Welcome to the BP Presentation to the Financial Community Webcast and Conference Call. I now hand over to Craig Marshall, Head of Investor Relations.
Welcome to BP's Q3 2018 results presentation. I'm Craig Marshall, BP's Head of Investor Relations. 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 UK 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. It has been another quarter of steady progress against the targets we laid out last year. The focus on safe and reliable operations and strategic delivery alongside an improving price environment has driven strong underlying earnings and operating cash flow. We'll start today with some comments on the macro environment before moving to highlights from the quarter and then covering our financial results in more detail. We'll then provide an update on our operational progress, including the status of our BHP transaction before finishing with a reminder of our financial frame and guidance for next quarter and the full year.
We'll then take time to answer your questions. Looking at the macro environment, with the oil market in a more balanced position, OECD commercial stocks have declined to below the 5 year rolling average. U. S. Crude and product stocks, which account for around 40% of total OECD inventory, have reduced significantly over the last year to the middle of the range.
With lower stock levels, the oil price remains volatile to any uncertainties, particularly around supply and geopolitics. Recent factors include the impact of U. S. Sanctions on Iranian exports, supply disruption from Venezuela, together with production uncertainty from Libya and levels of spur capacity within OPEC. In the U.
S, infrastructure constraints, particularly in the Permian have slowed tight oil growth. These uncertainties could persist well into the first half of next year, supporting wider Midland crude differentials. Similarly, pipeline and rail constraints affecting the movements of Canadian heavy crude between Alberta and the U. S. Are driving wider WTI WCS differentials, which are expected to be sustained over the coming months.
In gas markets, low levels of storage capacity in the U. S. Have driven Henry Hub prices closer to $3.30 for the first time in more than 6 months. In summary, the oil price outlook has strengthened. We expect the oil market to remain volatile in the near term, characterized by lower stock levels and ongoing geopolitical factors.
Looking further out, we expect current supply concerns to ease and continued robust demand growth to be matched by growth in the U. S. Tight oil production and additional supply from non OPEC countries. Turning now to highlights from the quarter. Underlying replacement cost profit for the 3rd quarter was $3,800,000,000 more than double that of a year earlier and 35% higher than last quarter in a very similar price environment.
This also drove strong underlying operating cash flow of $6,600,000,000 in the quarter, including a working capital build of $700,000,000 In the upstream, our continuing focus on safe and reliable operations saw underlying production increase 7% relative to the same quarter a year ago, driven by the ongoing ramp up of our major projects. Building operational momentum coupled with a stronger oil price delivered upstream underlying pre tax earnings of $4,000,000,000 in the quarter. We also expect another strong quarterly contribution through our shareholding in Rosneft with underlying post tax profit estimated at $900,000,000 The Downstream reported underlying pre tax earnings of $2,100,000,000 in the quarter. This reflected a stronger supply and trading result than last quarter and was further supported by high refining and petrochemical availability and retail performance. Looking further out, we remain focused on delivering our strategic plan and maintaining a strong and disciplined financial frame.
In the Upstream, we saw the recent start up of 2 further major projects in the Gulf of Mexico with the BP operated Thunder Horse Northwest expansion and on the Australian Northwest shelf with the start up of Western Flank B, both ahead of schedule and under budget. In the downstream, we continue with the growth of our retail convenience partnership model and have now rolled it out to around 1300 sites across our network. And as I'll discuss in a bit more detail shortly, we have made good progress towards completing the acquisition of BHP's Permian, Eagle Ford and Haynesville unconventional assets and expect to close the transaction tomorrow. As we approach the end of 2018, we have strong momentum across the business and are building a tangible track record of operational performance and strong financial results that underpin the delivery of our strategy. Now looking to prices during the Q3, Brent crude averaged CAD75 per barrel, similar to the 2nd quarter average of CAD74 per barrel.
Prices rose sharply through September, reflecting a reduction in Iranian exports and concern over the level of OPEC spur capacity. U. S. Henry Hub gas prices averaged $2.90 versus $2.80 in the 2nd quarter and BP's global refining marker margin averaged $14.70 per barrel, slightly below the average for the Q2 of $14.90 per barrel. Moving to our results.
BP's 3rd quarter underlying replacement cost profit increased to $3,800,000,000 compared to $1,900,000,000 a year ago and $2,800,000,000 in the Q2 of this year. Compared to a year ago, the result benefits from significantly higher upstream liquids and gas realizations, higher production from major project ramp ups and an increased contribution from Rosneft. In the downstream, the benefits of higher crude differentials are more than offset by lower industry refining margins and higher turnaround activity. Compared to the Q2, the result benefits from higher upstream liquids and gas realizations, a stronger supply and trading result and an increased contribution from Rosneft. It also benefits from strong operational performance in refining and petrochemicals, higher fuels marketing performance and a lower effective tax rate.
The 3rd quarter dividend payable in the 4th quarter remains unchanged at €0.125 per ordinary share. Turning to cash flow and our sources and uses of cash. Excluding all spill related outgoings, underlying operating cash flow was $19,000,000,000 for the 1st 9 months, of which $6,600,000,000 was generated in the 3rd quarter. This included a working capital build of $1,100,000,000 for the 1st 9 months, of which $700,000,000 was in the 3rd quarter. Organic capital expenditure was $3,700,000,000 in the 3rd quarter and $10,700,000,000 for the 1st 9 months of 2018.
Our organic free cash flow surplus was $3,000,000,000 in the 1st 9 months of 2018. Turning to inorganic cash flows. In the 1st 9 months of 2018, divestments and other proceeds totaled $400,000,000 We made post tax Gulf of Mexico payments of $2,900,000,000 and inorganic capital expenditure was $1,500,000,000 including an initial deposit paid to BHP of $525,000,000 And gearing at the end of the 3rd quarter was down to 27.5%. We have also remained active in our share buyback program and bought back 48,000,000 ordinary shares in the 1st 9 months of 2018 at a cost of $340,000,000 Now to operational delivery, where we continue to make good progress. In the upstream, our focus on quality execution is delivering strong operating performance with operated plant reliability at 96% so far this year.
We continue with the delivery of major projects, successfully starting up 2 most recent projects ahead of plan. The Thunder Horse Northwest Expansion Project in the Gulf of Mexico came online 4 months ahead of schedule and 15% under budget. The project, which achieved 1st oil 16 months after sanction, comprised of the new subsea manifold and 2 wells tied back to the existing Thunder Horse platform. This has brought forward valuable barrels and demonstrates our strategy in action of growing advantaged oil. The Western Flank B project in Australia came online under budget and well ahead of its scheduled 2019 start up.
The project consists of an 8 well subsea tieback to the existing Goodwin A platform. So far this year, we've delivered 5 major projects. Our remaining operated projects, Claire Ridge in the North Sea, which is in the final stages of commissioning and the next phase of West Nile Delta in Egypt remain on track for start up in the Q4. In September, BP accessed new acreage in the prolific Santos Basin offshore Brazil by winning the license for the Power Brazil block. This represents BP's 1st operator position in the Santos Basin.
In the Downstream, we continue to make good strategic progress. In manufacturing, Solomon refining availability for the quarter stood at more than 96%, the highest in 15 years. And petrochemicals earnings were the highest since Q3 2011. In fuels marketing, we continue to grow retail volumes and roll out our convenience partnership model, which is now in around 1300 sites across the network. In Mexico, we now have more than 370 BP branded sites.
And we continue to look for ways to provide lower carbon products to our customers and reduce emissions in our operations. The Air BP business recently entered into an innovative collaboration with Neste, a leading renewables products producer to secure and promote the supply of sustainable aviation fuel. And our Lingen refinery in Germany recorded a world first piloting the use of green hydrogen in the production of fuel. Before I turn to our guidance and outlook, let me take a few minutes to update you on the status of the BHP transaction announced on the 26 July. The acquisition of BHP's assets in the liquids rich Permian Delaware Basin and the 2 premium positions in the Eagle Ford and Haynesville Basin transforms our position as a Lower forty eight producer.
The transaction is expected to create significant value through the combination of a world class portfolio of oil and gas assets with BP's competitive Lower 48 operating model. Through the sources of value identified, this deal will be accretive to earnings and cash flow per share post integration. It is also leveraged to price upside, which we are benefiting from at the moment above the $55 per barrel WTI price assumption that underpinned the purchase price. Over the past couple of months, the team has been working closely with BHP and we expect to close the transaction tomorrow. On completion, we will make a cash payment of 50 percent of a $10,500,000,000 consideration, less the deposit of $525,000,000 paid in July and less customer re completion adjustments.
When this transaction was first announced, our intent was to fund the total consideration through a combination of cash and equity. The 50% cash payment was due on completion with the remainder deferred and payable over 6 equal monthly installments funded through the issuance of equity over the same period. An additional CAD 5,000,000,000 to CAD 6 dollars 1,000,000,000 of investments are expected to fund up to an equivalent level of share buybacks to offset the equity issuance. Since we announced the deal in July, oil prices have strengthened and our businesses have continued to deliver strong underlying cash flow within a disciplined capital frame. Our cash cover ratios also remain strong.
Our cash cover ratios also remain strong. Taken together and assuming oil prices stay firm around today's levels, we would now expect to finance the remaining deferred installments using available cash. This simplifies the transaction removing the equity issuance and the related dilution and friction costs that would have arisen. In this case, proceeds from the additional $5,000,000,000 to $6,000,000,000 divestment program will be used to reduce debt given we would no longer be issuing equity. Our commitment to fully accommodate this transaction within our existing financial framework remains unchanged.
A full cash transaction may move gearing to the top end of and potentially temporarily above our 20% to 30% band in early 2019. We would then expect gearing to move back down towards the middle of the BAM by the end of 2019, in line with the generation of free cash flow and receipt of disposal proceeds. We will continue to focus our existing share buyback program on offsetting dilution from the scrip dividend over time. As stated when we restarted this program at the end of 20 17, the pace and shape of these buybacks will reflect the ongoing judgment around several factors and may not necessarily match the dilution on a quarterly basis. However, assuming the BHP transaction is funded using cash, we would now expect to fully offset the impact of scrip dilution since Q3 of 2017 by the end of next year.
We continue to expect to accommodate the acquisition within our medium term organic capital frame of $15,000,000,000 to $17,000,000,000 and our guidance on returns remain unchanged. Before I summarize and as we look ahead, let me remind you of our guidance for the full year and the Q4. For the full year, we expect organic capital expenditure to be around $15,000,000,000 Divestment and other proceeds in 2018 are expected to be over $3,000,000,000 As noted in the Q2, this excludes proceeds from the divestment package we announced with the BHP transaction. The total DD and A charge is now expected to be around the same level as 2017. Gulf of Mexico $3,000,000,000 for the year and our balance sheet remains strong and we expect gearing to remain within the 20% to 30% band in 2018.
In other business and corporate, the underlying quarterly charge expected to average around $350,000,000 And finally, in the current environment, the underlying effective tax rate is now expected to be lower than 40%, reflecting an increase in equity accounted income from Rosneft and other portfolio mix effects. Looking specifically at the 4th quarter, we expect upstream reported production to be higher than the 3rd quarter with the addition of BHP assets in the U. S. Low 48. In the Downstream, we expect lower industry refining margins and we also expect higher levels of turnaround driven by activity at our Whiting Refinery in the United States.
Let me summarize. With delivery of another set of strong operational financial results, we approached the end of the year as we started it with momentum and a clear focus on the disciplined execution of the strategy we laid out almost 2 years ago. Across the businesses, we remain focused on safe and reliable operations with high levels of availability and reliability enabling us to capture the benefits of an improving price environment this year. We're also making tangible progress across the upstream and downstream in delivering our strategic milestones. We are near completion of the BHP transaction, have recently started up 2 major projects in the Gulf of Mexico and Australia and continue to grow our fuel retail network, notably in Mexico.
This is all feeding through to strong underlying growth in earnings and operating cash flow. We continue to expect the organic cash breakeven of the group to average around $50 per barrel on a full dividend basis in 2018. As we laid out last year, operating cash flow is expected to continue to grow at an oil price of $55 per barrel real and together with the continuing focus on capital discipline to drive growing free cash flow. Taken together, all of this supports our commitment to growing distributions over the long term as evidenced by the dividend increase we announced in the Q2 as well as our ongoing share buyback program. It also creates optionality for us to high grade our portfolio as seen with our recent BHP transaction, enabling us to drive competitive and improving returns across the business.
We are looking forward to seeing many of you at our Upstream Investor event in Amman, where we will go into a lot more detail on strategic progress and the future opportunities in the Upstream. Thank you for listening. And with that, we'll now hand over
Okay. Thank you again everybody for listening. We're going to turn to questions then. Just a reminder as usual, then. And we're going to take the first question from Christian Malek at JPMorgan.
Christian?
Hi. Thank you, Craig, and
thank you for taking my questions. Two questions. And so first, while we welcome a fully cash funded transaction of BHP, the only caveat sort of highlight is that this revised frame arguably makes you more implicitly long wheeled by virtue seeking to secure $5,000,000,000 to $6,000,000,000 of divestments in order to reduce debt. In your press release, shall you say, assuming oil prices remain firm, expect to fund a deferred consideration with available cash rather than issuing equity. So first question is, key the risk is that if oil price continues to be volatile, is it fair to say that you'd allow your gearing to run materially over the top end of your band in the event Orb does move lower?
And second question is shifting perhaps to more half glass full. I'd like to understand the scope to enhance total share return in 2019. I know you talked about it, Brian, on your introduction. Is it likely to be triggered through a target quantum of debt reduction? First, as you mentioned, your expectation to move towards the middle of the band by end 2019, so sort of the path of that upside would be very interesting.
Thank you. Thanks, Christian. So I think the way to characterize it is we had the option when we announced the deal at the beginning of July to do this on an all cash basis or on the basis of 50% shares, 50% cash. And what we've come out and said today is that we will now look do that on an all cash basis. It's a much simpler transaction than we would have expected in terms of having to issue shares.
And what that will create is much lower costs in terms of the final transaction value. I think the chances or probability of a major oil price correction, which is probably what we'd need to see for gearing to go significantly above the 30%. I think right now it's not clear it will breach through 30% next year depending where the absolute oil price is. And I think it's probably worth just picking up given oil price stock levels and it's been 4 months since we announced the transaction. Given oil price stock levels have now drifted down towards below the 5 year average, oil is now more prone to oil price movements and potential oil price major movements in either direction.
So I think you could see plus or minus 5 dollars plus or minus $10 It feels pretty firm right now. I think we saw it get ahead of itself through this quarter, particularly ahead of the Iran sanctions as we saw Iranian oil come off the market relatively quickly. We're starting to see some of that oil actually flow, whether it be into tank or into storage or domestically within Iran. But OPEC is sitting where it was vis a vis their quotas back in June. So I think it's unlikely we're going to see a major correction.
You'd have to see a fairly significant correction. And for this year, we think by the end of this year, we will be balanced at around $50 a barrel. That will naturally go to $35 to $40 a barrel on a point forward basis. And so I don't think there's a concern of it go majorly above 30%. It may drift to the top end of the land through the 1st and second quarter of the payments, but I don't think it will go beyond that.
And then in terms of gearing as an objective, that's not an objective itself. It will just naturally drift down. Now that we've said we will reposition the divestments now to pay down debt, we will start to do that going forward. So frankly, it will naturally drift towards the middle part of the band at around about $70 a barrel, assuming that's where we are for next year. But we won't actually set the plan for next year until January time.
So January, so not so your discussion around buyback would actually be approved around the January, February time as opposed to before year end?
Yes. No buyback. So what we've also said with this is that the scrip buyback program was always meant to be built over time and therefore would take some time. So for this year coming into 2019, we have committed to make sure that all the scrip is repurchased by the end of the year. We would have had this strange position through the 4th and first quarter where we'd be issuing stock and buying back scrip dividend, which we've all been counterintuitive, not really make a lot of sense.
So we'll probably slow down our scrip uptake through the first half of next year, but look to offset everything we've issued since the Q4 of 2017 by the end of next year.
Thank you.
Okay. We'll take the next question from Irene Homeowner at Societe Generale. Irene?
Thank you. Good morning. I had two questions. First, Brian, you referred in your prepared remarks to the oil market, oil price volatility. I believe Bob was recently quoted in an interview saying that in your project sort of investment appraisal process, you now tend to use 60 to 65 and 50 to 55.
I was just wondering if you can elaborate on that topic. Then secondly, upstream unit production costs up a little bit, 1.5% in the 9 months. I wonder if you can please share your expectations for that metric in 2019 as you incorporate BHP and if prices remain where they are? Thank you.
Thanks, Serena. Maybe on the I'll come back to the question of 6065 and Bob's recent comments because I've received a lot of questions about that this morning. So I think I'll just take this opportunity to clarify what Bob was talking about in terms of the oil and money gas conference and 6065. In terms of unit production costs, it's very simple, why you've seen a slight uptick. One is we had a big maintenance schedule through 3Q, which we typically do 2Q and 3Q in the Upstream.
And also, obviously, with the higher oil prices, you start to get PSA effects come through the volumetric measures, which therefore reduces the denominator. So as oil prices go higher, that volume number comes down. So you will see a little bit of movement around that. But the overall trend is still in the same direction, which is downward. And a lot of that's being driven by technology and another number of things that actually Werner will take you through in a lot more detail at our Investor Day in December.
So we'll go into a bit more granularity around that, but the overall trend is still down. In terms of 60, 65, I think Bob was talking about, so we run basically 2 or 3 numbers, but the ones that we're really focused on our investment case is $50 a barrel $75 a barrel. And I think basically where Bob was basically describing where the middle of that range is. I think he was actually referring coming into this year, we normally set our plan, our oil price for a 12 month period, which just helps us manage the cash flows within that 12 month period. This year, we set that at €55,000,000 A few weeks or months ago, we may have thought about what oil price was set for next year, something around €60,000,000 to €65,000,000 seems like a conservative number that we could start to plan on that basis.
But the $60,000,000 $65 does not reference anything around specific investments that we're making. We run those cases of $50 $75 a barrel, and it's $75 a barrel real over a very long period of time and $50 is the sort of base case that we run everything at. That's how we look at our projects.
Thank you, Brian.
Okay. Thanks, Irene. We'll take the next question from Jason Kenney at Santander. Jason, good morning.
Hi, Brian. It's Jason Santander. Just looking at your indicator sensitivity, and I'm wondering where the downstream indicator, I think it's $500,000,000 operating profit per $1 per barrel refining indicator. I'm just trying to see how that reflects the widening crude discounts that you can get in Canada. I know they're not necessarily specifically downstream or upstream, but just trying to gauge if we can get a better sensitivity idea quarter to quarter or even year to year on those guidance, 2019 in particular?
Yes, that's tough to do. But what we have done is so in terms of guidance, Bill, you have to remember, John, Jason, within any particular quarter, there's an awful lot of moving parts across the business. And so therefore, the rules of thumb are really designed for in a stable price environment, so an oil price of X that doesn't move by more than a few dollars within that year, then you could reasonably use these rules of thumb. When the oil price sort of goes from $50 to $80 a barrel, it's really difficult to use those rules of thumb. You're not going to get a perfect dollar for dollar move on those rules.
That also applies in the refining space. We have seen huge differentials between Canadian heavy and WTI, up to $40 $45 a barrel so far this year. They look like they're sort of set in terms of what we're expecting going forward. We do still expect a differential certainly through this quarter and into next year, higher than the average that we've seen over the last 2 or 3 years. You also have to then take into account the fact that, of course, we have a portion on the pipeline.
So we can't always run 100 percent heavy crude out of Canada. And that apportionment, even in October, which is all in the public domain, we were constrained and we could we had certainly could actually access only 43% in October, 45% in November. And that's all about recovery of Syncrude production. So it's pretty hard to give you a rule of thumb around that. But needless to say, the Whiting investment was done at sort of mid teens in terms of its the assumptions around heavy versus WTI.
So something around $14, dollars 15, dollars 16 is what we'd assumed in the economics back when the oil price was down at sort of $50,000,000 $60 We're seeing differentials significantly higher than that, but we have no specific rule of thumb that we can give you other than the sort of raw calculation you can do of $1 a barrel across the refining margin may give you a certain uplift. And I think people have tried to come up with estimates of that in the past, but we have nothing that we can sort of stand behind as a rule of thumb because there are so many other moving parts in the slate of the refinery and what the products looked like to really give you anything which would be helpful in terms of those calculations.
Okay. I mean, it is a great result in the Q3. Do you think the Q4 could be similarly stunning?
No, I think 3rd quarter in Downstream, you had supply and trading coming back to an average quarter from what was a small loss in the Q2. And you had high availability, which allowed us to capture those higher refining margins. So really, it's about if the kit is working, remember we're right in the middle of the turnaround with Whiting today, if the kit is back running at the sort of levels we saw in the Q3, But I think sustaining 96% availability from my humble experience of refining and marketing over 30 odd years, that's a pretty tough measure to sustain. The guys will try and do that through the Q4, but I don't think you necessarily see that repeat in the Q4.
I think Jason, just to add to what Brian said as well. We obviously talked in the Q2 about the Whiting Refinery being a 7 week turnaround. That kicked off around the middle of September, so clearly is weighted more towards a 4th quarter event. So in terms of capturing the differential, clearly, the team now works hard to do so, but there's a heavy weighting in that turnaround in the Q4, expected probably to end around mid to end of November.
Okay. Thanks.
Okay. Next question from Michele Della Vigna at Goldman Sachs. Michele?
Thank you for taking my question and congratulations on the strong results. I was wondering whether the improved tax guidance for this year to below 40% is sustainable in the coming years as well in a similar oil price environment? And secondly, I was wondering if you could give us an update on the remaining Macondo business and economic loss claims? Thank you.
Yes. Well, so Michele, tax that you said this year over 40%, we've steadily moved that down, now we're saying below 40%. It is purely a function of the portfolio mix that we have today. And as we get stronger earnings out of Rosneft, because those earnings come through on a post tax basis, that will reduce the overall underlying effective tax rate. So obviously, the higher the Rosneft number, that will weigh down that will be a contributing factor towards a lower effective tax rate.
But it's really about mix and the mix of the barrels and where the production is coming from. I think we're not we haven't set guidance yet for next year. We'll go through and do a portfolio assessment. We'll look at an oil price planning assumption for the 12 month period for next year and then we'll come up with a tax rate. I don't think it's going to be wildly different from the 40%.
It's probably we're probably going to be still over 40% for next year, but we'll come back with guidance on that at part of the 4Q results. And then on Macondo, in terms of the liabilities, we are down to the final series of claims, the majority, I mean, the vast majority of which have now been processed. But there is a process with the plaintiffs steering committee court supervised settlement fund that allows claimants that have been denied to resubmit, and they'll be in either 1, 2 or the 3rd cycle of resubmissions. But we're now in the sort of de minimis, and this is probably one of the quietest quarters that we've had around Macondo. Bell claims for this quarter, I think, around about $50,000,000 is what we've taken through in terms of provision.
But we are in the final sort of, I could say, 22 claims, but then there's a recycle effect that takes that number to 200. But there's a series of claims that have been denied and recycled in the system under the original settlements. But we're sort of in the de minimis end legal game now of whatever is now left on appeal, and then we'll fight those appeals through the 5th Circuit and the Court of Justice appropriately going forward, which is what we have been doing up to this point in time.
Thank
you. Okay, Michele, thanks. We'll move next to Lydia Rainforth of Barclays. Lydia?
Hi, good morning. Two questions, if I could. The first one on the upstream side and given sort of what was pretty flat production quarter on quarter and pretty prices, there was quite a big uplift in the profit there. Can you just talk through a little bit more detail around the drivers behind that? And then the second one, just on the divestments, it has seemed relatively quiet on the divestment front.
And so just wondering what sort of confidence
you can give us around
that $5,000,000,000 to $6,000,000,000 And should we think about it being more back end loaded towards next year? Thank you.
On the €5,000,000 to €6,000,000,000 Great. Thanks, Lydia. In terms of looking at upstream earnings and what was driving it, the majority piece of this was actually obviously off the back of the oil price as realizations. And it's realizations more than price improved, is the big lion's share of what we've seen come through. But something around about the same sort of level, but just below that, is higher sales volumes, particularly coming out of Angola in the North Sea, have been the big drivers because obviously at these higher prices, some of those regimes, particularly in the North Sea, highly leveraged to earnings at the higher price.
So that's the basic driver. But it's basically, 1, high reliability. We were up over 95% for Upstream across the piece this quarter. We had the production growth coming through underlying this quarter 7%, 6.8 percent and underlying production growth now for the year of about 10%. So Bernard and the team are delivering against what they said they were going to be delivering against.
And we have the extra benefit this year, particularly Thunder Horse and Western Flank B coming on stream ahead of where we had them planned for next year and significantly below budget. So I think all of those things have helped with the momentum that you've seen come through that earnings. But I think it's really about having the kit running reliably has allowed us to capture those higher prices and get those stronger netbacks. On divestments in terms of this year's program of over €3,000,000,000 it is completely back end loaded this year, as it was last year. And you'll recall last year, I think, the divestment proceeds around about €4,500,000,000 with €3,500,000,000 coming through in the 4th quarter.
It's going to be similar this year. I think so far year to date around CHF 400,000,000, CHF 400,000,000 in the 1st 3 quarters. We will still deliver we expect to deliver over EUR 3,000,000,000 by the end of the year. It's all going to be sort of 4Q is when they will come, just like last year. And then the EUR 5,000,000,000 to EUR 6,000,000,000 program is predominantly lower $48,000,000,000 We've certainly announced internally with the teams what those assets look like, a lot of the legacy historic assets we had, quite gassy in nature across the piece.
But on all cases, we feel that we have a pretty we're confident in terms of the potential buyer spectrum we have availability out there, I mean, especially given this particular basin. So we're confident about getting those away. And we'd expect to get the 1st tranche of those away next year, and we would not expect them to necessarily, with this particular tranche, be back end loaded. I mean, we've had time to get these ready. We've got the data rooms prepared.
We are going out to market. So we'd anticipate that you start to see the 1st tranche of those divestments done next year. They may well be at the end of the year, but I suspect they'll be coming into this year, we knew it was going to be back end loaded. We sort of told you that at the start of the year. In this case, I think we'll see what the market looks like as we get out of the market on the 5 to 6.
And the first tranche, it won't be 5 to 6 next year, it will be over a 2 to 3 year period. But the first tranche we expect to get away next year, we'll be able to let you know how that goes probably into the Q2, Q3 next year.
Wonderful. Thank you.
Okay. Thanks, Lydia. We'll go to Thomas Adolff at Credit Suisse next. Thomas?
Good morning and congrats on the strong results as well. Two questions for me. Firstly, on your CapEx guidance, now I'm quoting one of your peers. Equinor said €11,000,000,000 is a good medium term number based on today's cost index. And if you go beyond that, it would overstretch the organization, an impact on project execution.
So I wonder in the case of BP, would you say if you go above $17,000,000,000 it would overstretch the organization. I know you want to stay in the $15,000,000,000 to $17,000,000,000 range, but I wanted to understand whether that's also the sweet spot organizationally. And then secondly, in terms of LNG and FIDs, I wonder if you could give an update on Tortue FLNG. What's still missing? Will BP be the sole offtaker?
Has the development plan be approved? And what when exactly do you expect to take FID? Thank
you. Great. Thank you, Thomas. And so what I would $17,000,000,000 is that is a range which has a huge amount of flexibility. Dollars 2,000,000,000 is a huge amount of money in terms of flexibility of what we can do.
And certainly, as we've seen deflation continue to come through this year, surprisingly so given where oil prices are, we are still seeing, I think, technology driving a lot of deflation. But we're now saying €15,000,000,000 for this year. I think at the start of the year, we're expecting it to be close to the middle part of that range of €15,000,000,000 to €17,000,000 So we're down at €15,000,000,000 We have a huge amount of capacity that Bernard and his team have created, particularly in the Upstream, to absorb BHP and be able to ramp their drilling program up as we go into next year. And we're going to start that process in the Q4 probably around Eagle Ford and maybe just touching Permian, but we're not settled on that yet, but certainly in terms of Eagle Ford. So I think we have flexibility within the program.
What in terms of the organization, the size of the organization, we moved to Central Projects Group many years ago, back in 2,009. That has really come to fruition in the last 3 or 4 years as Berman's got that team humming in terms of rhythm. And I would describe a rhythm that you start to get into with an organization that it gets into a rhythm of delivering projects every 6 to 9 months, then coming on stream. You learn from all the things that you learned from the previous project and you take those learnings and move it on to the next project rather than a sort of stop start or a deployed organization where you have to relearn the things going forward. And I think that's why you're seeing the advancements of Thunder Horse this year, Western Flank B, why those projects have come on stream earlier, is really about understanding the rhythm of what we've learned from other projects.
So I wouldn't necessarily describe the capacity of our organization around a specific capital number. It's more about activity. And last year, I think Bernard was on record as saying, for last year, I think we get up to the most hours we've ever deployed in any one year on the series of projects we had that came on stream last year. We were probably at the top end of comfort in terms of bringing those projects on, which the team did a phenomenal job of doing. So we're pretty comfortable where we are today.
We're in that rhythm of bringing projects on, and we will sort of see how that progresses going forward. But we're not sort of in a place where we're going to move off the 15 to 17 band right now, so it's a bit of a mute point. And just to reiterate, we will bring the BHP transaction in, and we will live within the 15% to 17% frame, and that will allow us to ramp capital up in the low 48%, where it's the one place where you can ramp activity up quickly, certainly from what we've learned from our own business of running our old legacy assets. In terms of the Tortue project, the project entered its feed in April 2018, and we're still targeting FID by the end of 2018 and first gas in 2022. The project was targeting a first phase of about 2,500,000 tonnes per annum, and then we've got a further 2 phase to test up to a further 10,000,000 tonnes per annum.
We've got nothing left to update on that. We still expect FID this year, And I'm sure Bernard will have some more to talk about that in December at the Investor Day in a month.
Thank you, sir.
Thanks, Thomas.
Okay. Thanks, Thomas. Yes, let's go to Rob West at Redburn next please. Rob?
Hi, thank you very much. I'd like to start on production. I don't know where other people were in the quarter, but the production number was a little bit below what I had in, flat year on year. And really, Brian, I'd be interested if you could sort of check some exuberance results from that because I'm looking at the trajectory of growth that's still to come. So ramping Shack Denise further, the start ups like Clare and West Nile Delta.
And I'm wondering, should I look at this quarter as base that you're actually getting quite a lot of growth from that baseline? Or should I look at it and is there something in this quarter that is a negative in terms of the production that might continue going forward? So that was the first question. And the second one is just I'd just like to go back to the timing of divestments, the €3,000,000,000 that you've alluded to in your comments this morning. I think so far year to date, the run rate of divestments coming through is it's under EUR 500,000,000 And so my question is just in terms of the settlement of that $3,000,000,000 can you just say how much more of that is expected this year?
Or is it just announcing the transactions that you're aiming to do before year end? Thank you.
Yes. Let me just pick up the second part of that question because it's fairly straightforward. I mean, just like last year, we will announce basically effectively, last year we had $4,500,000,000 of disposals, dollars 3,500,000,000 of proceeds came in the 4th quarter. We'll have exactly the same this year. It won't be that level, but it will be overall, it will be over $3,000,000,000 for the year, which is what we've indicated.
We would still expect to be over $3,000,000 and we'll be looking to close a series of transactions in the Q4 that will get us over that figure. So that's pretty well underpinned. And we did say at the start of this year, it's a mirror of last year, precisely the same. We said it would be back end loaded. It is back end loaded.
And so there's no changes in terms of that. So it's exactly the same pattern that you saw last year. Then in terms of
this That's firm.
I said we still expect I can't be firm firm because that would be giving you guidance, which I wouldn't be able to do because it's a function of closing transactions. But we've indicated in all of our materials there that we still expect to be over €3,000,000,000 for the year. If we didn't think we're going to deliver in the 4th quarter, we would have told you that. So it's not but I can't be firm, firm because it's a function of whatever gets announced through the Q4 and it's a function of whatever gets announced through the Q4 and gets closed. So things can always slip into January.
That's always possible. But right now, our expectation is we will have over $3,000,000,000 of divestments by the end of this year. Then in terms of production, I think maybe if you go back to guidance and what we've told you before, if you take out the portfolio impacts of ADNOC PAE, the sort of PAE transaction true up and AGT, so you take those things out, the ADMA concession, which was in there last year, it wasn't there this year, it's significantly over 100,000 barrels a day production that we had last year that we no longer have because it's no longer in the portfolio. So if you actually adjust for that, I think you'll see close to 7% underlying growth this quarter. And then we've signaled to you for 4Q as a BHP transaction comes in, that will be additional portfolio volume that will come into the mix.
So actually, we're seeing on an underlying basis, if you strip out the portfolio that's been divested or has come out of the base business, actually quite significant growth this year to tune of about 10% underlying year to date.
Got it. Thank you.
Okay, Rob. Thanks for the question. We'll next go to Alastair Syme at Citi. Alastair?
Hi. Thanks, Craig. Thanks for the opportunity. Can you just provide this update on the impact of IFRS 16 as you see it? And will you revise the gearing band or will you look to absorb it?
And secondly, can you maybe give us a little bit of an update on the roadmap around the downstream free cash target towards €9,000,000,000 to €10,000,000,000 by 2021? If I'm right, we're running at about €6,000,000,000 over the trailing 12 month.
Great. Thanks, Alastair. So on IFRS 16, there will be an awful lot of moving parts associated with that particular accounting standard. And I think while it was intended as a standard to give clarity around sort of the extended debt book, Of course, it will move pretty much a lot of the lines of the P and L and balance sheet as a consequence. So it's going to be a little bit noisy for you all.
And what we will do at the end of this year as part of 4Q, we'll give you a true up of how it impacts each of the individual lines of the P and L and balance sheet. It's going to affect a lot. We will basically present all of the information on the pre IFRS 16 and post IFRS 16 basis. So at least you get clean line of sight and transparency on what's moving. We haven't made any decisions yet whether or not we will end up with a gearing on the old basis, I.
E, it's a non GAAP measure, we can define it however we think is appropriate in terms of our financial frame. But probably the most important thing about IFRS 16 in terms of the original intent is our cash cover ratio is unaffected by IFRS 16. The rating agencies already use extended debt in their calculations of cash cover ratio. So leases are already part of the extended debt book. So it will have no impact from a rating agency perspective, but it will create a lot of noise and clunkiness around each of the individual lines of the P and L and balance sheet.
But we'll give you a very clear route map of what that looks like. And then in terms of is that okay, Alastair?
Yes, that's perfect.
Okay. And then in terms of the target of $9,000,000,000 to $10,000,000,000 I'll wait till we get to the end of this year. But against that target, I think we are close to $7,000,000,000 delivered with a further $2,000,000,000 to $3,000,000 to come, but on track with the targets and the way in which Tufan laid that out out of 2021.
Do you think it would be quite lumpy into 2021, Brian? Or
is it
the expectation?
I think in the current market, what I will guarantee you is it will not come firstly along the lines of which we planned it. That's the one thing we've learned about the last 7 quarters because it will be a function of whatever the hell oil price or other factors are doing at the time. But that what I think you've seen Toufan and his team creating the Downstream is a huge amount of resilience to deal with various economic factors that may impact that business. And I think the biggest one of those was the way in which Tufail and the team have been able to neutralize the volatility of refining margins in their base business. So we could lay a plan out for you.
I will guarantee we will not follow the exact quarter by quarter trend of that plan. But I think what Tufan has created is a huge amount of optionality within its portfolio to manage that, and therefore, we have confidence around its delivery.
Can I just clarify, do you think the sort of macro environment, the trailing 12 month is representative of what you envisage for 2021 in that target?
No. I think we already know we're in a very different environment because originally the whole environment we set for all the targets is around $55 a barrel real. Now in the Upstream, we'll take benefits from that in terms of the additional free cash flow we get from where the prices are today. We've got, I think I mentioned earlier, volumes, I know it's a broken record, but volumes are back below the 5 year average or certainly close to 5 year average both on a macro global economic basis and within the United States. So I think certainly oil prices are pretty well underpinned above 70 for the next sort of 6 month period or so.
At least we can't see anything which would majorly move those out of kilter with that. And there may actually be some movement to the upside, but I think plus or minus $10 a barrel is pretty tough to call it. By the time we get to 2021, I think there's a lot of things could unwind. We'll see more production coming on Lower 48. You may see some softening of demand, although we're not seeing major demand side correction at the moment if prices stay very high.
But I think within in terms of the Downstream, we're seeing benefits right now, big light heavy spreads that we're seeing with Canadian crude coming into the big machine core Whiting Refinery, which can take up to 320,000 barrels a day of heavy crude. It's clearly not at those levels given curtailment issues. So I think what I'd say, Alastair, is look, we've created a portfolio now, which has a huge amount of optionality around that portfolio. So we're pretty confident with the targets we've laid out for you for 2021. We just may not end up delivering the same way that they were originally envisaged back in the start of last year, and we're already seeing that through these 1st 7 quarters.
Thank you very much.
Okay. Thanks, Alastair. We'll next go to Henry Tarr at Berenberg. Henry?
Hi there and thanks for taking my questions. Firstly, looking at new FIDs, have there been any changes to the strategy in terms of contracting? So you're looking to sort of lock in low costs, for example, Or do you see sort of no reason to do this today? And then in terms of the portfolio, assuming that oil prices remain firm, gearing comes lower over the coming quarters, you have some flexibility there. Where would you and maybe this is a longer dated question, but where would you be looking to add to the portfolio should the opportunity arise?
That's great. Thank you, Henry. That's a good question on the opportunities. So in terms of FIDs, I think we already have 5 this year from memory, which is around, I think, Oman, a couple in North Sea, India and Angola, whether we've seen 5 FIDs. I think what the organization has created now with Bernard's leadership and that exec team is a lot of our contracts are long term anyway.
So a lot of our rig contracts, I'll be honest, for a 5, 7 year basis on a rolling basis. So we've already been able to capture some of those lower rates. And we're certainly not seeing any inflation on the rig rate side right now. And so I think we'll look to contract and procure activity on a central basis across the suite of projects, and we'll look to optimize across that piece. And that's the whole purpose of the sort of central projects group and the central procurement groups that do those things.
So I think we've already got locked in contractually a lot of activity associated with some of these projects. So that's sort of point 1. And then in terms of opportunity set, I mean, I think we announced in September we've acquired a license in the Santos Basin. That will be an example of a sort of step out for us where we do think there's a huge opportunity for us in a country like Brazil where we've seen some major economic reform over progressive reform over the last 2 or 3 years. And we have a great partner there Petrobras that we're working with.
So that would be an example of the sort of areas where we'd look to be stepping out and sort of increasing, but within the $15,000,000,000 to $17,000,000,000 frame that we've already laid out. And maybe just building on that, you will have seen already this year, we've had new access in license rounds in I talked about Santos Basin, also U. S. Gulf of Mexico, our traditional backyard Mexico, the North Sea, another one of our traditional backyards and Azerbaijan. So but that's all within the 15 to 17 frame.
Okay, great. And just one quick follow-up then. With oil prices where they are now, are you seeing a greater emphasis then on exploration rather than acquiring barrels at this point in the cycle?
I think it's a mix. I mean, you always want to be able to find oil with your own drill bit or through exploration. That's always the primary focus because ultimately it would be the lowest cost way to access resources. Equally, if you look at what we've just done in Lower 48, I think we've bought a very premium position, which we will definitely enhance value around. And the more that we see of those assets, we can see that.
So I think it's going to be a mix going forward. But obviously, you'd always like to sort of find oil discovered resources through the drill bit.
Thanks. That's great.
Okay. Thanks, Henry. We'll next go to John Rigby of UBS. John?
Yes. Hi. Good morning, Brian. Two quick questions on one on disposal. So if I'm right, I think you count the Conoco transaction as a disposal.
So am I right in thinking that the net cash in through the Q4 despite the gross disposal numbers not likely to be that significant in which case? Am I also right in thinking that disposals next year will be through an aggregation of that that's linked to BHP plus I guess you probably want to continue to pursue the $3,000,000,000 ongoing disposal plan as well, so probably closer to $8,000,000,000 to $10,000,000,000 for 2019. And then just secondly, linked to that, but sort of more philosophically is, I know you keep talking about your 20% to 30% band. It seems to me that over the last couple of years BP has been wanting to be opportunistic in making acquisitions of assets and so on. I'm aware the Abu Dhabi transaction, you issued stock.
This one you almost did and then have chosen not to because of the complexity and the value. And I completely agree with the decision you made on that. But wouldn't it be better, all things equal,