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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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 First Quarter 2019 Results Presentation. I'm Craig Marshall, BP's Head of Investor Relations, and I'm here today with our Chief Financial Officer, Brian Gilvary. We are hosting our call today from Los Angeles in the U.S., where we are separately meeting with a number of our venture partners. It's also an opportunity to meet with some of our investors here on the West Coast.
With that, I'll draw your attention to our cautionary statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website.
Now over to Brian.
Thanks, Craig, and thank you to everyone for joining us on the call today. I would like to begin by drawing your attention to some changes we have made to our financial statements as a result of the IFRS 16 accounting standard that came into effect on the 1st of January, 2019, for all companies filing IFRS accounts. This new standard changes how we account for leases within our financial statements, but does not change how we run the business. While IFRS 16 has a negligible impact on underlying earnings and free cash flow, it does require changes to key lines of the income statement and the balance sheet, which we will take you through today.
You will also see that we have included further detail in the appendix of this presentation containing further information, and we plan to publish these each quarter through 2019. Additional disclosures are also included in the stock exchange announcement including on Page 2 in the supplementary information and the 2018 annual report and accounts. Craig and the IR team are also available to answer any further detailed questions after the call. In addition, with the reduced uncertainty remaining Gulf of Mexico oil spill liabilities, the detailed Note 2 in the stock exchange announcement has also been retired. Changes to liabilities will now be reported in the Additional Information section of the SEA alongside disclosures on cash flow in the quarter. Turning to highlights from the first quarter. Despite a volatile price environment, we have made a good start to the year building on the underlying operational and financial momentum established over the past couple of years.
We reported underlying replacement cost profit for the first quarter of $2.4 billion with underlying operating cash flow of $5.9 billion including a $1 billion seasonal build in working capital. We continue to make good operational and strategic progress across our businesses. In the Upstream, our operated plant reliability remains strong at 96.2%, and we continue to grow our balanced portfolio with 3 major project startups further underpinning our 2021 growth targets. We have also taken a number of final investment decisions on key projects, and we are progressing in integrating the recently acquired Lower 48 assets into our BPX Energy business. In the Downstream, we have momentum around our growth agenda with the continued marketing expansion into growing markets, notably this quarter in China, where we are positioning ourselves to take advantage of growing demand in the region. We also continue to advance our approach to the energy transition, recently announcing progress against our near-term emissions targets. By the end of 2018, we had delivered 2.5 million tonnes of sustainable greenhouse gas reductions across our business since the beginning of 2016. And on methane, we reported an intensity level of 0.2% in 2018, consistent with our target. And we announced the creation of $100 million fund as part of the ongoing engagement across the business supporting new emission-reducing projects in the Upstream.
Before turning to our financial results, a few comments on the macro environment. Brent crude recovered from around $50 per barrel at the end of 2018 to $68 per barrel at the end of March and is currently trading around $70 per barrel. The average price of Brent in the first quarter was $63 per barrel compared with an average of $69 per barrel in the fourth quarter.
The recovery through the first quarter reflects improving compliance around production cuts within OPEC and participating countries, alongside the continuing supply disruption associated with the ongoing political uncertainty in Venezuela.
Strong LNG supply growth since the end of 2018, coupled with warmer weather, caused global gas prices to fall through the quarter, notably in Asian and European markets. In the U.S., the return to more normal storage levels saw Henry Hub gas prices reduce to an average of $3.20 per million British thermal units compared with $3.70 in the fourth quarter. We expect LNG oversupply to continue through 2019, largely exceeding Asian demand growth with excess volumes being redirected primarily to Europe. BP's global refining marker margin dropped to around $6 per barrel in January before rallying to around $15 per barrel at the end of the quarter as refining outages, particularly in the U.S., led to reduced inventories. Across the quarter, the marker margin averaged $10 per barrel compared with $11 per barrel in the fourth quarter.
Looking ahead, we expect oil demand growth to remain relatively robust and supply growth to be modest, with disruptions in Venezuela and Iran continuing and ongoing compliance from the OPEC alliance in the first half of the year. These factors are expected to partly offset the increase in U.S. production, which is currently around 12 million barrels a day.
In North America, increasing offtake capacity from the Permian and the closer matching of production and pipeline export capacity is expected to keep the WTI-WCS differential at around the levels seen in the first quarter. Moving to our results. As I mentioned earlier, our first quarter results reflect the adoption of IFRS 16. This accounting standard brings off-balance sheet leases onto the balance sheet in a similar way to how credit rating agencies have historically determined extended net debt in their cash cover ratio calculation.
As of 31st of March, 2019, the lease liability on the balance sheet was $10.3 billion assuming a weighted average discount rate of around 3.5%. Some items have been reclassified within our income statement with operating expenses lower, but offset by an increase in DD&A and interest costs. In total, these changes have a negligible impact on group underlying replacement cost profit. Further information on the first quarter impact is contained in the appendix and the SEA. BP's first quarter underlying replacement cost profit was $2.4 billion compared to $2.6 billion a year ago and $3.5 billion in the fourth quarter of 2018. Compared to the fourth quarter, the result reflects lower North American heavy crude differentials and refining margins as well as lower Upstream realizations. It also includes a lower fuels marketing result and the impact of Upstream portfolio divestments and turnaround activity in the Gulf of Mexico. This was partly offset by a strong supply and trading result in both oil and gas and a lower level of refinery turnarounds. Compared to a year ago, the result reflects lower Downstream refining margins and North American heavy crude differentials as well as lower Upstream liquids realizations and the impact of turnaround activity in the Gulf of Mexico. This was partly offset by strong supply and trading performance in both oil and gas, an increased contribution from Rosneft and an improved fuels marketing result.
And finally, the first quarter dividend payable in the second quarter remains unchanged at $0.1025 per ordinary share. Turning to cash flow and sources and uses of cash. To reflect the impact of IFRS 16, we have chosen to adjust how we present sources and uses of cash to include lease payments as a use of cash. Lease payments are no longer reported within underlying operating cash flow increasing the reported number by around $500 million. Similarly, they are no longer reported within capital expenditure, resulting in a decrease of around $100 million. Taken together, these changes are offset by the addition of $600 million of lease liability payments, meaning free cash flow remains unchanged. Excluding Gulf of Mexico oil spill related outgoings, BP's first quarter underlying operating cash flow was $5.9 billion, which included a seasonal working capital build of $1 billion. Organic capital expenditure was $3.6 billion in the first quarter. Turning to inorganic cash flows. In the first quarter, divestments and other proceeds totaled $600 million, and we made post-tax Gulf of Mexico payments of $600 million. Inorganic capital expenditure was $2 billion including 2 further payments to BHP of $1.7 billion. The final 2 payments to BHP were made in April. We have continued our share buyback program, buying back 6 million ordinary shares in the first 3 months of 2019 at a cost of $50 million. Turning to operational highlights in the quarter. In the Upstream, we have had a strong start to the year, announcing 3 of the 5 planned major project startups in 2019: Constellation in the Gulf of Mexico; West Nile Delta Giza/Fayoum in Egypt; and Angelin in Trinidad. We have now brought 22 Upstream major projects online since 2016 and have 13 more to go as part of our plan to deliver 900,000 barrels of oil equivalent per day of new major project production by 2021.
We've also taken Final Investment Decisions or FIDs on 3 advantaged oil projects: Atlantis Phase 3 in the Gulf of Mexico; Seagull in the North Sea; and Azeri Central East in Azerbaijan. This recent FID in Azerbaijan sanctions a $6 billion development including a new offshore platform and facilities designed to process up to 100,000 barrels of oil per day gross. The project is expected to achieve first production in 2023 and produce up to 300 million barrels over its lifetime. And as I mentioned earlier, BPX Energy continues to integrate the Lower 48 assets acquired from BHP into its operations. Full control of field operations was assumed at the start of March, and we have 14 drilling rigs operating at the end of the first quarter; including 3 on our new Permian Delaware acreage and 5 in the Eagle Ford. We continue to be confident in the delivery of the synergies created by the transaction and are increasingly seeing further upside potential that was not assumed in our base case.
Looking to the Downstream. In fuels marketing, we continue to expand in new markets, adding more than 260 retail sites in the last 12 months. We have opened our first BP-branded retail station in Shandong Province, China, through our joint venture with Dongming. This marks the start of our plan to add 1,000 new sites over the next 5 years to our existing network in China of more than 740 sites.
In manufacturing, we have continued to grow volumes of bio-feedstock processed across our refineries. We also agreed an expansion of production capacity at our joint venture petrochemicals facility in South Korea. This will allow us to help meet the region's growing demand and will bring the total capacity of the plant to over 1 million tonnes per annum.
We are also in action across our businesses as we look to advance the energy transition.
In March, we established the Upstream Carbon Fund with a pledge to invest up to $100 million over the next 3 years supporting projects to deliver new greenhouse gas emission reductions in our Upstream oil and gas operations. We also entered a 3-year strategic agreement with the U.S. Environmental Defense Fund collaborating on projects to reduce methane emissions from across the global oil and gas supply chain.
And in Air BP, we have recently announced an agreement with Neste to supply sustainable aviation fuel to customers. Turning to the outlook for the second quarter. In the Upstream, we expect reported production to be broadly flat compared with the first quarter. This reflects the ramp-up of major projects, offset by ongoing seasonal turnaround and maintenance activities in high-margin regions.
In the Downstream, we expect higher industry refining margins compared to the first quarter, a similar level of North American heavy crude oil discounts and a significantly higher level of refinery turnaround activity. Following adoption of IFRS 16, we've updated some of our full year guidance. This ensures we retain a consistent financial frame enabling us to continue to track our strategic progress against this guidance as well as our medium-term targets. Under IFRS 16, we now recognize leases on the balance sheet as right-of-use assets. This results in a corresponding lease liability on the balance sheet, which we've disclosed separately to finance debt. The depreciation of the right-of-use asset is expected to increase our DD&A charge by $2.5 billion for the year. As mentioned earlier, the DD&A charge is largely offset by changes in other items in the income statement, resulting in a negligible impact on group underlying replacement cost profit. Turning to gearing. As lease liabilities are disclosed separate to finance debt, they are excluded from our definition of net debt and gearing. This ensures gearing remains consistent with the financial framework, with guidance maintained within a targeted range of 20% to 30%. In addition and for comparative purposes, we also report net debt including leases in the stock exchange announcement.
Following cash payments made during the quarter for BHP's onshore assets, gearing stood at 30.4% at the end of the first quarter. With divestment proceeds expected to be weighted to the second half of the year and assuming a Brent oil price similar to that seen in the first quarter, gearing is expected to remain around the top end of the 20% to 30% range through the middle of the year.
Organic capital expenditure is expected to remain in the range of $15 billion to $17 billion. We will update you on the range through the year, including taking into account the impact to organic capital expenditure arising from IFRS 16. Now turning to our medium-term financial frame. Organic capital expenditure is expected to remain in the range of $15 billion to $17 billion per year. Over the next 2 years, we plan to complete more than $10 billion in divestments. Our balance sheet and cash cover metrics remain strong. Free cash flow is expected to continue to grow. Alongside the receipt of divestment proceeds and assuming recent average prices, we continue to expect gearing to move towards the middle of our targeted range of 20% to 30% through 2020. And finally, we remain confident in our guidance on returns exceeding 10% by 2021 at a $55 per barrel real price assumption. In summary, we are entering the third year of our 5-year strategy and remain on track to deliver our 2021 targets. Through a continued focus on the disciplined execution of our activity set, we are building strong strategic and operational momentum across our business and are becoming increasingly resilient to external challenges and the evolving energy transition.
Our financial frame remains robust with operating cash flow and returns expected to continue to grow. Along with proceeds from our divestment program, this is expected to support growing free cash flow. This, in turn, should enable the strengthening of our balance sheet and support our commitment to growing distributions to shareholders over the long term. On that note, thank you for listening. We look forward to seeing those of you who are attending our Annual General Meeting, which this year is being held in Aberdeen on the 21st of May.
Let me now turn over to your questions.
[Operator Instructions]
Okay, thank you, everybody, for listening. I think we're going to turn to questions and answers now. [Operator Instructions] Let's take the first question, please, from Os Clint at Bernstein. Os?
Yes. Brian, I'd like to ask about maintenance, please. I think in the first quarter, there was -- you mentioned Gulf of Mexico maintenance, but I think there were some U.K. maintenance as well, both high-margin areas. But you're also talking about high-margin area maintenance in the second quarter as well, and I assume there's always some 3Q maintenance. So I'm just curious, is the level of maintenance this year higher than normal? Or is it front-end loaded this year and the second half should be free of maintenance? And ultimately, is cash flow this year potentially less than it should be if this maintenance seems to be a little bit higher than normal? That's the first question.
And secondly just on lubricants. It's normally your most, let's say, predictable number. It was much weaker in the first quarter. You spoke about some FX and one-off costs. I just wondered if you could quantify those. And is that really the delta here to the weaker lubricant result in Q1?
Thanks, Oswald. So on maintenance and turnarounds, we're back into now sort of steady-state, the routine flow of maintenance. You'll recall post 2010, we went through a big maintenance program in the Upstream. Something like 48 turnarounds in 2011, 35 in 2012, another 25 in 2013. We're now into a more steady-state. But as you've already highlighted, in 1Q, we did have the big high-margin Thunder Horse out, in the turnaround, that successfully came back. 2Q, [ what ] we do in Upstream, it's not -- there's nothing peculiar about this year in particular. But the timings of turnarounds and when we're doing those, there's nothing peculiar about that as well. But in the second quarter, we will have 3 turnarounds in Upstream all again in high-margin areas that will impact 2Q results. It's in Azeri, in AGT, Na Kika in the GoM and PSVM in Angola. So there will clearly be an impact in Q2. But of course, we've also got the ramp-up of the projects with the 3 projects coming onstream in the first quarter. Another project to come onstream potentially in the second quarter and then Raven at the back-end of the year. So that will compensate for some of the lost volumes via those turnarounds.
We've also got in refinery -- in the second quarter in refining, we've got turnarounds across 5 of our refineries of different scales and different sizes, but typically, 5 to 6 weeks in each case. And that's really getting the refinery system ready to ensure that we are operating at full tilt with IMO 2020 coming in next year. So that's basically what's going to happen as we go through the second quarter.
In terms of lubricants, I think the question came up on the previous call and indeed, the previous call before that. There has been a headwind that the lubes business has been dealing with ramp base oil prices. That is starting to level off now. So base oil prices have dropped off actually in 1Q versus the actual average for 2018 and 4Q, but it will take a period of quarters for that to start to come back through the numbers. So I think it's the last of the headwinds that we can see inside lubes.
And you'll know at the end of last year, we announced a big rationalization program of up to 800 jobs that will go out of lubes as part of a bigger efficiency drive. So I think you would start to see and anticipate a recovery in lubricants going forward, but you're absolutely right to highlight. It's been an issue for the last 6 quarters now, but a lot of that is being driven by the higher oil prices. Notwithstanding where base oil prices go into the future, you will start to see some recovery in those numbers going forward.
Thanks, Os. We'll take the next question from Biraj Borkhataria at RBC. Biraj?
Two questions, please. The first one is on Macondo. You guided to the $2 billion per year, but Q1 was just about $600 million. And then also in Q2, you had the predefined payment of, I think, $1.2 billion. So putting those 2 together, it suggests very little in terms of bell payments for the remainder of the year. So just want to get your thoughts on that and whether you feel comfortable with that guidance.
And then the second question is on more broadly the market for asset sales at the moment. A number of your peers are executing fairly significant asset-for-sale programs. I was wondering if you could talk about what you're seeing in the market and your confidence in your ability to execute on those.
And just related to that, in terms of gearing items getting to the midpoint by year-end, does that assume any benefit or divestments cashed in? Or is that on an organic basis?
Yes. Thanks for that, Biraj. On Macondo, we've said just over $2 billion for this year. We're on track for that. We're really now into the scheduled payments. We're down to sort of effectively all the claims have now being processed in the bell system, and we're simply now into the appeal stage where we have a series of appeals that will go forward to the court over a period of years, and that will get resolved and get taken each quarter. We took a few this quarter, but that number looks pretty well underpinned; and the other payments for scheduled payments from the settlements from 2012 and the settlements of July 2015. So that's pretty much structured now and order going forward, and we will live within that. And then for next year, it's gets to more like just over $1 billion a year on a point-forward basis.
Asset disposals, we've got -- we did $600 million of cash came in, in the first quarter. We have a suite of packages in Lower 48 that we've talked about. I guess, we've been surprised by the level of interest in the packages. There appears to be a lot of expressions of interest. And we already have across 3 of the package suites, a first round of indicative bids in. So actually, that market looks pretty well underpinned on the disposal side. And as you say, there's a lot of activity in the market, but there's still an awful lot of interest in those assets, both from neighboring companies that you'd expect, that are close to the proximity of some of those assets, and also from private equity, which we've seen across the piece. So they look pretty well underpinned.
On gearing, I think what the guidance we've given you is we'll be back towards the middle of the range by 2020 is what we've said given that we moved to the BHP cash payments rather than using shares. And as disposals come through now and certainly, with the higher oil prices that we're seeing today, we'd expect to see that gearing track down. The big payments around BHP are pretty much now gone out. The balance of those will get paid out this month in April. In fact, I think the final payment may well have just gone. And so it's just the Macondo payments that you picked up as the first part of your question to go out next quarter around the scheduled payments. And then, with the oil price where we are today and we see disposals coming through certainly in the second half of the year, primarily loaded to second half of the year, you'll see gearing naturally track down.
Okay. Thank you, Biraj. We'll take the next question from Christyan Malek at JP Morgan.
Just sort of revisiting the capital frame and just trying to understand best the relationship between the timing of disposals and incremental cash return. And clearly, the progress from the disposal program you've outlined, it seems to be well underpinned, albeit sort of it's fairly low in Q1. Can you sort of firm up if there is a relationship between your disposals and ability for you to sort of instigate or is there a threshold where you can then instigate increased shareholder distributions? I know we understand that the path to deleveraging, but it would be great to get some more clarity around that outlook on cash return. Is it sequential? Or can you -- how should we be thinking about it?
That's a great question. And the way we think about it is having moved the BHP transaction to a cash-based transaction, clearly, that means that you need to be able to absorb that through the financial frame out to the end of this month, and as I've said, our final payment has now gone. Once that's absorbed and the first suite of disposal proceeds come in, that then creates the space for a conversation at the Board around dividend distributions going forward. We also have a significant buyback program for the second half of the year that we've committed to around offsetting the scrip, which would be somewhere just north of $1.5 billion now, $1.5 billion, $1.7 billion of scrip to still repurchase, which is the outstanding scrip that's been issued since 2017 when we got the company back into balance.
I think one of the sort of things that gives us confidence in that, Malek, is actually, in the first quarter, we'd cash breakeven, even with the big turnarounds, with the weather problems that we saw in Northern Colorado around our Lower 48 business and the portfolio disposals that went out last year, we were still balanced at just over $50 a barrel, which is a very good place to be given where the actual flat price is today. And we had to deal with refining margins down, at indicator margins down at $6 a barrel at the start of the quarter.
So I think as we look and reflect on this quarter's results, it's a very resilient portfolio we have. And yes, 1Q is helped by supply trading, which we will have quarters from time to time where we get a strong result. But I think that's given us confidence in terms of what the financial frame looks like for the second half of the year and there will certainly be a conversation about distribution supplies in the year.
Thank you, Christyan. We'll take the next question from Lydia Rainforth at Barclays. Lydia?
Two questions, if I could. The first one just on the unit OpEx side. That looked like it was down 4% year-on-year, but I didn't know if that was just IFRS 16 or if you're still seeing underlying progress on the cost base.
And then second, given that you are in L.A., can you just talk about the -- what venture partners you have and what that -- in terms of what they are offering the BP business?
Thanks, Lydia. The unit OpEx is all IFRS 16, so actually, we're sort of flat year-on-year, which given where oil prices are, I think is a good result at this point and the ramp-up that we have that we can see this coming through. But effectively, that's IFRS 16. So DD&A has gone up and the operating costs have come down. And it's been quite a noisy quarter trying to get the IFRS 16 numbers through, and we've tried to give you a variety of tables to help explain what those movements are.
If you look at the venture piece, within this week, we've got the whole executive team out here. We've got various conferences that the different members of executive team are meeting and involved with. But then we've got 2 days with a lot of our venture capital. The guys are out at the Biosciences Institute that we have here in San Francisco tomorrow, so we've got a whole team that will be visiting our bio -- which is a BP Biosciences Institute. And then for the rest of the week, we're meeting with various companies that we've invested small seed investments in, and it gives us a sense of how they are progressing. Some are disruptors in terms of the business that we operate in. Some are going to help us be able to enhance some of the things that we're doing. There'll be a variety of companies that we'll be talking to, companies like Fulcrum and Freewire that we've talked about before on these calls. Freewire around mobile charging in some of our stations and Fulcrum, which basically takes waste to create jet fuel with the first pilot plant that's been commissioned out -- or is being commissioned out here in California. So it's going to be quite a wide varied suites of companies that we'll be talking with, and it will give us a little bit of a sense of how things are progressing in a number of different spaces.
Thanks, Lydia. We'll take the next question from Alastair Syme at Citi.
Can I just ask about the gas trading, just to get a perspective on where the gain came from? Is it sort of you're positioned across the book for the weaker European and U.S. pricing -- and Asian pricing? Or is it more to do with the volatility? And is there any way you can help us think about the magnitude of that gain?
Yes. We wouldn't normally get into a lot of detail, but I can give you a sense of -- in terms of the gas trading. A proportion of it came out of a very strong result out of North America, which was really positioning on some of the books around the cold weather that we saw that came through, which are around some of our bases positions allowed us to be able to capture the benefits of that. And also around our LNG book, which is really focused out of European gas and some of the LNG prices that we saw as the oil price weakened. It allowed us to play some arbitration plays that we had across the Atlantic. So it was across the piece, but I would say the big 2 chunks of the overall performance in 1Q was United States and LNG out of Europe.
I guess I'm getting -- it's a point, Brian, around given there's still a disconnect between spot and oil linked to pricing in Asia and Europe. Is the book still set up potentially to benefit from 2Q, 3Q, that kind of trend?
Yes. It's -- I can't really call it by quarter. We have a book where we have -- I mean, yes, we should expect. We have a number of equity positions, then we have a book of structural shorts that enable us to manage the arbitrage of the various prices that we have on those books. And some of those shorts are hub-based, some of those are Asia oil-related prices and some of those are European prices. And some allow us to optimize across the piece. But I couldn't call it quarter-by-quarter, but there's -- we certainly wouldn't reveal now that there's a structure that's sort of sitting there for 2Q. But it'd be really around how we can optimize the various shorts that we have and the ability to be able to trade some LNG molecules into those.
And finally, was there anything you could do to help us with magnitude?
I'm sorry, say that again?
Was there anything you could to help us think about the magnitude of what happened in 1Q, the gain?
Yes. No look, a strong result is normally where we have an average quarter result that we expect for trading. The indication of strong would normally mean that it's certainly over $100 million more than we would have expected in a typical quarter.
Thanks, Alastair. We'll take the next question from Jason Gammel at Jefferies.
A couple on the Downstream, if I could, please. Can you first of all talk about the situation at Whiting right now in terms of apportionment on the pipeline system, if you have any scheduled maintenance on Whiting specifically as we head into 2020?
And then the second one is just on the marketing business. It's clearly been a source of earnings strength for you recently. I was hoping you could maybe talk about the magnitude of the increase in earnings that you're seeing in the marketing business as a result of expansion.
Yes. So maybe on that last one, what we saw quarter-on-quarter versus last year in the fuels piece, something close to $300 million to $400 million of growth. A chunk of that came from the trading result that we talked about in terms of oil trading in 1Q. For fuels marketing, we're continuing to see growth year-on-year. And this is the strategy that Tufan and the team are executing very effectively. One example of that would be Mexico where we've effectively gone within 18 months of a standing start, we're now pumping more volume than we've pumped as the #2 player in the Netherlands. So just to sort of put it in context. But the build-out and growth of the fuels marketing strategy along with the convenience offer has become a very effective part of the portfolio, which is underpinning those targets that we've set out there in terms of $9 billion to $10 billion by 2021 of EBITDA free cash flow. And sorry, what was the second question?
Just the situation at Whiting related to apportionment and whether there is any maintenance plan at Whiting before IMO 2020 picks up.
Yes. I think we've got one small unit at Whiting that will be going through the maintenance this year, getting ready for IMO 2020 next year. And on apportionment, you'll be aware that Alberta -- the Alberta government effectively curtailed production through there to the tune of about 325,000 barrels a day in early -- I think late December, early January. We've seen that back off a little bit, but we would expect to still see -- I don't think you're going to see the sort of levels of light to heavy diffs that we saw last year. There's a number of things exacerbating that issue. There's the Canadian issues where we think curtailment will start to ease. We've already seen that crude production curtailment alleviated to about 250,000 barrels a day in February, and we'd expect to see gradual reduction to bring that back into where we were before. But equally, you're also seeing Venezuela and heavy production off the market through the sanctions, and therefore, you're seeing a tightness in general light-heavy diffs, which is exacerbated. I mean you look at the WTI-WCS diff and you're seeing the opposite with light crudes coming out of the United States, the sort of availability of light crudes. So I think that's going to be a structural thing that we'll certainly see through the next 6 to 12 months. I wouldn't expect to see big movements in light to heavy spreads going out for the rest of this year. But as the Canadian production starts to alleviate, you'll start to see that the spread open up more than what we see today. And we certainly saw it down at, I think, around at $9 at one point during the first quarter, and it's moved back up I think $12 to $13 now.
Okay. Thanks, Jason. We'll take the next question from Thomas Adolff at Credit Suisse. Thomas?
Two questions for me, please. Firstly, just operationally, as you look at the first quarter of this year or call it almost halfway through your 5-year plan, is this so far consistent with your internal assumptions? Are there any areas where things didn't go according to plan or areas that significantly surprised on the upside?
And secondly, just going back to the question on trading. Correct me if I'm wrong, gas trading is booked in Upstream and oil trading is booked in Downstream and perhaps you can comment on the oil trading side of things, how that compared on a quarter-on-quarter basis as opposed to year-on-year.
Thanks, Thomas. Operationally, I think actually, it was a stronger quarter for 1Q in terms of the Upstream than we might have anticipated. I think availability is up around 96.2%, which is a pretty strong -- it's a very strong number in the context of a single quarter. To be able to maintain that through the year, would be an exceptional result. But 96.2% for the first quarter was very strong and certainly, higher than we would have expected for our plans. But I think that reflects on the fact that we knew that we also had the Thunder Horse turnaround to deal with. So operationally, it was probably a slightly better quarter than we'd have expected in the Upstream.
On the Downstream, I think it was more -- looked more like an average quarter for 1Q. And then on the trading result, you're right. The gas trading gets reported through Upstream. The oil trading gets reported through Downstream. And certainly, this was a new quarter that both divisions generated strong results in both of those, and you will have seen some of that flow through to Downstream result. Similar orders of magnitude that I talked about around gas trading in terms of being above an average quarter and that's sort of hundreds of millions of dollars compared to, say, double digits. But yes, no, it was a good quarter.
Thanks, Thomas. We'll take the next question from Irene Himona at Soc Gen. Irene?
Two questions, please. Firstly, BPX, obviously, the first full quarter with the BHP assets. But I note that the production cost per BOE is up both sequentially and year-on-year by double digit. I wonder why that was and what you anticipate going forwards.
And secondly, Brian, you referred briefly to IMO 2020. Have you seen any impact from that in the market? And if not, would you expect to see any changes to product and crude differentials in the second half of the year?
Yes. So on the BPX, the simple answer is BHP's, the sort of more oilier side of their portfolio, carry higher unit production costs than the legacy BPX. But also, we had the volume outages with that weather Arctic polar vortex that hit northern Colorado with about 8-foot of snow. And there's some quite astonishing pictures of the assets being under snow, and therefore, some production was curtailed. So I think it's a combination of both. But I think primarily, it's driven by the fact that the unit production costs of the BHP assets that we acquired are on a higher level than the BPX legacy ones.
In terms of IMO 2020, everything looks pretty well set in terms of compliance, and I think you'll start to see in the back end of this year that will help underpin certainly margins going forward, at that end of the barrel. And we are expecting to see sort of compliance and adoption. There'll be the odd place in the world where I think exemptions will be put in place, but I don't think they're going to be significant. So I think there will be some upside and underpinning of the numbers going forward in terms of margins by the back end of this year.
Thanks, Irene. Okay. We'll take the next question from Michele Della Vigna, Goldman Sachs. Michele?
Brian, 2 quick questions, if I may. The first one relates to the production from your new projects. You reiterated a target of 900,000 barrels per day by 2021. I was wondering how much they have contributed to the first quarter production.
And secondly on BPX, we are seeing costs of completion in the U.S. coming down from the beginning of the year. I was wondering when you would think it will be optimal to start to ramp up the activity in the Permian.
Okay. So on that last question, Permian, we're already up to 3 rigs. And, in fact, we've got 8 rigs now working, 5 in Eagle Ford, 3 in Permian from the new acreage. So things are already starting to ramp up in there and we'll be able to -- I think as the previous question highlighted, we've only got a month's worth of BPX now. I think when we get to middle point of the year, we'll be able to give you a much deeper update on synergies, which look pretty well underpinned from what we can see. In fact, actually, the assumptions on synergies now looks somewhat conservative given what we've discovered in terms of the operations and what we've been able to absorb within our existing structure. And we'll be able to give you more of an update on where we are in terms of costs and integration and the absorbing that business. So I think there'll be more to follow on that middle of the year.
In terms of the ramp-up of major projects, it's up over 500,000 barrels a day from the 22 startups that we've had, up to the end of 1Q '19. In fact, it's above -- it's between 506 and 1,000 barrels a day is now onstream and online. And the track looks pretty good now in terms of that ramp to the full 900,000, and of course, BPX sits on top of that 900,000 barrels that we described in [indiscernible]. So I think things are looking pretty well underpinned, all the projects we need onstream are FID-ed or in operation now. And that's why we feel so confident about the 2021 targets and delivery of those given a lot of the portfolio's now been derisked by those projects coming on. And of course, we had the 3 that came on in the first quarter, which derisks another big piece of the portfolio, with the big 2 major ones now in the second half of the year of Clean and Raven in Egypt.
Thanks, Michele. We'll take the next question from Lucas Herrmann at Deutsche Bank. Lucas?
A couple, if I may. Brian, first, just going back to U.S. profitability, and maybe this comparison's unfair given it's different quarters. But I'm slightly staggered that the reported EBIT in the U.S. can move from $1.4 billion in Q4 to $600 million in Q1 given, the modesty, shall we say, of the production down and a relatively limited overall decline in price. That was the first. Just some better understanding of that quarterly move.
And the second, there's always a tension between return and resource in the oil industry. And I just wondered how you feel strategically about your position in Brazil at the present time, the acreage you have and whether the company would like to have a more material position going forwards. And obviously, that's with reference to the sale of rights that's expected later on this year and how BP might be thinking about that opportunity.
Thanks, Lucas. And yes, absolutely right about U.S. underlying earnings. There's 3 areas that have driven that reduction of $1.4 billion down to $600 million, which yet again, you'll find inside the SEA. The first one is the low realizations of $51 a barrel in 1Q versus $62 a barrel in 4Q. So you've got the actual realizations, because there is some lag effect that's come through in those numbers. There's also lower U.S. natural gas realizations. I think they came in around $2.60 versus $3.10 in 4Q. And then, of course, the third large item would be Thunder Horse. And I mean that, in some respects, shows you and demonstrates quite clearly the importance of those high-margin barrels coming through the portfolio. And that really makes up -- those 3 big components make up 85% of what we can see there in terms of underlying ARCOP.
In terms of returns and capital frame, Brazil, of course, is very interesting for us. We went into Brazil back in 2009, 2010 with the Devon acquisition. That allowed us to find some commercial resources, but didn't really play out the way we may have anticipated. And there are clearly opportunities for us going forward.
I think the key is similarly with what we did around BHP. Anything we look at needs to be accretive for our existing business, so to the degree that we get production accretive to earnings both on a cash and earnings basis and returns, and can be lived with within our capital frame because we've set a capital frame of $15 billion to $17 billion. If we have to step outside of that, then we need to find other parts of our portfolio that we can liquidate to pay for that potential growth. So it's no different to what we've looked at around the BHP position, where we've come up with a pretty significant suite of disposal that will cover half the investment inside there. But yes, Brazil is of interest. It's going to be of interest to everybody given the attractiveness of those assets, but we'd have to ensure we could do that within our existing financial frame.
Thank you, Lucas. We'll take the next question from Martijn Rats at Morgan Stanley. Martijn?
Yes. I only have one left. You mentioned briefly it's sort of a joint venture you set up with Neste Oil on renewable jet fuel. And when you answered Lydia's questions on sort of private equity and other sort of technology partners, you also mentioned a partner that is looking at renewable jet fuel. I was wondering these are fuels that I would imagine that at the moment BP cannot make itself but where you are seeing a growing market. I was hoping if you could elaborate a little bit on this.
Yes. Martijn, I mean, that's a great question. I think it tells you a lot about how this space will play out into the future as we think about climate change and the desire to try and get take less carbon intensity in the portfolio as we meet this dual challenge of eradicating poverty, growing energy. There will be a variety of partnerships that will come up. Neste was an interesting one for us. It was specific to aviation fuels out of Sweden. And there's no question, the aviation market will grow at rapid rate of knots going forward. There's a relatively small part of the population's never flown on airplanes, and that's likely to grow into the future.
And finding a solution, a sustainable solution to what that looks like will require the development of more sustainable aviation fuels. Fulcrum is an example of what we're trying to do around waste, taking basically household waste and creating a biojet fuel, which would be a solution for the future for the planet. And this was just another example. But I think what you're going to find is in this space of reducing carbon intensity, it will throw up a number of joint ventures and potential collaborations across the piece as we all try to do our piece in terms of trying to manage climate change effectively in terms of carbon intensity going forward.
Thank you, Martijn. We'll take the next question from Chris Kuplent at Bank of America. Chris?
I've got 2 questions left, although my typical disposal question's already been answered, so thanks for that, Brian. Just on buybacks, you very helpfully showed us or mentioned the scrip amount of issuance you're trying to offset by the end of this year. Can you remind us why you picked Q3 '17 and what we might be able to look forward to beyond 2019 in terms of future buybacks, linking those to historical scrip dividends up until Q3 '17, which I think still run in the billions?
And second question, BP is still adhering to a Downstream, Upstream segmental reporting structure. Are you of the view that as you increase, let's say, earnings contributions from higher multiple businesses, as your lower carbon business grows, are you of the view that it might eventually make sense to split them out separately in your reporting?
Thanks, Chris. On the first question, 3Q '17, actually, it was the point in which we declared that we were back into the balance of $50 a barrel, and therefore, we said we'd offset scrip from that point forward. And I think the actual figure that's now outstanding is something like 231 million shares that have not been bought back since that point in time. So it's about 1 point -- I think it's $1.5 billion, $1.7 billion depending where the share price is of buybacks required going forward, probably close to $1.7 billion. But it was effectively determined by that point in time. But what we committed to in 3Q was we would fully offset scrip on a point-forward basis, which is what you should expect us to do. And the $50 a barrel I quoted for 1Q included scrip, on a cash basis, more like $40 -- I think $42 a barrel given the large scrip uptake that we had in 1Q. But that's been added on to the outstanding shares going forward.
And then in terms of segmentation, I think once those businesses become significant, then we will look at maybe there are further disclosures. We've done that around fuels, chemicals and lubricants, which you can see. The sub 7 divisions that we put in place back in I think 2010 or 2011, we went to sub segmentation of those businesses, may even be earlier than that. And of course, we give you a lot of information around BPX. I think as our renewable -- certainly, alternative energy businesses like biofuels, wind and solar become significant enough and material enough, we will look at whether we provide more information around those, but they're still in the build phase over the next 5 to 10 years as we build those businesses out. But they will become a more and more important part of our portfolio going forward.
Okay, Brian. And just to confirm whatever then you do from 2020 onwards in terms of shareholder remuneration, you will not explicitly link to what occurred in terms of scrip issuance before that moment in time, 3Q '17. Is that right?
Well, no. So we took 3Q '17 because it was the point at which we got back -- if you recall at the end of 2014, we were about $2 billion surplus cash. You'll remember from your various notes, but we were around about $2 billion surplus cash at '14 off the back of the big Rosneft TNK transaction that we did. We were able to get the balance sheet back in structural order. That put us in a strong position as the oil price directed through '15, '16, '17. And we set a target of getting back to balance by the end of '17, and that's why we chose that particular point in time. But the Board is minded to look at distributions in the broad sense of buybacks over and beyond scrip, and that will continue, which we did. If you recall around TNK-Rosneft, we bought back $10 billion of stock off the back of that transaction. We will look at buybacks as part of the suites of options for us going forward. And so I think the key is we commit to offset scrip, which was helpful for us during the oil price correction. But we don't like the dilution. But shareholders generally like the scrip uptake, and that's why you saw a large uptake in 3Q of over 30%. And so we'll continue to offer scrip on a quarterly basis, but that will be determined by the Board each quarter.
Thank you, Chris. We'll take the next question from Peter Low at Redburn. Peter?
You've been in control of the BHP assets for almost 2 months now. Can you give us any color pm how your view of those assets have changed, particularly their potential, since the deal was struck?
And then secondly, you previously talked about 7 potential Upstream FIDs in 2019. You've done 3 so far. Can you give us any guide on which other projects you're hoping to sanction this year?
Great. Thank you. So in terms of BPX, it is literally 2 months in and the guys have also been dealing with the issues around the weather, around the existing asset portfolio and getting suites of assets ready for sale. So I think what I would say is we've got 8 rigs up and running now in the new acreage. We're learning from those. I would say everything we have seen, we will be more positive on now than when we did the -- actually did the transaction. So synergies look pretty well underpinned. The price assumptions we had are significantly above what we'd assumed. If you think at the time, we had a long-term Midland diff going to somewhere around $4 to $7 a barrel. Today, it's almost parity. It's just about $1 below given the NGL pipelines and infrastructure that was put in place in the first quarter, and there was more pipeline infrastructure to come in. So we can actually see now Midland pricing pretty much at WTI. So that's more positive. And so the absolute flat price of where we are today makes that more accretive from a -- in terms of the front-end value accretion is well underpinned now off the back of the environment synergies. And now, of course, we have the assets, and I would say everything we see so far is pretty positive, but we'll give you a more fuller update at the 2Q results where, by then, we'll have 5 months' worth of operation, and we'll be able to give you some early views on some of the results that we're seeing from the activity.
Okay. And just on the potential other FIDs this year?
Yes, sorry. So we've already had Atlantis, Seagull in the North Sea and Azeri Central East FID-ed this year. Areas that we would be looking at, we don't normally go into detail on those, but there'll be things like Thunder Horse water injection. There is still KG-D6 in India and potentially around the Herschel development, which we'll be looking at. There's also Thunder Horse south expansion that was also put in place in March 2019. But it's a question of phasing, but that's the kind of suite of options that we're looking at. So there's up to -- there's 8 FIDs, 4 of which have gone already now, with the potential for 4 more.
Okay, Peter. We'll take the last -- sorry, third last question from Colin Smith at Panmure Gordon. Colin?
Just to follow up on the scrip again. At the end of 3Q '17, you had 19.8 billion shares outstanding and you've now got 20.3 billion shares. That looks like you need to buy back more like 530-odd million shares in order to take yourself back down to the period-end number at the end of 3Q 2017. The number you're talking about is considerably less than that and I just wanted to understand what the difference was.
So the actual scrip issuance is about 231 million outstanding shares. There may be other shares that will have been put into issue around long-term incentive plans for our employee schemes where shares will have been issued against those, treasury shares will have been used for those. But I couldn't come back. We can come back off-line and give you a box balance of what that looks like. But in terms of the scrip, which is something we track, I mean, I've got a chart which I carry around with me so I can keep track of it myself. It's about 231 million shares now outstanding from when we first announced the buyback.
Thanks, Colin. We'll take the next question from Pavel Molchanov at Raymond James. Pavel?
At the beginning of the year in the strategy update, you laid out some pretty hefty exploration prospects in Azerbaijan. And I believe they were supposed to culminate in Shafag-Asiman, which is over 10 billion BOE in scale. Can you give an update on what the calendar is going to look like in terms of actually deploying the rigs and drilling those prospects?
I think if you look across the whole -- I can't give you the specifics on the Azeri position, but if you look across the whole piece, we've got somewhere around 25 exploration wells that we're looking at in 2019. Now whether they all get executed or not is it will be a matter of choice around the rig selection. But up to 25 potential exploration wells this year, and we've already got 1 discovery announced so far from the program, so far year-to-date. But we'll come back to you on more detail off-line around the Azeri prospects, which I don't directly have to hand in terms of where that program is at the moment.
Okay. Turning to an issue in Washington that's been coming up. In February, there was a bill called DASKA, which would essentially upsize energy sectoral sanctions against Russia reintroduced in the U.S. Senate. It hasn't been voted on yet. But given that it would effectively ban any U.S. domicile or U.S. operator from participating in Russian energy projects above $5 million a year, given your relationship with Rosneft, have you estimated or made any analysis of what kind of divestiture or changes in your capital spending would have to be made if this bill were to pass?
Yes. So look, we operate around the world and operate within the sanctions framework that sits in place in the places where we operate, and we try and work as closely as we can with nation states that deal with specific issues around specific countries.
There is nothing right now on the table in terms of enactment of any new policy or laws that would trigger any changes to the way in which we're operating our businesses today, particularly around Rosneft and Russia. But we would work in tandem with whatever the legislator comes through with in terms of potential sanctions. And in the same way, we have been operating within the existing sanction framework, we would look to that on a go-forward basis in those geographies. But there's nothing specific I could lay out for you today that will get into any details since we have nothing that has actually gone for legislation at this point in time. And we run various scenarios around potential outcomes of what that could look like, but we wouldn't really go through those on this call.
Thanks, Pavel. We'll take the final question from Bertrand Hodee at Kepler. Bertrand?
Brian, I have one question left. You mentioned that you expect and we are mainly to expect that LNG spot pricing in Asia and European gas prices to probably stay low for a couple quarters. What kind of headwinds do you see on your cash flow earnings resulting from that figuring weakness? BP has 0 exposure Upstream to European gas price, but do you believe this will have an impact on your LNG trading business? And can you help us quantify that, especially if spreads between basins stay low?
So I mean, I think, firstly, you're right. I think we can see an overcapacity coming through certainly in the second half of this year and probably into 2020 around LNG projects coming onstream. We've seen prices already correct down to somewhere close to $5 and MMBTU in terms of European and Asian pricing right now. I suspect that's going to continue. And I think you'll also see more exports coming out of the U.S.A. in terms of Henry Hub exports coming out or exacerbated.
From an LNG trading perspective, anything which trades volatility creates opportunity. So I think the way in which our portfolio is set up within LNG, and that may open up some opportunities for us in terms of the way in which we structured both our longs and shorts in addition to our equity positions. And the different pricing basis that we have does provide some opportunities for us.
So I wouldn't signal necessarily a lower absolute LNG price would necessarily impact the value that we can create through our LNG and gas trading businesses because we run them as a portfolio of assets while some -- where we see low volatility, it's more difficult to extract value. But other parts of that portfolio may well see volatility. Tangential volatility may appear that will allow us to capture some of those -- that value. So don't take a read through that lower LNG prices necessarily means lower performance out of the gas trading business.
Okay. Great. And may I have 1 follow-up concerning your U.S. Lower 48 divestment program? How much do you -- how many package do you believe you will be able to sell before year-end? And what kind of proceeds are you expecting in your plan to be executed in terms of U.S. Lower 48 divestment this year?
Yes, we wouldn't -- when we announced the BHP deal, it was $10.25 billion acquisition, the final price. We said we'd then dispose of $5 billion to $6 billion of assets, predominantly Upstream and predominantly Lower 48. So it's not all $5 billion to $6 billion. But the packages are all being progressed and marketed, some are a little bit slower given the weather issues that we had, which may lead to sort of pushing those off. It's a $10 billion program in total over 2 years is what we've committed to. $600 million of proceeds have come through in the first quarter, a small proportion of that was actually out of Lower 48. It was a $120 million bulk package that we did out of Lower 48, a legacy business that we had.
I think they are pretty much locked and loaded. There's a lot of interest in the assets. It's $10 billion over 2 years. You would hope to deliver at least 40% of that in the first year. But certainly, in terms of this year, a lot of it is back-end loaded, and so you'll see that come through. Some of it might slip in to next year, so -- but I could easily see $4 billion to $5 billion this year with the potential for some of that flowing into 2020, depending on actual close out of some of the deals. But things are well underway in the disposal process, and it's pretty well underpinned.
Thank you, Bertrand. Okay. That's the end of the questions. Let me just hand over to Brian for some closing comments.
Yes. Well, I think it's still morning where we are here in Los Angeles, and thank you for your patience and time today. As we've laid out, this is the third year of our 5-year strategy. I think the quarter was resilient, I'd describe it as resilient set of results given the backdrop of weak prices coming into the quarter, weather issues, the portfolio disposals from last year and the big turnaround we had at Thunder Horse.
I think with the strong trading result, it actually led to a very resilient robust result for us this quarter. So I think as we looked at this plan for this year, 1Q was always going to be tough and I think we've come through that with a solid set of results.
We remain on track to deliver our 2021 targets as we've laid out for you today around the projects that are already onstream and how that's underpinned with the financial frame unchanged. We've made good progress on our reduce, improve, create framework in terms of reducing emissions and we talked about, at the end of last year, that we've now taken out 2.5 million tonnes of CO2 from our portfolio since 2016 and the Paris Agreement. And you're going to see the balance sheet naturally deleverage into the second half of this year as disposal proceeds come in and the payments from 1Q and 2Q for both BHP and Macondo roll-off.
And I think as we look forward, we'll continue to maintain a strong capital discipline frame within our remit of safe and reliable operations. With that, thank you very much for your patience and we look forward to talking to you at the next call, 2Q. And for those of you that can make the AGM in Aberdeen this year, we'll get a chance to catch up with you there on progress up to that date. So thank you very much.