Welcome to the Royal Dutch Shell Quarter One Results Announcement Call. There will be a presentation followed by a Q&A session. If you have a question, please press star one. If you wish to be removed from the queue, please press star two. I would like to introduce your host, Mr. Simon Henry.
Thank you very much. Ladies and gentlemen, welcome to today's presentation. We announced first quarter results this morning. I'll take you through them. Of course, there'll be plenty of time for questions, and Ben will join us for the Q&A session. Just before I kick off, an auspicious day today. Not only do we have the BG acquisition in the background, but it's my 25th opportunity to discuss with you as a CFO, the results, and believe it or not, the 100th time I've done this within Shell. I look forward to appropriate treatment later. Before we start, let me highlight the disclaimer. Earlier this month, we announced a recommended offer to acquire BG. This is an important transaction for Shell. The combination with BG would accelerate our financial growth strategy, particularly in deep water and liquefied natural gas.
Both of these already growth priorities for Shell, and areas where the company is one of the industry leaders today. We've assessed this transaction on a range of parameters, including the intrinsic value. This is a transaction which delivers value for both sets of shareholders across a range of oil prices. The transaction would be accretive to earnings per share and cash flow per share in a relatively short timescale. It would have a strong complementary fit in a number of countries, and this, plus the efficiencies that would come from joining the two companies together, should lead to substantial value creation for shareholders over time. All of this should also be a springboard for a higher rate of portfolio change at Shell, with an increase in asset sales, a reduction in the combined capital investment, and a reduction in the number of longer term portfolio themes.
This should enhance our future dividend potential and of course, the potential for share buybacks. It's an exciting next step for both companies. Let me just say, there is no change to the strategic priorities set out for Shell a year ago by Ben. We are driving an improvement agenda today throughout the company. This is all about getting to a more competitive financial performance, improving our capital efficiency, and ensuring that we continue with the strong project delivery. The strategy is working, and it is leading today to more competitive performance from Shell. That emphasis won't change, and it's important we continue to drive that agenda in 2015 and beyond as we prepare to consolidate BG into Shell. Our current cost of supply earnings for the quarter at $3.2 billion excluding the identified items.
They were, of course, impacted by lower oil prices, although some offset from our integrated business model. Dividends were confirmed at $0.47 per share for the quarter and $1.88 per share for 2015. We're continuing to curtail our capital investment guidance today around $33 billion or less in 2015, and that is a reduction from what we announced three months ago of around $35 billion. Although the market for asset sales is difficult, we have made progress in the quarter, completing certain divestments in Nigeria, making new announcements in Oil Products . As I mentioned, we have announced a recommended offer for BG, which we expect to complete in early 2016. Turning first to the macro for the quarter, which has had quite some significant impact. Shell's liquids and natural gas realizations declined substantially from the first quarter of 2014.
Brent crude oil prices, some $55 a barrel lower or around 50% than a year ago, similar declines in WTI and other markets. The realized gas prices, 27% lower than year ago levels, with an even stronger decline in the gas prices in North America. On the downstream side, refining margins around the world were supported by lower crude and higher levels of industry planned and unplanned downtime, particularly in the U.S. Industry-based chemicals margins declined in Europe and North America as ethylene prices fell along with crude. However, intermediate margins increased on the back of reduced feedstock and energy costs, but also improved market conditions. Exchange rates moved sharply. Compared to Q1 2014, the U.S. dollar strengthened against the EUR and the BRL by more than 20%, the AUD around 14%.
In the quarter, the average movement was smaller, but still 8% and 4% respectively. This has quite a significant impact on our results. Turning to those results. Excluding identified items, our current cost of supply or CCS earnings were $3.2 billion for the quarter. That's a 56% decrease in earnings per share from the first quarter of 2014. On a Q1-to-Q1 basis, we saw significantly lower earnings in upstream, but higher earnings in the downstream. In the upstream, earnings obviously impacted by the significant fall in the oil and gas price, but also lower trading contributions and exchange rate effects. In the downstream, results improved. This reflected the higher industry margins, but also the steps taken by Shell to improve financial performance, such as from the divestment program and the underlying improved operating performance.
The return on average capital employed across the group was 8.4%, excluding the identified items, cash flow generated from operations was some $7 billion. Our dividend distributed for the first quarter of 2015 is the same as year-ago levels at nearly $3 billion or $0.47 per share. We repurchased around $400 million of shares earlier in the first quarter. We have more recently, of course, halted that share buyback program to conserve cash in the lower oil price environment. Our upstream earnings, excluding the identified items for the first quarter, were nearly $700 million. That's a decrease of some $5 billion compared with Q1 2014. This figure includes $4.7 billion reduction just from the oil and gas price alone, a very large move. Many of our LNG contracts are time-lagged against oil by somewhere between three and six months.
The first quarter of 2015, the LNG earnings do not yet fully reflect the drop in oil prices that we saw to date this year. On a Q1 to Q1 basis, we also saw an $840 million reduction in earnings, Upstream total, due to the increase in deferred tax balances as a result of the weakening Australian dollar and the Brazilian real. This was not taken as an identified item, so it's a negative $840 in the clean earnings. These were very large movements which masked some positive effects from the growth barrels from lower costs and lower exploration charges. The headline oil and gas production for the first quarter was 3.2 million barrels oil equivalent per day, excluding 190,000 barrels oil equivalent per day reduction from the asset sales and license expiries. While the overall volumes decreased, the underlying volumes increased by around 1%.
The volumes are supported here by the ongoing ramp-up in deep water fields, Nigeria, Malaysia, Gulf of Mexico. Maintenance impacts compared to last year increased. This included the Pearl gas to liquids train 1 in Qatar, which was in planned maintenance in the first quarter. Production there at Pearl has recommenced during April. In the Netherlands, the Groningen gas field production was impacted by curtailment of capacity, curtailment requested by the government by 105,000 barrels oil equivalent per day. This was fully offset in the quarter by the release of volume from underground storage. That is just a Q1 effect. Both effects are included in the performance category on this particular slide. Our LNG sales volumes in the quarter were almost 6.2 million tons.
That's up 1% year-on-year, reflecting good operational performance, but partly offset by the impact of the Woodside divestment in the second quarter last year. Turning now to the Downstream. The underlying earnings were $2.6 billion, 68% increase driven by higher Oil Products results, slightly lower Chemicals. In Oil Products, we benefited from increased refining margins, but also a much better operating performance. We have higher trading results, lower costs, some offset from lower contributions from marketing. Chemicals earnings were slightly lower than year-ago levels, but stronger intermediates offset the lower base chemical results. The refinery availability averaged some 95% in the first quarter, strong and improved performance compared with last year. In fact, probably our best ever. The chemicals availability at 84% was lower than a year ago, that basically due to the downtime at Moerdijk in the Netherlands.
That itself was improved from Q4 2014 levels as we continue to make progress with repairs there. The Moerdijk cracker is on track for a second half 2015 startup. That should be earlier than expected and at a lower cost. Exchange rate impacts in the Downstream are a mixture of positive and negative. They impact costs and margins, but probably minimal overall impact to the Downstream result. Overall, this was a stronger quarter for the Downstream. Return on average capital on a clean CCS basis was 13.4 percentage points at the quarter end. Downstream CFFO was around $10 billion over the last four quarters. Just looking at costs. These are actual costs that we see reported. There are cost reduction programs in place across Shell.
They look not only at our own cost, but also the supply chain. It was good to see the progress on cost in the first quarter. The total operating costs, as you will see them in the P&L, excluding identified items, fell by almost $1.1 billion in the quarter or around 10% year-on-year. About 65% of that movement is a result of stronger US dollar exchange rate effects. The remainder comes from our own actions to exit the non-core portfolio to cut back on our pre-FID options and ongoing cost reduction activities across the company. I remain convinced there's a lot more to come here as we drive down costs in 2015. Now, moving on to the cash flow. The cash generated from operations on a 12-month rolling basis was some $38 billion at an average Brent price of $85 per barrel.
Free cash flow, that's cash generated less investments, adjusted for M&A, was $2.7 billion in the quarter and nearly $22 billion over the last 12 months. Gearing at the end of the quarter was just over 12% or 12.4%. The returns to shareholders, dividends declared, plus the buybacks were $14.4 billion over the last 12 months. Just let me remind you of our financial priorities. We expect gearing to increase in 2016, particularly as we close the BG deal. We updated our financial priorities with the BG announcement a few weeks ago. First priority remains debt paydown. Secondly, of course, asset sales and project growth, very important part of that. Secondly, dividends remain our main route to return cash to shareholders. Shared buybacks have moved up in the priorities, will be assessed alongside capital investment, reinvestment in the business.
We did announce plans for at least a $25 billion buyback in the 2017 through 2020 period, assuming, of course, successful completion of the BG acquisition, progress with the debt paydown and oil prices recovering towards the middle of the long-term planning range. Now, we appreciate that at this particular point in time, modeling our results can be a challenge. To help you with this slide has some indications for the second quarter, also covered in the results announcement. You'll also see an update on the sensitivities at the end of this presentation. I won't talk to this slide, but I would emphasize it does cover the foreign exchange currency effects. Asset sales. In the quarter, these totaled $2.2 billion.
2013, we set out a strategic review of the Nigeria onshore portfolio with an aim to reduce our onshore footprint, particularly the oil, and to refocus SPDC onto the gas value chains. Now, we've now come quite a long way here. This has involved asset sales of some $4.8 billion in the last five years, all in line with the federal government of Nigeria's aim of developing indigenous Nigerian companies in the country's upstream oil and gas business. Recently, we completed the sale of the Oil Mining License, OML-24, and that was done at the end of 2014. OML-18 and 29, together with the Nembe Creek Trunk Line, were completed in March this year. Now, together, these mark very significant progress in the onshore asset sales program. Going forward, SPDC will continue to focus new investment on the associated gas opportunities.
We've also continued to work on Oil Products investments where the asset sales, including the MLP, Master Limited Partnership, last year, they totaled around $4 billion. Recent announcements in Q1 covered marketing positions in Denmark and the U.K. Turning now to capital investment. We set out a program over a year ago to moderate our spending in 2014 with a reduction in both the headline and underlying organic spending, and we are continuing with that approach in 2015. On the one hand, we need to make sure we have an affordable program, and on the other, to maintain an attractive growth portfolio for the shareholders. I can update you today, we now expect spending this year, 2015, at around $33 billion or less. In other words, that's a $2 billion reduction from the $35 billion ceiling on spending we set out three months ago.
We were very clear three months ago, this is a dynamic picture. We don't make all our decisions on the 1st of January. What you see now includes a series of pragmatic decisions on new opportunities. For example, we pushed out the final investment decision on Majnoon, the full field, into 2017 or later. We've continued to reduce spending in resource plays or unconventional Shell by around 20% this year, and we've rephased the development pace of Carmon Creek heavy oil in Canada, phases 1 and 2. We aim to optimize the design and re-tender some parts of that project to take costs out. These steps come on top of the cancellation of Al-Karaana Chemicals in Qatar and the other portfolio decisions that we made earlier this year.
We did curtail our spending anyway coming into 2015 to get down to that $35 billion level, and we continue to review the appropriate spending levels in the company, aiming to deliver that strategy of balancing growth and returns. Lastly, just let me update you on the competitive position. Clearly, in the absence of target, our actual performance on a competitive basis really matters. You know we take a dashboard approach. We're looking for a more competitive performance on a range of metrics over time, not just single-point outcomes. We've been trending higher on return on capital employed and cash flow. Last year, we saw a significant uptick in the free cash flow. Clearly, the oil price movements we've seen will push a number of these metrics downwards for at least the next few quarters. We have seen, though, that our competitive position is improving.
We will continue to focus on that. There is no complacency here. There remains still a lot we can do within our own remit. With that, let me sum up. The results reflect the strength of our integrated business against the backdrop of lower prices. Meanwhile, in what is clearly a difficult industry environment, we continue to take steps to further improve the competitive performance, redoubling efforts to drive the sharper focus on the bottom line. Looking ahead, the proposed combination with BG should create a stronger company for both sets of shareholders, and we're looking forward to completing this transaction 2016. The priorities that we set out at the start of this year have not changed. The strategy is working today and is leading to a more competitive performance from Shell. All of this underlines our commitment to shareholder returns.
With that, I'd like to move on to take questions. Please could we have just one or two each? The usual request, everybody has the chance to ask a question. Operator, please could you poll for questions?
Thank you. We will now begin the question and answer session. People dialed in, if you have questions, 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 Theepan Jothilingam from Nomura International. Please go ahead.
Hi, Simon. Hi, Ben. Simon, I don't know whether to congratulate you or commiserate you on 100 quarterly results. Just coming back to the capital investment decision process, could you just talk about what further decisions you can make in 2015 that would reduce that $33 billion? Does the decision to make an offer for BG change your view on CapEx going forward? The second question relates to the downstream. Strong performance with earnings, but I see a working capital build in terms of on a cash flow basis. Could you just talk about how you see working capital, particularly in the downstream, evolve through 2015? Thank you.
Thanks, Theepan. The capital investment, there are 2 levels to this. Large decisions, some of which I just mentioned, and then the smaller projects, the $500 million or less that essentially are managed on a portfolio basis. We are aiming overall to do 2 things. 1, just take cost out in the supply chain. A lot of that activity refers to decisions or investment decisions not yet taken. While we may get cost reductions, they may not impact hugely in the current year, except on some of that small project suite. The other area is really deferring capital where that can be done without losing value. I think the balance that we've taken so far shows you we're taking a fairly well-considered approach to that, working within our means. There are one or two large decisions still coming up.
The first couple, I guess, are the Appomattox investment, deep water, very large project decision, middle of this year. We also have other investment decisions on Vito and Bonga Southwest, and Libra in Brazil. Vito is also Gulf of Mexico. Those are four big deep water decisions. LNG Canada and the chemicals plant in Pennsylvania are probably the other large decisions in the next 12 months. In all of them, we're looking at what's the right timing and what is the right cost base to go forward with. In total, there are around 17 final investment decisions in 2015, 2016. We're not thinking about just the one year of CapEx. We're looking at essentially the next three to four years, where we're well aware that we need, even without BG, to be retaining as much flexibility and strength on the balance sheet as we can.
BG, does it change our view on CapEx? Well, for 2015, not really. We do what we can do. Our options are relatively limited. Going forward, what we did say is that we'd expect even in 2016, that the total investment should be less than the simple pro forma addition i.e., to add up to less than 40. Going forward, difficult to say anything more than that at this point in time, but clearly, richer portfolio, set of options. Hopefully, we can make sure we get a good balance of choices. Downstream capital build. The main reason it's come back a bit in Q1 is the price increase by the end of the quarter. We were heading up towards 60 or so, and that will continue. As long as the price increases, the working capital will increase.
If the question is partly about trading working cap, yep, we did give them an open credit line probably about eight, nine months ago now, which they've utilized up to $2 billion from time to time. I can't give you what they were at any given point in time, but that's the level of working cap they've been using. In addition, additional regulatory requirements in terms of putting transactions over the exchanges is chewing up capital over time. I don't have a figure for that, but we've previously spoken about $1 billion to $2 billion because of additional, and in our view, not only unnecessary capital requirements, but ones which increase the total risk in the market and decrease the liquidity and the ability to match risk for our customers. It A worrying regulatory development, which are not helpful.
The primary factor at the moment is the increase in the oil price. Thanks, Theepan. Move on to the next question.
Thank you.
Thanks.
We will now take the next question from Jon Rigby from UBS. Please go ahead.
Thank you. Hi, Simon. I have to say, I think you're starting to get the hang of it slowly on the quarterly. Keep the good work up. On the questions that I had, the first was, one of your competitors indicated that a likely delta to reflect the very strong trading conditions of $400 or $500 million. Would that be a sensible number to think about in the context of what Royal Dutch Shell was able to do just in the oil trading side? I understand the gas trading was not as good this quarter. The second thing is just on CapEx itself. You referenced that you had the option to defer spending. You clearly have the ability to go back to suppliers and discuss lower pricing, lower invoicing.
There's a third element to this, I think, which probably goes to the real problem the industry has, which is just how you go about doing stuff. Do you think over the next two to three years, we'll actually start to see something fairly material in resulting from reviews and a re-examination of how you go about doing projects, scoping them out, and then executing them? Thanks.
Thanks, Jon. I think you may be close to your own century, actually. Thanks for the comment. The changes in trading. Then maybe I'll ask Ben to comment on changes in projects. Trading, remember our trading business essentially is adding value to molecules that are flowing through the system, the fuels value chain in practice. We produce 1.5 million barrels a day, we refine three, and we sell six. We refine twice what we produce, and we sell twice what we refine. Trading is basically the glue and the activity that enables us to do this in the most optimal way. Two years ago, Ben changed some of the organization accountability. The way we think about managing that value chain.
Building on some work we've been doing, including systems development, and that transparency change in accountability have, in practice, helped us add more value, certainly to optimize the value in our downstream business. We talked last year about that plus cost reductions, adding maybe $1 billion pre-tax to the earnings performance. We are continuing to deliver that. Trading is not a separate activity. It is embedded in adding value to molecules moving to customers. Yes, the desks do operate 24/7, and they are operating some open positions with quite a limited value at risk. It would be wrong to characterize the activity as a standalone or separate from the day job of meeting customer requirements.
We did earn more on the oil products and crude trading side, but it's only in the order of a few hundred million, and it's almost impossible to extract that from the pure refining results as well, which also had one of their best quarters, partly in at least because they operated extremely well in the quarter. I can't say too much more than that, I'm afraid. Other than that the improvements made are structural and will last for some time. It's an excellent question about the will we see structural changes in the way that companies operate together, particularly on the project side, everything from scoping through design. It also may be in the complexity that we sometimes have. Ben, probably it's a good one for you to pick up.
Okay.
This is about competitive edge as well.
Thanks, Simon. Yeah, thanks, Jon. I think very good question. You're absolutely right. At the moment, it's all about making sure that we get the projects right in terms of timing and decision making. It's very much challenging. Can we afford to take this on? Also, if we take it on, is the cost competitive in the environment within which we make the decision? If not, then we have to find a way to work harder on that. By and large, indeed, you can, of course, rescope to some extent. If you assume that you didn't get the concept wrong to start off with, it is basically trying to either retender or get a more competitive deal. Fundamentally, you have to be right. A lot of the escalation that we've seen is somewhat more fundamental and structural.
We need to get a handle on that as well. I've made it very clear with our project organization, and Henriette Snedker Nielsen is in no doubt, getting our projects to be absolutely competitive in the industry, and more generally, getting our development portfolio more competitive, I think is a long-term license to operate issue. I don't think you can see it in any other way. What are the things that we can do? First of all, have better teams on it, have better practices, better approaches, better scoping, less reworking, better upfront decision making, front-end loading, all the sort of things that we have been doing for the last 10 years, which basically has moved us, by and large, into the first to second quartile, depending on what types of projects you look at.
I think we are probably sort of getting at the point where we understand how to do that well. That clearly isn't good enough either. We have to now think, and there's the right time for it. Can we indeed take complexity out of projects? Can we have a more standardized approach to projects? If you look at how projects have evolved over time, they are just taking up much more time, much more effort. They take longer to build, and some of it is the result of less experience in the industry, more overheating in general. Probably also the result of higher and more difficult requirements that regulators and society maybe in general puts on us. Some of it is probably also sophistication that perhaps we didn't quite need as much. Simplifying, standardizing is another approach to take.
With it, actually very closely related to it, you can think of how do I transform the entire supply chain. This is not going back and renegotiating contracts, but actually working differently with core suppliers, be it technology suppliers, equipment suppliers, working much more with standardized solutions, long-term solutions, replication of designs, ordering multiple items of the same thing at the same time, because you know you're going to use it going forward in multiple projects. These are the sort of things that we have been working on as well. We are making progress in the sense that we have good enterprise frame agreements, that we have strategic relationships, that we have investment themes like deep water, like integrated gas, that we take sort of multiple project views on things. There is more to be done, Jon.
I think, yes, you will see leading companies, and I like to think ourselves being amongst those, taking a different approach to projects going forward along those lines.
Thanks, Ben. Next question.
Thank you. The next question is from Oswald Clint from Bernstein. Please go ahead.
Yes. Thank you very much. Maybe, can I ask a question about the European gas business and kind of related to the NAM volume shut in the second quarter, which is a decent chunk of volumes. Especially in terms of not being able to store gas, does this pose any kind of customer delivery gas contract issues for the second half of the year, certainly through winter? Ultimately, if you could just talk about the NAM being potentially shut in for longer, or is it an opportunity whereby pricing could strengthen and you could actually sell forward some natural gas into the winter months? That's the first question. Secondly, I was just curious about going back to BG. I kind of remember the slides back on the day. It was $2.5 billion worth of synergies plus some further upside potential.
I think, Simon, I think the wording your comments was much more about substantial value creation this morning. I just wondered, is that a change in kind of wording over the last month? Have you had a better look at this? Is there more scope for that kind of value creation side? Thank you.
Thanks, Oswald. I'll take both of them. The EU gas business, no supply issues at the moment. Groningen Field has historically acted as the gas central bank for Europe in terms of demand being driven by the weather. It's actually been a pretty warm year so far, as you're probably well aware, and no supply issues at all. As we go forward to next winter, while cold winter could obviously put pressures on, the gas storage underground can be filled from sources other than Groningen, and I would expect there are many more sources than just Groningen that can help prepare. We don't know actually what the government will request as we go forward. The actual levels have changed a couple of times already. We're not expecting significant impact on pricing. On BG, the $2.5 billion synergies were externally verified, audited, then subject to regulatory reporting rules.
Therefore, they're real, but about as far as we can go. It's only three weeks since we announced, of course, even though it seems longer in many ways. We've not done a lot to change that detailed view, and it's unlikely that we will for some time. What the substantial value refers to is what I might call the rather more difficult to identify and value synergies. The 2.5 is reduction in spend, auditable. The real value comes from what can you create, for example, by bringing the two LNG portfolios together. From the deep water expertise technology operational that we can bring, for example, to Brazil. In general, as the BG portfolio matures more into development and production assets, that's perhaps more an area of strength for Shell than it was for BG, which built great value around exploration and LNG market development.
Some complementary skills, but obviously value opportunity that while we see it, we cannot claim it until the combination is in place and we are delivering it to the bottom line. Thanks, Oswald. Move on to the next question.
Thank you. The next question is from Irene Himona from Societe Generale. Please go ahead.
Thank you. Good afternoon, gentlemen. Firstly, on OpEx. You mentioned, Simon, that you had a $1.1 billion reduction in cost in the quarter, of which 35% is self-help, so that's $385 million out of $45 billion, I believe, cost base for Shell. My question is how sustainable is the 65%, which was effects related? I know you don't communicate external targets, but any comments would be much appreciated. Secondly, I just wanted to ask if you can provide some visibility, perhaps on the components of the Upstream America's loss this quarter. It lost over $1 billion, Canada is half of the production. Can you give some insight on the different bits of it, such as unconventionals, oil sands, et cetera? Thank you.
Sure, Irene. Thanks. The $1.1 billion is a year-on-year figure, so there's always a bit of seasonality in there as well. In general, if the currency rates stay where they are, we'd expect maybe a couple of billion-dollar reduction year on year, because they did move during last year. I hesitate to stick my neck out too far, but we ought to be seeing not entirely dissimilar numbers from self-help as well, but it will be offset as new projects do ramp up and create their own cost as well. Very focused within the company on delivering those numbers, and we'll update you on a quarter-by-quarter basis. We also aim to take the cost out forever as well, not just temporarily. Upstream America's loss of $1 billion is there. You know the business as deep water, heavy oil, unconventional, plus a bit of exploration.
Deep water and heavy oil, absent the Brazilian currency movement, we're about breakeven. Brazilian currency movement BRL 300 million, plus Alaska exploration spend, plus roughly similar numbers, actually, it's about a third each. The ongoing loss in the unconventionals contribute to the $1 billion loss overall. In practice, the unconventionals is in a much better place than it was a year ago. The challenge is a 250 Henry Hub gas price and realized liquids prices well south of $50, given the nature of the market within North America. I think it's fair to say that everybody is showing either a loss in the Americas or very close. We may have what is apparently the biggest loss, but please reflect that BRL 300 million is Brazilian currency and a similar number for the spend so far in Alaska. Okay, hopefully that covers that. Next question, please.
Thank you. The next question is from Fred Lucas from J.P. Morgan. Please go ahead.
Thank you. Good afternoon, Simon and Ben.
Fred.
A question around impairments and provisions. On provisions, can you remind us what provisions have been taken by NAM related to the subsidence issue there and what headroom you have over those existing provisions? How much of the provisions have been consumed? On impairments, again, you haven't taken any significant impairments. We've seen today Statoil take a very substantial impairment, which I think is explained by them as a change in their medium-term price deck.
On the same subject matter, could you remind us how you calculate or how you do your impairment test and at what point you overlay your medium-term price view beyond the curve, and perhaps also indicate if you were just to use the curve as far as it can be seen out to 2022, whether you'd still be safe from those impairments or whether the absence of impairments relies upon that recovery to the midpoint of your $70-$110 price view? Questions really around provisions and impairments, please.
Thanks. Do the NAM provision first. I can't remind you because I don't think we told you. It's not major at the moment. We're looking obviously very closely at the developments in terms of how compensation can and should be calculated. You may be aware of the parliamentary debate this week in the Netherlands. At the moment, there's very little impact in the results. The biggest impact has been the reduced production. On impairment policy generally, we basically look at forward cash flows using the midpoint of the 70 through 110 range. We take long-term 90. We test not only short-term with a lower price as well, but from time to time, and we did some of this in Q4 with a flatter and lower price at the bottom end of that range.
The assets that are closest to the impairment are, you very kindly say we haven't taken impairments. I think we have in the past, particularly in the shale and conventional activity in the U.S., both taken impairments but also divested quite significant parts of the portfolio. We have said that there remain a couple of assets there, Groundbirch and Appalachia or the Marcellus, that were we to take a different view on gas prices, not oil, but gas, we could come with a different outcome there. Or if we decided not to proceed with LNG Canada, as that's where the gas from Groundbirch is ultimately targeted. Elsewhere in the portfolio, there's not that much that is close to the edge. We've had discussions previously about Kashagan. That's really a question of when does it come up and running. It's a strong cash generator once it does.
Until that point, it would be vulnerable to a change, I'm sure, in oil price assumptions. Overall, the portfolio remains fairly robust against lower oil price expectations. Not run the forward curve out to 2022, basically because that's not what we believe the prices should be, nor necessarily that should be the basis for impairment. Hopefully, that helps. That's not a change in policy. That's basically ongoing policy. Thanks. We'll go on to the next question.
Thank you. The next question is from Lydia Rainforth from Barclays. Please go ahead.
Thanks. Thank you, Simon, for putting up with all the analyst questions for the last 25 quarters. Two quick questions, then one for Ben, if that's okay. On the cost base and the chart that you showed indexing cost back to 2011, was there a particular reason that you chose 2011? Is that the sort of scale of opportunity that you're thinking of, or is actually the opportunity greater than that? Just very quickly, can you remind us how much the investment in Arrow has been to date? Just finally for Ben, can you just talk through the reaction that you've seen from stakeholders, say the governments and whether it's the other operators post the announcement of the BG deal? Thank you.
Thanks, Lydia. Nothing sinister in the selection of 2011. It's just to go back several years. I guess it's post, we had a bit of a wobble in the cost base between 2009, 2010. If you remember, cost and oil prices dropped a bit then, 2011 was sort of the first year of the $100 run. It also, of course, excludes the Macondo year as a baseline, when quite a bit of impact on individual companies. The investment in Arrow. I'm not sure we've given this before, but it was several billion dollars up front, obviously, to enter. We then divested down 50% to PetroChina, and we've had ongoing activity, but in terms of Shell investment, several hundred million per year rather than billions.
Clearly, Arrow is in a position where we need to think about the best way forward to monetize and to create value from the position we have. Now there's an additional element which we can't consider yet until we're at the point of closing the deal. Depending how we monetize, I cannot and should not rule out any impairment on the carrying value of Arrow. It will depend on how we choose to develop, which in itself could, over time, depend on the combination with BG. Ben?
Thanks, Lydia. We, of course, had an interim update with some of you earlier on. Let me just say that by and large, going around the markets, it's fair to say that the logic, of course, is very well understood. Everybody thinks it's compelling, it's logical to do this. It makes sense. I think there was in the beginning, of course, quite a bit of discussion to what extent or at what oil price does this work? I think that is beginning to settle as well. People see it works in a wider range of oil prices. I think there's a little bit, and I'm sure you yourself will be right in the middle of that, a little bit of the modeling sort of perfecting going on to sort of understand the numbers that we have given out.
By and large, I think that is starting to converge and settle as well. I think what I've heard in the mix, if I add it all up, I believe the consideration, the way the offer has been structured and the way we have approached the valuation is being seen as sensible and fair for both sets of shareholders. In the meantime, I've been speaking to key stakeholders in the business as well. I've been to Trinidad and Tobago, which was a very positive and good meeting. Met with the prime minister there, who was very much welcoming, of course, of the development. If the transaction goes through, we will, of course, be then the largest integrated player in the country. It will be important for them to understand where we come from.
I think a very, very good understanding of what we like to achieve and what our long-term view is on the country and the assets, et cetera. Brazil, similar, if not even more positive. Meeting with the president was very positive. Meeting Petrobras was very positive. A meeting with the Mines and Energy Minister was very positive. Next week it will be Kazakhstan and China. Let's see what will come out of that. I think what we, of course, hear is, again, positive and logical. Likewise, we have good and positive reception and messages coming out of Australia. It's, of course, incredibly early days. We are, as you can imagine, right in the middle of getting all the applications filed for the regulatory approvals.
I think at some point in time, we'll probably need to give a formal update, at this point in time, it would be premature. I think so far so good. Early days.
Thanks, Ben. Next question, please, operator.
Thank you. The next question is from Lucas Herrmann from Deutsche Bank. Please go ahead.
Yes. Good afternoon, gentlemen. Thanks very much for the time. Two relatively straightforward, I think, Simon. CapEx, I just wonder if you could talk about what you're actually seeing in the market across the different service sectors in terms of pricing as you go in and discuss. Secondly, I just wanted to go back to OpEx and just walk through. I'm getting rather confused, apologies, in the context of the savings you hope you will be able to achieve on operating costs, I guess almost from the time that Ben started to push for change more aggressively or for efficiency more aggressively at the start of last year.
Okay. Many thanks, Lucas. What are we seeing in the market? Well, a variety of reactions. We can take a standard response to asking for reductions on the cost. I think Ben captured it pretty well ultimately around the capital investment in totality is as much about design and scoping and then efficient management of the supply chain, smoothing out the demand profile, et cetera, as it is about the unit price. It's also about working in a more collaborative way with various different elements of the supply chain. In some places, yes, you can take cost out. You can see that happening in places like the North Sea. You can see that happening with rigs, both onshore and offshore, particularly if you want a short-term offshore rig. It's not happening as much in the more oligopolistic parts of the business, the subsea equipment, for example.
There are some good discussions ongoing that may basically, as Ben said, lead to much longer, more structural and more constructive cost takeout for everybody. It's quite difficult to say more than that without getting lost in the weeds, Lucas. We do expect, though, that over time, CapEx, the unit cost level in aggregate trends in line with the oil price. The two are not independent metrics. On the OpEx. I'll try again, but the baselines do differ. Let's take $45 as a baseline number. It was last year's OpEx, and it's roughly where we've been. Now, we are seeing a 5% reduction in that from foreign exchange, like to like. That would flow through this year if FX rates don't change.
We are targeting at the micro level, not a big, hairy goal at the corporate level of $X billion, but within a business, within a function, within a geography, within a business. We've talked about unconventionals, for example. They, together with the Upstream Americas team, they know they need to take a $1 billion-plus out of their cost base. Now, some of that is overhead, some of that is at the frontline in terms of the drilling activity. Some of that comes into CapEx, some of it comes into OpEx. We have the downstream. John has talked about $10 billion of cash flow from ops and a 10% return on capital across the bottom of the cycle. He has cost targets embedded in that in each part of his business, whether it's manufacturing or marketing.
We're currently looking at the international upstream business as to the total level of cost in that business as to where that should go, particularly in areas where maintenance costs have been increasing over time inexorably, and think of the North Sea. Lastly, the functions. I personally have targets of around $1 billion in the finance and IT area from the spend we were at a year or so ago. Similarly, my other functional colleagues in legal and human resources. We're talking some non-trivial numbers by the time these all add up. There is no big hairy goal, either internally or externally for a very good reason. We do not want to divert the entire organization from creating and adding value through a multiplicity of value levers, including cost, and switch them on to just a single thing.
If you cut cost too much and with too much gusto today, you almost always regret it tomorrow. I can give you that, but probably no more. The direction is clear. It's going in the right direction. Ben, is there anything you would add to that? Because this is as much about the leadership psychology as it is about the numbers.
Thanks, Simon, and thanks, Lucas. I think, of course, it's incredibly topical at the moment, and it's, of course, very tempting to put all sorts of high level, big, hairy cost targets out there to show that the organization is responsive. I think in the end, as Simon says, it quite often also leads to the wrong behavior and wrong outcome. Just going around the organization saying, "Give me what you can do," or maybe even more stupid, "I will tell you what you should do," and then see whether we can deliver against it, never really gives anything which is either sustainable and most likely also not targeted enough. You have to, and that's the philosophy that we have adopted. You have to go deeper down into the weeds to understand where costs can be taken out.
It's either because you look at efficiencies in functions, you look at efficiencies in IT systems, et cetera, or you look into individual pieces of business, often down to the performance unit level, where you just say either, first of all, how is my cost base and how can I benchmark this to see whether it's competitive or not? Quite often you can already find therefore, the inefficiencies in a very targeted way. Why would my maintenance spend be three times higher or even 20% higher than what is first quartile in the industry? Then try and think that through, and maybe there is a good reason for it, but maybe also not. That will get you much more precise, focus on where the waste is.
You can also take a slightly different approach, which we often do in performance units as well, just say, if you want to have this as a competitive business, what sort of cost levels could you afford? How could I get to that cost level? If you can't get a way to that cost level, then maybe the business is fundamentally weak and you better get out of that business. Maybe you have to think of the business model or how you create margin in that business or whatever it is. You have to have that type of approach, so cost related to value creation and specifically targeted on an understanding of how the operation is doing, if you want to make the right sort of decisions that are sustainable and do not end up in regrets later on.
As Simon says, we have hundreds and maybe even thousands of target points throughout the company where people work along these lines on what are the right things with many, many metrics on what is my return on this piece of OpEx, what sort of utilization do I get out of that piece of work, et cetera. We don't add it up, we don't put a bow around it, we don't say, "Oh, it's X billion, and you're going to measure us against that." Again, that would fundamentally go against the grain and the philosophy on how you manage for performance. I know that other companies do that. The way we wanted to sort of approach it this time around is that look at what we deliver. Yeah? This is not about where I'm going to get to quarter-on-quarter.
This is basically how our performance looks like in terms of value delivery. Of course, we will take a cut out of the cost as well, so you can see how we are doing in terms of OpEx delivery. I think that should be a better way of judging whether we have the right approach to this.
Thanks, Ben. Next question.
Thank you. The next question is from Thomas Adolff from Credit Suisse. Please go ahead.
Hi, Simon. Hi, Ben.
Thomas.
Two questions, please. The first one, I just wanted to go back to Jon Rigby's question. Yes, indeed, the industry can improve, and the IPA has good statistics on that. You talk about simplify and standardize approach, take complexity out. Even with the old approach, if I look at Exxon, they're so way ahead of everyone else. I wondered whether there's simply a big knowledge gap or whether the industry has just been complacent because the oil price was at $100. Second question, I guess, is just on the capital intensity of the business. I think most companies or most of your peers would say the portfolio decline is around 3%-4% after some spend. If I look at the business pre and post BG deal, obviously you have some long life assets coming on stream over the next few years.
Given that BG overall as a business is relatively more long life, even the Brazil stuff, how should I think about portfolio decline as a combined entity? Thank you.
Okay. Thanks, Thomas. Let me talk to the first point. It's probably true that companies like Exxon are way ahead of everyone. They're very working in the same league as we are. I would like to push back to the idea that anybody else is ahead of us when it comes to taking cost out by understanding how you do projects well. We've been on this journey to improve the way we do projects since 2004. We very, very clearly for all major projects squarely benchmark in the first quintile. This is done in quintiles. Indeed, quite often together with Exxon or ahead of Exxon.
If you do not buy that, just look at their reports and it will be very clear, and maybe we should bring that back at some point in time as a proof point as well in one of our presentations. Yes, this is complex, this is difficult, but again, I do believe we are on track. There are many examples to make that point. If I just go back to this year, look at what we have done with Mars B, it is very clearly an example where, if we know how to manage the stuff, we will deliver outstanding performance. We have, unfortunately, also the ability to benchmark an awful lot within our own portfolio if we look at non-operated assets.
Also there you can see that systematically, if not without exception, we are ahead in terms of performance in our operated portfolio compared to a non-operated portfolio. That is a bit of benchmarking that we have in-house as well.
Thanks, Ben. Capital intensity, it's a complex question, so I'll try and be as quick and simple as possible. There are portfolio effects in any overall measurement, so clearly decline rates are different, whether it's conventional LNG/heavy oil, or Shell. Now, arguably, you need to separate them out. Overall, our portfolio has been running more like three percentage points decline year-on-year. That's what we saw Q1 versus Q1. That assumes some level of infill drilling and pressure maintenance, et cetera. As we go forward, not just through BG, but through the choices we make ourselves to upgrade, it is likely that we will be focusing on, if not zero decline, should say less mature assets.
Our exposure to high decline, and high cost of maintaining production assets is likely to decline overall and give us a portfolio not only with a longer life ahead of it, but one with lower capital maintenance requirements. It's difficult to say any more than that without getting quite granular. Yes, the direction is correct. Gas plus big deep water offshore, where you continue to have to drill, but typically the aim is to keep a facility full, such as the FPSOs in Brazil or in Nigeria, or the TLPs in the Gulf. That's what the choices, the big investment choices will be targeted at, ensuring we have assets that while we need to drill to keep them full, there is enough resource to do exactly that. It's worth also saying, look at the dollar per barrel metric. They're also highly driven by the portfolio.
I don't mind a higher dollar per barrel investment if, in fact, the margins available are they justify it. That's very much a measure of the fiscal regimes we choose to invest in. We strategically made quite large shifts in our portfolio some years ago to what we felt were more attractive fiscal regimes. You can see some of that coming through in our earnings and cash flow per barrel now and what are, in effect, lower tax rates in the upstream. Thanks. Just we move on to the next question, please.
Thank you. The next question is from Christopher Kuplent from Bank of America. Please go ahead.
Hi there. Thank you. I'm not really sure whether I'm allowed to ask questions given the restriction that the recent M&A activity has put on me, but I'll try anyway, very briefly. The sensitivities at the back end of your slide pack, would I be right in assuming that you're referencing this very much in a year-on-year context rather than a quarter-on-quarter? Because if I apply the Brent and Henry Hub sensitivities you've given us to first quarter 2014, which I remember was a very strong quarter, to first quarter 2015, and, obviously adjust for the FX effects. This looks to me like it's been a very strong quarter in 2015 again. Would that reflect the earlier gas price lag that you mentioned? Sorry for a very long question, probably only has a very short answer. Second question is purely on the refining margin outlook.
What are you seeing at the customer end, in terms of demand growth coming through or not? What do you expect directionally for the rest of the year? Thank you.
Thanks, Chris. I think as long as the Chinese walls are in place, you're welcome to ask anything you wish. The sensitivities, in simple terms, you're right, it was a good quarter for the upstream. Operationally, we did well. The other thing is our production was impacted by more turnaround on high-value activities in the Gulf and in Qatar. Actually, in terms of the actual performance of both upstream and downstream, we were quite pleased with what we were able to achieve. We continued to improve safety statistics as well. Unfortunately, in a $55 world, it doesn't all show through. It was generally a good quarter. Refinery margins, they have started to come off anyway. They were helped by demand, in North America that certainly U.S. demand has proved stronger than we might have expected, coming back a bit.
Cheap gasoline is always a bit of a boost to an economy. In developing markets, it's less clear. I mean, there is demand growth coming back. Last year was just below 1 million barrels a day, I think the growth. We would expect somewhere between 1 and 1.5 million barrels per day growth in any given year. This year, so far, looks like it will fall in that range. It's a little early to say, is this going to be enough to close the supply-demand gap? In and of itself, the answer is no, because the supply overhang is potentially quite a bit higher for some time to come. Over time, yes, it will. Just on the basing, the FX impacts there for any given quarter.
If you see the Australian dollar move by AUD 0.05 during a quarter, you should see roughly a $300 million earnings impact after tax included in the earnings, clean earnings. Similarly for the Brazilian real, although, of course, that's a much lower sensitivity. Many thanks. Suggest we move on to next question.
Thank you. The next question is from Jason Gammel from Jefferies. Please go ahead.
Thanks very much. I just wanted to square a couple of comments you made over the course of the call, Simon. Related to the Deepwater FIDs you would potentially take mid-year to before the end of the year, and contrasting that with the idea that you haven't really seen much in terms of savings on very specific Deepwater items. I would think Deepwater, in general, other than rig rates, what's the advantage in moving forward with those FIDs this year rather than waiting and seeing what happens from a deflation standpoint? Then just within the context of that question, are you able to move forward with the Bonga Southwest FID given the uncertain status of the PIB in Nigeria?
Good questions. Important, though. Basically, it's four big decisions, Appomattox, Vito, Bonga, and Libra. At one point, all four of them could have been 2015 decisions. Libra is just the first FPSO, of course. Appomattox has license conditions where we do need to reach a decision on how to develop during 2016. The good news is it's a very significant discovery, 700 million-800 million barrels. We own 80%. It's a new play. It's got still further exploration potential around it. In resource terms and potential value, it is the right one to be first. We went into FEED just about a year ago, and there has been a significant focus in that process on taking costs out, particularly around the drilling program, which is close to half of the total spend. That comes up for decision in a few months' time.
Vito, we are exploring around it. We've had success. It may end up being bigger than we expected. Great opportunity to do precisely what you said, although our original intent was to make the most of two projects and take synergies from the standardization and the bulk buy opportunity, two for the price of one. Bonga Southwest, we have been out to tender. We don't like the costs on some of the responses we've had. There are ultimately quite a few moving parts, one of which will be re-tendering some of the elements of the project. The government, there has been an election. We're very pleased to see the peaceful handover of power. The new government hasn't actually taken their seats until the end of May. This project has many partners. We will be the operator, but it includes almost all our large competitors.
There are some complexities in getting everybody to support a project. I can't say anything about the PIB. We will look for some stability in the fiscal framework if we're going to take a decision of this magnitude, and that obviously will need the new government to play their part as well. In practice, that decision is moving backward. In Libra, we are going ahead. The original plan, obviously, there is new Petrobras management in place, but that plan was to look to place the order for the first FPSO, take the investment decision by the end of this year, give or take. That's still the expectation. That's very much in the hands of Petrobras, which, as you probably realize, is under new management. There could be some movement there.
All of these projects, other than Appo, will benefit from the suggestion that you make as to just bide your time and take the costs at the right point in the cycle. Appomattox is probably the most attractive project amongst them anyway. Hopefully that gives the perspective. Move on to the next question, please.
Thank you. The next question is from Anish Kapadia from TPH. Please go ahead.
Good afternoon. A couple questions from me. On the BG deal, going back to that, it sounds like you see completion risk as relatively low. If this is the case, I was just wondering, given BG shares are trading at currently 11% discount to fair value, why not buy the BG shares in the market? Or are you waiting to get more certainty on the deal? The second question is, just more generally on Nigeria, you've had a pretty significant change in regime over there. Just wondering how that is expected to impact various things such as the onshore asset sale process, some of the gas projects you've got in place, and future investment decisions in Nigeria. Thank you.
Thanks, Anish. I'll take the first and maybe Ben can think about the second because it's very important countries for us remain so even post-divestment. The simple answer to the first one, ultimately, having made the offer, we're not really allowed to buy any stock at anything less than the offer we've made. It's not an option open to us. Clearly, the merger arb funds are playing a part at the moment, and if you assume that they typically look for a 10% return over an annualized basis, that we've said it could take up to a year to complete, that there are dividend differentials in between, the difference is reasonably easy to explain. It's not a concern to us. Yes, I can confirm that there are no prima facie reasons why we should not complete. We know the regulatory processes.
We're just probably testing the edge in terms of scale and scope of the couple of the countries such as Brazil and China. Ben, Nigeria.
Nigeria. First of all, let me also add my very positive reaction to the fact that the transition so far has been very peaceful and without disruption or security or safety risk to Nigerians in general, and also not our operations and people in country. Of course, Nigeria remains a very important country for us in many ways. It is a huge resource base. It's also a very significant resource base where we can get access to in terms of gas, in terms of the integration into LNG and in terms of deep water, Bonga Southwest being just one of a number of very attractive opportunities for us there. We will continue to take a look at Nigeria with a view that we want to invest there.
We have been, as you know, on a journey to gradually reduce our exposure to onshore oil, where we see the risk-reward balance not being appropriate. It would be completely different, of course, for onshore gas for domestic purposes, onshore gas into LNG, which has been a very robust and successful business, and as I said, deep water in Nigeria. All these businesses have been robust in terms of returns, have been also quite resilient despite the challenges that quite often are attributed to Nigeria, and are fundamentally very attractive. Of course, we will take a view generally on all the aspects of country risk like we do for many countries, for that matter, also the Netherlands and the U.K. Don't think for a moment that Nigeria is just out there in a special category.
We will look to take our decisions in the context of a good appreciation of that risk and an adequate reward for it. I think that is going to be available in Nigeria going forward, certainly given the prospectivity of the country.
Thanks, Ben. Next question, please.
Thank you. The next question is from Rob West, from Redburn. Please go ahead.
Hi there. Thanks very much. My first question, if I can, is on the integrated gas business. I'm really trying to get a sense of the moving parts there. You've gone from, I think, $3.2 billion contribution to earnings in 1Q 2014 to that $1.2 billion this quarter. Clearly, you had one of the two trains offline for most of the quarter at Pearl and some of the impact of lower gas prices coming through. I know sort of getting more detail on Qatari tax exposure is the chance of that as tight as an unfractured shale reservoir. Anything you can say around that, I'd be interested in sort of the trajectory of where that's going as Pearl comes back and the extra gas lag flows through. Secondly, on Brazil.
I think that's clearly one of the best assets in the whole industry that you've just gotten exposure to from BG Group below the ground. Petrobras has had some challenges with balance sheet and financing, where you look really good. In terms of increasing exposure there, what are your options to accelerate value creation? Is there anything you're looking at in terms of extra ways to help make sure the right amount of investment goes into those assets? Thanks very much.
Thanks, Rob. I'll take the first one, unless Ben, do you want to comment on the second one on Brazil? Again, that's got quite a strategic element to it. The integrated gas business is relatively simple. There are three elements around half a billion, $500 million each. The first is the tax move in Australia, second is the gas to liquids turnaround, and the third is the LNG trading business relative to the spot prices we were seeing last year of $20. You're talking single digit this year, of course. The rest is just pure LNG pricing across all of the different activities we have. Those numbers are very much rounded and approximate, but that's the basic step down year-over-year. Of course, the AUD 500 million Australian, I could claim it's a one-off. It's actually happened three times now to us in the past three quarters.
It's entirely driven by the FX rate. Ben, Brazil.
Yeah. Thanks, Rob. Brazil, indeed. You are absolutely right. It is a very strong asset. We, of course, hope to and expect to make the most of it. I am also very much aware of the Petrobras challenges, but as I said earlier on, I am also confident that Petrobras, which is after all, a very competent organization on many fronts will be emerging from this as a stronger company as well. Having said that, you are absolutely right also that they have announced a significant divestment program, which is going to spread across the upstream, downstream, and midstream. We will be looking at what comes out of that. If you look at the exposure that the combined company will have by the end of the decade to Brazil, it is going to be, of course, significantly higher than what we have today.
In my mind, it is going to be low enough for us to have appetite for more, especially considering, again, the tremendous attractiveness that sits in that resource base. If indeed things were to be offered up in the pre-salt, in areas that we understand, we would look at it with keen interest. Of course, it would have to be of the right value for us to consider it.
Okay. Thanks, Ben. Next question, please.
The next question is from Bertrand Hodee from Raymond James. Please go ahead.
Hi, Simon. Hi, Ben. Just two quick questions coming back on your potential final investment decision in 2015, in deep water on Appomattox. Looking at the development cost in deep offshore, over the last 12, 18 months, when we look at the kind of development cost project has been launched, it was in the range of $25-$30 a barrel. My view is that it's clearly not compatible with creating value at around $70 a barrel. What will be the criteria you will use to test and launch a project like Appomattox? The second question on Appomattox. Simon, I understand you referred to a deadline in 2016. If you don't take a final investment decision on Appomattox, you will have to relinquish the block. Is that correct?
Thanks for the question. The simple answer on the second one is probably. These things are always negotiable, but the aim is to take our decision, and we're well in place to do so. What would drive the decision criteria? Obviously, unit development cost is one of those because it impacts the return. Fundamentally, it's returns, net present value, and confidence that we can deliver, because there is always some level of uncertainty, both in construction, but also subsurface. The Appomattox is relatively unique because it's a new play in the Eastern Gulf. It is, at the moment, Shell's only company really drilling there, but there's more exploration potential as well. We will need to look at pipelines to shore or evacuation routes as well.
Having constructed the ability to make more from the first hub in any given area, particularly if you have developed the infrastructure, is well established. It's been the core of our development of value in areas from Mars B through to the recent Perdido development. It is how fundamentally you make good returns on your first investment, but excellent returns on all the follow-up. Appomattox is very well-placed to be a good project at the first investment decision, but to be a hub to capture value for many years to come. In totality, it's most likely to make the cut in return terms and affordability. We have one more. One more question. Final question. Please, operator.
Thank you. We will now take the last question from Sam Margolin from Cowen and Company. Please go ahead.
Thank you and good morning. Ben, just wanted to come back to your comments on Brazil. Brazil has always offered very good promise, but operational reality has always been different. Two questions for you, if I may. Based on your recent visit, what did you see or hear that makes you incrementally more positive? Second, as investors, what should we be focused on to figure out if things are really getting better? Are we looking at local content policy issues, supply chain issues, pre-salt policy changes? What should we be looking at? Thank you.
Okay. Thanks, Sam. Yeah, you're absolutely right. Brazil is a country with a lot of promise. I'm sure that as investors, you will look at it in a mixed way as well. I think for us, it has worked actually very well. Brazil has been, for the investments that we have made there, including the downstream assets, of course, has been a very very good country. The only thing wrong in my mind with Brazil was that it was just too small, and that we needed to have more exposure to it. Now, can we be more positive about what is going to come? I'd be a bit hesitant to comment on that.
It's always tempting to think that, of course, with the stresses that Petrobras may be under financially, the opportunities that may be there from divestments, the need and desire from the government and Petrobras to be very successful in the pre-salt. Maybe the realization that local content policy is also giving inefficiencies and constraints. It's very, very tempting to just look at it and say, well, surely opportunities must come from that. Again, let me just say that they have not been factored in to the way we have valued the BG assets there. If anything, and that is just nothing more than an observation and a single data point. Yeah, I've come away from Brazil remaining optimistic in all these areas. Again, it's not factored in. If it comes, it will be upside.
I do believe, and this is also why this is a shaping move for us. We will be, if the deal indeed closes, we will be fantastically well-positioned for whatever opportunity that will come our way in Brazil.
Okay. Thank you very much. I think that concludes the call today. Thanks for joining and sharing the event with me. Second quarter results scheduled to be announced on the 30th July 2015 , Ben and I will be back to talk to you again then. Thank you and have a good day.
This concludes the Royal Dutch Shell quarter one results announcement call. Thank you for participating.