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 third quarter 2018 results presentation. I'm Craig Marshall, BP's Head of Investor Relations. I'm here today with our Chief Financial Officer, Brian Gilvary. 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. 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 cashflow. We'll start today with some comments on the macro environment before moving to highlights from the quarter, then covering our financial results in more detail. We'll 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 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 five-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 spare 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 movement 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 six 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 third quarter was $3.8 billion, 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 cashflow of $6.6 billion in the quarter, including a working capital build of $700 million. 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 billion in the quarter. We also expect another strong quarterly contribution through our shareholding in Rosneft, with underlying post-tax profit estimated at $900 million. The downstream reported underlying pre-tax earnings of $2.1 billion 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 startup of two further major projects in the Gulf of Mexico with the BP-operated Thunder Horse Northwest Expansion and on the Australian North West Shelf with the startup 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 1,300 sites across our network. 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 third quarter, Brent Crude averaged $75 / bbl, similar to the second quarter average of $74 / bbl. Prices rose sharply through September, reflecting a reduction in Iranian exports and concern over the level of OPEC spare capacity. U.S. Henry Hub gas prices averaged $2.90 versus $2.80 in the second quarter, and BP's global refining marker margin averaged $14.70 / bbl, slightly below the average for the second quarter of $14.90 / bbl. Moving to our results.
BP's third quarter underlying replacement cost profit increased to $3.8 billion compared to $1.9 billion a year ago and $2.8 billion in the second quarter 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 second quarter, 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 third quarter dividend payable in the fourth quarter remains unchanged at $0.1025 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 billion for the first nine months, of which $6.6 billion was generated in the third quarter. This included a working capital build of $1.1 billion for the first nine months, of which $700 million was in the third quarter. Organic capital expenditure was $3.7 billion in the third quarter and $10.7 billion for the first nine months of 2018. Our organic free cash flow surplus was $3 billion in the first nine months of 2018. Turning to inorganic cash flows.
In the first nine months of 2018, divestments and other proceeds total $400 million. We made post-tax Gulf of Mexico payments of $2.9 billion, and inorganic capital expenditure was $1.5 billion, including an initial deposit paid to BHP of $525 million. Gearing at the end of the third quarter was down to 27.5%. We have also remained active in our share buyback program and bought back 48 million ordinary shares in the first nine months of 2018 at a cost of $340 million. 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 two most recent projects ahead of plan. The Thunder Horse Northwest Expansion project in the Gulf of Mexico came online four months ahead of schedule and 15% under budget. The project, which achieved first oil 16 months after sanction, comprises a new subsea manifold and two wells tied back to the existing Thunder Horse platform. This has brought forward valuable barrels and demonstrates our strategy and action of growing advantaged oil. The Western Flank B project in Australia came online under budget and well ahead of its scheduled 2019 startup. The project consists of an eight-well subsea tieback to the existing Goodwyn A platform. So far this year, we've delivered five major projects.
Our remaining operated projects, Clair 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 startup in the fourth quarter. In September, BP accessed new acreage in the prolific Santos Basin offshore Brazil by winning the license for the Pau Brasil block. This represents BP's first 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 third quarter 2011. In fuels marketing, we continue to grow retail volumes and roll out our convenience partnership model, which is now in around 1,300 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. 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 26th of July. The acquisition of BHP's assets in the liquids-rich Permian Delaware Basin and the two premium positions in the Eagle Ford and Haynesville Basin transforms our position as a Lower 48 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 / bbl 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% of the $10.5 billion consideration, less the deposit of $525 million paid in July, and less customary completion adjustments.
When the 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 six equal monthly installments, funded through the issuance of equity over the same period. An additional $5 billion-$6 billion 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. 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 billion-$6 billion 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%-30% band in early 2019. We would then expect gearing to move back down towards the middle of the band 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 2017, 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. Assuming the BHP transaction is funded using cash, we would now expect to fully offset the impact of scrip dilution since the third quarter 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 billion-$17 billion, 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 fourth quarter. For the full year, we expect organic capital expenditure to be around $15 billion.
Divestment and other proceeds in 2018 are expected to be over $3 billion. As noted in the second quarter, this excludes proceeds from the divestment package we announced with the BHP transaction. The total DD&A charge is now expected to be around the same level as 2017. Gulf of Mexico oil spill payments are expected to be just over $3 billion for the year, and our balance sheet remains strong, and we expect gearing to remain within the 20%-30% band in 2018. In other business and corporate, the underlying quarterly charge is expected to average around $350 million.
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 fourth quarter, we expect upstream reported production to be higher than the third quarter, with the addition of BHP assets in the U.S. Lower 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 U.S. Let me summarize. With the delivery of another set of strong operational financial results, we approach 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 two 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 two 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 / bbl 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 / bbl , and together with a 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 second quarter, 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're looking forward to seeing many of you at our upstream investor event in Oman, where we will go into a lot more detail on strategic progress and the future opportunities in the upstream. Thank you for listening. With that, we'll now hand over to questions.
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Okay. Thank you again, everybody, for listening. We're gonna turn to questions then. Just a reminder, as usual, please limit your questions to no more than two per person so that everybody gets a chance to ask one. We're gonna take the first question from Christyan Malek at J.P. Morgan. Christyan.
Hi, thank you, Craig, and thank you for taking my questions. Two questions. First, while we welcome a fully cash-funded transaction at BHP, the only caveat to sort of highlight is that this revised frame arguably makes you more implicitly long oil by virtue of seeking to secure $5 billion-$6 billion of divestments in order to reduce debt. In your press release, you also say assuming oil prices remain firm, expect to fund the deferred consideration, you know, with available cash rather than issuing equity. First question is, clearly the risk is that if oil price continues to be volatile, is it fair to say that you'd allow your gearing to run material over the top end of your band in the event oil does move lower? 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, on your introduction. Is it likely to be triggered through a sort of target quantum of debt reduction, first, as you mentioned, your expectation to move towards the middle of the band by end 2019? Just sort of the path of that upside would be very interesting.
Okay.
Thank you.
Thanks, Christyan. 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. What we've come out and said today is that we will now look to 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. 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. I think it's probably worth just picking up. Given oil price stock levels, it's been four months since we announced the transaction. Given oil price stock levels have now drifted down towards below the five-year average, oil is now more prone to oil price movements and potential oil price major movements in either direction. I think you could see ±$5, ±$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. OPEC is sitting where it was vis-a-vis their quotas back in June. I think it's unlikely we're gonna see a major correction. You'd have to see a fairly significant correction. For this year, we think by the end of this year, we will be balanced at around $50 / bbl. That will naturally go to $35/bbl-$40 / bbl on a point forward basis. I don't think there's a concern of it going majorly above 30%. It may drift the top end of the band through the first and second quarter of the payments, I don't think it will go beyond that.
In terms of gearing as an objective, that's not an objective in 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. Frankly, it will, you know, it will naturally drift towards the middle part of the band at around about $70 / bbl, assuming that's where we are for next year. You know, we won't actually set the plan yet for next year till January time.
Till January. Not, your sort of discussion around buyback would actually be approved around the sort of January, February time as opposed to before year-end?
Yeah, no, buyback. What we've also said with this is that, you know, the scrip buyback program was always meant to be built over time and therefore would take some time. 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 fourth and first quarter, where we'd be issuing stock and buying back scrip dividend, which would all have been counterintuitive, not really make a lot of sense. 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 fourth quarter of 2017 by the end of next year.
Thank you.
Okay, we'll take the next question from Irene Himona at Société Générale . 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-$65 than $50-$55. I was just wondering if you can elaborate on that topic. Secondly, upstream unit production costs up a little bit, 1.5% in the nine 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, Irene. Maybe I'll come back to the question of 60/65 and Bob's recent comments, 'cause I've received a lot of questions about that this morning. I think I'll just take this opportunity to clarify what Bob was talking about in terms of the Oil and Money Conference and the 60/65. In terms of unit production costs, it's very simple why you've seen them a slight uptick. One is we had a big maintenance schedule through Q3, which we typically do, Q2 and Q3 in the upstream. Also obviously with the higher oil prices, you start to get PSA effects come through the volumetric measures, which therefore reduces the denominator. As oil prices go higher, that volume number comes down. You will see a little bit of movement around that.
The overall trend is still in the same direction, which is downward. You know, a lot of that's being driven by technology, and another number of things that actually Bernard will take you through in a lot more detail at our Investor Day in December. We'll get 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, we run basically two or three numbers. The ones that we're really focused on our investment case is $50 / bbl and $75 / bbl. I think basically where Bob was 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. A few weeks or months ago, we may have thought about what oil price was set for next year. Something around 60/65 seems like a conservative number that we could start to plan on that basis. The 60/65 does not reference anything around specific investments that we're making. We run those cases at $50/bbl and $75 / bbl, and it's $75 / bbl 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 at Santander. Just looking your indicator sensitivity, and I'm wondering where the downstream indicator, I think it's $500 million operating profit per $1 / bbl 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 for 2019 in particular.
Yeah, that's tough to do. What we have done is, in terms of guidance bill, you have to remember, Jason , within any particular quarter, there's an awful lot of moving parts across the business. 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/bbl-$80 / bbl, it's really difficult to use those rules of thumb. You're not gonna 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/bbl-$45/ bbl so far this year. They look like they're sort of set in terms of what we're expecting going forward. We still expect a differential certainly through this quarter and into next year, higher than the average that we've seen over the last two or three years. You also have to take an account into the fact that, of course, we have apportionments on the pipeline, so we can't always run 100% heavy crude out of Canada. You know, that apportionment, even in October, which is all in the public domain, we were constrained, and we could actually access only 43% in October, 45% in November.
That's all about recovery of Syncrude production. It's pretty hard to give you a rule of thumb around that. Needless to say, the Whiting investment was done at sort of mid-teens in terms of its the assumptions around heavy versus WTI. Something around $14, $15, $16 is what we'd assumed in the economics back when the oil price was down at sort of $50, $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, you know, $1 / bbl across the refining margin may give you a certain uplift.
I think people have tried to come up with estimates of that in the past, but we have nothing that we could 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 look 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 third quarter. Do you think the fourth quarter could be similarly stunning?
No, I think third quarter in downstream, you had supply and trading coming back to an average quarter from what was a small loss in the second quarter. You had high availability which allowed us to capture those higher refining margins. 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 third quarter. I think, you know, 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 fourth quarter, but I don't think you necessarily see that sort of, that repeating through fourth quarter.
I think Jason.
Okay, thanks very much.
Jason, just to add to what Brian said as well. We obviously talked in the second quarter about the Whiting Refinery being a seven-week turnaround. That kicked off around the middle of September, clearly is weighted more towards a fourth quarter event. In terms of capturing the differential, clearly the team there works hard to do so, but there's a heavy weighting in that turnaround in the fourth quarter. 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. Secondly, I was wondering if you could give us an update on the remaining Macondo business and economic loss claims. Thank you.
Yeah. Well, Michele, tax, you know, we've 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. As we get stronger earnings out of Rosneft, 'cause those earnings come through on a post-tax basis, that will reduce the overall underlying effective tax rate. The, obviously, the higher the Rosneft number, that will weigh down, that will be a contributing factor towards a lower effective tax rate. It's really about mix and the mix of the barrels and where the production's coming from. You know, 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 gonna be wildly different from the 40%. We're probably gonna be still over 40% for next year. We'll come back with guidance on that at part of the full Q results. Then on Macondo, in terms of the liabilities, we are down to the final series of claims. The majority, the vast majority of which have now been processed. 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 one, two, or the third cycle of resubmissions.
We're now in the sort of de minimis, and this is probably one of the quietest quarters that we've had around Macondo. BEL claims for this quarter, I think around about $50 million is what was taken through in terms of provision. 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. You know, there's a series of claims that have been denied and get recycled in the system under the original settlements. 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 Fifth 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 at Barclays. Lydia.
Sounds great. 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 flat 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? The second one, just on the divestments. It has seemed relatively quiet on the divestment front. Just wondering what sort of confidence you can give us around that $5 billion-$6 billion, and should we think about it being more back-end loaded towards next year? Thank you.
On the $ 5 billion-$6 billion, 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. It's realizations more than price improved is the big lion share of what we've seen come through. Something around about the same sort of level, but just below that is higher sales volumes, particularly coming out of Angola and the North Sea have been the big drivers. 'Cause obviously at these higher prices, some of those regimes, particularly in the North Sea, highly leveraged to earnings at the higher price. That's the basic driver. It's basically one, 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%. Underlying production growth now for the year of about 10%. You know, Bernard and the team are delivering against what they said they were gonna be delivering against. We have the extra benefit this year of particularly Thunder Horse and Western Flank B coming on stream, ahead of where we had them planned for next year and significantly below budget. I think all of those things have helped with the momentum that you've seen come through that earnings. I think it's really about having the kit running reliably has allowed us to capture those higher prices and get those stronger net backs.
On divestments, in terms of this year's program of over $3 billion, it is completely back-end loaded this year, as it was last year. You'll recall last year, I think the divestment proceeds around about $4.5 billion, with $3.5 billion coming through in the fourth quarter. It's gonna be similar this year. I think so far year to date, we're around $0.4 billion-$0.5 billion in the first three quarters. We expect to deliver over $3 billion by the end of the year. It's all gonna be sort of Q4 is when they will come, just like last year. The $5 billion-$6 billion program is predominantly Lower 48.
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. 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. We're confident about getting those away, and we'd expect to get the first tranche of those away next year. 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. We'd anticipate that you'd start to see the first 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 gonna be back-end loaded, and 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 to the market on the $5 billion-$6 billion. The first tranche, it won't be $5 billion-$6 billion next year. It'll be over a two to three year period. The first tranche we expect to get away next year. We'll be able to let you know how that goes probably into the second quarter, third quarter next year.
Wonderful. Thank you.
Okay. Thanks, Lydia. We'll go to Thomas Adolff at Credit Suisse next. Thomas.
Morning, congrats on the strong results as well. Two questions for me. Firstly on your CapEx guidance. I'm quoting one of your peers. Equinor said $11 billion is a good medium-term number based on today's cost index, if you go beyond that, it would overstretch the organization and impact on project execution. I wonder in the case of BP, would you say if you go above $17 billion, it would overstretch the organization? I know you want to stay in the $15 billion-$17 billion range, wanted to understand whether that's also the sweet spot organizationally. 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 been approved?
What, when exactly do you expect to take FID? Thank you.
Great. Thank you, Thomas. What, what I would describe in terms of the $15 billion-$17 billion is, that is a range which has a huge amount of flexibility. $2 billion is a huge amount of money in terms of flexibility of what we can do. 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, you know, we're now saying $15 billion for this year. I think at the start of the year, we were expecting it to be closer to the middle part of that range of $15 billion-$17 billion. We're down at $15 billion.
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. Yeah, we're gonna start that process in the fourth quarter, probably around Eagle Ford, and maybe just touching Permian, but we're not settled on that yet, certainly in terms of Eagle Ford. I think we have flexibility within the program. In terms of the organization, the size of the organization, you know, we moved to central projects group many years ago, back in 2009. That has really come to fruition in the last three or four years as Bernard's got that team humming in terms of rhythm.
I would describe a rhythm that you start to get into with an organization that it gets into a rhythm of delivering projects every six to nine months, them 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're having to relearn the things going forward. I think that's why you're seeing the advancement 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. I wouldn't necessarily describe the capacity of our organization around a specific capital number. It's more about activity.
Last year, I think Bernard was on record as saying for last year, I think we got 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. 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. We're not sort of in a place where we're gonna move off the $15 billion-$7 billion band right now, so it's a bit of a moot point.
You know, just to reiterate, we will bring the BHP transaction in, and we will live within the $15 billion-$17 billion frame, and that will allow us to ramp capital up in the Lower 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. We're still targeting FID by the end of 2018 and first gas in 2022. The project was targeting a first phase of about 2.5 million tons per annum. Then we've got a further two phases to test up to a further 10 million tons 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 Oman .
Thank you, sir.
Thanks, Thomas.
Okay. Thanks, Thomas. Yeah, 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. Really, Brian, I'd be interested if you could sort of check some exuberance that kind of results from that, because I'm looking at the trajectory of growth that's still to come. You know, ramping Shah Deniz further, the startups like Clair and West Nile Delta. I'm wondering, should I look at this quarter as, you know, a base that you're actually getting quite a lot of growth from that baseline?
Or should I look at it, is there something in, you know, in this quarter that, you know, is a negative in terms of the production that might continue going forwards? That was the first question. The second one is just I'd just like to go back to the timing of divestments, the $3 billion 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 under $500 million. My question is just in terms of the settlement of that $3 billion, you know, can you just say how much more of that is expected this year?
You know, is it just announcing the transactions that you're aiming to do before year-end? Thank you.
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 last year, we had $4.5 billion of disposals. $3.5 billion of proceeds came in the fourth quarter. We'll have exactly the same this year. It won't be that level, but it will be overall, it'll be over $3 billion for the year, which is what we've indicated. We would still expect to be over $3 billion. We'll be looking to close a series of transactions in the fourth quarter that will get us over that figure. That's pretty well underpinned. 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.
There's no changes in terms of that. It's exactly the same pattern that you saw last year.
That's firm?
I said we still expect. I can't be firm.
Okay.
because that would be giving you guidance
Yeah.
which I wouldn't be able to do.
Yeah.
It's a function of closing transactions. We've indicated in all of our materials there that we still expect to be over $3 billion for the year. If we didn't think we're gonna deliver in the fourth quarter, we'd have told you that. It's not-
Right.
I can't be firm 'cause it's a function of whatever gets announced through the fourth quarter and gets closed. Things can always slip into January. That's always possible. Right now our expectation is we will have over $3 billion of divestments by the end of this year. In terms of production, I think maybe if you go back to the guidance on 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, you take those things out, the ADMA concession, which was in there last year but wasn't there this year. It's significantly over 100,000 bbl a day production that we had last year that we no longer have 'cause it's no longer in the portfolio. If you actually-
Yeah.
Adjust for that, I think you'll see close to 7% underlying growth this quarter. We've signaled to you for Q4, as the BHP transaction comes in, that will be additional portfolio volume that will come into the mix. 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 the 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, Brian, give us an 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? Secondly, can you maybe give us a little bit of an update on the roadmap around the downstream free cash target towards $9 billion-$10 billion by 2021? If I'm right, we're running at about $6 billion over the trailing 12 months.
Great. Thanks, Alastair. On IFRS 16, there will be an awful lot of moving parts associated with that particular accounting standard. 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&L and balance sheet as a consequence. It's going to be a little bit noisy for you all. What we will do at the end of this year as part of Q4, we'll give you a true-up of how it impacts each of the individual lines of the P&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, 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, id est because it's a non-GAAP measure, we can define it however we think is appropriate in terms of our financial frame. 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, leases are already part of the extended debt book, it will have no impact from a rating agency perspective. It will create a lot of noise and clunkiness around each of the individual lines of the P&L and balance sheet. We'll give you a very clear route map of what that looks like. In terms of Is that okay, Alastair?
Yeah, that's perfect. Thank you.
Okay. Then in terms of the target of $9 billion-$10 billion, I'll wait till we get to the end of this year. Against that target, I think we are close to $7 billion delivered with a further $2 billion-$3 billion to come. On track with the targets and the way in which Tufan laid that out to 2021.
Well, what do you think it'll be quite lumpy into 2021, Brian? Or do you think it'll be steady?
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 seven quarters, 'cause it'll be a function of whatever the hell oil price or other factors are doing at the time. That what I think you've seen Tufan and his team create in the downstream is a huge amount of resilience to deal with various economic factors that may impact that business. I think, you know, the biggest one of those was the way in which Tufan and the team have been able to neutralize the volatility of refining margins in their base business. We could lay a plan out for you. I will guarantee we will not follow the exact quarter-by-quarter trend of that plan.
I think what Tufan has created is a huge amount of optionality within his portfolio to manage that, and therefore we have confidence around his delivery.
Can I just clarify, do you think the sort of macro environment of the trailing 12 month is representative of what you envisage for 2021 in that target?
I think we, well, we already know we're in a very different environment, because originally the whole environment we set for all the targets is around $55 / bbl real. You know, 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 are a broken record, but volumes are back below the five-year average or certainly close to five-year average, both on a macro global economic basis and within the U.S. I think certainly oil prices are pretty well underpinned above 70 for the next sort of, you know, six-month period or so. At least we can't see anything which would majorly move those out of kilter with that.
There may actually be some movement to the upside, but I think, you know, ± $10 / bbl is pretty tough to call it. By the time we get to 2021, I think, you know, 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. I think, you know, 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 called Whiting Refinery, which can take up to 320,000 bbl a day of heavy crude. It's clearly not at those sort of levels given curtailment issues.
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. 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. We're already seeing that through these first seven quarters.
Brilliant. Thank you very much.
Okay. Thanks, Alastair. We'll next go to Henry Tarr at Berenberg. Henry.
Hi there, thanks for taking my questions. Firstly, looking at new FIDs, have there been any changes to the strategy in terms of contracting? You're looking to sort of lock in low costs, for example, or do you see sort of no reason to do this today? 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, 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, on the optionalities. In terms of FIDs, I think we've already done five this year, from memory, which is around I think Oman, a couple in North Sea, India and Angola, where we've seen five 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. A lot of our rig contracts will be on a sort of five to seven year basis on a rolling basis. We're certainly not seeing any inflation on the rig rate side right now.
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. That's the whole purpose of the sort of central projects group and the central procurement group, so the upstream that do those things. I think we've already got locked in contractually, a lot of activity associated with some of these projects. That's sort of point one. In terms of opportunity set, I mean, I think, you know, we announced in September we've acquired a license in the Santos Basin. That would 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 two or three years.
We have a great partner there, Petrobras, that we're working with. 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 billion-$17 billion frame that we've already laid out. Maybe just building on that, you'll 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. But that's all within the $15 billion-$17 billion frame.
Okay, great. Just one quick follow-up then. With oil prices where they are now, are you seeing a greater emphasis than on exploration rather than acquiring barrels at this point in the cycle?
I think it's a mix. I mean, you know, you always wanna be able to find oil with your own drill bit or, you know, through exploration. That's always the primary focus, 'cause ultimately it'll 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. The more that we see of those assets, we can see that. I think it's gonna be a mix going forward. 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 Jon Rigby at UBS. Jon.
Yeah, hi. Good morning, Brian. Two , quick questions on one on disposal. If I'm right, I think you count the ConocoPhillips transaction as a disposal. Am I right in thinking that the net cash in through the fourth quarter, 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 sort of an aggregation of that's linked to BHP plus I guess you probably want to continue to pursue the $3 billion ongoing disposal plan as well. Probably closer to $8 billion-$10 billion for 2019.
Just secondly, linked to that, but sort of more philosophically is, I know you keep talking about your 20% to 30% band, but it seems to me that over the last couple of years, BP's been, you know, wanting to be opportunistic in making acquisitions of assets and so on. I'm aware, you know, the Abu Dhabi transaction, you issued stock. This one you almost did, have chosen not to because of the complexity and the value, and I completely agree with the decision you made on that. Wouldn't it be better, all things equal.