Welcome to the BP Presentation to the Financial Community Webcast and Conference Call. I will now hand over to Craig Marshall, Head of Investor Relations.
Welcome to BP's Q1 2018 results presentation. I'm Craig Marshall, BP's Group Head of Investor Relations, and I'm here today with our Chief Financial Officer, Brian Gilvari. Before we begin, I'd like to draw your attention to our cautionary statement. During today's presentation, we will make forward looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our U.
K. And SEC filings. Please refer to our Annual Report, Stock Exchange Announcement and SEC filings for more details. These documents are available on our website. Now over to Brian.
Thanks, Craig, and thank you to everyone for joining us today. Before we begin, let me take a moment to comment on the updated format of today's presentation. This time last year, we introduced a new SEA, which was designed to provide a simplified approach to ensuring key information was presented to you and the investment community in a user friendly format. Consistent with those changes, we have updated our results presentation to provide a succinct strategically focused set of quarterly materials that underpin delivery of our medium and long term targets set out over a year ago. The supplementary materials contain further disclosures, which together with our SEA provide all of the usual material around our quarterly results.
So starting with highlights of the Q1, Following a year of strong delivery and growth in 2017, we have had a good start to this year. Underlying profit for the Q1 of $2,600,000,000 grew by 23% relative to the previous quarter and 71% versus the same quarter last year, making this the strongest quarter for 3 years. In the upstream, we delivered 14% growth in underlying production relative to the same quarter last year. This growth coupled with the stronger oil price environment enabled us to deliver upstream underlying pre tax earnings of $3,200,000,000 our best result since the Q3 of 2014 when oil prices were over $100 a barrel. Our downstream delivered underlying pre tax earnings of $1,800,000,000 this quarter benefiting from the continuing high availability across our North American refining systems, which enabled us to capture wider light heavy crude discounts for available heavy crude out of Canada.
We also continue with our share buyback program through the quarter. Since we started the buyback program in the Q4 of 2017, we have bought back 69,000,000 shares at a total cost of $460,000,000 This quarter, we also published the annual update of our energy outlook, the second technology outlook and most recently our reporting on advancing the energy transition. This report lays out our reduce, improve, create framework, setting out short- to medium term measurable emissions targets as well as our approach to creating low carbon business opportunities where we see potential. In summary, it has been another busy quarter of continuing development and delivery across the businesses. Now before turning to results, we'll take you through our view of the environment.
Brent crude averaged $67 per barrel in the Q1 of 2018 versus $61 per barrel in the Q4 of 2017. This reflected continued robust global demand growth building on the 1,700,000 barrels per day growth in 2017, a high level of compliance with the supply cuts targeted by OPEC and participating countries and geopolitical concerns about future supply disruptions. U. S. Henry Hub gas prices spiked briefly in January in response to extreme cold weather.
The price moderated in February with warmer weather and increased U. S. Production averaging $3 per 1,000,000 British thermal units for the quarter. BP's global refining market margin averaged $11.70 per barrel in the Q1 of 2018, down from the Q4 of 2017, but flat compared with a year ago. Looking to the rest of the year, we expect the Brent oil price to be influenced by the degree of continued production discipline from OPEC and other participating countries, the pace of U.
S. Lower forty eight supply growth and global demand strength. There remain significant uncertainties including geopolitical risks and the possibility of further guidance from OPEC as OECD commercial stocks near their 5 year rolling average. Looking now at the Group results for the Q1. BP's 1st quarter underlying replacement cost profit increased to $2,600,000,000 compared with $1,500,000,000 a year ago and $2,100,000,000 in the Q4 of 2017.
Compared to a year ago, the result benefits from higher liquids and gas realizations coupled with continued underlying performance delivery across the business. In the upstream, we saw production increase as a result of the ramp up of the 7 major projects that started up in 2017 and continued strong performance from the base. In the Downstream, we also saw benefits from increased commercial optimization and higher Canadian heavy crude oil discounts. Compared to the Q4 of 2017, the improvement in earnings reflects higher liquids and gas realizations and high production in the upstream. In the downstream, lower industry refining margins were more than offset by the benefit from higher Canadian heavy crude oil discounts, lower costs and a lower level of turnaround activity.
The Group results also reflects a higher overall trading contribution this quarter. The Q1 dividend payable in the Q2 of 2018 remains unchanged at $0.10
per ordinary
share. Turning to cash flow and our sources and uses of cash in the Q1. Excluding oil spill related outgoings, underlying operating cash flow was $5,400,000,000 This included a working capital build of $1,700,000,000 driven by the increasing oil price and normal seasonal builds across our businesses. Organic capital expenditure was $3,500,000,000 for the quarter. Divestment proceeds totaled $200,000,000 and we made Gulf of Mexico oil spill payments of $1,600,000,000 including $1,200,000,000 relating to the final Department of Justice 2012 settlement agreement.
These payments along with the seasonal working capital build saw quarter end net debt of $40,000,000,000 and gearing at 28.1 percent within our 20% to 30% band. As mentioned, we remain active in our share buyback program and bought back 18,000,000 shares through the quarter at a cost of $120,000,000 While the shape of the program will vary from quarter to quarter, we continue to buy back shares to fully offset the dilution impact of the scrip dividend issued over the year. Across our operations, we continue to make good progress. 2 weeks ago, we announced a new strategic alliance with Petrobras with a commitment to work together in Brazil on a range of opportunities across our whole business. In the upstream, our focus on execution is delivering improved performance.
Plan reliability in our operations was a record 96 percent in the Q1. This helped us deliver an operating efficiency of 86%, a 2% improvement on our previous best. In February, we announced the successful startup of the Atoll gas field in Egypt ahead of schedule and under budget. This gas project was brought on stream less than 33 months after the initial exploration discovery. We've also taken final investment decisions or FIDs on the development of Gezir, the second phase of a giant Kazan gas field in Oman, KGD-six satellites, the 2nd project in the integrated KGD-six development in India and Allergan and Voilik, 2 new U.
K. North Sea Subsea Field developments. In the Downstream, we've continued to make good strategic progress leveraging our strong brands and quality portfolio. In retail, premium fuel volumes grew by 5% compared with last year and we continued the rollout of our convenience partnership model across our network. We also celebrated our 1st year of operations in Mexico where average fuel volumes per site have increased by over 60% and we recently opened our 200th site.
At our Whiting Refinery in the United States, we processed over 10% more heavy crude than a year ago, partially capturing the higher light heavy discounts. And in petrochemicals, we achieved a new production record at our PTA plant in Zhuhai, China. We have also continued with the development of our alternative energy business with the recent creation of a new Indian joint venture between LightSource BP and Everstone Capital to create EverSource Capital. This partnership provides us with an interest in an innovative fund management platform for low carbon infrastructure projects in India, which we see as a market with huge demand and potential. Before I summarize, I'd like to take a moment to talk about our 2018 guidance.
In the second quarter, we expect upstream reported production to be lower than the Q1 due to the expiration of the Abu Dhabi, ADMA Offshore Concession and seasonal turnaround and maintenance activities. In the Downstream, we expect seasonally higher industry refining margins and narrowing of the discount for North American heavy crude oil and a significantly higher level of turnaround activity. Our full year 2018 guidance remains unchanged from what we laid out in February. We expect upstream underlying production to be higher than 2017, driven by the continued ramp up of the 2017 major projects as well as the 6 major project startups in 2018. Actual reported production will depend on divestments, OPEC quotas and entitlement impacts.
The total DD and A charge is expected to be higher than 2017, reflecting the growth in upstream production volumes and the major project startups. We expect organic capital expenditure to be in the range of $15,000,000,000 to $16,000,000,000 at the lower end of our medium term $15,000,000,000 to $17,000,000,000 frame, reflecting the continuing focus on disciplined spend. In other business and corporate, the average underlying quarterly charge is expected to be around $350,000,000 although this may fluctuate between individual quarters. In the current environment, the underlying effective tax rate is expected to be above 40%. Our balance sheet remains robust and we continue to target a gearing band of 20% to 30%.
With operating cash flow continuing to grow within our frame and Gulf of Mexico oil spill payments reducing, we expect gearing to trend down through the rest of the year. So in summary, we've had a good start to the year with the financial and operational momentum from 2017 continuing into 20 18. We will maintain our disciplined capital frame, focused on delivering against our operational and strategic targets across our upstream, downstream and low carbon businesses. With growing operating cash flow, we continue to expect the organic breakeven for the group to average around $50 per barrel on a full dividend basis in 2018, reducing steadily to $35 to $40 per barrel by 2021, in line with growing free cash flow. And as we look beyond 2018, we continue to expect to grow returns as we grow our earnings within our disciplined investment framework.
While we still have some way to go on returns, we are seeing good progress on the underpinning drivers of improvement. With the continued momentum across the businesses and growing free cash flow, we remain active in our share buyback program. With gearing expected to trend down this year, we will continue to ensure the right balance between distributions and disciplined investment. Thank you for listening and I'd like to hand over
questions to no more than 2? That will help us manage the time and also ensure everyone has the opportunity to ask a question. IR is obviously available after the call to follow-up on anything else. First question then from Biraj Borkhataria from RBC. Biraj?
Hi, thanks for taking my questions. I've got hopefully 2 easy ones. But firstly, could you just give us an update on the Woolworths acquisition and where you are on that process? And then secondly, could you let us know if you have any significant maintenance at Whiting this year? Thanks.
Thanks Biraj. On Woolworths, there isn't really an awful lot we can say other than the fact that we are in conversations with them and the regulator in Australia around potential remedies and the way forward. So I think there'll be more to follow on that this year. But in terms of on the assumption that that transaction may or may not close, it's more likely to be towards the end of the year before anything happens. And indeed, I suspect there's any cash impact of that, it's more likely to be maybe into the Q1 of next year.
But we're working through that right now. And it's a little bit premature to say anything about where we end up to with that transaction. On maintenance schedules around Whiting, nothing out of the ordinary. I think we went through a large one last year at Whiting around the cokers, but there's nothing out of the ordinary planned for this year.
Great. It's very helpful. Thanks.
Okay. We'll take the next question from Oz Clint at Bernstein.
Great. Thank you, Brian. Good morning. I wanted to ask a yes, somewhere around the quarter, the upstream OpEx upstream unit OpEx number picking up a little bit in the Q1, a little bit bucking the trend of the broader industry. Could you talk about that number and why you expect it to continue to decrease through 2018, please?
And then secondly, just on refining in North America, again, I wonder if you could potentially say what type of contribution may have been delivered there from those wider differentials in Q1 around Whiting because you talk about it diminishing as you go into the second quarter. Any sort of additional granularity around that would kind of be useful, please? Thank you.
Thanks, Oswald. The little ramp up that you saw in 1Q was really around some Gulf of Mexico workovers and well work that we were doing. So we would expect to see that continue on the trend that we've seen. We are acutely sensitized to any signs of inflation at the moment, but we're not seeing any of that come through, certainly not in the contracts that we're looking at the moment. So it's one of the areas that we focus on just to make sure that as we see these higher prices that we start to see inflation creep back in and that doesn't appear to be the case at the moment across the pieces we look to look at our contracts for this year.
But that uptick in 1Q was purely driven by gone well work. Would expect that now to start to taper off through the rest of the year in terms of the costs that you saw coming through in the Q1. And then in terms of North America, of course, refining margins were relatively suppressed in the Q1 compared to a year ago. But of course, the light heavy diff is what really sort of uplifted what in terms of the refining system in North America, particularly Whiting Refinery. We weren't able to capture all of that because of curtailment issues and the light heavy spread opened up off the back of a tranche of production that came on in the Canadian heavy market.
And then of course curtailment issues that began to get constrained coming in. So we were not able to capture all of the volume at that heavier discount, but we certainly caught a fair proportion of that and that's what helped support the downstream numbers through the Q1.
Okay. Very good. Thank you.
Okay. We'll take the next question from Lydia Rainforth at Barclays. Lydia, I gather you're in Calgary.
Thanks, Greg. That's right. And good morning. A couple of questions. So just in terms of the share buyback, Brian, and we were running it below that level and I know that's going to be linked to the net debt side.
But as you go through the year and given where oil prices are, that balance between debt repayment and share buyback, can you just talk about how you see that coming through? And then just secondly, in terms of the upstream production numbers, they clearly have been very good. Is that are we seeing sort of again that benefits of low decline rates coming through? Thanks.
So on the first question, I think we laid out with the Q3 results last year, we talked about reinitiating the share buyback to offset the script. We knew that we'd have a lumpy series of quarters ahead of us, particularly the Q1. So what you'll have seen in the Q4, we fully offset the scrip dilution from the Q3 of last year. We've partially offset it through the Q1 this year knowing that we had the $1,200,000,000 cash payment that went as part of the final DOJ settlement from 2012. So we were going to back off a little bit to the Q1.
Now we've got through that hump, if you like, in the Q1 of those payments associated with that settlement and the usual Macondo payments that are going out, we'll start to ramp the buyback program back up again. And again, as we've said before, over time, we'll expect to fully offset the scrip dilution and we'll certainly start to ramp that activity up and you'll see that this week as we go back into the buyback market. But it was really a function of knowing debt would rise through the Q1 with those payments and a typical seasonal build. What we will now see is net debt, certainly at these prices, net debt will naturally start to decline. And then that will then give us an opportunity later this year to look at potential further distributions either through buybacks or a conversation with the board around dividend.
And then on production?
On production, I think what you're seeing is A, definitely in terms of the base, we're still seeing strong performance coming out of the base. This what we talked about before about negative decline. I think that's becoming more systematic in our numbers, but we'll know more about that as we get through this year. And the projects coming on early and ahead of budget last year has helped, the ramp up of those projects has gone well coming into this year. And that's why you're seeing actually headline production was up 9%, but underlying production was up 14%.
And I think it's just a function of the performance of the projects coming on, the execution of those. We've brought on our first project already this year in Egypt in January. We'll look to ramp up the other 5 projects, those other 5 projects will come on later on this year. But it really is, it's a function of the 2 things, ramp up the projects from last year and continuing strong performance at the base.
Okay. We'll take the next question from Alastair Syme with Citi. Alastair?
Yes. Thanks, Craig. Good morning, Brian. Can you just I mean, you just recently sanctioned the Kazan Phase 2 project. Can you offer any perspective of around how we should think about the economics of that compared to Phase 1?
Any sort of high level comments you want to
make? I think from memory I recall, I think there's a 3rd gas train, a second liquids train will come with that project. And we can't talk commercially about the nature of the contracts. But again, it's the gas will go into a domestic gas market. And in that respect, the economics are attractive, robust within terms of what we look at and especially given what we've learned from Kazan Phase 1, the optimization that we're able to do around that, it gives us great optimism around what Kazan Phase 2 might look like.
And it's basically a development that I think is around 4 discoveries and we'll be able to utilize the existing facilities. So from a cost perspective, that enhances the economics. But there'll be more to follow on that as we go through this year.
Okay. Thank you. Can I
follow-up also on Tortue, which is that I guess the next sanction on the pipeline? What needs to happen for that to move forward?
We're right in conversations right now with our partners and with the local government concerned around Mauritania and Senegal. And again, really not a lot to say about that other than the fact there'll be more to come this year in terms of what the Phase 1 looks like of that development. I suspect Phase 1 may look very different to what the subsequent phases then look like. But we will be looking to move this one forward this year. But we're still in the discussions with our partners around what the final concept will look like.
Okay. We'll take the next question from Teepan Jocellingham at Exane BNP. Teepan.
Yes. Hi. Good morning, gentlemen. A couple of questions. Brian, you touched on the performance of the kit and the growth.
I was just wondering if you could maybe quantify how much of the new projects has been sort of installed out of the 900,000 for the 5 year plan? And what production is actually delivering as of end of Q1? The second question was just on the strategic alliance with Petrobras. I think a number of your peers have had similar alliances. And I was wondering is with the timing of this, is there something specific BP has identified that they can that you can execute with Petrobras?
And is that incorporated in the $15,000,000,000 to $16,000,000,000 of organic CapEx? Thank you.
So I'll pick up a second one. I'll ask Craig. Craig will come back on the production numbers in the first question, which he's got there in front of him. On Petrobras, we actually had a meeting of cross sections of our executive team 2 or 3 weeks back actually and found that there's a big overlap with the DNA. First of all, Petrobras is a world class operator.
There's no doubt about that. And I think we found that across a whole range of subjects from technology to sharing people and knowledge transfer, there is clearly a lot of opportunities. And I think you'll see some of those unfold as the year progresses. And actually from our perspective, it's a classic that we talked before about what's really important, what's the differentiator for all of us. It's about technology and it's about relationships.
And it was clear that there was a huge amount of empathy between the two teams, which led to the signing of that MOU. And I think there'll be simply more to follow on that as this year progresses. So nothing specific today, but as we explore different opportunities, you'll see more come to the fore a point forward basis. On production, Craig?
Yes, on production, Teepan, we laid out as you'll remember earlier this year in February, the 900,000 barrels a day by 2021 of major project production. If you recollect the chart we showed you, it does actually break down into the production that's operating, the production that's under construction and then that production element towards the back end that is yet to be FID ed. In short, based on those wedges, we'll approach this year around 400,000 barrels a day of that 900 on stream. And then obviously, as we start up the rest of the major projects, they're in construction with Atoll, obviously, already haven't started up that production will ramp up through next year and beyond. Okay.
We'll take the next question from Thomas Adolff at Credit Suisse. Thomas?
Hey, thank you. I've got two questions, please. Firstly, on the upstream. Obviously, one of the 6 major projects have been brought on stream and again ahead of schedule and below budget. So I wondered if you can talk about the other 5 projects where they are and whether the better performance is reflected in your cash flow breakeven estimate for the group.
Secondly, just on technology and obviously you talk about technology creating efficiencies, but obviously efficiencies also create redundancies. And I wanted to focus on the latter. 2014. Now it's down to around 18,000 employees in Upstream. And I just wondered how much more fat there is within the organization in terms of people or organizational layers, etcetera.
Thank you.
Okay. So on the first one, the other 6 projects which we've laid out for you in the supplemental information and we've talked about in previous discussions, we've got the big one of Shaktani Phase 2 comes on stream this year, which we'll start to see some commercial projects flow into Turkey. Ultimately, that will take gas into Europe. So that's an incredibly strategic and important project, certainly for Europe in terms of how that gas will flow and the various pipelines that we have in place and the construction of those pipelines. But Shack Deniz Phase 2 this year, that's 99% complete with an expected start up through the year.
We also have Constellation, which is non operated in the Gulf of Mexico, where we have a 2 thirds working interest. And again, that's expected to start up this year. That's a tie back to one of our other discoveries with our partners there. West Nile Delta this year is another project. We have Taz in Russia.
And then of course, Claire Ridge, which is a big North Sea project where we'd expect to see start up this year. So they're all progressing well. A lot of completion as you said already our towers come on stream. And all of those things will help overall in terms of production that drives our breakeven price down to about $35 to $40 a barrel by 2021 as a function of the surplus cash that we then see. And then in terms of technology, what we're seeing now is there is no question, I mean, I'd have said 3 or 4 years ago, we were scratching the surface.
We're now deep into the surface of technology and what we're learning in terms of productivity and use of people. I think what you're going to see Thomas is first of all, we'll continue to keep our focus on costs. We have a strict capital discipline in terms of $15,000,000,000 to $17,000,000,000 And if anything, this year we're trending towards the lower end of that range, although we've set the range this year at $15,000,000 to $16,000,000 With the Q1 CapEx numbers, it looks like we're certainly we'd set things up at sort of mid part of the range, but we're drifting towards the bottom end of that range at the moment. We'll continue to keep a focus on costs. But I think what you're now seeing with the technology is we're getting more productive use of time for the people that we have and we now have the alternatives to redeploy people within the organization on more productive roles given that they're now getting access to real time data in any number of different applications, not just in the upstream, but in the downstream in our trading businesses and across the piece.
And I just think the whole world of digitization is moving at such a rate of knots and the cadre of people that we're now hiring is showing us how we can exploit that technology and put it to good purpose and good use that ultimately helps enhance revenues. So yes, there may be more efficiencies to come in terms of our workforces, but it will be really about how we redeploy people into more productive roles within the company as we use more and more types of technology that are coming through.
Great. Thank you very much.
Okay. Thanks, Thomas. Next question from Rob West at Redburn. Rob?
Hi there. Thank you. The oil price is high. As you said, CapEx is coming in below where you're guiding. What I wanted to ask you is, how does that change your willingness to flow extra capital into the U.
S. Shale business and unlock some of the value there? I noticed the CapEx is slowly going up in the detail you hopefully disclosed. But if you could talk about are there plans to add any more rigs in some of the sub basins? And I guess it's a year on from the last time you already updated us in detail on that business.
But is there any way that's looking particularly attractive to add any incremental rigs and volumes?
So Rob, yes, that's a great question. And low-forty eight is the one place where we can ramp up and ramp down. And of course, it's also a function of price. Our breakeven economics now are very, very low. In terms of cash breakeven, they are certainly close to $1 for some of the wells that we're looking at, dollars 1 a barrel on a cash breakeven basis.
We've got 12 operated rigs that we've been running through the Q1. Actually we had the team in last week Dave Law and the team were in last week. We were sort of going through that. I think we've got about half of those, just over half of those in Southern Haynesville, which has been incredibly productive for us. It's a choice and it's an it's something Bernard can do if he chooses to ramp that up.
Right now, we're still seeing some deflation come through in the capital numbers, which is why I say we sort of seem to be trending towards the lower end of that 15% to 16% Although I think somewhere in the midpoint is a good assumption for the year. But it's a choice for us in terms of Lower 48%. You have to remember we're very gassy portfolio that we have in Lower forty eight. It's about 85% gas, 15% liquids. And so it's really opportunity driven on a point forward basis, but it is the one place where you can ramp up and ramp down.
That's great. Thank you. Just to be clear, so would the extra rigs be Haynesville or some of the more emerging areas in the portfolio?
It's such a choice for Dave. I couldn't really sort of pick up the specifics here. Right now, I think it's just over 6 or 7 rigs we have in the Southern Haynesville, which has been quite a prospective area for us in terms of some of the things I've been doing with the multi fracs down there. So it's that's where they are at the moment. I don't know what the current plans are for the rest of the year.
All right, great. Thank you.
Okay. Thanks, Rob. We'll take the next question from Michele Della Vigna at Goldman Sachs. Michele?
Thank you very much and congratulations on the strong quarter. I was wondering if you could give us an update on your LNG strategy. You have clearly been very active with Tangu under development or to pre sanction, but also BP has been quite active in contracting new supply and effectively scaling up the marketing efforts. Secondly, I was wondering if you could quantify the economic impact of the expiry of the ADMA license, which has relatively large volumes, but pretty small margin? Thank you.
So on LNG, I think we've laid out before, Bernard has laid out and this is integrated with our trading business. So LNG, we see it as an integrated equity and marketing business, but we do have an ambition to expand its portfolio to up to 25,000,000 tonnes per annum. And that's from both a equity perspective and a merchant LNG. As you said, we've taken contracted volumes around the world. We'll continue to move forward on that.
We have the Freeport option to export gas out of the United States that comes up in the time window over the next 18 months. In terms of that investment, we have a fleet rejuvenation of our LNG fleet. We'll take that up to I think about 6 new vessels, 7 more of a total fleet of about 7 LNG vessels going forward. So we'll continue to ramp that activity up and I think it gives us a huge amount of opportunity. I think you're going to see quite a number of LNG projects come on to market out to 2022, if we look at the next big rafter projects.
So I'm not sure how much gas will ultimately get export out the United States, but we still have a very strong ambition in the LNG space. And in fact, actually, we had a good set of results in terms of the Q1 in terms of our gas marketing and LNG activity that you would have seen come through the numbers in the Q1. In terms of ADMA, I think it's 90,000 barrels a day, which someone's or yet about around 90,000 barrels a day that will back out net production as that concession rolls off going forward. And economically wise, it will won't have a huge impact in terms of the overall earnings given the nature of that contract, but that will roll off this year.
Thank you.
Okay. We'll take the next question from Chris Coupland, Bank of America. Chris?
Hello. Thank you. Brian, just quick two questions. Firstly, I think you didn't fully answer Teapan's earlier question around Brazil. Clearly, Bernard has been out there singing the praises of presold and its attractiveness.
And I suppose what Tifan was also asking is how you think you can fund exposure because an MoU so far is, I suppose, fairly cheap. But I wonder whether any additional activity together with Petrobras in the presold will happen within that €15,000,000,000 to €16,000,000,000 CapEx range? And secondly, just a quick follow-up on these strong trading results that you've highlighted also in your upstream division, whether you can give us a little more granularity as far as they are outside of your achieved oil and gas realizations? Thank you.
Yes. Sorry, Chris, and thank you for reminding me about T Pen's question because it did occur to me answering the question last but one that I hadn't picked it up. So we will continue to manage within the 15 to 17 frame. That is that's not negotiable. The upper end of that frame is very clear.
The lower end of that frame is flexible depending where the oil price is. Clearly, where oil prices are trading at the moment, I think it's unlikely we'll have excursions down to $45 a barrel at the moment. So therefore, $15 to $17 is a good frame going forward. For this year, dollars 15 to $16 is where we sit and we'll live within that frame. And I think if you link back, Chris, to the previous comments around where we're seeing deflation and CapEx trending to, we're trending towards the lower end of that range anyway.
And therefore, we'll have up to $2,000,000,000 of flexibility within the existing framework. So there's I don't think there's anything there that would constrain us going forward in terms of the opportunity set. And of course, every opportunity has to be weighed up against other opportunities that we have in the portfolio set. And I think you're right, Bernard is very strong on the pre salt in terms of Brazil and we'll see what comes out of that if there's any potential opportunities for us with Petrobras. But the 15% to 17% frame is clear and we'd be very clear about that in 2021.
And then sorry, Chris, your second question was?
On trading contribution.
Trading contribution. Yes, no, I think the way to describe it for this quarter, because we don't give you specific guidance, The oil trading was above average, but it was sort of around a plan type number for this quarter. And on the gas trading, it was a strong result, which means it's above average. And that would mean typically $100,000,000 or more over what would be in a typical trading quarter. That came out of North America Gas and Power.
It was as much out of that position and some of the LNG positions that we have, but it was a strong Q1 for them.
Okay. We'll take the next question from Jon Rigby at UBS.
Thank you. Hi, Brian. Couple of questions. But first, can we just go back to Whiting and maybe Toledo as well? Was Toledo also affected by apportionment of crude flows into it?
And then around that, I noticed that the sort of benchmark Midwest refining margins are sort of down, but spreads are up versus sequential earnings in 4Q. So are you able to sort of characterize net net the contribution from the Midwest refineries sequentially, so we can get an idea because a lot of moving parts. The second question is just on Deepwater Horizon. We're obviously another quarter into the payments. So I just wonder whether you can just offer some observations as you sort of triangulate on final settlements and outcomes, etcetera.
Thanks.
Yes. John, actually, I do know I've not gone into that level of detail around the Midwest. But knowing what I know about the contracts and the way we trade the crude out of Hardisty and some of the pipelines, I would suspect that Toledo would have been marginally impacted, but the bulk of the impact would have been Whiting. And so that's the conversations we've had with Tufan. I think the issue is really bound curtailment has been around Whiting, less so with Toledo given the way in which the pipeline system works coming into Toledo.
So, Toledo will have been impacted, but I think the majority of the impact would have been Whiting. And then in terms of where the spreads are at the moment, I think they're back down in the sort of $15 The spreads opened up off the back of the wager production we saw coming in out of Canada. The Canadians are now into those positions are now into turnaround. So we're seeing less of that exacerbation. So spreads have moved back into around I think $15,000,000 $16 which is a good place to be because that's effectively where we set the economics for the Whiting upgrade.
So I think $15 is a good place for it to go to settle. But with the curtailment issues, we were sourcing some heavy crude at differentials below that minus 15. But of course, we were also capturing the minus 25 on the barrels that we could actually access through Canada. And then in terms of Macondo, well, we had the big bullet payment, the final payment to do with the DOJ settlement of 2012, which is $1,200,000,000 that's now firmly closed. We of the 600 claims that were left inside Bell that led to that higher provision that we had to the 4th quarter activity, We're now down to I think 299 or 300 claims left to be resolved.
There are other claims still being recycled in the system that have been previously denied that will come through the usual appeals process. But I think we have a pretty strong handle now on what the payment schedule looks like. We have everything that was agreed in 2015 with the July 15 settlements. They will start to now kick into action in 2019. 2018 we had a rest in terms of a because of the big payment on DOJ there was a sort of a pause in 2018 on that schedule.
That schedule now kicks in next year with the remaining of the Bell piece where we took the extra provision at the end of last year. So I think the numbers for this year of just over 3,000,000,000 this year with 1,600,000,000 already gone out in the Q1. Next year around 2,000,000,000 may actually be it will be around 2,000,000,000 it could be less than 2,000,000,000, but let's say around 2,000,000,000 and then a 1,000,000,000 a year out to 2,032. But I think we're getting more confidence around what that looks like and the only uncertainty now is left 300 planes, which are left to resolve through the facility. And we have a process by which we are closing out the balance of those.
And as part of that process, payment schedules are being put in place that can go out to 5 to 10 years. So we have some flexibility around how the cash flow flow on that front.
Okay, great. Thank you.
Okay. Thanks, John. We'll take the next question from Irene Harmona at Societe Generale. Irene?
Thank you. Good morning, Brian. Two questions, please. Firstly, the start up of your 7 major projects last year is what is driving this very strong 14% production growth this quarter. Can you give us a sense of whether the 500,000 boed plateau of those projects has been reached?
Or when during the year it reaches that plateau roughly? And then secondly, obviously your upstream free cash flow targets are formulated at $55 real. We are now at $75 for the moment. Can you just talk a little bit about what would need to happen perhaps in terms of either the Board's thinking or balance sheet gearing for the decision to be taken to step up the dividend rather than devote the free cash flow to more buybacks? Thank you.
Yes. I'll take the second question and I'll ask Craig just to follow-up on his previous comments around the 400,000 barrels there and how that looks in terms of plateau. I think we knew this year would be another €3,000,000,000 of Macondo payments to go out that the first focus now well, the first priority was to offset the scrip. And so you'll see us do that this year and you'll start to see the buyback start to ramp back up again. Having got through that Q1 of those bigger payments around Macondo and the typical seasonal working capital build that you see at this time of the year just like last year.
Now as the year progresses, we'll let net debt and gearing come down naturally and there is no question the Board will want to have a conversation. And certainly we talk about it every quarter the dividend. And so I think we'll be talking more as we go towards the second half of this year. The Board will want to go into what would be the conditions that would set up a move on the dividend and how would that look versus buybacks? That will be something for the Board to consider.
I think as a backdrop, we'd like to sort of see net debt drift towards the middle of the band. But I mean, frankly, we've got a lot of capacity within that 20% to 30% band. Gearing is at 28% now, which really reflects the working capital build in the Macondo payments in the Q1 that will naturally come down. So I think as that starts to drop down and we'll that's going to be helped by somewhat by where the oil price is for now if it stays there. Then I think that will be a second half of this year conversation, but we'll pick it up at 2Q results and undoubtedly the Board will have a conversation around that.
Yes, Irene on the production, the 500,000 barrels a day from those projects, firstly, that's installed production capacity. Obviously, the projects run at assumed efficiency, operating efficiency. That said, I think as you go through 2018 certainly by the end of the year, we'll be up at around 500,000 barrels a day as regards to those projects.
Thanks very much.
Okay. We'll take the next question from Martin Ratz, Martin at Morgan Stanley.
Yes. Thanks. Like many of my questions have already been answered, but there's one that I was hoping you could still comment on. The 96% and the 86% on plant availability and overall operating efficiency, sort of new disclosure to get very specific numbers on this. Could you give us a bit of a feel for how these numbers have sort of behaved sort of historically?
You said that the 86% was 2 points up from the previous all time high. But when was that, for example? And how did these numbers do year over year? And what's the sort of historical band in which they have historically moved? And also where could you see those numbers still going going forward?
Yes. So Martin, thank you. That's a really good question actually. If you'll recall when we put out our new SCA last year, the Q1 of last year, we talked about plant reliability in terms of the 86%. And I think that's 2% higher than the previous high.
We also though in refining talk about availability, I. E. When is the plant available, when it was scheduled to be available with taking into account turnarounds. And so we put the upstream on the same basis this year just for consistency in our reporting. So but we report both numbers.
On the reliability measure, we have a long history track record of that. And I think what you're seeing come through that number, the 86% is the consistency of the projects that have come on stream and how they're performing in that 1st 6 months when they come on stream. But also the focus on the huge number of turnarounds we did in 2011, 2012, 2013, I think it was 48, 35 and somewhere around 27 the following year of turnarounds of kit focused on safety and ensuring that the integrity of the kit was safe. And of course, where the 2 things now come together is that stronger safer environment we have leads to better reliability. So we always talk about safety and operational liability being sort of 2 hands that go together.
And the track record basis at 86% is 2% above the high and that high I think was back in the Q1 of 2015 previous high was 84%. In fact, yes it was, 84% in the Q1 of 2015.
All right. As a brief follow-up, I recognize there was a risk, of course, that you give us one thing and then we always want the next one. But say that 86% goes to, I don't know, 88% or 90% or something along those lines, right? Is there a rule of thumb for every 1 or 2 points improvement? It has this impact on cost or earnings?
Or is there a way of sort of translating that into a financial number?
That's really hard, Martin, because it depends on where the production is coming from. If it's coming from a very high revenue cash flow per barrel stream, then obviously that gives you an enhancement. I think it'd be impossible to come up with a rule of thumb for that. Just by the diverse nature of the cash flows in the regions that we operate in.
Okay. We'll take the next question from Colin Smith at Panmure Gordon. Colin?
Yes. Good morning, guys. Two questions. First of all, just on the effective tax rate came in quite a bit below the guidance for the year. Just wonder if you could comment why that was and what happens?
What's the thinking about maintaining the 40% plus guidance for the balance of the year? And then just on CapEx, I'm curious to see that you included the extension payments in ACG within the inorganic number given how long you've been involved there. And I wonder if you could just talk a little bit about how you split inorganic versus organic CapEx because obviously things like that do at the end of the day represent cash out for investment.
Yes. Maybe from the first one on the second one Colin, the ACG is I think it was over 5 years. You'll see those payments coming through and that was an inorganic. That was the renewal that we did, I think, about 18 months ago, was the renewal of the ACG license. And so therefore, that wasn't inorganic and it's amortized over 5 years.
So the payment pops up in each of the 5 years after that.
Ultimately that I think my point was about why is that considered to be inorganic.
Yes, sorry Colin, I was just going to come to that. And that needs to be managed through the frame that says inorganics and Macondo payments are covered through disposals. And so ultimately, it's a reinvestment strategy. And because that was part of a renewal and a license extension, it was treated as inorganic, which just basically comes under our accounting rules of how we treat those investments. But ultimately it has to be paid for through further disposals over time.
On effective tax, is that okay, Colin?
Yes, that's right.
Okay, sorry. And then in terms of effective tax rate, it moves around every quarter. It's impossible to pinpoint it based on a single quarter. But based on everything we can say and all the inputs and outputs that we can see, we think above 40% is still good guidance for the year. This quarter it was down below 40% driven by deferred tax balances and forex movements and that will happen every quarter.
But as we look at the forward schedule of revenues and each of the regions that we're current looking forward to, of course, it's a function of where the revenues and profits arise. We think above 40% is still a good number for the year.
Thank you.
Okay. Penultimate question from Lucas Herman at Deutsche Bank. Lucas?
Thanks, Greg. Good morning, Brian. 2 if I might.
Brian, I just wonder
if you could comment on the rate of return, which you think you're recycling capital at at the moment. I know the objective is 15% to 20 percent leased Greenfield, Brownfield. But when I look at the projects that you've taken FID on this so far this year, the return profile looks, let's just say, it's markedly better than that in certain cases. And the second question was, apologies for asking this in part, mineral oil tax in Germany. Can you just explain the mechanics in terms of cash flows in and out slightly better?
I mean, I think our assumption is that the big payment that takes place in the Q4, one almost expects a reversal in the Q1 of this year. But just so I've got a better idea of how one should expect working capital, if that is working capital to move across Q4 and into Q1?
Yes. So I'll take mineral oil tax first because it's fairly straightforward. It all flows out at the end of the year. This year for 2017, the actual payment was 1,300,000,000 flowed out in the Q4. And then over the 1st 6 weeks of Q1 of this year, it all flows back in again.
And then the Q1, so you take effectively €1,300,000,000 add that to the €1,800,000,000 you'd see the working capital build of maybe instead of €3,000,000,000 which would be typical for this year, driven by price and volumes that are coming through. But you only see the net impact. Of course, you have that cash flow flowing back in, in the Q1. But again that will flow out at the end of this year. Again, it's typically in the range of 1.2 to 1.4, but for 4Q it's 1.3.
And then in terms of rate of return, I mean, I think you've heard Bernard and Tufan both talk about this. The typical projects we're looking at are mid teens internal rate of returns significantly above double digit percentages above our cost of capital. And we'll continue to do that. But what you see in the overall returns of our portfolio and of course it's not it's a portfolio. We look at the portfolio.
We look at strategically where we're looking to grow the
company and we'll make we'll will not necessarily be reflective of the whole portfolio that we're looking at. And typically mid teens, but we're also dealing with the $100 a barrel investments we had over 2010 to 2014 and it will take time for that DD and A to work its way through the system before you see us back up above 10% returns of the portfolio and ultimately back into the mid teens for the overall portfolio as we go forward.
Okay. Brian, thanks.
Okay. Thanks, Lucas. Right. We'll take the last question from Christian Malek at JPMorgan. Christian?
Hi, guys. Thanks for taking my questions. So I dialed on a slightly bit late, but this may have been addressed. But just around despite the CapEx run rate, I just want to understand better to what extent is capital efficiency, learning curve around new projects coming online. And you should talk about your leading edge focus on technology digitization.
How does that all unlock further deflation at the industrial project breakeven level? And could you quantify whether it's a few dollars or possibly more than that that we're looking for or solving for at sort of the industrial level?
That's a great question, Christian. It's really hard to quantify. So a lot of this is anecdotal or qualitative rather than quantitative. But there is no question now having established the technology platforms that we initiated 4 or 5 years ago with things like August and Apex, there is no question now that we are seeing some benefits of that. And that's why I say CapEx this year, we'd set a 15% to 16% within our 15% to 17% frame.
But we are undoubtedly moving towards the lower end of that range. And we and that's basically coming across the piece in the upstream in terms of technology and how that's helping us, enabling us to drive deflation, continue to drive deflation down in terms of numbers. And we're also seeing that in the downstream as well if you look at some of the things that we're deploying in a way of technology there. I mean, I think I said earlier on the very first part of the call that 4 years we were scratching the surface, we're deep into the surface now of technology digitization. And I think there'll be more to follow on that this year.
And I think at the midpoint, mid results this year at 2Q, we'll give you a lot more flavor about what we're actually starting to see now from the technology that we've deployed across the piece.
And then you just follow-up, I mean, you sort of obviously had a low sort of say low CapEx of 3,500,000,000. Were you surprised at that in terms of efficiencies driving a bit more of a delta that you're now starting to see that you plan for let's say CHF4 billion for the quarter and it came out of CHF3.5 billion. Is it right to frame it like that that you're actually surprising yourself the downside in terms of structural change more interactively?
No. I think we're seeing some deflation still come through, but actually 1Q tends to be a low quarter for capital anyway. So yes, I wouldn't take 3.5 times it by 4 and get to 14. That would probably be the wrong thing to do. 1Q tends to be a lower capital quarter.
But I think in terms of the upstream of what Bernard is seeing with his team, there is no question they continue to see some benefits of technology come through in those capital numbers. And like I say, we're going to give you a lot more detail on that as the year progresses.
Okay, very good. That's the end of the questions. I'll hand back to Brian for some final comments. Thank you.
Great. Thanks, Craig. So thank you for your patience and your time. I hope that the new format has resonated and we'll take some feedback from you in terms of how that has landed with you in terms of trying to understand the numbers. I think the way to catch this is we are now a quarter the way through the 5 year plan that we laid out for you back in February of last year.
We've got 5 quarters under our belt. I think that has built a huge amount of confidence for our team in terms of the trajectory of delivery. We're slightly ahead of where we thought we would be last year and that momentum has carried on into this year. And there is no question that the safe and reliable operations that underpin everything we do is now starting to flow through in terms of the quarter results. So with that, I thank you and I will look forward to speaking to you at 2Q where we should have Bob with us on that call.