BP PLC

LSE:BP

Earnings Call Transcript 2018-Q2

[Operator]

Welcome to the BP presentation to the financial community webcast and conference call.

I now hand over to Craig Marshall, Head of Investor Relations.

[Craig Marshall, executive]

Welcome to BP's Second Quarter 2018 Results Presentation. I'm Craig Marshall, BP's Head of Investor Relations, and I'm here today with our Chief Executive, Bob Dudley; and 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 Bob.

[R. Dudley, executive]

Thank you, Craig, and good morning, everyone. Thank you for joining us.

It's certainly been a busy first half of the year for BP, even busier these last few days with the news that we will acquire the U.S. onshore assets from BHP. I will talk about that transaction as part of this call, but the main focus for today is to provide you with a summary of our results for the second quarter of 2018 and an update on the financial and operational progress for the first half of the year.

I'll start with some highlights from the first half and provide some reflections on the market forces that have been at play in the macro environment. I'll also talk about how we are shaping the business for the future and then go on to summarize the key points of the BHP deal once more. Brian will report on the detail of our second quarter numbers, financial frame and 2018 guidance, and I'll then come back to update you on our operational performance so far and provide more detail on our commitment to advancing the low carbon agenda. And then we'll take your questions.

So to begin with some highlights from the first half of the year, we're now 6 quarters into our 20-quarter plan, and we continue to move ahead. Underlying profit for the second quarter remains strong at $2.8 billion and compares to $2.6 billion in the first quarter and $700 million a year ago. And our underlying cash flow of $12.4 billion in the first half more than covered our organic capital expenditure and the full dividend. These are numbers that reflect our continued focus on disciplined execution of the strategy we laid out at the beginning of 2017, and we're also seeing similar progress across the business segments.

In the Upstream, we reported underlying pretax earnings of $3.5 billion, underpinned by around 10% growth in underlying production compared to the same quarter last year. That's an improvement on our first quarter 2018 result, which itself was our best since the third quarter of 2014.

We also continued to build our portfolio in a way we believe is distinctive to BP, optimizing the value of our assets in both incumbent and growth areas. Last week's announcement is a good example of our approach. Last week's move materially high grades and repositions our U.S. Lower 48 business in line with our Upstream strategy.

In the Downstream, we reported underlying pretax earnings of $1.5 billion. The segment continues to deliver against this growth agenda, notably across fuels and refining, with continued growth into new retail markets.

And we announced the series of investments through the half year in FreeWire, StoreDot and Chargemaster. This combination of interest in fast-charging technology, battery innovation and the U.K.'s largest electric vehicle charging network operator helped to position us effectively for the fast-evolving electric vehicle market. Not a threat but an opportunity for BP. We are doing all of this while maintaining our tight organic capital expenditure range of $15 billion to $17 billion over the medium term and gearing within a range of 20% to 30%.

Given our quarter-by-quarter results and with our confidence in the outlook for group organic free cash flow, we announced last week a 2.5% increase to the quarterly dividend. With this, the second quarter dividend is increased to $0.1025 per ordinary share or $0.615 per ADS. This is the first increase in the dividend in 4 years, demonstrating the confidence the board has in our disciplined financial framework, the operational momentum across the whole business and our commitment to growing distributions to shareholders over the longer term.

Turning to the macro environment, the world economy continues to grow despite concerns around potential trade disputes and other market forces. Global GDP is expected to increase by around 3% in 2018 and '19, supporting strong oil demand growth as well as increasing demand for natural gas, notably Asian demand for LNG. Across the refining system, margins remained strong at above-average levels, supported by high levels of utilization and diesel demand.

Looking at the oil market more closely, OECD stock levels have returned to a more normal level, as shown in the chart on the left. Oil prices have trended higher this year supported by strong demand growth and a number of contributing supply factors which have unsettled the outlook, particularly supply disruptions from oil-producing nations, particularly Venezuela and Libya. There are questions over the timing and effects of U.S. sanctions on Iranian crude exports and U.S. infrastructure bottlenecks, particularly in the Permian basin.

OPEC and other participating countries have agreed to increase production to counter the effects of these supply disruptions, but there is uncertainty as to whether there's sufficient spare capacity if the disruptions increase significantly. These uncertainties could serve to maintain upward pressure on the oil price over the near term. Looking further out, we continue to plan for oil prices in the range of $50 to $65 per barrel.

So we have been delivering this strategy we laid out to you in February last year, shaping our portfolio and creating a business that is resilient and fit for the changing world. We continue to grow our gas and advantaged oil portfolio in the Upstream. We have a strong set of major projects out to 2021, driving growth in the near term and creating deep optionality into the next decade. I can't remember when it has looked this good.

Alongside that, we are optimizing and high-grading the portfolio by deepening it in our core areas and exiting assets where we can create value by divesting to others. Over the past few years, you have seen us do this in the Norwegian North Sea, Gulf of Mexico, Argentina and most recently through the transaction involving our Clair U.K. North Sea oil field.

At the same time, we continue to look for things that are accretive to shape our portfolio through inorganic investments, such as the recent BHP transaction, which creates increased optionality across our existing U.S. onshore operations, as well as growing value in a basin where we previously didn't have access.

Looking at the Downstream, our market-led growth strategy is making strong progress, particularly in our fuel's marketing business around the world. We've expanded in major growth markets, such as China and Mexico, where we can offer customers a differentiated experience through our brand, high-quality products and services. We continue to progress our convenience retail offering in established markets, further supporting our goal to grow our earnings in the Downstream.

As I mentioned earlier, we are moving forward in the broader advanced mobility space, which is integral to our low carbon agenda. We've made a number of investments so far this year in electric vehicle charging infrastructure and battery technology. These investments position us to take a compelling offer to a mobility market that is increasingly looking to electrification for its solutions. We're underpinning all of this activity with our commitment to modernize the whole group from the systems and tools we employ to the data we collect and the new technologies which can transform the way we work.

Before I hand over to Brian, let me take a few minutes to discuss the key points of the transaction we announced last week, one of the most exciting and transformational investments we have made in recent years. The Lower 48 team laid the groundwork for this over the last 4 years, having radically transformed that business, driving significant improvements through the application of leading operational processes and technologies and turning it into a top quartile operator.

The acquisition of these U.S. onshore assets builds on this proven track record. It gives us access to one of the most exciting regions in our industry, the liquids-rich Permian-Delaware basin, as well as premium positions in the Eagle Ford and Haynesville basins. It adds high-quality assets and over 4.6 billion barrels of oil equivalent of resources that repositions our existing Lower 48 business, materially high-grading the portfolio.

Importantly, and this is very important, this acquisition will be accommodated within our existing financial frame with our medium-term organic capital expenditure of $15 billion to $17 billion, and our guidance for our balance sheet and returns on capital employed remaining unchanged.

To go together with this, we've announced the intention to divest an additional $5 billion to $6 billion of assets, predominately from the Upstream, bringing our net investment to around $5 billion in the transaction. Proceeds from divestments are expected to fund up to $5 billion to $6 billion of further share buybacks over time. Post-integration, we expect this acquisition to be accretive to earnings and cash flow per share; and by 2021, the Lower 48 is expected to be contributing an additional $1 billion to Upstream pretax cash flow.

As we look to the longer term, these long-lived unconventional oil and gas assets are an important addition to the suite of growth options we have, and they provide material value creation potential into the next decade and beyond. We will talk to you more about our plans for the business in the coming months. However, for now, let me hand over to Brian who will take you through our second quarter financial results.

[Brian Gilvary, executive]

Thanks, Bob. Firstly, a brief overview of the environment in the second quarter. Brent crude has averaged $74 per barrel for the second quarter of 2018 compared with $67 per barrel in the first quarter. This reflects continued strong oil demand, the reduction of OECD inventory levels and the supply and demand dynamics Bob mentioned earlier.

U.S. gas prices saw less volatility than in the first quarter, with Henry Hub gas prices averaging $2.80 per million British thermal units in the second quarter compared with $3 in the first quarter. BP's global refining marker margin averaged $14.90 per barrel in the second quarter, seasonally higher than the first quarter average of $11.70 per barrel and higher than a year ago. This reflects strong diesel demand leading to lower distillate stocks.

Moving to the results summary, BP's second quarter underlying replacement cost profit increased to $2.8 billion compared to $680 million a year ago and $2.6 billion in the first quarter of this year. Compared to a year ago, the result benefits from significantly higher Upstream liquids and gas realizations, lower exploration write-offs and an increased contribution from Rosneft.

In the Downstream, the benefits of stronger industry refining margins and higher Canadian heavy crude discounts were partly offset by a small loss in oil supply and trading and the divestment of our interest in the SECCO joint venture. Compared to the first quarter, the result reflects an increased contribution from Rosneft, higher liquids realizations and lower costs in the Upstream.

In the Downstream, the result benefited from a stronger performance of fuels marketing, higher industry refining margins but lower WCS heavy crude discounts. In both the Upstream and Downstream, the results are partly offset by a higher tax rate, increased turnaround activity and a weaker overall trading contribution. As Bob previously mentioned, the second quarter dividend payable in the third quarter of 2018 has been increased to $0.1025 cents per ordinary share.

Turning to cash flow and the sources and uses of cash. Excluding oil spill-related outgoings, underlying operating cash flow was $12.4 billion for the first half, of which $7 billion was generated in the second quarter. This included a working capital release of $1.3 billion in the second quarter, partially offsetting the $1.7 billion build we saw in the first quarter.

Organic capital expenditure was $3.5 billion in the second quarter and $7 billion for the first half of 2018. In the first half of 2018, our organic free cash flow surplus was $1.6 billion.

Turning to inorganic cash flows, in the first half of 2018, divestments and other proceeds totaled $300 million. We made post-tax Gulf of Mexico payments of $2.4 billion and inorganic capital expenditure was $800 million. We've also remained active in our share buyback program and bought back 29 million ordinary shares in the first half of 2018 at a cost of $200 million. At the end of the second quarter, net debt reduced by $700 million and gearing was down to 27.8%.

Turning to our guidance for 2018, looking to the third quarter, we expect Upstream reported production to be broadly flat with the second quarter, reflecting continued seasonal turnarounds and maintenance, offset by the continued ramp-up of our major projects.

In the Downstream, we expect lower industry refining margins. We also expect significantly higher levels of turnaround activity in the second half of the year, particularly at our Whiting refinery in the U.S.

At the midpoint of the year, we've revised some of our 2018 guidance. Specifically, we now expect organic capital expenditure to be around $15 billion, reflecting continued capital efficiency and cost deflation. And divestment proceeds in 2018 are now expected to be over $3 billion, with proceeds weighted towards the fourth quarter. This does not assume any proceeds from the divestment package we announced associated with the purchase of BHP's onshore Lower 48 business.

The rest of our guidance remains unchanged. The total DD&A charge is expected to be higher than 2017, reflecting higher Upstream production volumes. Gulf of Mexico oil spill payments are expected to be just over $3 billion in 2018, with $2.4 billion already paid in the first half of the year. Our balance sheet remains strong, and we expect gearing to remain within the 20% to 30% band.

In Other business and corporate, the average underlying quarterly charge is expected to be around $350 million, although this may fluctuate between individual quarters. And in the current environment, the underlying effective tax rate is expected to remain above 40%.

In summary, our financial framework is robust, underlying earnings continue to grow, underpinning the 2.5% increase to our quarterly dividend to $0.1025 cents per ordinary share. Our organic capital spend is now expected to be around $15 billion in 2018, and we continue to expect 2018 organic free cash flow breakeven to be around $50 per barrel.

Beyond this, we expect the oil price breakeven to steadily reduce to around $35 to $40 per barrel by 2021; and over the same period, ROACE to improve to over 10% at $55 a barrel. We expect to offset the dilution from scrip dividend issuance over time. And as seen with the dividend increase announced last week, we remain committed to growing sustainable free cash flow and distributions to our shareholders over the long term.

On that note, let me now hand back to Bob.

[R. Dudley, executive]

Thanks, Brian. Let me now update you on some key milestones for our operating segments before we take your questions.

What you see in summary here on the slide for the Upstream is how our focus on quality execution is continuing to deliver record operating performance, with operated plant reliability remaining at 96% in the second quarter.

We have started up 3 major projects so far in 2018, Atoll in Egypt, the Taas expansion in Russia and, earlier this month, we started commercial deliveries from the Shah Deniz Phase (sic) [Stage] 2 ahead of the schedule.

Shah Deniz 2 is our largest operated subsea development, and along with the South Caucasus Pipeline expansion, we expect cost to come in about 20% below sanction. It is the starting point for the Southern Gas Corridor series of pipelines that will deliver natural gas from the Caspian Sea direct to European markets for the first time.

Looking ahead to growth into the next decade, we made 5 final investment decisions on projects in Oman, India, Angola and 2 in the U.K. North Sea. This further de-risks the 900,000 barrels per day of incremental production from major projects that we expect to add by 2021.

We also recently announced that we are deepening our operator position in Clair in the U.K. North Sea, increasing our equity from around 29% to 45%. Clair has more than 7 billion barrels of oil initially in place and has significant value associated with future development opportunities, including the Clair Ridge project currently under development.

I'd like to also mention a great example of how we're moving ahead with our modernization and transformation agenda. Earlier this year, we introduced you to APEX. It sounds like the top of a mountain. Actually, it acts like a digital twin of real-world facilities and allows us to optimize production. In 2Q, we added it to over 1,000 wells in Alaska, and we now have 22 operated assets globally using the tool. Last year, APEX contributed to the 0.6% growth we achieved in our base production, which gives you a sense of impact digital can have.

In the Downstream, we're also moving ahead. In manufacturing, we continue to grow the value from refining commercial optimization with our Whiting refinery in the U.S., processing record levels of crude for the half year. We also extended biocoal processing into more of our refineries. An in petrochemicals, we announced 2 new PTA licensing agreements, one was SOCAR in Turkey and the other was Dushan Energy in China, demonstrating the strength of our industry-leading proprietary technology and allowing us to generate reliable sources of income without the need for capital investment.

In retail, we now have our convenience partnership offer in more than 1,200 sites across our network. Due to the strength of our brand and offer, we have also continued to grow premium fuel volumes. And in Mexico, having entered the market just last March, we have now opened up more than 300 sites.

As mentioned, we have significantly progressed our advanced mobility agenda through the acquisition of Chargemaster. And in May, we invested in StoreDot, a leading developer of ultra fast-charging battery technology. With these deals and our differentiated fuels and convenience offers, we are well-positioned to become the leading fuel provider for both conventional and electric vehicles.

Turning now to the dual energy challenge and our role in providing the world with the energy it demands but produced and delivered with fewer emissions. Earlier this year, we released our advancing the energy transition report, which lays out our commitment to advancing a low-carbon future. This commitment is integral to the broader strategy of BP. It's clear and it involves every part of the business.

Our reduce, improve, create, or RIC framework, sets out how we will achieve this across all parts of our business. By reducing emissions from our operations, this includes targets such as zero routine flaring in the Upstream by 2030 and the use of solar energy instead of gas to power pumps in our Lower 48 business.

The I in the RIC framework, improving our products, in addition to our PTA Air (sic) [PTAir] products and BP fuels with active technology, we are looking at other ways to incrementally improve the products our Downstream manufacturers, such as carbon-neutral lubricants. And the C in the framework, creating low-carbon businesses, like Ligthsource BP, which recently completed its first project in India, marking the company's first utility solar asset to be commissioned in a country with huge potential for solar energy.

These are all practical examples of our reduce, improve, create framework and action. They include specific targets because that's how you get things done, and it's an approach that draws on what we've learned over more than 2 decades of low carbon activity. It's an approach we like and that we believe will deliver on the commitment we made.

Now let me finish with a reminder of the BP proposition to you, as shareholders, and not only the words on the slides, but what it looks like in reality. Safe, reliable and efficient operations always come first, day in and-day out, executing our plan with discipline. We're delivering on our plan. Our operations are running reliably and we're bringing on major projects on time and on budget, and well under budget in the case of the Shah Deniz Phase (sic) [Stage] 2 project.

We're a global energy company with a distinctive portfolio that's balanced regionally, onshore and offshore, conventional and unconventional and with a growing low carbon mix. It's packed with optionality, and we're optimizing it all the time. There is no better example of that than our new access to premium U.S. onshore acreage in the Permian, Eagle Ford and Haynesville basins in the U.S., but you'll also see other examples this quarter like the Clair transaction with ConocoPhillips and our acquisition of Chargemaster.

And our commitment to capital discipline remains unchanged, generating even greater value for shareholders from our access right around the world, including some of the best basins in the U.S. onshore. And we're doing so while remaining within our existing and disciplined financial frame, as I set out earlier.

Together, this is a proposition that we have had in place for some time. It's consistent, it's working and it's all in service to our goal of growing sustainable free cash flow and distributions, as we did last week with the increase to our dividend.

Thank you very much, and let me now turn over to you for questions.

[Operator]

[Operator Instructions]

[Craig Marshall, executive]

Okay. Thank you, everybody, for listening. We're going to turn now to questions and answers. [Operator Instructions] We will take the first question from Lydia Rainforth at Barclays.

[Lydia Rainforth, analyst]

Two questions, if I could. The first one's for Bob. When you're talking about modernizing the older BP group, are there areas where you're seeing that going ahead of schedule or other areas where it's a bit difficult, or is it evenly across the group? And then the second question for Brian, if I could. Just in terms of the cash flow numbers for this quarter, if I look at the cash flow levels on an underlying basis versus last year, they seem very similar despite the higher oil price. And I understand that you have trading loss and the Gulf of Mexico maintenance, but I was just wondering if you could quantify some of those broader impacts for us.

[R. Dudley, executive]

Lydia, thank you very much. This modernizing the group is extraordinary things happening all across the industry. And with BP, we throw around big words like Big Data, but actually, the use of sensors and working through the data all the way through exploration, all the way through our reservoir engineering and optimization of wells and field developments are quite astounding. And I think we're going to show some of you in September as visitors to BP. The areas that I think are going faster than we thought, and it comes from not mandating it from the top or putting these technologies out in the uptake and where they're being used in digital platform, such as blockchain, quantum computing, cognitive computing is starting to improve efficiencies, but it's really the use of our data, sensors and the ability to visualize these things and make decisions faster is quite, quite astounding. I don't -- I can't say what all the other companies are doing, but these is going faster, I think, than any of us thought. And it's -- once it gets going, the momentum just builds and everybody wants to use them.

[Brian Gilvary, executive]

And then Lydia, on terms of cash, it's a 90-day window, so there's a lot of moving parts. So if you sort of look at the first half cash numbers, I think that gives you a better feel. But I'll talk about what's happened in 2Q versus 1Q that creates a bit of the noise. As you look quarter-to-quarter or 2Q versus 2Q last year, it's similar things. If you look at EBITDA on a straight 1Q-2Q, it's flat. You'd expect it to have come up. The difference is basically what you said. It's maintenance, the maintenance programs in Q2 and the slight loss in trading, which meant that effectively trading is a weaker result 2Q over 1Q. If you look at specifics over the year, half year $12.8 billion. If you strip out the $400 million of working capital build that we saw in the first half of the year, set against the $7 billion capital number and about $3.9 billion for the full dividend, including scrip, gives you some circa $2 billion of surplus cash in the first half of the year. Which if you run it through the rules of thumb is not far off where you'd expect it to be. But there's quite a lot of other moving parts that you can't see in the second quarter, and I'll just highlight 3. One is cash tax paid in 2Q is $400 million in the first quarter. There is a string of NOIs, nonoperating item, cash flow impacts in 2Q associated with, for example, restructuring costs. CapEx -- cash sorry, cash going out from [ RATX ] in the second quarter is higher than it was in the first quarter. And then the trading result we talked about, although trading made money in the second quarter, we had a small loss inside the oil trading result. And therefore, the delta of 1Q-2Q in terms of total trading created the difference. So it's hard to try and zone in on just 90 days as being what's happening with the operating cash. If you look at first half, it's not far off where you'd expect the rules of thumb for it to be.

[Craig Marshall, executive]

Okay. Thanks, Lydia. We'll turn next to Jason Gammel at Jefferies.

[Jason Gammel, analyst]

I just wanted to come back to the BHP transaction. And Bob, can you talk about why you decided to essentially bid on the full package rather than just targeting the Permian basin or the Permian basin and the Eagle Ford? I guess, specifically, were you looking at Haynesville as being low-cost of supply in North American gas? Or were there any other drivers there? And then I guess just one more follow-up, can you talk about any growth rate assumptions that you have on production when it comes to the $1 billion of free cash flow that you expect to deliver?

[R. Dudley, executive]

Jason, thanks. I'm just going to throw that right over to Brian because he just answered the question just before the call.

[Brian Gilvary, executive]

Yes, so just on the package bit, one is it's probably one of the public auctions we've seen for a series of assets given the amount of coverage on it. There were 7 packages. And I think it's fair to say that if you added up all the bids on those 7 packages, we would not have been able to get anything like as an attractive deal as you saw. That said, actually, this is a suite of assets that we've looked at for some time even before it came on the market. We've talked historically about trying to find solutions for Lower 48 that would give us access to a broader suite of potential options, and we talked those through with our investors historically. So we knew these assets. When they came on the market, it was clear to us that the real advantage and benefit was the total package. As there were 7 packages, I can tell you this because we know it as a matter of fact, we have had a number of inbounds already on these assets that we've just won because certainly, I think there were some people out there that may have bid on specific assets as part of the 7 packages that certainly would have a number significantly above where we were. So our attraction was there were clear synergies in the Haynesville and Eagle Ford, and then it then gave us a very important foothold. As Bernard described last week, if you look at the activity in Reeves County, it is a sweet spot inside the Permian. And that, therefore, enabled us to get a foothold into there. So for us, it was where the value was, actually the total package. If you look at the breakdown of the 7 packages, I think the sum of the parts was, I suspect, above where we came in. The issue, I suspect, for our counterpart of BHP would've been executability of those 7 packages. And I think the advantage we gave them from day 1 was a very fast transaction that was clean, that was not incumbent by other parties, that we will be able to execute. And I came back to this last week, our M&A teams have done something close to over $100 billion of transactions now in the last 8 years, and part of the offer we put on the table is that we could act and quickly on those assets.

[R. Dudley, executive]

And Jason, I'll just add another driver for this is we have a great team in the Lower 48. And you all will know that they primarily have dry gas to work on. So being able to put their tools and techniques and expertise now to this set of assets was another driver in it. And we'll high-grade and shift around that portfolio somewhat.

[Brian Gilvary, executive]

And then, Jason, in terms of sort of production, I think Bernard laid out last week that, actually, this will enhance what a production looks like over the next 5 years. But we'll give you more guidance on that at the end of the year when we do the Upstream Investor Day.

[Craig Marshall, executive]

Thanks, Jason. Okay, we'll turn to the Theepan Jothilingam at Exane BNP next.

[Theepan Jothilingam, analyst]

Two questions, please. Firstly, just come back to cash and think about the evolution in H2, could you give a little bit more detail in terms of the impact on Whiting versus sort of the volume momentum? The second question, could you just please give us an update in terms of Macondo, where we sit with the BELs and the process of closing the facilities and payments?

[Brian Gilvary, executive]

Yes, okay. I'll take both of those, Theepan. So yes, we've got high turnaround activity coming through. Actually, we've also got it at Cherry Point as well, but we don't normally quantify what the price effects will be. In terms of Whiting overall, you saw the light-heavy spread came in, in the second quarter to the tune of about $5 and that impacted some of the results and cash and what we saw coming through. But we do have a higher turnaround coming through in terms of the second half of the year around Whiting, primarily Whiting. It's due to begin around September and it will last for a period of 7 weeks. So I think we wouldn't normally give you specific guidance on what that will mean, but I think you can sort of work out. If you look at production runs for Whiting, what the 7-week impact will have in terms of cash flows. In terms of Macondo, we have paid out the bulk of the cash payments for this year. We said they'll be slightly over $3 billion. We paid out $2.4 billion. The $2.4 billion in the first half of the year was primarily the 2 big major settlements we did in October 2012. The final payment of that went out in the first quarter, $1.2 billion. The first payments went out around the 2015 July settlements in the first and second quarter. And then we're into the sort of final cash payments going out around the Plaintiffs' Steering Committee settlements. You saw we took a slightly higher provision around BEL this quarter, which was cleaning out the sort of tail of those under the $190 million after tax. We're now down to basically about 40 claims in the system that need to be resolved or will be resolved through 3Q and 4Q. So in terms of cash payments on Macondo, the bulk over 80% or up to 80% have gone out already than what we have anticipated for this year. And now, we're just finally in the litigation tail. You also saw this quarter we cleaned out some litigation outside of BEL, it was taken care of. And now, effectively, the choice for Eric Nitcher, our General Counsel, is whether we look to try and settle things before they get to the Fifth Circuit on appeal, which we'd taken a chunk through the second quarter or we let the litigation process run out, where he's had a relatively successful -- so far in terms of the case he's taken forward. But we're now into sort of what I call litigation tail, and therefore, there'll be some movements, but it will be de minimis around the quarters.

[Craig Marshall, executive]

Okay. Thanks Theepan. We'll go to Michele Della Vigna next at Goldman Sachs.

[Michele Della Vigna, analyst]

Two questions from my side. First, if you could update us on the progress towards the FID at Tortue and on the next wave of FIDs in your portfolio. And then secondly, if you could have an update on these start-ups for the rest of the year, in particular, Clair Ridge, and what production you expect for the full year.

[R. Dudley, executive]

So Michele, the first one on the Tortue, the Phase 1, we've just been meeting with Mauritania and Senegal and the governments on that. We're heading towards an FID in the fourth quarter this year. Your second question was on...

[Craig Marshall, executive]

Clair Ridge.

[Michele Della Vigna, analyst]

On production, yes.

[R. Dudley, executive]

Clair Ridge. From Clair Ridge, we expect start-up before the end of the year on 4Q, and we're about 97% complete on the Clair Ridge project. I won't give you a figure yet for the year. I've got it, but I think it's probably not the right thing for me to do given our partners in there.

[Craig Marshall, executive]

Okay, Michele, thanks. We'll turn next to Os Clint at Bernstein. Os.

[Oswald Clint, analyst]

Yes, just going back to M&A, and obviously BHP helps solve the kind of U.S. liquids underexposure. But Bob, you also mentioned LNG demand being strong. And I guess you're a little bit underexposed relative to your larger peers in this particular segment. So I'm just curious, is there appetite or do you feel the need at some point in the future to kind of beef up just in terms of LNG exposure? And second question perhaps in the quarter or sort of the first half of the year so far, rest of world liquids looks like a relatively steep decline so far this year. I'm just curious is that Angola and is that decline in -- coming in the line with your plan, please?

[R. Dudley, executive]

Oswald, thanks. I think some people forget how much LNG we do have with Atlantic LNG out of Trinidad, part of those 4 trains there, our involvement in the North West Shelf. We've got the 2 trains in Tangguh, and the third one coming along well to start up. So I think those are -- it's a fair number. We've invested in offtake agreements. We've got some big offtake agreements in Mozambique with ENI and some big ones off the Gulf of Mexico. So we're certainly trading a lot of LNG. They are big, expensive, capital-intensive projects, for example. We also have some in Angola as well. So I'm not sure we feel light in LNG. There's always a project in Alaska that's been talked about for years. We and Exxon and Conoco are involved in that, we'll see about that. But it's not a burning desire in the portfolio.

[Brian Gilvary, executive]

And then in terms of production numbers, Oswald, you'll see that underlying production was up 11.7%. What you're probably seeing in terms of the liquids -- the rest of world liquids is turnarounds and seasonal impacts that come through in this quarter. And in the reported numbers, remember, you also have the expiry of the ADNOC concession that came off the numbers, which was around about, from memory, about 66,000, 70,000 barrels a day. So that would probably explain the delta, that and along with turnarounds.

[Craig Marshall, executive]

Thanks, Os. Okay, we'll turn to the Rob West at Redburn next, please.

[Rob West, analyst]

One is a reflection on the shale deal from last week, and the way you're divesting assets to cut some of the costs of that deal. My question is, is that partly motivated by looking through the portfolio and seeing assets where you can unlock value that's specifically not being recognized by the market, and let's swap it out for an asset like the Permian, which the market is clearly much more prone to give full credit to? And if you could talk to about any specific areas where you feel like that hidden value might fit, that will be interesting. The second is a specific one. Just about the North Sea, particularly Clair Ridge where you deepened your stake, is it true that there's some test of a fractured basement below Clair getting scheduled for this year? And is that in any way part of your motivation to deepen there?

[Brian Gilvary, executive]

So on the first part, Rob, we wouldn't normally talk about specific transactions, although actually, the example you just gave in terms of swaps is -- actually, the [ comparing ] Clair swap is a good example of where we're looking to deepen into things -- value versus volume, deepen things where we know we can have additional value. And so you see you'll see more activity in the swap space. I think you'll see that across all the majors, actually, over the last 4 or 5 years as we look to try and consolidate positions. In terms of specific suite of packages associated with BP HP (sic) [ BHP ], this was all about how we finance the deal and the high-grading of our portfolio. So it's really about focusing where the cash will go in terms of value creation in that new portfolio and how we're going to fund it through tail asset disposals. But we wouldn't normally talk about specific assets. We don't normally go to sort of public auction processes. We will transact, as I've said before, the team are pretty hot in terms of what they've done over the last 8 years. We'll transact, and you'll see these the announcements around those assets as we start to do that and then you'll get a flavor for the sort of assets that we're talking about. And then on North Sea in terms of Clair, we wouldn't talk about the specifics of that. I think that will be a good question for the Upstream Investor Day come December.

[R. Dudley, executive]

But I'll just footnote to that point you raised, whether that's correct or not, is not in our valuations when we do that swap.

[Craig Marshall, executive]

Okay. Rob, thanks. We'll go next to Christyan Malek at JPMorgan.

[Christyan Malek, analyst]

Firstly, just 2 from me. First, when you [ ex out ] the working capital, the cash flow for $5.7 billion [ emerges ] from what should have been a stronger quarter on an underlying basis with higher oil. It looks as though there's been some unexpected leakage, which you sort of explained. But what are the areas that you think you can improve on in the second half? Or is it fair to say the high oil price is coming with more one-offs even when you think about based from a 6-month view instead of a quarterly snapshot? The second question, Bob, I just want to understand better the executive management and board's portfolio strategy from here. Would always keep in mind -- sort of an open mind in terms of building versus buying? Or following the BHP deal, is it fair to say BP's done solving for its long-term portfolio? And I guess, in that context, should we think about excess funds now going directly to shareholder returns?

[Brian Gilvary, executive]

So in terms of on the cash flow on the first question, look, it's a 90-day window, so it's pretty hard to predict what happens. As oil prices go up, you get all sorts of working capital movements. I think if you come back to the first half numbers, Christyan, I think it gives you a better flavor on what's actually happening ex the one-offs that I talked about that have come through in the second quarter versus the first quarter. And it will be driven by -- I mean, I think EBITDA is probably a safer place to go and look in terms of trying to get through a trend of what's actually going on in the underlying operating cash flows ex other things moving across the sort of 7 different business models. We have a lot of moving parts in each of them, and it's pretty hard to capture it in a 90-day window to say I can take this as a firm trend from the previous quarter. I think 4-quarter rolling average is a pretty good place to go, but I'll point you towards EBITDA as being the safest place in terms of actually what's happening in terms of the underlying cash flows. And then you'll get inter-quarter moves like you did here with the tax restructuring costs and the fact that we had a lower trading result in 2Q over 1Q.

[R. Dudley, executive]

And just to add about portfolio and board philosophy and executive philosophy here, I think we've been cautious to work within this narrow fairway that we've had really for many, many years after the Gulf of Mexico incident. We have done a series of bolt-on acquisitions through -- beginning in late '16 and into '17. This is the first large transaction we've done. We've done all of these within the guidelines and the boundaries of our thinking that they have to be accretive and they have to give us the ability to high-grade the portfolio. So rather than shutting down any activity, I'd be open-minded about it. It's not our plan to begin to continue with a series of acquisitions. But if they fit this financial framework about being accretive, allow us to grow, allow us to generate greater free cash flow, to stay with that philosophy and increasing distributions to shareholders. We'll continue to be open for this things.

[Christyan Malek, analyst]

So gearing and those -- [ it results to ] net gearing -- I mean, in that case, we should never think about gearing coming down as a hard target. I mean, I don't want to put words in your mouth.

[Brian Gilvary, executive]

No, no. Well, yes -- no, sorry. I mean, I think the more important measure is the amount of funds that we're generating over extended debt. That's the measure that really matters in terms, because ultimately that drives credit rating. So we want to keep our credit rating in the sort of band of where we are. Gearing is just a proxy. I mean, frankly, 30% gearing, 35% gearing is not an issue. We keep 30% gearing as a way to create more discipline within the financial frame, and that's why it's started in good stead now for the best part of 30 years. We took it down to 10% to 20% during Macondo because we have the huge potential liabilities coming through from that. So I don't think it necessarily means that we'll stay up anywhere near 30%. Actually, the trend this year will be coming down. It's disguised somewhat by the $2.4 billion of Macondo payments that went out in the first half of this year. In fact, it's disguised by something close to $16 billion worth of Macondo cash payments that have gone out over the last 3 years, if you include the first half this year and the previous 2 years. If you back those out, our net debt will be in a very different position. So I don't think it that you should imply anything from that other than the fact that, right now, gearing and net debt is trending down, especially at these higher oil prices.

[Craig Marshall, executive]

Okay. Thanks, Christyan. We'll move next to Irene Himona at Societe Generale.

[Irene Himona, analyst]

Two questions, please. The first one for Brian on lubricants. Lubes is about 20% of your Downstream earnings. It's also 20% of your targeted $3 billion Downstream earnings improvement by 2021. Yet Q2-- in Q2, the result is down over 8% year-on-year. It's down sequentially. It's gone either nowhere or downwards for the past 5 or 6 quarters. I wonder if you can share with us what's going on and what may change this trend that we've seen. And secondly, a question for Bob. Bob, you've always made it clear that the focus is on value and free cash flow, and that volume growth is the result of your strategic delivery. Is it possible to share with us what you think the BHP deal, which is a highly strategic transformational deal for BP, what that deal may do to your 5% volume growth that you are guiding out to 2021, please?

[Brian Gilvary, executive]

So first was just on lubricants, Irene. And I think this is definitely a business -- it's fast moving consumer goods. It's one that you have to look at over a run of years. And what you will probably know straightaway is that in a market where oil prices are growing quite so rapidly at the rate at which they are -- that clearly impacts the base oil price, and it takes time to move those prices into the marketplace. So I wouldn't worry that there is a negative trend that's been developed, but there's no question though, going through these weaker quarters, as they move their prices onto the street. But you can't immediately -- it's not like with retails fuels and lubricants, because of the nature of the product itself, it takes time. And therefore, what they're dealing with is a higher base oil price that come into their base cost. You can't simply just immediately move that price onto the street. So will see a lag. It's a much longer lag than you would see in certain terms of fuels. What I would say, though, in terms of lubricants is actually they're continuing to grow their premium products, which you'll know from the Downstream Investor Day, there are 2 important parts of the lube strategy underpinned by technology and their people which are probably their biggest assets, truly their biggest assets for the lubricants division. But growing their premium products and growing in the non-OECD fast-growing markets. And they are, in both of those cases, actually we reviewed it last week, they're both continuing to progress in that strategic agenda. So I think you have to just look through the environmental impacts of the higher base oil prices that come with the higher oil price, impacting their business over a short to medium term. Ultimately, they'll come back through that as prices now have got back into more stable piece, and some of those prices get moved on to the street.

[R. Dudley, executive]

And Irene, on your question about the BHP transaction, of course, it will bring in, on the anticipated closure at the end of October, 190,000 barrels of oil equivalent. I have no reason to think that we won't get those assets up to 320,000, 350,000 barrels a day going forward. It'll certainly be more liquids, it will be more valuable. But in terms of putting the percentages out there, it really does depend on what divestments we might make for the overall group. Our projections though is, from the -- these assets, it'll increase the Upstream free cash flow by over $1 billion by 2021, which is why we upped the targets coming out of the Upstream by $1 billion. And I think that's not off on the Lower 48, but primarily from these new assets. So couldn't put a number on it. In terms of percentages, like you say, it's value over volume and free cash flow is the objective. We'll just have to see what assets we might decide to divest to put a number on it.

[Craig Marshall, executive]

Okay. Thank you, Irene. We'll turn next to Jon Rigby at UBS. Jon.

[Jon Rigby, analyst]

Two questions. The first one, I guess Brian will know that I was going to ask this question, so I'm going to ask about trading. In the quarter, how would you characterize what happened? Was it a function of the market or your positioning vis-à-vis the market? And if it's a function of the market, are you able to sort of characterize the kind of conditions in the market that might give rise to either weak or strong opportunities through your trading business just so that, prospectively, we can judge and understand perhaps where you're likely to have a good or bad quarter? Or is it just too difficult to make that judgment? The second question, just is on -- going back to the announcement on the dividend increase on Friday. Are you able to sort of talk as to how you think about where you want to pay for that dividend? You referenced $50 to $65 is your sort of expectations for operating conditions as the base case. Are your -- is your dividend effectively pinned at the $50 level in terms of the way you want to be able to fund this and the visibility you have on it?

[Brian Gilvary, executive]

So on the -- so just coming to the first question on trading. Look, Jon, you know we can't give you any more detail than what's already out there. Where I would say specific -- so first of all, I mean, just on facts. First half of the year, all trading made money. So they're in profit for the first half of the year and trading overall was in profit for the first half of the year. And then the second quarter, our total trading was in profit. So it's the oil trading part of the total piece. What specifically happened through 2Q, and I don't think we were the only company to have this issue, was that there were some specific positions around some particularly difficult market calls and we got the call wrong. It's as simple as that. Now therefore, can we predict that? Absolutely not. What I can say, though, is you'll know it, if you look at our results over a run of 5 years or 10 years, we will have the odd quarter, this will be the third one in the last 5 years where we had a small loss. It's asymmetric risk because of the way in which we build optionality into that business and the base business that we have. That means that there may be, from time to time, a quarter where you'll have a small loss. Equally, you'll know just from what we've said historically, we can have quarters where it's an average plain quarter or it's a strong quarter. So the risk -- the way in which the risk is structured in that businesses, there can be a quarter where you have a small loss. Equally, the opposite is true that there'll be quarters where you have a very strong quarter significantly above the average historical plans. So I don't think there's anything particularly in this quarter. It was around one specific position in one book where they made the wrong market call. And actually, they did a very good job of exiting that position, which they have exited. But we can't give you more detail than that. I don't think you should take that as an indicator for future. I realize it's difficult and frustrating, therefore, to predict future results, but I think the sort of frame we've given you before around the sort of 5 components that we think about: slight loss, below average, average, above average and strong, are the best characterizations we can give you for that business.

[R. Dudley, executive]

And Jon, as we think about the dividend, where the board looks at it and we've laid out the future, we continue to plan the company really precisely, I would say. Rather than a range of $50 to $65 working assumption around -- saying the dividend is based on $55 real, and we started that in 2017. So that'll be the linchpin of our dividend planning.

[Craig Marshall, executive]

Okay. Thanks, Jon. We'll turn next to Martijn Rats at Morgan Stanley. Martin.

[Martijn Rats, analyst]

I wanted to ask you 2 things. First of all, about the refining margins, we're actually off to a rather good start for this quarter. So I would to ask about your comment you expect lower margin in the third quarter. Is that just a mix effect from some complex refineries like Whiting going through turnaround? Or is there is sort of an underlying sort of -- is there underlying market core in that comment? And then secondly, perhaps a bit sort of mechanical, but just wanted to understand this. On the $5 billion to $6 billion of disposals that you are now mentioning, is that basically the number for 2019? Or does that come on top of some underlying sort of rate of disposals of another sort of couple of billion dollars?

[Brian Gilvary, executive]

Yes, Martijn, you're absolutely right. We've had a strong start to the quarter. I think it's driven by distillate right now. We're seeing stronger distillate draws, that's led to higher cracks on the distillate side and that's what you're seeing. Our view is simply, seasonally, it's not specific to BP in terms of refining margins that you'll need to take the Whiting turnaround into effect separately to this. But generally, as we get towards the end of the third quarter, we expect to see a bit more softness in the refining margins. But there is no question that, today, we're seeing a degree of strength driven by that. But as we come out of the driving season, we'd expect it to rebalance just based on seasonally what we'd anticipate at this point in the cycle. The $5 billion to $6 billion is absolutely not a target for next year. We've signaled now that we expect disposal proceeds this year to be over $3 billion, which we view based on line of sight of what we've seen and what's in the pipeline. That doesn't include any of the $5 billion to $6 billion. The $5 billion to $6 billion is linked to the deal. Once we get the assets on board at the end of October, which is the current scheduled close date that we've -- that we have agreed with BHP, we've already started to create data rooms around the $5 billion to $6 billion and we'll announce those transactions over time. We're -- we have way too much experience in this space of the M&A space. We think it'll be a pretty strong market that we'll be going into, but we'll see as we bring these assets to the market. But it's absolutely not a target for next year. But it is a target in terms of -- over the next few years as we integrate the deal, we'd expect to get those $5 billion to $6 billion away. We'll give you more specific guidance on that as we get towards the end of this year in terms of what that may look like for 2019, with full year guidance at the end of the year.

[Craig Marshall, executive]

Okay. Thanks, Martijn. We'll go next to Chris Kuplent at Bank of America.

[Christopher Kuplent, analyst]

I'm going to continue with this theme, Brian, I'm afraid, on asset disposals. You've done less than $0.3 billion or around $300 million this first half. Still looking for $3 billion. And in your quarterly report, you mentioned to expect the contribution from the Conoco asset swap, whereas I've read somewhere else that, that was meant to be cash neutral. So perhaps you can shed a little light on -- or reconcile those 2 statements. And then another question for you, Brian, on buybacks versus scrip. I've noticed that during the first half, you've bought back less than half the amount you've issued in scrip equity. And I wonder whether we should expect that ratio to not just be one in the second half but perhaps be higher than that to make up for the first half running slightly below.

[Brian Gilvary, executive]

So the first half I think is straightforward. We've said that it'll be done over time, and therefore, the $2.4 billion of Macondo payments in the first half of the year means that actually the scrip buyback will accelerate into the second half of the year. So I think -- I mean, Chris, we've been very clear about that from day 1 that we'd offset over time, recognizing the asymmetry to the first part of your question, which is divestment proceeds have always been back-end loaded for this year, we made that clear at the start of the year. And we're now expecting to be over $3 billion. With the inorganic frame we have, in terms of the asset swap on ConocoPhillips, the accounting treatment will have a disposal proceed, there is no way to avoid that. So you'll see disposal proceeds coming through for the input of that, but you'll also see cash going out for the other side of the swap, which was the acquisition. So that's just accounting. But in terms of what we're looking for in terms of disposals to cover Macondo liabilities, it's something close to over $3 billion is what we're looking for, for this year. And that is again -- this is not in a specific 12-month time window, Chris, it's over time. So there is, again, you will have seen last year, disposal proceeds were running low at the Macondo payments as they were in the year before, but there'll be a catch-up going forward on the $2 billion to $3 billion. Macondo payments next year will be close to $2 billion. We'll continue with our $2 billion to $3 billion churn of the tail portfolio over and above the $5 billion to $6 billion, which is quite separate. So -- but we've been very clear this is over time, and it takes into account the asymmetry of disposal proceeds in Macondo.

[Craig Marshall, executive]

Okay. Thanks, Chris. We'll turn next to Lucas Herrmann at Deutsche Bank.

[Lucas Herrmann, analyst]

A couple, one detail, one fundamental. Bob, can I just go back to Jon's question on dividend and ask why is 2 -- why did the board decide that 2.5% was the right number? So just thinking around the scale of the increase at this stage. And then just in the context of or detail around turnaround this quarter, can you give us any indication as to whether they are high or low margin assets? I'm just looking at Q2, the downtime was Mad Dog and Mars, which typically would have very healthy cash margins.

[R. Dudley, executive]

Yes, Lucas, we haven't had a dividend increase in 15 quarters. So I would say this was a cautious decision to signal the confidence on where we are, where the financial framework is. It wasn't a great sign, so it could have been 2%, it could have been 3%. But this was the number that the board talked about and said it would send the right signal and get us moving on increasing distributions again. I think that's fair. Brian, any other thing you'd add to that?

[Brian Gilvary, executive]

Yes, the only thing to add is it's a progressive dividend. So it's not a percentage of earnings. So we held that dividend when our earnings per share were down $0.06 against the $0.10 dividend. And now that our earnings have come back above $0.10 per share, which they have been for now 3 quarters in a row, the board -- it was an important signal for them to signal an increase. So I mean, 2.5%, it's sort of in line with what we've done before around the progressive dividend. But there's no more science to it than that.

[R. Dudley, executive]

And on the turnarounds, as Brian mentioned, Whiting, the Whiting turnaround, which is a significant turnaround, that'll be in third quarter. That's certainly not low-margin. But we got a good...

[Lucas Herrmann, analyst]

Sorry, I was thinking more Upstream, Bob.

[R. Dudley, executive]

Oh, the...

[Craig Marshall, executive]

Yes, Lucas. So the turnarounds, as you pointed out, there was a heavy burden in the Gulf of Mexico with some of those fields. I think as you look forward into the third quarter, there's going to be some in the North Sea and elsewhere. So there'll be similar characteristics. But obviously in the second quarter, you're right, some of the highest-margin barrels we have is in that portfolio.

Okay, Lucas, thanks. We'll turn next to Thomas Adolff at Crédit Suisse. Thomas.

[Thomas Adolff, analyst]

Two questions from me as well, please. Firstly, just on the resource base, you do have a fairly big one, which is I think 50 years' worth. So I guess it is about high-grading when you do something inorganically. So I wonder, should you buy discovered resources such as those potentially in Brazil, namely the transfer of rights by the end of the year or early next year, would that coincide with the new disposal plan? Is that the right way to think about it? And secondly, just in terms of concentration risk, the top 5 countries in terms of capital employed for you include the U.S., Azerbaijan, Russia, Egypt and Angola. The U.S. is obviously now a bit bigger with the BHP deal. And in the past, you said that typically for a key region or a country, production should be in the range of 200 to 250 kbd. Equally, you also said that it could be more if returns are attractive. Now if we look at the U.S. Lower 48, it could be double that 250 kbd number after the BHP deal. So geographically or from a concentration risk perspective, I guess you're fine with that. But strategically, I wondered how big do you want your shale to be if there's such a thing as a number. For example, one of your peers argues that shale should be similar in size to deepwater because of X, Y and Z. And I wondered if there's anything interesting you can say on that.

[R. Dudley, executive]

Okay. Well, thank you. First, anything we'll look at. For example in the transfer of rights in Brazil, we'll look at that. It's not true that the timing and the pace of that and the Brazilian political framework is clear right now, but we would accommodate any options that we would do within the overall financial framework. So that would include everything we've talked about before. Divestments, we want to keep the entire financial framework intact. On geographic distributions, I mean, we have said it's about value not volume. We've got a spread of value around the world. We don't have really artificial constraints on any one area. I would see, with BP now in the United States, we have offshore in the Gulf of Mexico more than 300,000 barrels a day. The shales have the potential to be over 300,000 barrels a day, and we have our activities in Alaska. But again, we'll look at all of those around value over volume rather than being driven by a sort of a geopolitical risk framework.

[Craig Marshall, executive]

Thanks, Thomas. Yes, over to Colin Smith at Panmure Gordon. Colin.

[Colin Smith, analyst]

I'd just like to return to the question of the dividend increase and eliminating the scrip. Obviously, you've said you'd eliminate the scrip over time, but don't you think it's a bit dissonant to actually cut the scrip elimination in 2Q at the same time as you're raising the dividend? And I wonder if you could also comment in that relation, what the board thinks as sort of sensible payout ratio or ratio bandwidth might look like given that, on the quarter, you're still on a 72% payout ratio?

[Brian Gilvary, executive]

Yes, so let's be clear. We have not cut the scrip through the second quarter. We were very clear in October of last year when we said we'd eliminate scrip, we did it through the fourth quarter, we've done it through the first quarter, fully eliminated. We're now in the second quarter to eliminate the first quarter scrip. We're about, as Chris pointed out, halfway through, that will get eliminated through the third quarter. So we're talking about a time window of 2 to 3 months. I don't think that's disingenuous. And it reflects the fact that within the financial frame we have, we had $2.4 billion of payments going out to Macondo through the first half of the year. So I think it's really important to signal to shareholders to say we will offset scrip, and we will do that over a rolling 12-month period. So you shouldn't assume that we're going to suspend scrip purchase. We have been buying back shares through the second quarter and we're buying back shares through this week. Now we're back-end to -- out of the close period. But within the constraints that we have in terms of how much we can deal with and the constraints around the Macondo payments, the asymmetry of that, there's absolutely no intent to stop the scrip buyback program. But we did say -- we were very clear from day 1 that would be over time. So I think there isn't any confusion around that at all.

[Colin Smith, analyst]

Right. But the payment out for Macondo went down in the second quarter and the scrip elimination went down as well. I mean...

[Brian Gilvary, executive]

No, no, sorry. No, no, no. There was still $1 billion or so, $700 million of cash payments went out in the second quarter. The 2 things are not linked. It's a function of many things around the balance sheet and how we're running the balance sheet. But it's not -- these are -- we said it would be over time. It is over time. We will have offset the 2Q divi that was issued in the second quarter by the time we get to the end of 3Q. So I don't think there's any issue with pace here, we are buying back shares.

[R. Dudley, executive]

Okay. Thanks, Colin. And we'll turn to the last question from Jason Kenney at Santander.

[Jason Kenney, analyst]

So I've got a question on the breakeven profile. I think you're talking around $55 this year, and that kind of fits with the dividend which is set at $55. And by 2021, you're looking for a lower breakeven profile. What do you think the impact of current $70, $75 oil will have on your ability to lower the breakeven over the next 2 to 3 years? And I suppose, implicitly there, what are the chances of us seeing, in your view, a $50 oil price in 2021 versus the $75 oil price in 2021? I know it's an impossible question, but just trying to get a feeling for how inflation effects could be restricting the ability to lower the breakeven over the next couple of years.

[Brian Gilvary, executive]

So Jason, maybe just -- the plan we laid out February last year was at $55 a barrel real. Effectively, we laid out a growth profile through 2021, that we'll see something around -- I mean, you can do sort of ranges on this, but something around $7 billion of surplus free cash over and above an $8 billion dividend, and that's what drives you down to $35 to $40 a barrel breakeven. As we distribute between now and then, obviously, that changes what that profile looks like because you're now starting to distribute that cash to shareholders, which is what that dividend increase last week and what was confirmed this week in the results is effectively doing. So at $55 a barrel we'll look to still manage a progressive dividend. The payout ratio, I didn't actually answer the previous question on payout ratio. Typically, if you look over the period of 10 to 15 years, our payout ratio is around 25% to 35%. We've just come through a period where the oil price was down as low as $28 a barrel. So it's not really reflective of what would come through. And the whole point of a progressive dividend is for our shareholders, we will hold that dividend for you as the oil price drops, as it did. And as things get back into equilibrium, we'll rebalance the books. And we now believe we can rebalance those books all the way down to $35 to $40 a barrel if you assume $55 a barrel real oil prices. But this is no -- I don't think there's anybody around the table here who'll try and predict oil prices for 2021, it will be a function of supply and demand. Right now, supply and demand is in balance. I think Bob laid that out in his comments this morning. We're seeing strong demand, dampened a little bit by the oil production that we see coming out of Lower 48. And we're now -- now we're back into the 5-year averages, you're going to see a lot more movement around the oil price plus or minus $5 based on all the issues that Bob raised this morning in terms of short term disruptions or more production coming on. It's impossible to predict what we think it's going to be in 2021, but I think the number that Bob used historically at $50 to $65 for the sort of medium to long-term is not a bad assumption in terms of what we'd assume for planning purposes in terms of planning our company. What the actual oil price outturn will be a function of what supply and demand looks like in 2021. I mean, it would appear demand is continuing to grow at 1.6 million, 1.7 million barrels a day, and that certainly creates a degree of support around the sort of levels where we are today.

[Craig Marshall, executive]

Okay. Thank you, Jason. And that's, I think, the end of the questions that we have. I'm going to hand over to Bob for a few closing remarks. Thanks.

[R. Dudley, executive]

Well, first a big, big thank you. As always, very good questions from all of you, thank you very much.

I hope you've heard from us a commitment to a disciplined financial framework. We've got many moving parts going on right now, but we actually feel pretty good that we're able to move through these and meet our commitments. This is the sixth strong quarter we've had. We look at it inside the company as the sixth quarter out of 20 that we laid out before.

As a demonstration to commitments to increasing distributions to the shareholders, you've seen a dividend increase this quarter with a lot of time and thought in it. It's the first time in 15 quarters. And we've outlined for you a big transaction for us in BHP, offset by -- and we think of it as not a giant transaction, it is in fact a really good transaction that we will use to high-grade BP's portfolio.

We're hitting the road today and tomorrow all the way through the end of the week. We'll see many of you on road shows. We'll have 3 teams out in the U.K. and across the U.S. So hopefully, we'll cross paths here in the next few days. And again, thank you very much for your interest in BP.