Well, welcome to today's presentation. We've announced our third quarter results this morning. Hopefully, you've had a chance to review, and I'll begin with a summary, and of course, there will be plenty of time for questions. I am also joined, I should note now, by Maarten Wetselaar, Director of Integrated Gas and New Energies. Maarten will join for the Q&A session. We have a prompter slide for you, prompt you with a few questions. We thought it'd be useful if business directors join me on these calls from time to time. Before we start, just let me highlight the disclaimer statement. Shell delivered better results this quarter, reflecting strong underlying operational and cost performance. Lower oil prices continue to be a significant challenge across the business, and the outlook does remain uncertain.
We've delivered some $3 billion of underlying CCS, current cost supply earnings in the quarter, $7 billion over the last 12 months. The integration of Shell and BG is now essentially done. It's been completed well ahead of plan. It's worth a reminder, it's essentially 19 months since we announced this deal. We spent 10 months completing it, 40 major regulatory approvals, no value given away, 9 months on integration, all the value now embedded in plans. The integration is proving a very important catalyst now, though, as we make significant and lasting changes to the combined company's working practices, to our cost structures, and of course, overall to the portfolio. Our underlying operational costs in 2016 are already at an annualized run rate of $40 billion. That's a quarter ahead of when we suggested we would achieve this, which is by the end of the year.
That's $9 billion lower than Shell and BG costs were together in 2014, $9 billion. They should reduce even further on a like-for-like basis as the deal synergies and the ongoing other performance improvements continue to be delivered. We're delivering on lower and more predictable investment plans. That'd be around $29 billion this year, of which some $3 billion is non-cash. Next year, capital investment 2017 is expected to be around $25 billion, which is at the low end of the $25 billion-$30 billion range we've previously communicated. We are currently actively working 16 material asset sales, material meaning above half a billion dollars or more. That's as part of the $30 billion overall divestment program 2016 through 2018. Simultaneously delivering profitable new projects. This is the biggest driver of the long-term performance.
The startups this year, 2016 alone, are expected to add more than 250,000 barrels oil equivalent per day when we're fully ramped up. Turning now to the financial results. Excluding the identified items, Shell's CCS earnings were $2.8 billion. That's an increase both year-on-year and quarter-on-quarter. On a Q3 to Q3 basis, we saw higher earnings in upstream and in integrated gas and lower earnings in downstream. The return on the average capital employed was 2.8%, cash flow in the quarter $8.5 billion. That's cash generated before investment. Dividends distributed in the third quarter were $3.8 billion, $0.47 per share, of which $1.1 billion was settled under the scrip program, so $2.7 billion in cash. Brent oil prices, $46 were some 10% lower than a year ago, 2015. They're almost exactly the same as Q2 2016.
Realized gas prices, some 30% lower than we were in Q3 2015. Those lower oil and gas prices reduced the results year-over-year by around $1 billion, and the refining and trading results were also significantly lower than the same quarter last year, reflecting relatively weaker global refining conditions. Offsetting this, of course, the uplift from the BG volumes, the lower costs despite the increase related to the consolidation of BG, and lower well write-offs, they've all combined to deliver a profitable quarter despite those lower oil prices. The usual waterfall charts by business are provided in the backup materials where you'll find details of the earnings for each business segment. As is normal for large transactions, and it's worth reminding, BG was a $64 billion transaction.
We have been reviewing the accounting treatment quarter by quarter, and we intended in Q3 to put as much of this on a same basis to go forward as possible. That has resulted in an increase in the goodwill of around $1.5 billion, total goodwill $10.5 billion, and some adjustments to the premium price allocation and the way that we then depreciate that. There was, in the third quarter, a help to earnings of some $250 million in the Q3 earnings. This was as a result of the revision of that PPA. You see full details of this in the results announcement. Moving on to production. The headline oil and gas production for the third quarter was 3.6 million barrels oil equivalent per day. That's 25% or a quarter higher than Q3 last year. Of course, the uplift from the BG acquisition accounts for most of this increase.
I think it's important to point out, at the same time, that our overall upstream operating performance continues to improve. There's a focus on margins, on reliability and available uptime for the facilities that really is delivering to the bottom line. Doing all of that while we're seeing quite a substantive decline in the operating cost. The liquefied natural gas or LNG volume is also higher, obviously also impacted and helped by the BG acquisition. Turning now to the cash. Priorities for cash have not and I expect will not change. Debt reduction is top of the agenda, followed by support for the dividend, then we think about capital investment and share buybacks. Cash generated from operations 12-month rolling basis was some $17 billion or excluding working capital, $21 billion. That $21 billion at an average Brent price of around $42 a barrel.
The cash balances in the quarter on the balance sheet increased by $5 billion. We had $20 billion or so on the balance sheet. That was a result of the free cash flow performance and the increase in the gross debt. Depreciation for the third quarter was $6.2 billion. On an underlying basis, this is around $5.5 billion. We are expecting an annual DD&A or depreciation charge of around $22 billion on today's portfolio. Downstream is just over $3 billion of that, and that's been a relatively constant figure, the remainder being upstream. That is clearly $22 billion is a substantially increased number with the new portfolio. 2015, the number was around $17 billion. That uptick reflects new projects on stream as well as the addition of BG. Our gearing, net debt divided by total capital employed at the end of the quarter was 29%.
As we've said before, we managed the company through the down cycle, pulling on significant financial and operating levers. Let me update you on that, all four of them. Firstly, asset sales. We are using divestments as an important element of the strategy to reshape the company, not just the balance sheet, but to focus our activities. Up to 10% of Shell's oil and gas production is earmarked for sale, including several country positions or exits and a number of midstream assets to the Master Limited Partnership or MLP in the U.S., and also some downstream positions. As of today, we have 16 separate asset sales transactions above $500 million in progress. Only six of them are shown on this slide. This is the transactions that have been announced or completed and those that are known to be in progress.
This is consistent with all previous statements, increasing cash contribution towards the $30 billion divestment program and the $6 billion-$8 billion to be visible this year. It is a value-driven and not a time-driven divestment program, and clearly, it's an integral part of the portfolio improvement plan. It is about high-grading the portfolio and focusing not just the balance sheet. We're not planning for asset sales at giveaway prices, and there's no reason today to think that we can't achieve the $30 billion figure with that proviso in mind. Year to date, there are $5 billion of divestments visible to you on the slide, getting us closer to the $6 billion-$8 billion guidance we gave you for 2016. We'd expect to be in that range, and we have clearly further deals in the pipeline to deliver, and to progress at least a similar amount in 2017.
I'll move on now to overall spending. The second and third lever is capital investment and operating cost. We continue to reduce capital spending, and we continue to reduce costs across the board. Capital investment for 2016 is on track, $29 billion, of which $3 billion is non-cash. Capital investment for next year, new statement, is expected to be around $25 billion. The low end of the $25 billion-$30 billion range we previously advised. There'll also likely be a couple of billion dollars there that is non-cash. Our underlying operational costs in 2016 are already in Q3 at an annualized run rate of $40 billion. That's a quarter ahead of the plan and the intent that we previously highlighted. That $40 billion figure is $9 billion, almost 20% lower than the Shell plus BG cost in 2014, $9 billion. It should reduce further on a like-for-like basis.
We haven't yet finished with all the deal synergies and some of the performance improvement programs that have delivered the $9 billion still have some way to go. In short and very simple terms, we just did a $64 billion acquisition. We've absorbed BG's entire cost base and spend into Shell this year. No increase. We're running the combined company for the same cost and broadly speaking, the same investment level. No increase overall on a combined basis. The fourth lever, of course, is delivering profitable new projects that turn investment or negative cash flow into very positive free cash flow. This is the largest single lever over the medium and long term in terms of improving our financial framework. By 2018, the start-ups since 2014, so over a four-year period, in the two combined portfolios should be producing more than 1 million barrels oil equivalent a day.
Almost all of it high margin, equivalent to $10 billion of annual CFFO at average $60 oil prices. The cash operating costs on this set of projects are $15 per barrel, and the statutory tax rate around 35%. You can see high margin, both earnings and cash. In the third quarter just closed, we saw the start-up of Stones in the Gulf of Mexico. That's 50,000 barrels a day, 100% Shell. The first cargo from Gorgon in Australia, and the first export of crude oil was achieved at Kashagan in Kazakhstan. I'll just turn now to the LNG supply and demand, and the market dynamics that we're seeing this year to date, and maybe some questions arise from Marteen later. The LNG industry is clearly in the midst of a large series of supply capacity additions.
No surprise, as most of them take four or five years to deliver. Over 100 million tons per annum of LNG capacity is either under construction or has recently started operation. The majority of these capacity additions are in Australia and the United States of America. A result, in comparing the same period last year, so far, and this is the nine-month figures, so far during 2016, the market's grown by an additional 12 million tons of volume, and most of that has been supplied from Australia. Obviously that gas has to go somewhere. We're seeing a healthy growth on the demand side, and that's more than compensating for the declines in the traditional North Asian markets and the Latin American market, which in itself is more a reflection of rain in Brazil and extra hydropower.
This year's demand growth has been especially strong in the Middle East, particularly in Egypt, in Jordan and Pakistan. Middle East LNG demand overall has gone up by around eight million tons. The growing role of India and China in the total global mix has been mirrored in the year's LNG growth as well. Each has increased by approximately four million tons so far. In the case of China, the increase is mostly the result of a ramp-up of contractual volumes, including from ourselves, whereas in India, we're observing the effects of lower prices, changes in policies around power generation and fertilizer, and lower domestic production. A result, the global LNG market is relying less on Europe as the LNG balancing market, with the benefits of LNG finding its way to an increasingly larger and more diversified customer base.
Martin, I'm sure, can go into more details on this in the Q&A because clearly, as we go forward, a lot of value delivery from Shell and from the acquisition rests in how we are able to take advantage of that great LNG position on a global basis. To summarize, our investment plans and the portfolio actions that we're now taking, they're focused firmly on reshaping Shell into a world-class investment case. It will be thus at all points on the oil price cycle because we aim for stronger returns and improved free cash flow per share. We are making good progress. You can see it in the results today towards this aim, in spite of the current challenging market conditions. In parallel with the integration of BG, we have actually been managing the company from an overall sense through the down cycle.
We are reducing costs just about everywhere. We are reducing investment levels, and we're simultaneously executing the divestments. Most of all, we are now seeing the start-up and contribution from the profitable new projects. With that, I'd like to move on to the questions. As I noted, Maarten is here with me as well. Please could we try and restrict ourselves to one or two each so that everyone has the opportunity to ask a question? Come back again a second time if you want to follow up. Thank you for listening. Operator, please could you 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 1. If you wish to be removed from the queue, please press star 2. We will now take our first question from Oswald Clint from Bernstein. Please go ahead.
Thank you very much. Yes. Maybe one question each, please. Simon, just on the gearing number, the 29%, I think you've guided it pretty well the last 6 months or so, saying it should trend up in the short term, which it has. As you look at these numbers today and your CapEx guidance and your trajectory back towards the 20%, is that something you feel is certainly on the cards as we enter 2017? Is that a kind of gearing number we should think about as maybe by the end of 2017? Please, that'd be the first question. Since Maarten's there, I'd like to ask about the Singapore LNG contract that you've just announced. I'm curious, is this more of your short-term gas in your portfolio or your short-term gas you're allocating to Singapore?
Is that happening at certainly a better price, in terms of our modeling? Also, I noticed that there's been a new 5.5% sulfur cap on maritime fuels last week announced by 2020. Is that feeding into your aspirations for LNG into transportation? Is that something we should pay particular attention to, Maarten, please? Thank you.
Oswald, thanks. I'll leave the second question to Maarten. There's a great story there, particularly on your second point on sulfur and marine. 29% gearing indeed, we guided well. If I just step back a year, we were talking about gearing in the mid-20s post-BG. What's changed since then? A couple of things. One is that the oil price has stayed lower. That's probably cost us several percentage points, probably 3+. The divestments have been slightly slower. That's probably cost us another 1 percentage point. Importantly, you will have picked up, hopefully, that the finance leases that we have recognized will have added to the gearing. These were operating leases in the BG books, and we've actually added further finance leases both in Brazil and in the Gulf of Mexico since we completed the acquisition.
The total effect of the leases has added 2 percentage points to the gearing. On the flip side, our overall performance has been better and we've delivered much lower costs, that's helped the gearing. Overall, we're around 4 percentage points higher, but 2 of those don't really count on the grounds that it's just an accounting change. It's slightly better off in that sense than one would hope for. How do we feel for 2017? Well, certainly 2016, it could go slightly up or slightly down in Q4. It will depend a little bit on divestments and oil price. Perhaps just to wind back to the CFFO, the cash flow statement, and tell you how these numbers feel through to us. The third quarter was good cash generation, but it's never really insightful to look at a single quarter for cash generation.
If we look at the 12 months. Let's go back 12 months, 8 months of the BG included there, of course. We delivered $21 billion of cash flow excluding working cap. That was a $42 oil price. If we adjust that back to today's oil price, you can probably add $4 billion, maybe more. If you adjust for not only an extra 4 months of BG, but the clearly improved performance in terms of production and lower cost, there's another few billion dollars there. As we go forward into 2017, we will take more cost out and we will deliver more from the projects that are coming on stream now, because most of the large ones, Gorgon, Stones, Kashagan, haven't yet contributed to the bottom line. We've got 2 more FPSOs in Brazil to come in Q4. We have Plaquemine, Malikai. We are investing in the Permian.
There is quite significant cash flow growth to come. You can easily see a logical path to a low 30s cash generation, even at today's oil price. We are then looking at next year's capital investment, maybe $23 billion or so of cash and a $10 billion cash dividend. Absent divestments completely, it is not unreasonable to balance the books next year. Divestments could contribute directly to bringing the debt down. I would be a little disappointed if the oil price stayed where it is and the gearing was still 29% at the end of next year. If we deliver this plan, we should be in quite a bit better position than we expect to end 2016. Hopefully that helps cover a few of the issues around gearing because it's not as simple as just the outcome number.
Maarten, can you enlighten us on Singapore LNG and some of the opportunities in LNG into transport? Maarten, then.
Mr. Wetselaar, please ensure mute function is turned off. Thank you.
Let me cover that question then.
Can you hear me? I'm trying to speak into the phone, but I'm not sure. Is it working now?
Transport fuel. Please.
Simon?
Yes. Maarten, go ahead, please.
Yeah. Sorry, I appear to have lost the line for a moment. I'm dialing in from somewhere else. We are very pleased to get the Singapore license awarded. We inherited from BG, of course, a 3 million tons exclusive license that was almost full in the sense that they had contracted 2.7 million tons. This is a right to contract long-term volumes. We've now been able to add to that another 1 million tons long-term tranche into Singapore. In total, we'll be selling 4 million tons of LNG long-term into Singapore. This will come from our portfolio, but it will reduce our near-term and long-term length by another 1 million tons of premium market access. Indeed, very pleased with it, but it's not necessarily only focused at short-term volume. The volumes will be well into the 20s and early 30s.
Interesting, in this case, we are able to serve our own demand. We have 0.7 million tons of LNG demand with the Bukom Refinery and the Jurong Chemicals complex that we are now able, as of 2018, to serve through the Shell network and integrate the whole value chain. Indeed, we've been focused on LNG to transport as a very important new sector for LNG to serve going forward because the heavy transport can't electrify, so gas is quite likely the kind of destination energy source for heavy transport. If you convert the current shipping market to LNG in its totality, you would find about 250 million tons of extra LNG demand. On the onshore heavy trucking and long-distance market, it would be about 500 million tons. That would together be three times the current global LNG supply.
Very important and material sector for us to slowly unlock. These sectors have good affordability. They don't have coal as an alternative of other sources. The alternative is oil, and that's a price link that we like competing with in the gas side. The IMO decision to cap sulfur emissions down from 3.5% to 0.5% is a very big step change in the shipping business. What it will require ship owners to do is to either install scrubbers to try and bring their shipping emissions back to within this limit, or to shift to LNG. What we see now at quite a rapid rate is that new builds in shipping are shifting to adopting LNG, and that some of the older ships are actually being considered for putting gas turbines into the ships. A very positive development for the LNG business.
We are well-placed. We've been investing ahead of the curve in this business. We have supply points in Europe. We have won the supply point rights in Singapore, and we are setting up supply points in Gibraltar, in the Middle East, and in the Americas. Recently celebrated a somewhat iconic contract with Carnival Corporation, who ordered a total of potentially up to 13 big cruise ships to run on LNG. We got the exclusive rights to supply them as they come on stream. I think this is big news for the industry. It will still be a ramp-up of volume over time as shipping industry and trucking industry converts. It is a major new sector with good affordability and a sector that, given our downstream footprint, we are very well placed to serve.
Many thanks. It's a great story. Can we take the next question?
Our next question comes from Thomas Adolff from Credit Suisse. Please go ahead.
Afternoon, guys. Two questions from me as well, one for Simon and one for Maarten. Let me begin with Simon. Maybe if we talk about, if we look at your priorities for cash, you've mentioned that debt reduction is a top priority. Perhaps if I put it differently, is maintaining the A credit rating status more important than preserving the dividend? That's my question for Simon. For Maarten, I think you talked about where you've given some unrisked figures in terms of upside from LNG to transport, et cetera. If you had to give a risked figure for the IMO-related demand growth to, say, 2025, in addition to a risked figure for FSRU-related demand growth to 2025, what would that be for the LNG market? Thank you very much.
Thanks, Thomas. I'll obviously leave the LNG for Maarten. Priorities, number 1 is debt reduction. We need to bring the debt down. The question between credit rating and dividend is one I hope not to have to face in practice. At the moment, as I hopefully just indicated, it's tight and it's close, it does require the oil price to stay roughly around 50, we should be able to manage reasonably well through the next 12 months. It is clearly important. The debt reduction is a proxy for maintaining the credit rating. The credit rating is very important. I think we could effectively survive 1 notch further, we're double A with 1 rate agency and single A with the other, 3 notches different.
We could survive some level of down rate, as long as it was clear how we were going to get those ratings back. The best way of getting the ratings back is fundamentally to work on the numerator of all the ratios. Take cost out, keep it out. Deliver those new projects. Each quarter we see a little bit more there, clearly it's the divestments that reduce the denominator, the debt in the short term. I think we'll have to do both to ensure that we keep both the debt markets and the equity markets happy and comfortable. I believe quietly confident that the underlying performance of the portfolio is moving into a position where we can achieve that. Maarten.
Thanks, Simon. If I start with LNG to transport, that's the one with the biggest range of uncertainty, that range has probably crept up this week with the IMO announcement. The range I would use for the 2025 volumes, something in the range of 35-60 million tons of LNG to go into transport. That does include road which isn't affected by IMO. The IMO is only for ships, LNG for road transport is also ramping up over the period. It would then into the 2030s, could well potentially break 100 million tons before the end of the decade if growth indeed continues. This partly depends on the infrastructure being built, of course. If you look at the rest of the LNG market, we see it grow between 150-170 million tons between now and 2025.
Your question was about FSRUs, there's of course, also market growth into onshore terminals that are not floating regas units, but basically countries like China and India, but also Europe where not FSRU is used, but larger tanks in ports. It's probably about a third FSRUs, two thirds bigger onshore import facilities, if I got your question correct. The FSRUs are predominantly Africa, Latin America, Middle East and Southeast Asia. Land infrastructure, very much built into China, into Europe, and to some extent, India is a bit of a mix. That's what the import picture looks like. You'd be looking at a range of about 420 million tons and a high end of 440, 450, depending on exactly how fast the transport business indeed grows. All by 2025.
Thanks, Maarten. The next question, please.
Our next question comes from Tipan Dodlingham from Exane BNP Paribas. Please go ahead.
Afternoon, gents. Two questions, please. Firstly, Simon, could you just talk about the scenario then beyond paying down debt, how we should think about the group turning off the scrip? What type of debt metrics should the market look for? Or is there a signal on the oil price at a particular level where you think the scrip can be removed because it is arguably dilutive or increasing that dividend burden in the long term? Second question is, hopefully relatively vanilla. Just could you give us an update on Prelude and startup and what remains to be done in terms of commissioning? Thank you.
Many thanks, Tipan. It's quite handy having Martin available. I'll pass Prelude to you because it's your project, Martin, but not too many details, please. Scenario beyond debt reduction. A key trigger, you will feel, and we will feel comfortable that the financial framework is rebalancing in our favor will be to turn off the scrip dividend. Fully agree with you that the dilution and the additional dividend are not something we want to live with forever and would like to address as soon as possible. It's this combination of two factors likely, Tipan. First, we actually have to get the metrics moving in the right direction. The debt must be coming down, but it must be doing it in a sustainable way so that we don't take the scrip off and six months later find ourselves having to put it back on again.
Or feeling that was the prudent thing to do. I said before, we need to have line of sight to gearing of 20%. That, to be honest, is just a good proxy for the overall rating metrics. Indeed, where the oil price settles out will be important. Now for the next 12 months, we see the oil markets by and large in balance in terms of supply and demand. Thereafter, it's likely that demand, if it continues as it is, will outstrip supply. Where the oil price settles out in that period will be a factor, no question. Before then, I think we need not only to deliver, if you like, the organic cash balance that I talked about, getting the cash generation up into the low 30s, but we need to deliver some divestments. That will start to turn the metrics.
Really you need the net debt heading down more towards 50 than running in the 70s before we would look at the scrip. It's really about being confident in the sustainability and not just a one-off set of numbers. Martin, Prelude.
Thanks, Simon and Tipan, of course. I was recently on Prelude to review progress. We've been busy steam blowing in the third quarter. That's getting close to being finalized. We're really into a period now where the major construction work is over, and we're into starting commissioning, handing over to operations, and working things up. Prelude progress is solid. It is as per our plan, which means that the message about getting substantial cash flow from Prelude in 2018 is still very much on, and increasingly looking de-risked as we progress this project. Going well and looking forward to cash in 2018.
Great. Thanks, Maarten. Can I turn to the next question, please?
Our next question comes from Jon Rigby from UBS. Please go ahead.
Yeah, thank you. Two questions. First is, this quarter resembles much more like a quarter at the current macro that I expect Shell to deliver. 2Q didn't. I know at 2Q, it was a bit of backwards and forwards about why it was such an odd quarter. I just wondered whether with a bit of time after the second quarter and also reviewing the third quarter results, whether there's any more insight into that delta, 1Q to 2Q now to 3Q, that you can share with us, and maybe sort of confirm that the third quarter, as you would see it, is much more sort of resembling the financial and operating performance of the underlying business, if that were possible. The second question is just on the downstream. The marketing result looks a very strong result.
If I look back against history, when you have disclosed those numbers, it looks right at the top end. Yet, if I look at the macro, it's not obvious that it was a quarter where marketing should do fantastically well. We didn't see a huge drop in oil prices. It wasn't obvious that demand was going very strongly. I just wondered, are you able to sort of share something about why marketing was such a standout result in the quarter? Thanks.
Sure. Thanks, Jon. Important question in the first one. Certainly, it was not easy to explain Q2 because there were quite a lot of small factors that in and of themselves were a bit one-off, and some of them have reversed in this quarter as well. I'd say about $400 million has come back into the third quarter, most of which, in fact, all of which, shows in the upstream results, that Maarten's got $100 million negative upstream, probably got close to $500 positive. I talked about the adjustment to the PPA or the purchase price allocation, premium allocation from the BG acquisition. Actually, in practice, a reduction of that step-up on the PPA, where we previously talked about $300 million a quarter.
I think going forward, that step-up will be more like $200 million a quarter, although it will grow over time as the production continues to increase. There's a couple of tax items which also either reversed or are one-off in the third quarter. Q2 underlying understated to an extent, Q3 slightly overstated. Q3 is more representative, although I would note the refining margins in downstream were particularly weak and that chemicals still have more earnings and cash generation power when all the crackers are running. There is clearly in the fourth quarter, what we will be watching is, one, the oil price, two, that the costs come out and stay out sustainably, and three, that the new projects, because all the ones I sort of talked about, Gorgon, Stones, Kashagan, two FPSOs in Brazil. They didn't actually contribute a lot to the third quarter financials.
They should all contribute more to the fourth quarter financials. An uptick of revenue generation, continuing lower cost, and the oil price being at $50 for at least a month should help the fourth quarter, and both should be more representative than the second quarter was. I did also say that we expect that 2016 is a transition year. We just banged together two enormous companies. There will be a little bit of noise in the results. We tried to take as much out as possible in Q3 so that we are cleaner going forward into the new year, and that 2017 would be an easier year, not just for you, but for us. Downstream marketing, indeed, it's strong, but fundamentally, we are seeing premium marketing. It's working for us. In retail, we're getting a stronger unit margin from penetration of V-Power, and management of the price demand elasticity.
Lubricants, we are very well-placed in some very important markets, particularly in China. It continues to grow successfully. Again, premium product penetration, stronger unit margins, is making a difference. We're about 30% up year-on-year in terms of contribution from marketing, and that's good. It is sustainable. It is a result of a significant number of genuine marketing problems. We're not just wholesaling and moving the molecules. We are marketing. Finally, we did actually, although we'd sold Butagaz, the LPG, we've seen aviation pick up on the fuels business. Our actual aviation margins were better as well. Strong performance across the board, but sustainable. It's not just a one-off.
Thanks, Jon. Take the next question, please.
Next question is from Rob West, Redburn. Please go ahead.
Hi, thank you very much. I'd like to ask my first one on the GOM. I think there's a couple of wells in the southwest part of your Norphlet acreage, Leesburg, Castle Valley. There's one other, I think, called Dover. Is there any update on that this quarter? And just looking back at the well you announced last quarter, is that something that could become a hub around the southwest of that position? Or is this stuff all just tiebacks to Appomattox? That's the first question. The second one is just maybe for Maarten, maybe for whoever you who prefers it. I'm just a bit interested if you can say anything about the onerous contract provisions you took in LNG and just a bit of what's behind that. Thank you.
Many thanks, Rob. I'll handle the GOM. I think the onerous contract really is gas tolling into Spain. Maarten, can you cover that?
Yep.
On the GOM, you're right. The Norphlet play is in the eastern Gulf of Mexico, and we were the first in there, and we're effectively partnered with Nexen, but there aren't many other people in the region. The APO discovery keeps growing, both from nearby discoveries and in itself. We took the FID on Appomattox last year. We've seen the original break-even price around $55. We've continued to take costs out, so that break-even price now starts with a four, and we're continuing to look for further opportunity. One of the things that's helping is greater volumes. You're right that Rydberg last quarter was a success, that we are now drilling in Castle Valley, and I'm not sure about Leesburg at the moment, but we are effectively not announcing anything there at the moment.
We have used the early mover advantage to take further acreage in the region. Is it a hub region? Well, absolutely. Once APO is up and running, we're talking of 220,000-230,000 barrels a day, but we are already looking at whether and how we could debottleneck, because it is quite clear that the discoveries we already have will keep that full for quite a lot of years, and there is still further potential. It will be at least one hub, one pipeline back into the Gulf Coast. It's looking like a great opportunity. On average, we're something close to 80% of the holding in the acreage, with most of the rest being, in fact, nearly all the rest being held by Nexen. It's a good partnership, great prospects.
The hub development already in play, 2 to 3 years before it produces, but it will be one of the major cash generators for Shell into the 2020s. Maarten, onerous contract?
Yeah, I think that's a contract that was from the middle of the last decade, for 2005, a tolling deal in Spain, the type which we haven't really done since then. We had a few tolling deals in the U.S. as well in that period. None of them worked out very well. This deal particularly has been underwater for most of its duration. We only have now had 4 years to go, there were no plausible price scenarios anymore where this contract would ever get back into the money, therefore, we wrote it off, the last 4 years of it, off as an onerous contract. You can't do that too early in the life of a contract, although even 4 years ago, we didn't have much hope. There are rules around how far in advance you can recognize this, given that markets are volatile.
this one was now so far out of the money that we were able to take it out of the books and forget about it.
Thank you, Maarten. Move to the next question, please.
Our next question is from Irene Himona from Societe Generale. Please go ahead.
Thank you. Good afternoon, Simon. Two questions. First, on the cash flow. Capital expenditure in the nine months is shown at around $16.4 billion. You're guiding today to effectively $26 cash CapEx for 2016. Are we looking at $9 billion-$10 billion for the fourth quarter CapEx? Related to that, your DD&A guidance for this year, $22 billion. Could you kindly give us some guidance, some sense of what happens to DD&A next year, please? My second question, just on Brazil, where obviously they've changed the legislation recently to relax the requirement for Petrobras to operate everything in the pre-salt. How is Shell strategically thinking about this opportunity, please? Thank you.
Irene, thank you. On the capital investment, I have to say, we focus more on 2017, 2018, 2019 than we have been doing on the next 3 months, because that tends to be locked in. Maybe at 29, it's a little bit rich, but that's not going to drive the metrics too much one way or the other. We do have a couple of one-off items in the fourth quarter, including the payment to enter the chemicals development in Guangdong province to CNOOC in China. We have additional FPSO coming on in Brazil. Let's see how it turns out. I would regard 29 as a maximum. DD&A is 22 for this year. That will be how it starts next year. I think over the year, as we see the following come on stream and ramp up, it will increase.
We will see Kashagan kick in for a full year. We will see Gorgon, Trains 2, 3, hopefully come on stream. We will see Sakhalin, we will likely see some of the tiebacks in the Gulf and a ramp-up in activity in the Permian. I'd expect all of those to drive depreciation up, but it will then be driven down by proved reserves bookings at the end of 2016. I don't yet have a fix on that, simply because we don't do the work in detail until basically November, December. Over the next quarter, we will get a fix on the DD&A. The figures I gave earlier on the cash flow are not impacted by DD&A, but obviously the earnings that go with them would be. Hopefully, that helps. In Brazil, it's early days, really.
Indeed, there have been statements about changes in requirements on operatorship, level of ownership, how local content plays in. In principle, we're interested. Brazil is going to be one of the top 4 countries in Shell, along with Qatar, Australia, and the U.S. In fact, probably already is in terms of current value generation today. We're investing up to $3 billion a year there for the foreseeable future as we continue to build out the FPSOs. Clearly we're interested in consolidating on the good assets in the country and looking at further opportunities to create value from the assets we're already involved in. It's still a little early. I think Petrobras is an excellent operator, while we work together with them in the pre-salt. BG had good relationships. Shell had the relationship in Libra.
On the back of what both BG and Shell have been able to bring, I would like to think that we would have further opportunity in the future, either on assets or in the way that we govern and operate. That's for the future. Right now, we're focused very much on, it's 2 FPSOs this year, another 2 next year. That will take us to 11. There are another 4 on order, under construction. 15 FPSOs on BM-S-9 and 11, and get those up and running while we also start the first 1 or 2 on Libra. That's quite a challenge and a fantastic business. Okay. Hopefully, that was of interest to everybody, important areas of performance. Can I take the next question, please?
Our next question comes from Guy Barber from Simmons. Please go ahead.
Thanks very much. You're giving clarity on 2017 CapEx a little bit earlier than normal, which we very much appreciate. Relative to that prior range of 25-30, can you just discuss the rationale behind the decision to guide to $25 billion at this point? Is it reflective of efficiency capture? Meaning the low end accomplishes pretty much everything that you wanted to accomplish before. I'm just curious how fluid that guidance is at this point in time to better understand the commodity price assumptions, and under what pricing scenarios you might flex that higher or lower. I had a follow-up.
Thanks, Guy. Good spot. This is at least three months earlier than we would normally communicate next year's capital investment. To an extent, it's slightly easier than it normally is because the reason it's going down from this year is we actually finished projects. I won't repeat the list of projects that I've just stated, we stopped spending on those projects. We're not taking significant new investment decisions. I mentioned Appomattox earlier. We're investing in chemicals, both in Pennsylvania and China. We continue to finish off, obviously, Prelude, we're investing in subsea activities, whether it's Nigeria, Gulf of Mexico, or the North Sea. There's still quite a lot going on. We gave a range of 25-30 as being bookends that were not necessarily associated with the top and bottom of the price cycle. In terms of affordability, obviously they are.
25 was seen to be a soft floor. If we have to, we can drop below, and 30 is a hard ceiling. We will not go above $30 billion, even if we have the cash, until we have embarked on the buyback program, which is post-script, and certainly when we're in a better financial framework overall. We're several years away from that. That's why what we stated on the range. Why 25 now? Well, we are coming off very significant investment. Our priorities are reduce the debt, and therefore it's appropriate when we don't have to jump into new investments, that we focus on maximizing the value from the investment we've just been making. Can we go lower? Is it flexible? To an extent, yes. Lower oil prices would drive that.
It will be driven by affordability in the short term, not necessarily the medium term, but very much so in the short term. What else has driven it down? Well, supply chain costs have helped. To be honest, it's a lot more than that. The whole industry, but particularly Shell, we've taken a pretty close look at why did costs go up so much in the first place? Some of it was just the ways of working, the methodology. Whether it's simple things like how you manage the logistics, the boats out to offshore platforms, or design standard valves, et cetera. There's been a huge momentum working in many cases positively with the supply chain just to take cost out. We're not doing a lot less. We're doing a bit less for a lot less cash.
A bit less activity for a lot less cash. That will continue and gives us some hope we can keep at $25 billion if we need to, or go lower without compromising medium and longer term growth prospects. The $25 billion was actually stated as being a level we believe gave us some moderate growth, not significant growth on the portfolio. Remembering the balance sheet is, well currently, take the cash out, it's $245 billion of assets employed in the business. $25 billion is only 10% and is only slightly higher than the ongoing depreciation. To go much further down is possible. I wouldn't say it was likely in 2017, simply because of commitments already in place. If, as we go forward, the price is further pressured downwards, we will continue to take cost out or activities out. You said you had a second question, Guy?
It dropped off.
We will take the next question from Lydia Rainforth from Barclays. Please go ahead.
Thanks. I just had one question, actually, please. Coming back to the OpEx numbers and the underlying costs already being at the $40 billion run rate that you talked about back in June, what has actually driven that? Can you give us some examples of where the costs have come down and just any indication in terms of how much further they could go, or when we might see that coming through? Thanks, Simon.
Yeah, will do. Thanks, Lydia. Interesting tables at the back end of our results announcement now on pages 21, 22, and 23 give a bit more detail around things like returns, divestments, CapEx, gearing, and operating expenses. What we've done is actually split out off the face of the P&L statement, the total operating expense, which this quarter was almost $10 billion exactly, and therefore $40 billion run rate. Also adjusted for the one-off items that we effectively include in identified items in the earnings statement, so that you can actually see underlying operating expense, $9.2 billion in Q3. Is $28.5 billion for the year to date. That includes eight months of BG. That compares with nine months last year at $29 billion, not including BG, hence the comments I made earlier. Where has it come from? Well, pretty much everywhere, I have to say.
If we look at our costs above the asset, so think finance, IT, HR, legal, we've taken out, if we look 2015 through to 2017, something like 25%. That's been done partly by delivering the synergies from the deal. We don't need to do certain things twice. It's been done through doing things differently, fundamentally, simplification, offshoring of work to centers in Chennai, Bangalore, Manila, Krakow, and simply by doing things simply. On the assets, we have had quite significant programs in the upstream around operational excellence that have focused on better availability, effectively managing the wells, the facilities and the reservoir in a more farsighted manner, and one that builds in the cost over a period of time, and is actually driving unit cost down in particular.
I think it's a bit of an intangible, but bringing the BG guys into Shell is almost a bit of internal competition as to how far can we go. Good ideas. Almost everywhere we look, the cost is improving. The total figures have benefited from foreign exchange movements to an extent. So some of that reduction, it depends how you measure it, maybe up to a third, is FX-driven. Again, while the dollar remains strong, that remains the situation. If the dollar gets weaker, typically the oil price goes up. There's a bit of a hedge in there as well. What we are still seeing is we've got quite a long way to go on those performance improvement programs that I referred to in the functional cost area. For example, I just gave you the 2017 target, which is quite intent versus 2015.
It's quite a lot better than 2016 in and of itself. Don't know how far it will go. Reluctant to give a headline target, because in the downstream, for example, we are allowing them to spend more in certain areas, such as trading and supply, where they're taking margins from new short positions. In the marketing, back to the earlier question, which I think was from Jon, you can't get premium marketing margins without spending a bit of marketing money. If you get $2 back for every dollar you spend, it's the right thing to do. Therefore, we don't set headline OpEx targets, but we do look very carefully through what are now quite well-defined cost management frameworks. At each dollar, where it's being spent, is it benchmarked? Is it competitive? Can we afford the ultimate impact on the performance unit that's actually delivering?
There's quite a well-established rhythm now of performance appraisal on that basis. It is just working. I probably shouldn't say it, but it's actually positively surprised us internally as to how quickly the momentum has been achieved. Many thanks, Lydia. Go to the next question, please.
Our next question is from Lucas Herrmann from Deutsche Bank. Please go ahead.
Simon, hi. Maarten, afternoon. Couple, if I might. Simon, you've mentioned the Permian two or three times on this call. I think Ben described them as sleeping beauties, but it sounds as though they're starting to wake up. Can you talk a little bit more around the way you may be thinking about that acreage plans, rigs activity, et cetera, at this moment in time? Secondly, I wondered if you could give us a little more flavor on the $16,500 million-plus divestments that are ongoing. Just flavor in terms of to what extent or how near or far some of those may or may not be to actually hitting the headlines, for want of a better phrase. Finally, I've got to ask this. South America, Brazil, if I look at the regional profit performance, we've seen a $700 million net income turnaround in that business.
I wonder if you could provide some explanation. I know barrels are up, the profit improvement is dramatic.
Sure. The simplest answer on the last question, I think, Lucas, is some of those one-off reversals that I mentioned earlier relate to depreciation in Brazil. It's something around $200 million-$250 million positive in Q3 that was negative in Q1, Q2. There's a bit of tax assistance as well, plus more barrels, lower cost.
Okay.
That probably is the big driver. At Permian, what will we do? We have 300,000 odd acres. We bought most from Chesapeake some time ago. It's great acreage. We're in some of the sweet spots. To date, we've been investing somewhere between $500 million and $1 billion a year, it's been on appraising rather than producing. I think it's fair to say. A lot of that acreage is in joint venture with Anadarko. We are operating four rigs at the moment, likely to go up to five. Anadarko is operating similar, that we are certainly from a Shell perspective in our operating acreage, we're now looking at moving to what we call the harvest phase. We know what we have. Now we start to harvest some value. About, well, just over half of our Permian acreage, we believe, is break-even price below $40.
We have 2,500 locations that we've already identified that should work at below $50. There are three particular, what we call common value areas, that we're now looking to develop. We will start developing those. This is real genuine pad drilling, moving to the manufacturing approach, as opposed to drilling one or two wells in a section and moving on once you know what you have. You move on to 10, 15, maybe more wells per pad, multiple horizons, et cetera. It's actually quite exciting as we look forward. It's good acreage, and we want to be part of developing that. We've also recently recontracted some of our evacuation infrastructure and halved the pipeline cost going out for us, which is one of the reasons we've not developed previously as well. We're in a pretty good place in the Permian.
Sometimes you'd like a bit more, sometimes you might want to sell at the margin. The core of the activity is a great core to our overall Shell's business. 16 divestments. There are 6 on the slide, 2 of which we just announced in Canada Shales and in the Gulf of Mexico, Brutus. The other 4 of the 6 were at the bottom of the slide that I showed. Thailand, New Zealand, U.K., and I think Gabon. There are a series of transactions currently close to a milestone. When I say a milestone, it's either we agree or we don't. A price and a deal. When we have $5 billion announced. They were on the slide. We talked about 6 to 8 clearly in progress during 2016.
I would expect a small number, but certainly not a zero number of announcements between now and the year end that will take us into the 6 to 8 range, hopefully closer to 8 than 6. Behind that, there are other transactions, and of the total, a further 5 are downstream, 11 are upstream. Basically, it's a third, two thirds. They're not the only things we're working on, either. There are more that are either smaller or are slightly further down the queue, but the 16 are the ones that I see on virtually a weekly basis at the moment. The progress that we are moving through on that will deliver the next $6 billion-$8 billion next year.
We fully understand and appreciate the importance to get some momentum in this program, to see some significant runs on the board and cash in the bank in the first half of next year, while the uncertainty around the oil price is greatest. Let's see where the oil price goes beyond that. That's not to say we stop the divestment program, but there's a question of balance in terms of the priorities. Hopefully that gives some flavor. I don't want to go into naming names of the ones that are not on the list already, but none of them is $5 billion or above. They're all above half a billion. That's all I can say, really. We're not going to do 3 $10 billion deals.
We may end up doing 15 to 20 solid, significant deals, and we do have the resource and the asset base on which to do that. Okay. Thank you. Next question, please.
Our next question is from Iain Reid from Macquarie. Please go ahead.
Yeah. Hi, Simon, Maarten. First question for you, Simon. You probably saw what Exxon said on Friday about looking at their reserves. They did a pre-release of this. I know you said you're going to be doing it at the end of the year, appreciate a comment if you could. They basically said they were going to de-book oil sands due to the current environment, you've got a pretty similar asset there. I'd be interested to get your view on that. Question on Maarten, U.S. LNG. You seem to be saying that it's not going to Europe at the moment because you've got other areas where it's more profitable to take it. I presume when we get the big volumes coming, it's going to have to go to Europe.
I'm just wondering what your outlook is for European gas prices when that starts to happen.
Iain, thanks. Obviously, I'll leave the second question to Maarten. On reserves, indeed, we look at these in November, December. I won't comment on competitors directly, Oil Sands Mining, we have obviously the Athabasca Oil Sands project. There's two mines. There's 1.94 billion barrels of oil in proved reserves today, and $100 million or so of positive earnings, and roughly that amount, slightly less in positive free cash flow in the third quarter earnings. At $46, Oil Sands is both earnings positive and importantly, free cash flow positive. I say importantly, because the challenge with reserves in a low price environment is the need to pass the economic limit test. You need enough reserves to be able to show a positive forward cash flow.
That's probably all I can say is if we're positive at 46, we should just about be okay, I would have thought, at whatever the average price for the year turns out to be. Elsewhere in the portfolio, low prices, it could possibly have an impact. Of course, it would not necessarily make much difference to the operation or the value embedded because it merely is a mechanical spreadsheet extrapolation of a price, a historic price, based on approved volume number only, which may not be anything like the total resource associated with an asset and the current balance sheet. It's basically into a sausage machine. I can't comment either way until we've done the work. Oil Sands, interestingly, looks reasonably positive. Maarten, on U.S. LNG.
Yeah, thanks, Simon, and thanks, Iain, for that question. Indeed, in the early days of U.S. LNG, the best way to deal with those cargos has been to keep them in the Americas and send them to Chile or Brazil, and that's where they've sort of the hour allotments have been ending up. You're right to say, as that production volume ramps up, there won't be enough demand in Latin America necessarily to absorb it all, and it's going to have to go somewhere. Just a long-term comment in that and then a short-term comment. The long-term, the way I see prices move in the medium term is that a recovery in oil price is going to drive initially mostly Asian prices up, simply because a lot of the Asian business is oil-linked, and that will drag prices in the Asia- Pacific Basin up.
Also, that's where most demand growth will sit. Europe will sit in between, depending a little bit on the balance in the market on that moment in time, whether it will more follow Asia or whether it will sit at a U.S. plus freight differential. In the near term, what we've been seeing is two things. It's actually price spreads widening. At the moment, we see Henry Hub sales of three. European gas price is back to about six, and we're selling energy spot in the Asia Pacific at seven again. These are our prices, where certainly the way our Sabine Pass contract is established, we would be able to send the volumes either into Asia and or into Europe and make a margin. The demand trends that Simon highlighted on the slide he showed on the energy market are quite profound.
You saw the Middle East grow by 8 million tons. That is from a total of 8 million tons last year in the first 9 of the months. That's a doubling of the market. We've just had Egypt announce a tender for 96 cargos for 2017-'18. 96 cargos, that's about 6 million tons of energy. We see similar numbers or similarly large tenders coming out of India and other places by new customers. I think in the near term, there is more opportunistic demand, partly driven by lower prices, that I think will attract that LNG from the U.S. Clearly the lower price contracts, and we have the best one in the business through Sabine Pass, ex-BG, will be the ones to benefit first.
In a very negative outcome, you could see the higher price contracts running into a place where they don't actually operate at all. As I say, I rate it as a lower probability, and certainly we are not in those contracts.
Thank you, Maarten. Could I take the next question, please?
Our next question comes from Christopher Kuplent from Bank of America. Please go ahead.
Hello, thanks. I'm going to keep it very short. Simon, I know this sounds like Groundhog Day, me asking the same question on every call. Given that we've seen Total again in the market issuing hybrid bonds with coupons near 3%, wanted to test yet again your appetite for doing the same. We've talked about protecting your single A credit rating, et cetera. How attractive do you think is that route relative to asset disposals or indeed accepting another notch downgrade to A-minus? Thank you.
Thanks, Chris. My memory isn't good enough to remember it's always you, so you're off the hook. Hybrid bonds. We go to market and we get very tight pricing, even with the lower credit ratings that we've been achieving with S&P. Hybrid bonds are not cheap financing. They might contribute to the rating, but they are expensive. The carrying cost, it is expensive, as is discounting your dividend. We do not need to do that. If I needed to do that, then maybe we'd think about it, but we don't need to do that. I will continue to stay plain vanilla in the debt capital market for as long as that is by far the cheapest and easiest available source of debt to me. It's really probably the same answer I gave last time, Chris. It's relatively low quality source of finance and not cheap.
Just for avoidance of doubt with everybody, I do understand that [Nora's] equity issued through scrip, hence the earlier comment about high priority, reduce the debt so that we can take the scrip off. Thanks, Chris.
Our next question is from Jason Gammel from Jefferies. Please go ahead.
Thanks very much. I had two questions, please. First, Simon, I wanted to come back to some of the comments you made around both the divestiture process and the Permian. The Permian does seem to be one of the few places globally where upstream assets are attracting some pretty solid valuations. You referenced, obviously, being in a very good neighborhood there. What do you think about the idea of monetizing some of the acreage position while maintaining your core and putting a pretty solid set of runs on the board from a transaction there? Second question is on the LNG business. The sales volumes are now up about 50% from prior to the BG merger. I was just wondering, Martin, if you could talk about how the scale and flexibility have changed and how that affects how you run that business.
I'm thinking in particular in terms of accessing new customers and of even potentially terming out some of your hub links and spot contracts into longer term.
Jason, thanks. I'll leave the second one for Maarten. You're absolutely right, Jason. The hottest properties on Earth at the moment seem to be in the Permian, where $50,000 an acre appears to be the going rate. We actually have two smaller packages on the market at the moment that are very good acreage. They're not that contiguous or close to our likely development activity. Let's see how that process unfolds. More generally, in terms of the shale business, it's worth thinking, why do we want one as Shell? Partly because we can. We have great acreage, 12 billion barrels of total resource we've talked about previously. Five basins, Argentina, two in Canada, and two in the U.S.
As a strategic element of the portfolio, it offers an optionality and a flexibility that we don't get in the rest of the portfolio, i.e., we can ramp investment and development up and down according to price and opportunity. If we don't have that in the portfolio, then we don't have that optionality, and we have less resource to work with as well. That's the reason we want a Shell business. The Permian is, to an extent currently, and possibly for quite some time, it is the crown jewel. Not just in terms of the value and quality of the asset, but also the capability that is being developed there. We, and the industry, learn more when there is more activity ongoing about how to maximize the value.
It is important for us to be in the Permian, but that doesn't mean we need every acre that we currently hold, nor that we're not interested in adding acreage. The patchwork nature or the patchwork quilt nature of the acreage across the basins in which we're interested may offer opportunities over time there as well. The aim is focus so that we end up with a more efficient development program, and that areas or acreage that we're not likely to invest in in the near term, that we sell them rather than leave them sleeping. That is the aim. We're actually at the moment following your advice. There were Small enough packages not to be on the list of 16 because there was a materiality criteria.
It'll be interesting to see if by the time they get priced, they creep onto the list of 16. Maarten, sales volumes and LNG in general, what the thinking is.
Yeah, thanks for the question. We could spend a bit of time on this if we wanted to. I'll try to keep it short. Indeed, our LNG volumes, our sales are now about 15 million tons a quarter, that brings us up to well over 50 and actually close to 60 million tons a year, which is almost 25% of the current LNG market. That clearly gives us enormous footprint in terms of supply options. It does a few things for us. One is that in the LNG market, the business model of finding a big Asian utility to take 4 million tons at a high oil-linked price off your hands at high seas is still going to be relevant going forward, it's not where the growth is.
The growth is in smaller customers that look for smaller volumes, often have worse credit, also often only have one or two contracts in their portfolio, they need security of supply. They need certainty of delivery. In many cases, what we're actually finding is that it's easier for us to win the business with those customers because we have so many supply options to give them security. Also because we are one of the very few suppliers, and the state of Qatar would probably be the other one, that doesn't need a condition precedent on a future FID when we make a supply promise. We have enough size and flexibility in the portfolio to promise someone 1 or 2 million tons without having to take an FID to back that up.
That isn't only the case with customers, that is also very much the case with countries who are starting to import LNG for the first time. Jordan is a case in point. We didn't get the business in Pakistan, it doesn't always work. That went to Qatar. In many cases, these countries are looking for certainty of supply because they're betting a part of their energy system on gas, they don't want to be beholden to an uncertain FID. There are also other ways in which this footprint helps us, it's not only about size, but it's also about the ability to absorb and manage risks into our portfolio, risks that customers can't take by themselves.
We find people that in the rush to commit to U.S.-based energy supply, signed up for supply from the U.S. to Asia and now regret having the contract in their portfolio and really can't manage it. We have a number of instances where we actually take over those regret contracts. We absorb them, and we do much more plain vanilla, often longer-term, higher volume deals with them in return. We can absorb the risks that they don't want anymore, much easier than them. It's risk management, it's volume, and it's basically the ability to make offers that have no CPs to them, that I think differentiate us in the market. That makes sure that we are aware of every piece of demand and every piece of open supply in the market.
Quite often, we're able to connect the two much easier than individual parties who just basically are not in all these conversations at the same time. The network of people and contacts we've built up is unique and gives us trading opportunities every day.
Thanks, Maarten. Next question?
Our next question comes from Biraj Borkhataria from Royal Bank of Canada. Please go ahead.
Hi, thanks for taking my question. I had one for Simon, one for Maarten. For Simon, just following up on your comments on gearing. You're currently at 29%. You did say that 2% of that doesn't really count. I was wondering, should I think of your gearing ceiling as 32% rather than the 30% you previously talked about? I know that's a fairly small margin, but given you're quite close to that, I thought it was worth asking. For Maarten, just an easy question. Could you provide any kind of update on Lake Charles and how that's progressing? Thanks.
Thanks, Biraj. You're absolutely right that like for like, when we started talking about 30%, that the 2% is different because it's on-balance sheet finance leases. The rating agencies look through that anyway. Their debt figure is considerably higher than the $77 that you see on the balance sheet today. 30% is just a proxy for their overall metrics. It's not an immediate trigger either to them or else if we go through 30%. It's just a signal that we need to be giving extreme priority to bringing it down again. If we stay above 30%, whether it's 30% or 32%, that becomes a less sustainable financial framework over time. Stick with 30% as the proxy. That's what we like to manage to. It's easy to remember. Like for like, indeed, really, it's 2% higher in terms of the economic substance. Maarten, Lake Charles.
Thanks, Simon and Biraj. Lake Charles is, I think Lucas earlier on the call mentioned the Permian as one of the sleeping beauties in the Shell portfolio. I think Lake Charles probably is in its own way a sleeping beauty from the ex-BG portfolio that I am very pleased to have in the portfolio. It is an extremely competitive U.S. LNG project. Obviously brownfield, the way BG has built this up, has designed it, and has pulled it together is first class. It's a very good opportunity to build LNG supply right at the left-hand side of the low-end side of the cost curve, that we will benefit from. The trick here really is to try and judge when is the LNG market going to need this volume again.
As you would've seen, if you tracked this market, in the last 18 months, we've really only had one FID. That was the new train on Tangguh by BP. Most of that LNG is actually going to stay in Indonesia. Apart from that, it's been dry in the industry, and it could remain dry for a bit. That's not a bad thing because there's a lot of energy coming into the market, as has been noted before on the call. Somewhere in the course of the early 2020s, whether that's 2022 or 2023, it's going to depend more on demand than on supply. There are some good signs on demand. This market is going to rebalance and inevitably then go short, because the supply reaction is always delayed, of course.
The trick is really when do you take your best supply projects into an FID to be there when the market needs the volume and is willing to pay good prices for the volume? That is not today, is my feeling and has been our decision. We don't really think this is the right time to take an FID at the moment. We look, of course, at the affordability in the company, and we say that's actually quite convenient that we are able to postpone this piece of capital. It is certainly a project that I'm very pleased to have in the portfolio, an option that is a good one for us to have. Hopefully find the right time to exercise it and bring it into the onstream portfolio. We review that periodically.
Thanks, Maarten. Let's go to the next question.
Our next question comes from Alastair Syme from Citi. Please go ahead.
Thanks very much. Hi, Simon and Maarten. Can you just talk about your long-term strategic planning? I think you've traditionally done this in the third quarter. I just wanted to confirm that you've done this exercise again this year and did you change your internalized long-term view around oil and gas markets? Secondly, just a very quick question. Can you remind us of the state of play on the Showa Shell and Motiva disposals? Thank you.
Thanks, Alastair. The first one could be a long or a short, so I'll keep it short as it's a call. What we do in essence is a more three-year strategic planning cycle where we do a full bottom up around the portfolio, once every three years and reaffirm strategic intents. We really did that last year as we were still doing the BG deal. This year we updated it in an assessment. That in itself has thrown up some questions around gas markets, gas pricing, and actually Maarten's pretty much given you the oversight of how we think about those already. Oil, we've long been of the opinion that demand will peak before supply, and that peak may be somewhere between 5 and 15 years hence, and it will be driven by efficiency and substitution, more than offsetting the new demand for transport.
We still have that view. We still have a view that there will still be a substantive business for us for many decades to come as a result. That also the reason Maarten also has the new energies business in his mandate is that actually new forms of energy used for transport, such as gas, or electricity or biofuels or hydrogen, will actually form part of the future energy system after the transition. Therefore, even if oil demand declines, its replacements will be in products that we are very well placed to supply one way or the other. We need to be the energy major of the 2050s. That underpins our strategic thinking. It's part of the switch to gas. It's part of the work we do in biofuels, both now and in the future, second-gen, third-gen.
Hopefully it will be part of how we develop the new energies business overall in the electric or electricity value chain. Showa Shell is a two-part transaction. We sell the shares to Idemitsu, then Idemitsu and Showa Shell merge. The first part of that transaction is subject only to completion of the competition review within Japan. It has been our intent to complete that deal when we receive that competition authority approval. The second part of the transaction, the merger, is the piece that has created some issues with some of the shareholders of Idemitsu, I can't really comment further on that because that's partly an issue for Showa Shell and Idemitsu to resolve. We are still of the intent to conclude the first part of the deal as and when competition authority approval is received. Cannot give you a date on that.
Could be this year, could be next year. Motiva We basically agreed a non-binding agreement earlier this year stating how we will split the assets after 17, 18 years together. That is from a 50/50 joint venture, Saudi Aramco will take slightly more of the value, likely that would lead to some form of cash balancing payment when we actually close the deal. Closure is expected early next year. Not sure if we've given a specific date. We're working on the final agreements. I can't say any more than that at the moment. It won't complete this year, is one thing I can be sure about. I think that was it. Do we have any more questions? We seem to have run out of questions, good timing.
Ladies and gentlemen, this concludes the question and answer session. I would now like to hand the call back to Mr. Simon Henry, CFO.
Thank you very much. Well, thanks everybody for calling in. I realize it's been a busy day with two sets of results and more. Thanks for the questions. Pretty good coverage today and some really important issues covered. Hopefully, both in the presentation and the answers, you can see evidence that the portfolio, both the Shell portfolio and the way it now combines with BG, have quite some power. Power to perform as we're going forward, power to generate cash, and power to deliver the value that we stated when we first did the BG deal. I keep on needing to repeat $64 billion acquisition. We are 19 months since announcement, job done, synergies being delivered, value being identified. We know who's delivering it, how it's going to be delivered. Two companies together, same cost base as one company. We've done this years ahead of expectation.
Not our expectation, but the expectation external to the company. That is really having an impact today now on the underlying financials that you see. Now, we will be having an investor day in New York next week on November the 8th, actually one week today. Ben, myself, and several other members of the executives team will be in attendance, and we really look forward to talking with you face-to-face then, and giving you the chance to hear a bit more and ask a few more questions about the substance behind the comments made today and the performance that you see. Thank you for your time today, and look forward to seeing you. Take care.