should have nine up and running by the end of the year. We should just see a little bit more every quarter for quite some time to come. There are actually 16 FPSOs in progress. I think the last one comes on in 2019. So far so good.
The actual ongoing production, the decline rates in some of the wells, some of the reservoirs, very low. Still very early days to be talking about impact on resource and ultimate recovery. Many thanks. Next question.
Our next question comes from Jason Kenney from Santander. Please go ahead. Your line is open.
Well, hi Simon, thanks for your time with questions today. I just wanted to go back to cash flow as well. Here I'm looking at the medium-term sensitivity guidance, which I think in the past you have said would have been around $3 billion-$4 billion for every $10 per barrel shift over the next couple of years. Maybe moving towards $4 billion-$5 billion 2018 onwards. Now, I was looking at some of the consensus estimates when the Vara Research guys pulled together the annual numbers and comparing that to the oil price estimates that were used to drive that consensus. The average analyst there has got some sort of $7 billion shift for every $10 per barrel, in the next few years, which is potentially over-egging the cash flow. Is that a possibility or is it something I should be ignoring?
At $7 billion, I think you should ignore, Jason. The production that we see going forward needs some growth before we get to the $5 billion of earnings and cash flow for every $10 sensitivity this year. It's probably closer to four than five as we ramp up. As I noted earlier, effectively, the new BG production is highly price sensitive. Most of it is directly price sensitive. In Brazil, Australia, Kazakhstan, U.K., Trinidad, those are the primary countries that we're adding. Of course, our own new production is in the Gulf, in Australia, also in Kazakhstan. Basically, every barrel brings some kind of price exposure with it. We are becoming certainly more price sensitive as we go forward, but it'll be really 2017, 2018 before we hit the full $5 billion sensitivity.
We don't have any scenarios that I've seen where it goes above five. Okay. I believe no more questions or that's the end of the call. We're at the end of the time. What I'd like to do is say many thanks for your questions and for joining the call today to everybody. Reiterate again, the Capital Markets Day, London, Tuesday, seventh of June. Everybody on the call hopefully will be able to join us. I will be joined by Ben and by most of the executive team. Great chance for you to hear a bit more about strategy intent, some of the opportunities, some of the challenges that we face. Very much look forward to talking with you all then.
Between now and then, please feel free to connect with the IR team, and help with your own modeling, because I think it's in everybody's interest that we all understand this better, quickly, so that as we go into Q2 and Q3, we're all sort of working to the same expectations. Thank you very much. Have a great day.