英國石油 (BP) 2018 Q4 法說會逐字稿

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 Fourth Quarter and Full Year 2018 Results and Strategy Update.

I'm Craig Marshall, BP's Head of Investor Relations.

And I'm here today with our Chief Executive, Bob Dudley; and Chief Financial Officer, Brian Gilvary.

We are also joined by Upstream Chief Executive Bernard Looney; and Downstream Chief Executive, Tufan Erginbilgic.

Before we begin, 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 Bob.

Thank you, Craig, and welcome to everyone joining us today.

Six months ago, we opened our second quarter remarks by commenting on how busy the first half of 2018 had been.

And the second half was no different.

We're now 2 years into our 5-year plan and are making strong and steady progress despite the continuing volatility in the energy market.

First, to the agenda today, I'll begin the presentation with a review of the strategic highlights from 2018, reflecting on some of the key themes we have seen in the broader energy markets and demonstrate how our strategy is consistent with advancing the energy transition.

Brian will then take you through the detail of the fourth quarter and full year results and provide you with guidance on the outlook for 2019 and our financial frame.

Bernard and Tufan will then have an opportunity to update you on their businesses.

Lamar cannot be with us today as he is flying to meet shareholders, so I will provide an update on our low carbon strategy that he shared with you last year.

We'll then be ready to take your questions.

Now to highlights from the year.

The continuing business momentum has underpinned another strong set of operational and financial results.

This is a testament to the resilience of our strategy and supports our commitment to growing free cash flow and distributions to shareholders.

We reported underlying replacement cost profit of $12.7 billion for the full year, more than double that of a year ago.

Our underlying operating cash flow increased to $26.1 billion.

This is up 33% on 2017 after adjusting for a working capital build, reflecting real growth from across our businesses.

Organic capital expenditure was in line with guidance at $15.1 billion demonstrating our continued focus on cost and capital discipline.

And return on average capital employed was 11.2%, almost double that of 2017.

In the Upstream, we remain on track to deliver 900,000 barrels per day of new major project production by 2021, supported by the start-up of a further 6 major projects during 2018.

We also completed the transaction to acquire BHP's Lower 48 assets, creating a significant position in the region that is already contributing to production, earnings and cash flow growth.

And with the sanctioning of a further 9 projects in 2018, our organic reserves replacement ratio was just over 100% for the year.

On an organic-plus-inorganic basis it was 209%.

In the Downstream, we delivered our best underlying pretax earnings on record of $7.6 billion.

This was underpinned by the continued growth of our fuels marketing business in new and established markets, with 17% year-on-year earnings growth.

Across our manufacturing business, we continue to see strong performance with record refining throughput in the year.

We also made a series of announcements of interest that support our advanced mobility agenda, notably our purchase of Chargemaster, the U.K.'s largest electric vehicle charging company.

In Russia, our 19.75% shareholding in Rosneft provides us a strong position in one of the largest and lowest-cost hydrocarbon resource basins in the world with access to major markets both East and West.

In 2018, BP's share of production from Rosneft was around 1.1 million barrels per day, and we also received $620 million in dividends and these are after tax.

In addition to our equity position, we also have established technical cooperation arrangements on our building and material business that is generating incremental value through stand-alone joint ventures both in Russia and elsewhere.

Bernard will touch on these projects later.

Turning to our renewables and low-carbon businesses, in alternative energy, the partnership with Lightsource BP goes from strength to strength, having doubled its footprint around the world since we first combined.

In conjunction with our existing biofuels and wind businesses, we firmly believe that this kind of strategic partnership will drive further growth in our alternative energy portfolio.

We have also been in progress on the broader energy transition agenda.

We are addressing the dual challenge and setting ambitious targets to reduce our emissions, continuing to improve our products and creating new low-carbon businesses and markets.

I'll talk more about this and the announcement last week of the BP board's support for a proposed climate reporting resolution later.

I want to update you on the safe, reliable and efficient execution across our businesses.

It's a story of real progress, however we remain focused on moving that agenda forward.

Safety remains our #1 priority and a core value.

As you'll see from the slide, there was a reduction in the number of process safety events in 2018.

This is an important indicator of how we are working to keep our people out of harm's way and our plants running safely.

Our aim remains the same: to have no accidents, no harm to people and no damage to the environment.

There is always more we can do to drive improving results today and in the future.

As you have heard me say before, safety is good business.

This commitment to safety also leads to improving reliability of our underlying businesses which in turn leads to improved cash flows, thus, business performance.

In this regard, we have seen a consistent improvement in our Upstream plant reliability, a record 96% in 2018; and in the Downstream, our refining availability remains strong at 95%.

Turning then to the macro environment, we continue to see a number of factors contributing to an increase in volatility in the energy markets.

Over the course of 2018, OECD stocks moved back in line with 5-year average levels.

During the second half of the year, inventories began rising driven by a combination of increasing OPEC production levels, record U.S. supply growth and the decision by the U.S. government to grant waivers to buyers of Iranian oil.

Together, these saw the Brent oil price fall from a 4-year high in October of $86 per barrel to around $50 by the end of the year.

Looking to 2019, the Brent oil prices improved to around $63 as OPEC+ have started to implement their decision to reduce production for the first half of 2019.

On supply, U.S. tight oil is expected to continue to grow strongly, especially in the second half of the year, as new pipeline infrastructure is introduced.

On demand, we expect growth to remain above average supported by continuing gains in China and India.

The outlook for oil is expected to remain volatile with many uncertainties, including how markets respond to evolving sentiment around ongoing trade discussions, and Venezuela is an obvious concern.

Turning briefly to gas markets, the Henry Hub gas price moved significantly in the fourth quarter, increasing to $3.70 per MMBtu, with storage levels well below historical averages.

Year-to-date, prices have returned to recent average levels of around $3 due to milder weather.

Relatively low levels of storage mean that prices are likely to remain sensitive to weather conditions over the next few months.

So as investors and the wider society are faced with the challenges of near-term price volatility, so too are we, focusing our collective attention on the dual challenge facing the global energy system, that's meeting society's demand for more energy while at the same time working to reduce carbon emissions to help the world tackle the threat of climate change.

First, we estimate that the world is likely to need around 30% more energy by 2040 to continue to grow.

The majority of this additional demand comes from a growing prosperity in Asia with around 2.5 billion people set to be lifted from low to middle incomes over the next 20 years.

Second, carbon emissions need to fall rapidly to be on a path consistent with meeting the Paris climate goals.

There are a range of paths, but even our even-faster transition scenario, which I'll mention shortly, sees emission reductions in the order of 50% or so by 2040.

We all have a role to play in reducing emissions: governments, consumers as well as businesses like BP, yet on current trends, emissions are likely to continue to edge upwards in the near term.

As a global energy business, we are very committed to playing our part in a lower-carbon future.

We have introduced a clear framework that will shape our approach and hold us accountable through clear targets.

We call it RIC, or R-I-C, and more on that shortly.

Let me then spend a moment looking at how BP is thinking about the 2 parts of the dual energy challenge.

Turning to the first part, that of a growing demand for energy.

A year ago, Spencer Dale, our Chief Economist, laid out some scenarios within our Energy Outlook as to how the energy transition might evolve, and he and his team will release this year's Energy Outlook in just over a week.

I want to refer to a couple of scenarios from last year's Energy Outlook that help inform us about the future and position BP to be flexible through a range of outcomes.

First, an evolving transition scenario, which sees recent changes in global government policies, technological developments and social preferences continuing at a pace consistent with recent history.

By 2040, energy demand increases by 1/3, with oil demand growing from around 100 million barrels per day today to 110 million barrels per day by 2040.

But carbon emissions increased by 10%, far higher than the rapid decline thought necessary to be consistent with the Paris climate goals.

Second, an even-faster transition scenario, which sets a trajectory consistent with meeting Paris climate goals.

Carbon emissions fall by nearly 50% by 2040, while energy demand grows by over 20%.

Gas demand is broadly unchanged in 2040 versus today, while oil demand falls to around 80 million barrels per day.

Third, a scenario we have called supply with no investment, which assumes new investment in oil has stopped and existing oil production declines at a conservative rate of 3%, such that oil falls to around 45 million barrels per day.

So what does all of this mean for BP and our industry?

The world will need all forms of energy to meet demand in any scenario.

Renewables will grow significantly at a faster pace than any other form of energy in history.

However, oil and gas, in particular, still have a significant role to play in the dual energy challenge.

Successful companies will be those who have the greatest flexibility adapting to the prevailing price environment to produce the energy required in the form demanded.

For oil in particular, under a scenario that is broadly consistent with the Paris goals, significant investment is required.

Many trillions of dollars to bridge the gap between available levels of supply in the no-investment case and the likely levels of oil demand in 2040, even in scenarios designed to be consistent with meeting the Paris goals.

We believe we are well placed to compete.

Our focus on advantaged oil and gas is driving down our breakeven so that our barrels are increasingly competitive.

To enable this, we are investing our capital with discipline, improving the efficiency of our spending through standardization, driving deflation and implementing technology leading to improving returns.

We believe we can also compete through a strategy of maintaining balance and diversification across our portfolio, be it oil or gas, growing our low carbon renewables portfolio or investing in different geographies, markets or pricing regimes.

In summary, it's about progressing our strategy but doing so in a way that keeps us flexible and adaptable to the pace of change and to the changing environment.

The second part of the dual challenge relates to the need to reduce emissions.

We have embedded our approach to lower carbon and reducing emissions within our advancing the energy transition report, which we launched in April last year.

This clearly articulates our commitment to advance a low-carbon future through what we call our reduce, improve, create, or RIC framework: reduce the emissions in our operations, improve our products to help our customers reduce their own emissions from the products they buy and use, and create low-carbon businesses building on our existing alternative energy business.

Within this, we also set out clearer targets for the first time for reducing emissions in our operations.

So even as our business grows to meet growing demand for energy, our net carbon emissions will not.

Almost a year later, I'm pleased to say that we have made significant progress across our business in support of the targets we laid out.

Just a few examples include significantly reducing flaring at our offshore plant in Angola; using waste heat for power at our Whiting refinery in the U.S.; and testing technologies to quantify methane emissions in Azerbaijan and the U.S.; as well as setting out a framework for what we can do across our business operations, we also take action outside the organization, contributing to international initiatives like the OGCI, the Oil and Gas Climate Initiative.

We plan to publish an update on all of this in our sustainability report in April.

Before I hand over to Brian, let me briefly summarize.

As I mentioned at the start, it's been a busy year.

But we've created a strong track record of executing against our strategy.

This strategy was laid out 2 years ago and is based on 4 clear priorities.

Together, these embrace the energy transition and shape how we continue to create shareholder value in this rapidly changing world.

These 4 priorities are: first, growing supplies of clean gas and low-cost high-margin advantaged oil; second, market-led growth in the Downstream for our technologically advanced fuels, lubricants and petrochemicals and a growing range of bioproducts, electric vehicle charging and industry-leading carbon-neutral offers; third, venturing in low carbon across multiple fronts, including testing new emerging and potentially disruptive technologies and business models; and fourth, continuous modernizations of our plants, process, portfolios and ways of working.

The strategy allows us to flex and evolve with the changing environment, while staying committed to our proposition of growing shareholder value.

On that note, let me now hand it over to Brian.

Thanks, Bob.

Looking at the environment in the fourth quarter.

Brent crude averaged $69 per barrel compared with $75 per barrel in the third quarter, reflecting the significant fall in oil prices following the peak at the start of October.

Stronger demand along with low storage levels saw U.S. Henry Hub gas prices increase, averaging $3.70 per million British thermal units versus $2.90 in the third quarter.

BP's global refining marker margin averaged $11 per barrel compared with $14.70 per barrel in the third quarter, driven by ongoing product oversupply.

Moving to our results.

For the year, we saw a significant growth in earnings, cash and returns.

This was driven by a combination of higher oil prices, continuing strong reliability and availability across the businesses, and growing throughput and production.

This in turn provided us with the flexibility to manage our financial framework through a volatile price environment, while also providing the capacity to complete the $10.3 billion transaction to acquire BHP's Lower 48 assets.

Underlying replacement cost profit for the year was $12.7 billion compared to $6.2 billion in 2017.

For the fourth quarter, underlying replacement cost profit was $3.5 billion compared to $2.1 billion a year ago and $3.8 billion in the third quarter of 2018.

Compared to the third quarter, the fourth quarter result was impacted by lower Upstream liquids realizations, significantly higher turnaround activity in the Downstream and a lower contribution from Rosneft.

This was partly offset by a strong capture of the available heavy crude discount by our U.S. refining system, a strong fuels marketing contribution and higher Upstream production, including the addition of the BHP Lower 48 assets.

Compared to a year ago, the result benefits from higher Upstream realizations in production, strong fuels marketing growth in the Downstream, a higher supply and trading contribution and an increased contribution from Rosneft.

This was partly offset by a higher effective tax rate.

The fourth quarter also had a $1.2 billion nonoperating charge, which includes environmental and other legal provisions, as well as around $440 million for restructuring.

This is primarily noncash.

This is the final restructuring charge relating to the program that started in 2014, which has seen significant restructuring and rationalization activity across the group.

The total charge since this was initiated is $3.3 billion.

And finally, the fourth quarter dividend payable in the first quarter remains unchanged at $0.1025 per ordinary share.

Turning to cash flow and our sources and uses of cash.

Excluding oil spill-related outgoings, underlying operating cash flow is $26.1 billion for the year, of which $7.1 billion was generated in the fourth quarter.

This included a working capital build of $2.6 billion for the year, of which $1.5 billion was in the fourth quarter.

The fourth quarter build was primarily driven by price and timing effects including German mineral oil tax payments.

Organic capital expenditure was $4.4 billion in the fourth quarter and $15.1 billion for the year.

After adjusting for the working capital build, our 2018 organic free cash flow surplus was $6.5 billion, equivalent to an organic cash breakeven of around $50 per barrel on a full dividend basis.

Turning to inorganic cash flows, full year 2018 divestment and other proceeds totaled $3.5 billion, and we made post-tax Gulf of Mexico payments of $3.2 billion.

Inorganic capital expenditure was $9.9 billion for the full year, including payments in respect of the BHP acquisition of $6.7 billion.

Gearing at the end of the year was 30%.

We remain active in our share buyback program and bought back 50 million ordinary shares in 2018 at a cost of $355 million.

Now turning to guidance and our outlook for the first quarter of 2019.

In the Upstream, we expect reported production to be flat versus the fourth quarter.

This reflects the volume impact in high-margin regions from asset divestments, including Magnus and Bruce in the North Sea and Kuparuk in Alaska, as well as turnaround maintenance activities at Thunder Horse in the Gulf of Mexico.

We expect the volume impact to be offset by major project start-ups and a full quarter benefit of the BHP Lower 48 assets.

In the Downstream, we expect industry refining margins to be significantly lower with global product oversupply, particularly for gasoline, as well as narrower North American heavy crude differentials.

Looking at our guidance for the full year, we expect Upstream underlying production to be higher than 2018, with continued growth from major project start-ups.

Actual reported production will depend on divestments, OPEC quotas, entitlement impacts and other factors, including the pace of integration of the BHP assets.

Organic capital expenditure is expected to remain in the range of $15 billion to $17 billion.

The total DD&A charge is expected to be around the same level as 2018.

We expect to continue our share buyback program and to fully offset the impact of scrip dilution since the third quarter of 2017 by the end of this year.

Gulf of Mexico oil spill payments are expected to step down to around $2 billion in 2019 in line with the historical settlements.

These payments, along with the final cash installments relating to the BHP transaction, will be weighted towards the first half of the year.

With divestment proceeds weighted to the second half of the year and assuming current oil prices, gearing is expected to remain around the top end of the 20% to 30% range through the middle of the year.

In Other business and corporate, the average underlying quarterly charge is expected to be around $350 million, although this may fluctuate between individual quarters.

The underlying effective tax rate is expected to be around 40%.

As usual, we will provide updated rules of thumb for 2019 on price movement impacts for the year and expect to publish these on our website by the end of this month.

Finally, with the implementation of the new IFRS 16 standards on leases, we will be including additional disclosures in our Annual Report and Accounts for 2018 to be published later this year.

We also expect to revisit our guidance detailing any associated impacts from IFRS 16 at the time of our first quarter results.

To summarize, we continue to maintain a disciplined financial framework and are on track to deliver the 2021 targets we laid out 2 years ago.

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 commitment to fully fund the BHP transaction within the financial framework using available cash remains unchanged.

Through the end of January, we have paid the initial consideration and 3 deferred installments totaling $7.7 billion, with the remainder to be paid through April.

With the continuing high-grading of our portfolio alongside strong financial results, we also saw return on average capital employed improve from 5.8% in 2017 to 11.2% in 2018.

We remain confident in our guidance on returns of greater than 10% by 2021 at $55 per barrel.

In addition, our balance sheet and cash cover metrics remains strong.

At current oil prices and in line with growing free cash flow in the receipt of divestment proceeds, we expect gearing to move towards the middle of our targeted range of 20% to 30% through 2020.

We maintain our progressive dividend policy and the commitment to the share buyback program and expect to fully offset dilution from the scrip dividend since the third quarter of the 2017 by the end of this year.

Taken together, all of this supports our commitment to growing sustainable free cash flow and distributions to shareholders over the longer term.

On that note, let me now hand over to Bernard.

Thanks, Brian, and good morning, ladies and gentlemen.

In December, we hosted many of you at an event in Oman where I shared a detailed update on our progress and plans for the Upstream.

Today, I will summarize the key messages from this event, provide an update on 2018 delivery and provide some context on future plans.

In Oman, we shared the following key messages: First, our continued strong track record of delivery, doing what we said we would and doing so competitively and safely.

Second, we are on plan to deliver the 2021 cash flow growth target.

Third, we have improved both our capacity to grow and the quality of that growth.

We have the capability within our current resource base to grow pretax free cash by 40% to 50% from 2021 to 2025 under the current capital frame and with increasing returns.

Fourth and finally, we are transforming our business.

Our teams want it, the next generation will demand it, our shareholders deserve it and it is now hitting the bottom line.

We have momentum and we see enormous opportunity.

I'll touch briefly on some of these themes after we take a closer look at 2018 performance.

First, we grew reported production 3% versus 2017 ahead of our plan, with underlying growth of 8%.

We had record plant reliability of 96% and our average base decline over 5 years was 2.5%, better than guidance.

Second, we said we would maintain discipline and invest between $12 billion and $13 billion of organic capital per annum.

In 2018, we invested $12 billion of organic capital, underpinned by continued gains in execution performance, great delivery from the team and thereby creating the space for the BHP transaction.

As an example, 70% of our offshore wells are now top quartile, up from 25% just 5 years ago.

A lot of waste remains, but we will continue to drive the efficiency of spend through our transformation program to make more capital available for the group.

Third, we delivered 6 major project start-ups, which on average we delivered under budget and on schedule.

We also made 9 final investment decisions.

Fourth, all this helped us generate $16.5 billion of pretax free cash flow.

This is significantly higher than 2017, even after adjusting for higher oil prices.

Fifth, we strengthened our portfolio, notably through the acquisition of BHP's U.S. onshore assets, which added 4.6 billion barrels to our resource base.

And finally, as Bob mentioned earlier, we are making good progress in the Upstream on reducing emissions and have completed more than 50 projects to deliver sustainable emissions reductions.

A few examples include reducing flaring in Angola Block 18, electrification of compressors in Alaska and methane reduction in BPX Energy.

This is good progress, but we have more to do.

Moving to our projects, we remain on track to add 900,000 barrels a day of oil equivalent from our new projects in 2021.

20 of these projects have been delivered, including the start-up in January of the Anadarko-operated Constellation project in the Gulf of Mexico, and we have 15 to go.

With the recent sanction of Atlantis Phase 3 in the Gulf of Mexico and Cassia compression in Trinidad, all of the projects needed to deliver this plan have passed through the final investment decision gate.

We expect to deliver this plan with around $15 billion or 25% less capital than we envisaged when we first set out our plans.

As well as 35% higher cash margins, these projects are expected to have at least 20% lower development cost than the base business had in 2015.

This is advantaged oil and gas.

Next, to an update on BPX Energy, as we said in December at our event in Oman, the valuation looks just as good today as it did when we originally showed it in July, and likely, better.

In our newly acquired BHP acreage, we're up and running.

Our first 2 BP-operated rigs are now operating in the Eagle Ford and we spud our first 2 wells in early January.

By the end of 1Q, we expect to assume full control of field operations.

As we spend more time with these assets, we are confident of delivering the synergies.

We continue to see material upside potential through capital efficiency, and over time, we plan to exploit additional resource potential from zones that were not in our base case.

You will increasingly see this performance show up through the separate BPX Energy disclosures, and we will look to update the market on progress through the year.

Our 2018 delivery, progression of major projects and our enhanced position in the Lower 48 hopefully demonstrates why we are increasingly confident in our guidance.

Our plans for 2019 will continue to keep us on track for delivery in 2021 with another year of disciplined growth.

We expect underlying production to be higher than 2018 as we continue to ramp up major projects.

Reported production will be relatively flat as we go through our significant divestment program.

We expect our organic capital expenditure to be between $13 billion and $14 billion as we continue to focus on capital discipline and productivity.

We expect to start up around 5 major projects and take a number of final investment decisions on projects in the Gulf of Mexico, in the North Sea, AGT and India, underpinning growth to 2021 and beyond.

This underpins our confidence in the progress we are making to deliver $14 billion to $15 billion in pretax free cash flow by 2021.

I now want to turn to the longer term.

While maintaining our focus on delivery to 2021, we believe we can continue to grow through the next decade while remaining focused on value and quality.

The foundation is a high-quality resource base.

We have around 50 billion barrels of discovered resource.

Around 25 billion barrels of discovered resources proved and nonproved is in our forward plan.

Out of that total resource, around 50% is already booked as proved.

Another circa 30%, around 8 billion barrels, is expected to come from base management, new wells in our conventional reservoirs and our BPX Energy acreage.

These opportunities leverage existing infrastructure and are very capital-efficient, they're flexible and have quick paybacks.

The final circa 20% is from major projects, those that have been sanctioned or have yet to be sanctioned, and have or are expected to meet our hurdle rates.

To conclude, we don't need more resource to grow in the medium term, and we'll continue to look for opportunities to high-grade.

Now I will describe the next wave of around 20 potential major projects that may reach final investment decision over the next few years, and they're shown on the map.

There are several opportunities around our existing hub in the Gulf of Mexico, and we see similar opportunities in our other high-margin oil regions of the North Sea, Angola and Azerbaijan.

We continue to strengthen this hopper, for example, at Thunder Horse in the Gulf of Mexico, where we recently unlocked an additional 1 billion barrels of oil in place gross.

In Mauritania and Senegal, where we recently sanctioned the Greater Tortue/Ahmeyim development, we have the potential to create a major new LNG hub.

This is the first major gas project to reach final investment decision in the basin and was sanctioned at a fast pace, around 3.5 years from discovery.

In Trinidad and Australia, we are focused on keeping the existing LNG infrastructure full as demonstrated by the sanction of Matapal, formerly known as Savannah, in December.

Finally, as Bob mentioned, we continue to progress our joint ventures with Rosneft.

Taas, one of our 2018 major project start-ups, is producing and already returning cash to BP.

In December, we closed on our acquisition of a 49% stake in Kharampur and are developing an existing oil field and significant future gas production in West Siberia.

And our Yermak exploration joint venture in Western Siberia, where we also hold 49%, completed an extensive seismic program in 2018 and drilled an exploration well.

With all of this, we have increased confidence in continuing to grow beyond 2021.

We believe we have the capacity to increase pretax free cash flow by a further 40% to 50% by 2025 at constant capital.

This is not a promise or a target, but a scenario which demonstrates the depth and quality of our portfolio.

Finally, let me touch on our transformation agenda, which is really starting to bite.

We think of it through the lenses of digital, agility and mindset.

We now have around 1,000 projects across the Upstream aimed at sustainably improving both performance and how it feels to work in the Upstream.

Some are still in the idea phase, but the majority are in action, with a growing number already executed.

We spoke about these 4 examples in Oman, which demonstrate the enormous potential that we see in this area.

To accelerate digital further, we have now created a new digital function which stands alongside our operating functions.

Digital is going to be as important a capability in our industry as knowing how to drill a well.

I am keen that we move faster this new function, and hence, increased focus will help.

Agility is a potential game changer.

Last year, this went viral with over 3,000 staff trained on agile ways of working, not because they were forced but because the organization is energized about how this can transform the business.

Finally, mindset shift remains a must-do.

Last year, we made our largest investment in leadership training in a decade.

3,000 Upstream leaders trained in mindsets and ways of leading, 2,000 additional staff engaged in mindset-focused events and more to come in 2019.

In summary, 2018 has been a good year for the Upstream, where we increased confidence in 2021 delivery and underpinned our ability to continue growth well into the next decade.

But we're not stopping there.

We will continue to maintain a relentless focus on safety, pushing to improve the underlying efficiency of our business and are building momentum in transforming how we work.

Thank you for listening, and let me now hand over to Tufan.

Thank you, Bernard.

Good morning.

Today, I will provide you with an update of progress against our strategy.

To begin, let me briefly touch on the key global trends that are shaping our Downstream industry.

Driven by rising prosperity, global demand for fuels, lubricants and petrochemicals products is expected to continue to grow.

The majority of this growth will come from developing economies.

Demand is also projected to significantly grow across convenience retail markets.

As the energy transition evolves, products and services will need to be delivered in new and better ways, creating increased demand and material gross margin pools in the areas of advanced mobility, via low-carbon products, as well as the circular economy.

Digital transformation will also continue to rapidly progress.

With these trends in mind, our Downstream strategy was developed to deliver underlying earnings growth and build competitively advantaged businesses.

It is fit for now and fit for the future.

It focuses on the 5 key priorities of safety, profitable marketing growth, advantaged manufacturing, efficiency, low carbon and digital.

We are making strong progress and are on track to deliver our targets.

Let me now take you through 2018 delivery in more detail.

Firstly, our 2018 earnings of $7.6 billion are a record and some 70% higher than 2014 despite 2018 having one of the highest levels of turnaround activity in our history.

If you look at the chart on the left, you can see this performance reflects $4 billion of underlying earnings growth since 2014, with $1 billion delivered in the last 2 years.

A strong delivery particularly in a challenging 2018 environment where oil market opportunities negatively impacted our supply and trading business resulting in a lower contribution, which we do expect to come back.

And in lubricants, increasing base oil prices had an adverse lag impact.

Drivers of growth have been across marketing and manufacturing.

If you look at the chart on the right, you can see that in the last 2 years, they have delivered $1.4 billion of growth, $0.5 billion of which was in 2018, putting us firmly on track to deliver our $3 billion target.

We are also making progress on free cash flow growth, improving earnings quality and our competitiveness, while delivering attractive pretax returns.

As you can see from the chart on the left, we have grown EBITDA at double-digit rates since 2016.

It now stands at $9.6 billion, reflecting $2 billion of growth in the last 2 years.

As planned, to support the sustainability of this growth, we have increased our capital investment in high-returning projects with attractive cash profiles.

As a result, free cash flow in 2018 grew to nearly $7 billion, on track to deliver our $9 billion to $10 billion target in 2021.

This performance improvement further strengthens the quality of our earnings.

As you can see, we reduced the BP refining marker margin to deliver 15% returns to $8.6 per barrel, almost at our 2021 target.

And pretax returns of 21% in 2018, our best on record, means we have achieved our 2021 target of around 20% 3 years ahead of schedule.

This delivery further enhances our competitiveness and provides us with an excellent platform for continued growth.

Indeed, this strong delivery means that we now lead the competition in net income per barrel of refining capacity, a key measure of overall competitive performance which adjusts for business scale.

We have come from the bottom of the peer group in 2014 to the very top.

In addition, on the right, you can see that this competitive advantage and earnings quality has allowed us to grow net income differentially to the competition year-on-year.

Now let me share progress across marketing and manufacturing.

Our marketing businesses are material and differentiated.

In 2018, earnings grew to $4.1 billion.

As you can see on the chart, a growth of around 50% over 4 years, and pretax returns remained in excess of 30%.

In fuels marketing, earnings in 2018 grew by 17% to $2.8 billion, reflecting $0.5 billion of underlying earnings growth in the year.

In retail, we continue to strengthen our offer.

Our convenience partnership model continues to deliver differentiated returns as well as a strong value proposition to our customers.

We now have 1,400 convenience partnership sites, an increase of 290 in 2018.

As I previously shared with you, a main driver of the increase in our convenience partnership sites is our REWE To Go offer in Germany, where we now have 460 sites with this offer.

If you look at the chart in the middle, you can see that these sites already delivered significantly higher earnings than an average industry site.

And at full maturity, we expect that to be even higher.

The success of our convenience partnership model is reflected in our non-fuel retail gross margin, which grew to more than $1.2 billion.

In new markets, we continue to expand our footprint.

In Mexico, we now have 440 BP sites, with volumes already running at a level which makes this the fifth-largest market in our portfolio.

And we are also active in other new markets, such as China and Indonesia.

We anticipate that the earnings growth from our new markets will scale up from 2019 onwards.

We also continue to grow our B2B fuels and Air BP businesses, with Air BP's earnings growing by 10% in 2018.

Turning to lubricants, which in 2018 delivered earnings of $1.3 billion with highly competitive return on sales of 18% in what was a challenging base oil environment.

Indeed, our brands and differentiated position have enabled us to mitigate a large part of the recent base oil price increases, which, over the last 2 years, have impacted our cost of goods by more than $400 million.

This business has significant growth potential, with good exposure to growth markets and a growing premium segment.

Earnings from growth countries increased to 65% and premium lubricant volumes grew by 2% in 2018.

In summary, our marketing businesses are making strong progress.

We have demonstrated we can grow earnings at double-digit rates over the last 4 years while sustainably delivering attractive returns.

We also have good and increasing exposure to growth markets.

All of this underpins our confidence in further earnings growth to 2021 and beyond.

Turning to manufacturing.

We have an advantaged portfolio that has consistently delivered underlying earnings growth.

You can see from the chart we have delivered $0.9 billion of growth since 2016.

Delivery has been underpinned by our multi-year business improvement programs and strong operational performance.

In refining, we continue to progress our key programs of reliability, efficiency, advantaged feedstock and commercial optimization.

In 2018, refining availability was 95%, and we achieved record levels of throughput despite 2018 being a year of high turnaround activity.

At Whiting, for the second consecutive year, availability was sustained at the highest level in more than 10 years, allowing us to capture the benefits of wider North American heavy crude oil differentials.

And through our commercial optimization program, we delivered additional value from margin improvement initiatives, low-carbon bioprocessing and yield optimization.

All of this supported a continued improvement equivalent to $1 per barrel in underlying net cash margins since 2016, bringing the total improvement to $2.7 per barrel since 2014.

In petrochemicals, our operational performance, industry-leading technology and efficiency gains have supported the delivery of continued underlying earnings growth and pretax returns of more than 20% in 2018.

In fact, 2018 earnings of around $630 million was higher than 2017 despite the divestment of the SECCO joint venture.

Our technology remains a significant source of competitive advantage.

In 2018, we secured 6 new licensing agreements out of the 10 PTA and PX licenses [enhanced] globally.

And we recently signed a heads of agreement with SOCAR to evaluate the creation of a joint venture to build and operate a world-class petrochemicals complex in Turkey.

This facility would be the largest and most competitive integrated PTA/PX and aromatic complex in the Western Hemisphere.

In summary, across manufacturing, we delivered strong operational performance and continued earnings growth.

Looking forward, our business improvement plans support more than $1 billion of additional earnings growth over the next 5 years that underpins delivery of our 2021 targets.

In addition, our refining portfolio is well-positioned for the upcoming IMO 2020 changes, with around 47% of our yield being distillates and less than 3% being high-sulfur fuel oil.

This delivery potential and selective investments in an attractive and growing petrochemicals market gives me confidence in further earnings growth to 2021 and beyond.

Now turning to the transition to a lower-carbon and digitally enabled future.

We have a clear strategy with a focused activity set.

We are capturing the emerging material gross margin pools by building capability, strategic partnerships, collaborating with industry leaders and leveraging our venturing investments.

We have many projects underway.

The plans we have in this space will transform our business over time and are already beginning to create value for us now.

To illustrate, let me share a few examples.

In advanced mobility, we are developing new customer-centric solutions.

Our electrification strategy is to provide the fastest and most convenient network of charging solutions.

In 2018, we acquired Chargemaster, the U.K.'s largest electric vehicle charging company.

Our ambition is to roll out more than 2,000 additional charging points, bringing the total to around 9,000 by 2021, including more than 400 new ultrafast chargers at our retail forecourts in the U.K...

We have plans to scale up advanced mobility opportunities in focused countries, such as U.K., Germany and China.

In bio and low carbon, advantaged bio-based feedstocks and technologies will be key differentiators.

We have made significant progress in innovative technology deployment, some of which are already generating value.

In refining, we have expanded lower-carbon bioprocessing to 4 of our refineries, which generated $70 million of margin in 2018.

We have plans to expand this threefold by 2025.

In petrochemicals, the circular economy is a major driver in the chemicals and plastics sector.

We see chemical recycling as a game changer for the plastics circularity.

We are developing technologies to lead the market in this space and looking to commercialize these technologies by 2025.

Turning to digital, in customer and consumer experiences, BPMe is our global customer engagement platform.

It will be the portal to a suite of offers and services that will transform our retail offer and deliver an enhanced and personalized customer experience.

It is already in 6 countries with over 1 million downloads, and the number is increasing every month.

In the U.K., one of the first-launch markets, users on average buy around 3x more Ultimate fuel than other customers.

Across manufacturing, we are developing digital solutions focusing on 3 key areas: world-class productivity, plant availability and optimized production, which are being implemented at our refineries in Kwinana, Whiting and Cherry Point, respectively.

We are already using a range of technologies, including deployment of sensors, predictive analytics and artificial intelligence.

Through the use of digital technologies across our manufacturing portfolio, we expect to deliver $0.5 billion of earnings growth by 2025.

As you can see, across these new business models and digital, we are already in action and creating value in this space.

In summary, our strategy continues to deliver results.

We have grown underlying earnings by $1.4 billion across marketing and manufacturing in the last 2 years.

In 2018, we delivered nearly $7 billion of free cash flow, with returns of 21%.

This strong delivery puts us firmly on track to deliver our 2021 targets, primarily underpinned by: in marketing, the continued expansion of our successful convenience partnership model, increasing growth market exposure and the scale-up of new market earnings; in manufacturing, more than $1 billion of earnings growth in the next 5 years from our business improvement plans; and across all our businesses, continued focus on efficiency and cost competitiveness.

Looking beyond 2021, we expect continued earnings growth from these areas as well as significant growth potential from selective investments in an attractive and growing petrochemicals market, and our new business models in advanced mobility via low carbon as well as digital.

In closing, our strategy is clear: It is fit for now and fit for the future.

Our delivery gives me great confidence and I am excited with the scale and breadth of opportunities I see.

We have committed and capable people, the know-how, innovation and partnerships to deliver this.

Now let me pass you over to Bob.

Thank you, Tufan.

I would now like to take a moment to share our work across our low-carbon businesses, one of our strategic priorities.

In alternative energy, we already have 5 significant and growing businesses: renewable fuels, renewables products, wind energy, solar energy and biopower, and I want to highlight just a few examples of tangible work.

Our renewable fuels business, which operates 3 world-scale sugarcane ethanol plants in Brazil, has increased production by 40% in 5 years through the innovative use of digital technologies as well as distinctive partnerships such as our JV with Copersucar.

As I mentioned earlier, we are a year on from forming our strategic partnership with Lightsource BP and have expanded activity from 5 countries to 10.

We found new ways of leveraging Lightsource's solar capability with BP's networks and resources to expand under a capital-light framework.

Growth has also been driven by a strong platform of partnerships, including in India, where Lightsource BP and Everstone Capital have partnered to manage a fund focusing on new energy and conservation projects.

In the U.S., our wind energy portfolio now has 1.8 gigawatts of gross capacity across 11 sites.

We've been restructuring and redeploying capital to optimize the portfolio for long-term growth, including the power storage investment we made in partnership with Tesla.

In renewable products, our Butamax joint venture with DuPont is progressing a plant upgrade in the U.S. that will commercialize our proprietary technology converting sugars into an energy-rich bioproduct, bio-isobutanol.

In addition, alternative energy are developing new digital energy in low-carbon power and storage opportunities that offer attractive synergies with our existing portfolio.

This includes the agreement with the government of Azerbaijan to jointly evaluate opportunities to develop renewable energy projects there.

The dual energy challenge and accelerated adoption of digital technology is also creating new and very interesting business models.

We are investing in new products, companies and technologies which leverage our core knowledge and capabilities.

We have a clear financial frame, investing around $0.5 billion annually across 5 focus areas.

They are advanced mobility, bio and low-carbon products, carbon management, power and storage, and digital.

These focus areas were selected for their potential to become material businesses in the future, and our capital commitment level is designed to provide the right balance between portfolio optionality, commercial scaling and responsible investment.

In addition to what Tufan described, we made big steps in 2018.

For example, in carbon management, we invested in projects that generated more than 25 million tonnes of CO2 equivalent offsets last year just in forestry projects.

We invested in StoreDot, an ultrafast charging battery developer; in Voltaware, a residential and commercial energy management system, and in fact, our overall ventures pipeline grew to more than 40 active investments with more than 200 partners.

In addition, we continue to foster and expand relationships at an industry level to ensure future success.

In November, the OGCI's billion-dollar investment vehicle, Climate Investments, announced a feasibility study for the U.K.'s Clean Gas Project, a world first in CCUS technology for capturing industrial and gas-fired power generation emissions.

I believe we are in great shape to act where we see opportunity to make a positive difference in this transition.

It's inspiring our people to look for new and better low-carbon ways of doing things, while creating new value for our company.

Well, thank you for listening over the past hour or so.

Let me briefly summarize before we move to Q&A.

2 years into our 5-year plan, we've created a powerful track record of delivery doing what we said we would do.

This delivery is coming from across our growing businesses.

It's seeing us invest with discipline into the growing Upstream, both organically and through acquisitions, where we believe we can create value.

In the Downstream, we're expanding our marketing business alongside a strong refining system with high availability.

We're also investing into our existing alternative energy business and creating new low-carbon businesses.

And all of this is delivering strong financial results.

Many of you may have also seen our announcement last week supporting a proposed resolution from a group of investors called Climate Action 100+.

This proposed resolution seeks additional corporate reporting in the context of the Paris goals.

It addresses BP's strategy, our metrics and targets and how we evaluate material new capital investments.

We've listened carefully to investor sentiment and opinion over the past few months on the role of BP in the energy transition, recognizing the views are wide-ranging.

Together with recent engagement between BP and Climate Action 100+, this has enabled us to support the proposed transparency resolution.

The board intends to provide more detail in a notice to shareholders ahead of our annual meeting in May.

So in closing, we are building business momentum, delivering our strategic priorities and are growing the business, all of which underpins our commitment to growing shareholder value.

And I'm very optimistic about the future and the role that BP, as a global energy company, has to play in advancing the energy transition.

Now Brian, Bernard, Tufan and I are now ready to take your questions.

(Operator Instructions)

Okay.

Thank you again, everybody, for listening.

We're now going to turn to questions and answers.

(Operator Instructions)

On that note, let's take the first question from Jon Rigby at UBS.

Jon, good morning.

Yes, 2 questions.

The first is on the results or the outcome of the results.

So I mean, I think you've clearly signaled a gearing level at the end of this year of about 30% or so.

And that was an output from the decision you made not to issue equity for the BHP transaction.

And I think since then, obviously, macro conditions have deteriorated.

So I just wanted to get a better idea about where you stand on debt.

My sense is, is that you feel somewhat more relaxed about levels of gearing than perhaps some of your peers who appear to be keen to drive gearing down lower from levels that are already below 20% or so.

So I just wanted to understand a little around the prioritization of debt versus CapEx versus anything else you do or disposals across the next 1 or 2 years, if indeed macro conditions are somewhat weaker than they were in 2018.

The second question is on the low-carbon strategy.

I get and fully support the reduce and improve, I'm a little nervous about the create bit.

Because it seems to me -- and it's sort of backed up by the press release last week, is that the reaction or a response to quite a lot of pressure around doing low-carbon businesses.

But what has never really been properly articulated, or I might have missed something, is the return framework around that.

So it's of good intention but an absence of what the financial outcome is likely to be, and it's the financial structure that clearly applies to your Upstream and your Downstream business.

So I just wondered to what degree do you move forward with that strategy before we, as investors and analysts, get to judge what the financial returns on these kind of investments are?

So Jon, let me pick up the first part and Bob can pick up the piece around the low carbon.

I think you've answered a lot of the question in your question itself.

The environment did deteriorate through December, but, of course, it's now back over $60 a barrel and looks pretty constructive around those sort of levels.

So it's significantly above our assumptions and what we're receiving around the original BHP transaction.

And you also know with the various announcements in Lower 48, the Midland differentials come right into WTI.

I think, it's trading just about $0.60 below.

So the economics of that transaction looks even better than what we described when we announced it.

And I think the use of cash versus shares has been incredibly positively received by our investor base.

So I think universally, the investors are very happy with that.

But of course, as you've laid out, it means that gearing will be up at the higher end.

We've got about just over $2.5 billion of payments left to go on the BHP transaction, which will come out through to the end of April, so the end of February, end of March and end of April, the last 3 final payments.

We have about $2 billion of Deepwater Horizon payments for this year, which is on the schedule that we laid out back after the 2015 settlement.

So we're now back on the first year of that schedule.

So they're pretty much prescripted in, in the first half of the years.

And the disposal proceeds are going to be sort of again weighted towards the second half of this year, but we have actually now specified, it's over $10 billion over the next 2 years.

So you're going to see those proceeds come through.

And I think what's resonated with the investor base is those proceeds will clearly be used primarily initially to bring gearing down.

And then, of course, at these higher oil prices, last year, one of the big parts, if you look at the balances for last year, we balanced the books of $50 a barrel.

We're currently today sitting at $62 and it would appear that it looks pretty constructive in this range.

So I think while we're balanced at $50, constructive at $60 a barrel, I think there'll be more to come this year and I'm sure Bernard will talk about BHP as we integrate those assets into the portfolio.

But there is no question now from the board perspective, deleveraging now off the back of the disposal proceeds through the back end of this year and into 2020 is now one of the primacies in terms of the balance sheet and financial frame.

Okay.

Thanks, Brian.

Jon, hi, this is Bob.

You asked a good question about creating new business models.

And essentially, we have a large renewables business today that generates operating cash flows that are healthy and getting healthier.

Our approach to this is: one, we know the direction the world's going to a lower-carbon future.

No one knows exactly how that's going to unfold.

But as a company, we need to be nimble about it and we need to be able to respond to customer preferences that'll change.

I think, a key aspect of our strategy is really flexible, agile, just to be sure we can adapt quickly to changing circumstances.

It is a capital-light model.

The speed of this transition over the next few decades is highly, highly uncertain depending on technology, societal preferences, government policies, all those things.

So you are right.

Uncertainty means long-term plans with big commitments and big bets are risky.

So we're going to be cautious about this.

For example, capital-light Lightsource BP, so it's a company that's growing.

We work with them, provide them access to other places where we work and actually there's an integrated set of economics that are probably different than other people see that we look at.

So we think this is all part of the energy transition.

We're going to be part of it, we're going to try to be a leader with other companies who are doing good things in this.

But right now, we believe our strategy that we've laid out 2 years ago is consistent with Paris.

And what this is, the resolution is more transparency about what we're doing, we like transparency.

We have, inside the company, a renewal committee that's run in junction with our big capital commitment's committee.

All the executives are involved in it to learn, even though the size of these investments are nothing like other parts of the business.

So we realize we have to be very disciplined about the shareholders' money.

And that level of investment to us looks like it's going to position us in lots of ways.

Chargemaster, the electric charging company here, we know that it's going to be important, particularly, in cities here in the U.K. They're going to be on our forecourts and there's a business model evolving around that, which involves convenience stores.

So there is -- I can go on a lot about this, but I wouldn't get worried that we are not going to steward the capital with a discipline, but we are going to invest in some of these businesses.

Okay.

Thanks, Jon.

We'll take the next question from Lydia Rainforth at Barclays.

Lydia?

Two questions again, if I could as well, please.

Bob, you were quoted this morning in the news as saying that BP will move to sizeable buybacks over time.

I'm just wondering if you can clarify those comments as to kind of what sizeable means and over what time frame we should be thinking about that.

And then secondly, linked a little bit to Jon's question, Bernard talked about the ability to grow Upstream free cash flow on a pretax basis 40% to 50% by 2025.

At what point do you actually have to make the decision to allocate the capital to the Upstream business to do that?

And some of the other choices that you might have to make around of the energy transition work?

Lydia, can I take -- if I just take the first part of that question around buybacks?

I think, as we've already said, for this year, we're going to offset all of the scrip dilution from the third quarter 2017 announcement.

We'd slow down the repurchase of shares when we announced the decision to use cash versus equity on the BHP transaction.

But we've committed today that actually there will be a sizable buyback program in the back end of this year.

And then if you go back to this strategy that was laid out 2 years ago, as you've seen in the dividend increase last year by the board was a signal.

As we start to see that free cash flow appear over and above what Jon talked about earlier in terms of disposal proceeds initially being used to bring gearing down, as the strategy plays out over the next 3 years, there is a significant amount of free cash that will come with it.

And then the board will be able to decide whether we look in terms of progressive dividend, further buybacks over and above scrip and other opportunities within the company.

And Lydia, you asked a question about allocation of capital between, I think, the Upstream and new energies.

Is that -- was that the essence of your...

Yes, it was just the idea that if Bernard can keep the capital framework flat at $13 billion to $14 billion and be able to grow free cash flow by 40% to 50% by 2025.

At some stage, that has to become a commitment that [said that he could sort of] get by capital available.

And it's what -- at what point you actually need to commit to doing that or is the choice between Upstream and either Downstream of the renewable side?

Well, right now, we are on track to be able to do that.

So with the Upstream capital and the efficiency of these big projects bringing them on time, what we're able to do with the dollar, our capital is quite different than it was, so we're going to keep the overall disciplined framework $15 billion to $17 billion.

We're going to flex within that, no magic formulas really between the Upstream and the Downstream.

And spending in alternative energies, I think, is sort of rounding in all that.

So Bernard, you want to comment on and see the direction of capital you'll need with the growth that we have?

Yes, I think -- thank you, Lydia, and good morning, everyone.

I think the scenario that we laid out was a scenario with the existing resource base and with constant capital, as Lydia said.

And we feel quite confident in the quality.

And ultimately over time, it becomes a choice for the board and for Bob to decide what level of reinvestment.

Our job is to ensure that the quality of the investment opportunities are there.

And as we discussed in Oman, we see the real potential to grow.

And as every year moves forward, that cash flow increase potential becomes more and more real.

I'm just going to add a footnote, Lydia, to what Bernard said and when you think about allocating capital, I mean, we do see generally we turn over the entire balance sheet really in 8 to 9 years.

So as the energy transition moves along, we're going to have flexibility to move down the road between if the new business models become material that we'll begin to reallocate capital.

But we're going to have the flexibility to do that.

And I think, when I hear people talk about stranded assets and we're investing in things for very long term and we are a very long-term company, it's you can turn the balance sheets over of not only us, but the IOCs in under a decade here.

So we're planning flexibility and adaptability sort of longer term in our thinking.

Thanks, Lydia.

We'll take the next question from Alastair Syme at Citi.

I was wondering if you could talk a little bit about the decision to increase the size of the disposal program.

Is it just that the initial signs are that the data rooms are doing well or are there some sort of broader strategic ambitions as you want to sharpen the business?

And secondly, I just wanted -- I know you give a lot more disclosure in the annual report, but any sort of color you can give around the reserve bookings, particularly, if you'd like to share an ex Rosneft number for us?

So Alastair, on the first part, I don't think there's any new news than what we've said today.

I think the only bit of new news is the specificity of the 10 over 2 years, because previously we'd set off the back of BHP, we'd look to sell $5 billion to $6 billion of assets to fund that acquisition.

And we have a typical $2 billion to $3 billion churn every year, which historically we've set aside in the most recent years for Macondo payments.

So if you combine those 2 things, it gets to a figure of around $9 billion to $12 billion.

So we've specified actually a figure of $10 billion for the next 2 years and we are well-advanced in terms of that portfolio, particularly the pieces around the Lower 48, which are pretty public in terms of the marketing of those assets from the historical legacy position that BP had and a suite of other options we have globally, but I think high-grading the portfolio is just good for all seasons and especially if you look at these new margin barrels that Bernard and the team are bringing on, it gives us more opportunities to be able to high-grade.

So I don't think there's anything specific other than the specificity of the 10 over 2 years rather than maybe the 5 to 6 over 3 years.

Alastair, and I think on reserve bookings, we're not going to break them out separately, but there's healthy reserve bookings at both parts of the business in there.

And it sounds very sort of number out of the air at 100, it's actually 100.4% if anybody thought we were rounding.

And I think the -- if you take into account disposals and acquisitions with BHP, we have -- including the divestments, 209% for the year, but we're not going to split the 2 out.

And I'm not even sure we have the permission of Rosneft to do that now.

We will, however, Alastair, give the full detail on the breakdown, as usual, in our annual report and accounts, which I believe is published on the 3rd of April.

Okay.

Next question from Biraj Borkhataria, please, RBC.

Two, please.

One was for Bernard.

Earlier in the call, you referenced Upstream reliability a new record for BP, but I believe that was for operated projects.

Could you talk a little bit about the nonoperated side performance there and how that compares to the operated?

And the second question, just a very quick clarification on Macondo.

So $2 billion guidance for 2019, could you talk about the -- if there's any uncertainty to that number?

I think the defined element is about just over $1 billion.

So how much confidence you have on the remaining part?

Biraj, thank you for the question.

Yes, we have seen our highest reliability on record in 2018 results of a lot of hard work by the team over many, many years and that's been improvements right across the board.

Reliability in the North Sea, for example, has gone up by 10 percentage points over the last 4 to 5 years and it's really an investment into the operating mentality and the operating equipment inside the Upstream.

How it compares to operated by others?

I think we try to benchmark ourselves locally in each of the basins we operate around the world.

I think our track record is good in a relative basis.

And to your questions, one of the things that we have underway at the moment is a project that is looking at our governance of nonoperated joint ventures and operated by other facilities.

And one of the purposes, Biraj, is to see if we can help in any way transfer some of our learnings on that reliability improvement program over the last several years into those operated properties.

And by the way, we can learn from them as well.

So the learnings will go both ways, but that is a specific project that we have underway to improve how we govern and how we transfer learnings between ourselves and our partners.

Biraj, in terms of Macondo, the total provision now is at $67 billion pretax or $50.5 billion posttax, of which about $52.7 billion of pretax has been paid out.

Pretty much now, we are done with the BEL process, which is where the uncertainty was historically.

We're left with just less than 100 claims on appeal.

So they've all been processed and they're now going to the appeals process.

But this is pretty stable now back on the original schedules that were negotiated back in 2015 and 2012.

And so therefore, we wouldn't expect any major changes.

It's now really around basically the appeals process and any litigation associated with that for which we've already provided in our provision, but we'd expect this to stay pretty stable now with around $2 billion this year.

Last year was $3.2 billion, which is pretty much what we signaled at start of the year is where the actual payments came out and then we get into the runoff effectively next year of $1 billion a year out to, I think, it's 2032 is the final year of the settlements that were put in place in 2015.

Okay.

Thank you.

We'll take the next question from Christyan Malek of JPMorgan.

Christyan?

Two, if I may.

First, with the strong cash flow result, I guess, you're continuing falling cash breakevens relative to the prevailing oil price.

I wonder is there a target gearing or divestment size that you're looking to achieve first before you roll out your cash return framework.

And just to be clear, lowering gearing paves the way for cash return as opposed to more M&A.

I guess, secondly and somewhat -- I'll add to that, when you look at your growth options and sort of, indeed, your scenario to grow free cash flow in 2025 by probably 50% versus 2021, a lot of these projects seem to be at least skewed to where you've build long-standing legacy relationships with Angola, Azerbaijan, Oman, Egypt.

Are you comfortable that the portfolio is sufficiently diverse?

Because it strikes me that it remains quite exposed to conventional oils and legacy assets relative to your deepwater and shale positions and so it makes you wonder whether you may still be tempted to exercise M&A as opposed to sanction many of these slide FIDs into the next decade?

Thanks, Christyan.

So just on the first question, there's no specific target around gearing other than, I think, certainly from the board perspective and our investors.

They would now expect us to let gearing come down along the pathway I have already described around the cash flow that goes out in the sort of first half of this year and the disposal proceeds that come back in.

I think, it's also worth noting that our relative position on net debt and gearing is not that surprising given the $16 billion that was paid out over the last 3 years around Deepwater Horizon settlements.

It's the reason why our gearing is relatively high compared to maybe the peer set.

But right now, the primacy will be around gearing coming down initially certainly and we've signaled out to 2020 that we'd expect it to get back into the middle part of the range.

But I think the board would want to keep all options open around shareholder distributions, which we saw last year with the dividend increase, share buybacks which Bob had already alluded to certainly in terms of the scrip buyback and maybe beyond that in terms of surplus free cash.

And we'll always look at renewing the portfolio and will continue to divest assets.

So I think, yes, the -- pretty much the framework that's seen us through the last 8 years and seen us through some pretty turbulent times, if you think about Deepwater Horizon and then the oil price correction will serve us well going forward.

And turn it over to Bernard on some of the Upstream views of the portfolio, but I actually think it's a great portfolio.

It's got a wide diversity across it.

And legacy assets always, if you can add on to what you've got, you've got the overheads, you've got the infrastructure, generally are always really good investment.

So I don't think we'll turn away from those things.

But we've got FIDs coming up in Gulf of Mexico again in the North Sea Azerbaijan, Mauritania, Senegal, Egypt, Australia.

I mean, it's a very wide portfolio and I think they have a great potential to continue to provide great returns for shareholders.

But Bernard, you've been thinking about the diversity here in those all kinds of things to keep going?

Yes.

Thanks, Bob, and thanks, Christyan.

We missed you in Oman.

But I think one of the things that we laid out in Oman is just a few points I'd make around either, that the quality of the existing resource base and some of the new options that we have.

So if you look, for example, today, the top 4 cash-generating regions in the company, which you would classify as existing regions, Angola, Azerbaijan, North Sea and Gulf of Mexico, they produced about 40% of the cash flow of the Upstream in 2018.

By 2025, because of the quality of that resource base with no new exploration, we could see that cash flow grow by 50% from those 4 regions by 2025, just gives you a sense of the existing resource base that we have.

Specifically Gulf of Mexico, 2013, 200,000 barrels a day.

Today, 300,000 barrels a day.

And in Oman, we said by 2025, it could be doing 400,000 barrels a day.

And existing 1 billion barrels we've just discovered at Thunder Horse oil in place, 2 new discoveries in the Gulf of Mexico.

And then -- so that's examples from the existing resource base.

And then beyond, I mean, Mauritania and Senegal, we just entered at the end of '16.

Just sanctioned Phase 1 of Tortue.

We've got Phases 2, 3 and 4 to go in Tortue.

We have appraisal to do at Yakaar in Senegal.

We have more work to do at [Berala] in Mauritania.

So I think, yes, the existing regions continue to give and give and give, which, as Bob said, is a characteristic of great basins.

And secondly, we are expanding the diversity of it as well through examples like the entry into Mauritania and Senegal just a couple of years ago.

I'm just going to add another footnote.

I mean, broadly, we really like what we have.

It doesn't mean we're going to continue or standstill with shaping the portfolio, but we worked pretty hard after the events of the Gulf of Mexico to significantly change the portfolio and focus down.

We look at not only in the Upstream, Downstream and with alternative energies, where -- we look at geographies, fiscal regimes, balance of oil and gas and other forms of energy provisions here.

So we look at it and we're always open to comments and suggestions and observations.

But to us, it feels like a very balanced portfolio.

Thanks, Christyan.

Yes, thank you.

We'll take the next question from Henry Tarr at Berenberg.

Henry?

A couple of questions from me.

One is, how you're thinking about investments in the Lower 48 this year?

And then the second thing would be just on the restructuring and the provision in the quarter.

Could you give maybe just a little bit more color on what that restructuring is achieving for you?

Very good.

Henry, in the Lower 48 -- it's Bernard, we basically assumed the business at the end of October.

So we had 2 months in the first quarter -- in the fourth quarter, sorry, in 2018.

We'll assume full operation, operation control on March 1 of this year.

Integration is going well.

We just spudded our first 2 wells on the new acreage, both of those in the Eagle Ford.

Synergies are going well.

I think, there were about 550 people in the existing BHP operations team.

I think, we've offered jobs to just 120 of those.

So a lot of work going on, on that.

We had about 6 rigs running in our existing base.

They had about 6 rigs running in their business.

I think, we seek about a 15-rig program in 2019.

We were spending close to $1 billion a year of capital.

That will get up to about $2 billion this year.

The majority of that investment will be in the Haynesville and the Eagle Ford with some in the Permian.

And then over time, we'll probably ramp capital up to around $2.5 billion with the majority of the capital over time as the logistics constraints get lifted shifting towards the Permian.

So very pleased with what we said.

I think, Brian said it well that the deal looks as good as it did when we first did it today and it likely looks quite a bit better.

So that's what I would say on the Lower 48.

And then in terms of restructuring, since we announced we started this program back in the fourth quarter 2014, if you recall, that was the sort of time when we were in that space of lower-for-longer on oil price and concerned about where we thought directionally at that point in the fourth quarter '14 when the price was starting to come off.

We started a rationalization program.

This quarter, the charge -- the total charge since we started is about $3.3 billion, which has led to very significant and major restructuring of our company, which is actually why one of the biggest drivers of why we can now balance the books of $50 a barrel from where the oil price was in the fourth quarter -- the start of the fourth quarter of 2014 up at $100 a barrel.

So that's been a big part of that.

In the fourth quarter, it's the final restructuring charge we're going to take around that program.

In terms of a go-forward basis, it'll just be routine business as usual in terms of restructuring.

And of the $440 million, just less than half of that is in the Downstream and the balance is in corporate functions and still part of the Upstream.

So it's been a major program.

It's a program now that we've run over 4 years since it was first announced.

And it's led to a significant reduction in our cost base and being able to drive those efficiencies within the system.

Okay.

Thank you, Henry.

We'll take the next question from Irene Himona at Societe Generale.

Irene?

So 2 questions.

Firstly, Upstream.

Bernard, you referred to the creation of a digital organization alongside the business.

I wonder if you can help us conceptualize the potential benefits.

You're probably reluctant to quantify, but should we be thinking about something truly noticeable, spectacular and significant medium term?

Second question on the Downstream, Tufan, lubricants reported earnings declining both in Q4 and in the full year.

You referred in your remarks to the base price effect.

I mean, I don't know what the time lags are, but surely that must have kind of walked its way through the system by now.

And if it has, should we be anticipating an improvement in lubricant earnings this year?

Irene, I'll do the first on digital.

Spectacular, I would love.

I'm not sure that we're yet ready to promise that.

But we've gone about this with real intent.

And I feel good about what the team has delivered on digital over the last couple of years.

And the APEX production optimization model that you saw in Oman delivering 30,000 barrels a day of incremental production in 2018 helping our base decline go down to less than historical averages.

That's a great example of what's possible.

Inspection cost down by $200 million and so on.

But having said that, we still are dissatisfied actually with the pace because we believe that while we're doing good, we believe we could do much, much more.

And that's why we've created the function.

[Ahmed] has put together a 100-day plan that I'll be reviewing here in a couple of weeks' time.

We'll then move from there into an annual plan.

And our ambition is that we don't have just 1 APEX story to tell you in 6 months' time that we have many such material stories of where we have moved products from beyond minimum viable product stage and into real applications.

So it is early yet.

I think, we're reluctant to quantify and issue targets around this because, quite frankly, when we get into it, it's only then that we discover what's possible and we'd rather be led by the results than necessarily led by a specific target because the target may simply not be enough.

So I think a real intent here to do something quite different, too early to start to put some specific targeted numbers to it.

Irene, thanks for the lubricants question.

The way to think about lubricants is it's highly differentiated business.

65% of our earnings in growth countries.

So it is fundamentally growth business.

But last 2 years, we had this cost of goods sold increase because of base oil -- because of crude prices and base oil.

And the lag in this business, because it is B2B2C business, i.e., with intermediaries, generally if 3, 4 months.

So if you take that into account, that is the -- and with the competitive intensity as well, that's the lag impacting the business.

But because we are highly differentiated, we actually offset most of -- a large part of that increase in the cost of goods.

Going forward, yes, you should expect that this business will continue to grow.

Okay.

Thank you, Irene.

We'll take the next question from Chris Kuplent, Bank of America.

Chris?

Just 2 questions I've got left here.

First one, I suppose, for Bob on your comment regarding the Paris climate goals.

With this latest announcement that you endorsed the AGM resolution from a number of your large shareholders, does that mean you are going to add to the disclosure that you've given today and existing targets, for example, including Scope 3 in that debate?

And the second question is more of a financial one and Brian probably knows it well.

Whether there is or ever will be a guidance for inorganic CapEx?

And I'm not talking about BHP.

You're not going to tell us about these acquisitions in advance, but you could say external resource additions that over the years have always been around $1 billion, $2 billion, $3 billion a year.

Is that a reasonable expectation to continue to have through 2019 and beyond?

Right.

Thank you for the question.

So on this shareholder resolution, we're just going to continue and transparency is always a basis of what we do.

If you've seen what we've written in our reports, we've always had the view about being transparent.

We're going to go further and be transparent about some of our decisions, how we make them on major capital investments.

It will be work for us.

It will be talking further about this reduce, improve and create models and -- as part of our thinking.

It does not -- it's not a resolution requiring us to spend capital in predetermined boxes or businesses because no one knows where the transition is fully going.

We support the work and are consistent with the goals of Paris.

And of course, there's many, many ways to get to the goals of Paris.

On Scope 3, and I know I have a different opinion than some on this, and by the way, it seems to be there's several definitions out there of Scope 3, but for those of you who are not sort of up on these language, think about in a simple way Scope 3 seems to be that we take responsibility for the emissions of all our products.

And I'm going to take this personally and the company believes this and, of course, we always have the debate inside.

But we cannot be accountable for how everyone uses our products.

And a real simple example of that is if you're driving from London to Edinburgh, you're driving from New York to Chicago, you can have a small economy car with 4 people in it and you have a certain carbon footprint with that.

Or you can be 1 person in a big SUV driving that and you get a totally different carbon footprint.

So there's a lot of responsibility for the use of energy that has to do with the consumers.

And so we're very clear in what our products are and their footprints.

But this Scope 3 thing, which is fine, people want to do that and take responsibility for it, but I think that's why we have a different view about Scope 3 and many of you probably won't even know what I'm talking about Scope 3, but, Chris, you obviously are up on that.

Chris, then in terms of inorganic capital, I don't think anybody gives guidance on inorganic capital, but you're right.

I mean, I think, it's opportunity led.

The ones that you would have seen outside of the big major transaction like a BHP, I think you're more talking about sort of portfolio churn.

It would be opportunity driven.

Our basis internally around inorganics is that they have to be accretive generally.

They come back to value over volume, which Bob has talked about many times before.

And they have to be able to be accommodated within the financial frame.

So -- but beyond that, I wouldn't give any specific guidance around what that might look like.

What I would say, though, and what we laid out a couple of years ago, if you recall that there was a series of transactions we did about 2 to 3 years ago around Abu Dhabi, Mauritania, Senegal and so on.

With it ultimately, we would have to be able to afford those in the financial frame and in terms of the inorganic side of that frame is really around disposals covering both Macondo payments and any acquisitions.

Now of course, Macondo payments, $16 billion over the last 3 years, they start to run down now to $2 billion -- just over $2 billion this year and $1 billion a year beyond that.

The $2 billion to $3 billion capital churn that we have in terms of disposals would more than compensate for any other opportunistic inorganics that come along, but we wouldn't normally give guidance other than they need to be accretive and they need to be manageable within the financial frame.

Thanks, Chris.

We'll take the next question from James Evans at Exane.

Really one thing to Bernard.

A couple on the short term, just wondered if you could talk about whether you expect to see further momentum in OpEx reductions in 2019?

And if you could clarify what the current run rate of the impact of OPEC+ quotas on your business currently?

I know you can't talk about it for the full year already.

And then maybe a bit more medium term, around the LNG portfolio.

It's obviously an area of excitement.

There is an ever-growing queue of projects, there is a willingness of your peers to push through these projects without offtake from long-term customers as well.

So I just wondered in that context where you do see future phases of Tortue within your portfolio, within this global context?

And just share with me your appetite and exposure to taking equity volume risk either from this project or from elsewhere.

Very good, James.

Thank you.

First of all, on operating cost, we saw our costs on a production cost per barrel basis.

Last year, we saw them increase by about, I think, less than 0.5%.

So our costs have flattened out last year.

That slight increase was actually driven primarily by well work at the beginning of the year and increased well work, which you would argue, is a good thing.

But overall, our production costs are down 45% since 2013 when we were at about $13.10.

And we were at $7.24 last year.

The guidance that we gave in Oman is that we will continue to aim to drive our unit costs down.

We're guiding externally for them to being flattish, I think, in 2019.

And we do, of course, have to adjust for the BHP portfolio that we will have a full year of in 2019.

And their production costs per barrel are higher by probably 40% to 50% than our existing Lower 48 business.

And that's purely because it's a more liquids-based portfolio, which is why we wanted it.

Now we'll clearly be applying the same intelligent operations type of activities to that as we have done our existing base.

So I think guidance for production cost for the year is flattish.

We might see a little bit of an increase due to BHP portfolio.

We're not seeing inflation around the world and, in fact, even in the Lower 48, we're now beginning to see deflation again as prices have come back down off their peaks.

On OPEC quotas, I won't get into any specifics, James.

I'm sure you'll understand that.

We will obviously be guided by what we need to do in our host countries.

But so far, no material impact on our business there.

And in terms of the LNG portfolio, absolutely delighted on the 21st of December to get the first phase of Tortue across the line.

The team has done an extraordinary job working across 2 countries to get that project from discovery to sanction in 3.5 years and possibly discovery to production in 7 years, which is about half the industry average.

The real excitement, I think as you said, comes in the next phases of Tortue as we build the system out.

We will have preinvested in the original infrastructure, so to speak, and the subsequent phases will be extremely economic.

So 2 additional phases, building up to about 10 mtpa and something that we're all very excited about.

And of course, X potential beyond we said in Oman that we see the potential for 50 to 100 tcf of gas in place across the entire region in Mauritania and Senegal.

And as you know, we have a pretty significant footprint there.

So hopefully, that helps, James, with your questions.

Thanks, James.

We'll take the next question from Lucas Herrmann at Deutsche Bank.

Two, if I might.

The first to Bernard or to the team in general and maybe this is too simplistic a way of thinking about things, but I'm looking at your high quality growth capacity slide.

Obviously, conscious of fact you're focused on advantaged oil and gas.

And as you move from 12 billion to the potential 25 billion barrels whatever of resources there to be monetized.

What rate of return do you think you're going to be recycling at?

And I ask in part because $4 billion of resources new wells where I'd expect the returns to be extremely high, BPX Energy similarly I'd expect comfortably into double digits probably north of 20, excluding the acquisition cost.

Post-FID major projects, same observation.

Pre-FID, I think, you've always very clear that 15 or so is the hurdle.

So kind of the first question is just what rate do you think you're recycling capital at in the Upstream now?

And the second, if I might, to Tufan.

I guess, 2 things.

A, if Tufan could just mention where he thinks the PTA cycle is at the present time and consequently the outlook for your chemicals business?

And secondly, the target for fuels marketing from memory was around $3.7 billion or so of EBIT or cash flow by 2021.

Australia was in that.

It's obviously not any longer.

The extent to which, Tufan, you're just still confident in delivery and clearly the progress to date has been very, very good.

Lucas...

Sorry, long questions.

No.

Thank you, Lucas.

Maybe I can give a relatively short answer.

But I think you've asked the question clearly, and I think my response would be the new wells, the BPX Energy, Lower 48 absolutely 20% plus IRR hurdle rate, $60 set.

And I think I would say that we exceed those quite well.

So even in BPX Energy, with the gas in the Haynesville, we're getting 35% to 40% rate of return on those wells at $2.75 Henry Hub.

So the infill drilling and the Lower 48, the hurdle rate is 20% plus at $60.

And then the post-FID and pre-FID are absolutely 15% for greenfield, 20% for any brownfield in there.

Again, we're comfortably meeting those hurdle rates across the board.

We have seen the return on investment improve between the time we did the presentation in Baku in 2016 and Oman by 5 percentage points.

So we've gone from the high teens overall average to the low 20s as an overall average of the investment portfolio that we see ahead of us.

So a real improvement in the returns average that we see in what is ahead of us in the plan.

And I think, the post-acquisition returns on the BHP transaction are going to be above 25% again at $55.

So I think that's how I would answer it.

Tufan?

Thanks, Lucas.

Two questions, I guess, petrochemicals and fuels marketing.

Let me start with petrochemicals.

I think, our petrochemicals business and the environment, if you think about 2014, we actually lost money.

And since then, underlying performance improvement in this business was actually more than $500 million.

And the way -- and the environment improved at the same time definitely versus 2016.

What happened effectively, we made $600 million this year in 2018.

Effectively, environment improvement offsets cycle divestment.

That's what how you should think about it.

And underlying earnings effectively improved our number to $600 million.

Going forward, we expect looking at the refining sort of petrochemicals capacity coming in and demand growth, demand growth continues to be good actually in China.

Both of our businesses PTA/Aromatics and acetyls.

So we expect 2019 environment to be similar to 2018.

And 2020 utilizations may even go up because demand will continue to grow and there is not much capacity coming in.

After 2020, there is capacity coming in, which may affect the utilization.

That's how you may want to think about petrochemicals.

Fuels marketing, I think as you said, actually we are making great progress.

I think in IR Day, we said more than $3.5 billion in 2021.

And frankly, since we set the strategy in 2014, we increased the earnings in this business by 70%.

It is $1.7 billion frankly since then.

And since 2016, it is $700 million improvement.

So it is -- it's actually driven by our underlying programs.

What is happening in this business is when our underlying programs, like convenience partnerships, they are doing 2 things: they are actually improving their earnings, but at the same time they are actually changing the shape of the business model and making it more robust with more non-fuel income.

Going forward, you are right.

Woolworth was in our numbers.

But actually, our progress in spite of Woolworth not being there, we were able to offset effectively that.

And going forward, I think the growth will continue to come from convenience partnerships, growth markets, but also new markets will start to scale up in terms of earnings.

We have been scaling up volumes, but actually there wasn't much earnings so far.

So I would say, we are on track in fuels marketing to deliver those targets.

Okay.

Thanks, Lucas.

We'll take the next question from Michele Della Vigna at Goldman Sachs.

Michele?

Two questions, if I may.

The first one relates to the dividend policy.

Clearly, you are indicating a progressive dividend increase.

In 2018, you increased it by 2.5%.

The underlying business is growing faster in terms of production, in terms of cash flow and earnings, but at the same time, you probably feel a need to reduce what is quite a high payout ratio.

How should we think about the dividend increase for 2019 and beyond that as your business continues to progress and grow strongly?

And then secondly, a more technical question on the quarter.

We've seen a counter seasonal buildup in operating working capital in the quarter by $1.5 billion.

I was wondering if you could walk us through the key dynamics there and whether you expect that to partially reverse in the first quarter.

Thanks, Michele.

Actually, I'll take the second question first and then I'll come back to dividend policy.

Working capital, you'll see actually one is a single quarter is not a great indication in terms of what was happening.

This quarter, we had the mineral oil tax outflow of around $1.3 billion and then we had another series of different timing effects that came through in terms of the overall impact on the quarter to the tune of about $200 million.

So we've sort of working capital build of about $1.5 billion in the quarter and it's about $2.6 billion, I think, for the year.

If you actually look at it over the last 8 quarters, it's dead flat.

And what we do inside the company and actually something we initiated way back when the oil price was down at $28 a barrel was we managed that working capital really tightly quarter-on-quarter.

So you won't see huge fluctuations beyond the $1.5 billion intra-quarter as we manage that working capital particularly around our trading activities.

So it's actually a relatively modest change given what happened with the price, but it is basically a function of what was going on this quarter around certain timing effects.

And the German mineral oil tax, which flows out of the end of every year, which is advanced payments of tax into Germany that then get returned in the first quarter, which we talked about historically.

In terms of dividend policy, you're right.

We did increase 2.5% last year.

It was a progressive step-up.

It was a number of years.

It was actually back in 2014, I think, was the previous, the move up.

In terms of what we've laid out for shareholders, in terms of free cash flow surplus in the 5-year strategy, there is significant free cash flow out to 2021.

And I think, it was important the board signaled last year that they were ready to move the dividend up on a progressive basis.

Ultimately, it's a function of how sustainable we think the free cash flow surplus looks on a go-forward basis.

Clearly now, we've had 8 quarters of what was a 20-quarter strategy.

And we're pretty much on track with what we laid out to 2021.

So notwithstanding absorbing the BHP acquisition, getting this $10 billion of disposals away to get the balance sheet back in line in terms of the previous questions we've had on the call today.

The board will have an opportunity again to look at the balance of progressive dividend increases over and above other uses for that surplus free cash, including the scrip purchase repurchase that we've already signaled for the end of this year.

Okay, Michele.

Thanks.

We'll take the next question from Os Clint at Bernstein.

Perhaps a question for Bernard, firstly.

Just on the Gulf of Mexico, it obviously didn't take long to use your seismic imaging to find some more oil around Atlantis and turn into a sanctioned project last month.

But in terms of Thunder Horse and the 1 billion barrels of oil in place, could you talk around next steps from here in terms of kind of proving that up, appraising it and perhaps converting it into some future projects?

And perhaps just an indication of some of the development costs per barrel you're actually getting these projects away at in terms of the Gulf of Mexico, please?

And then secondly, Tufan, just I think you answered it back with Lucas' question, but in terms of Mexico, I think you had a target of 500 retail stations for last year and I think you said today 440, so a little bit behind.

But again, you talked about scaling up in earnings from this year onwards.

Is that the case with Mexico?

Is it moving as fast as you expected?

Should we see some earnings contribution from Mexico retail in 2019?

Oswald, thanks very much for your question.

I think on the Gulf of Mexico, on Thunder Horse specifically, we can see the potential for another expansion project to be sanctioned this year.

That's well within our sights.

I think overall across the Gulf, we see 6 to 7 projects that, quite frankly, we didn't see just 18 months ago.

And that is Thunder Horse is definitely a predominance of that, but also as you point out at Mad Dog, at Na Kika and at Atlantis as well.

So I would expect 2 to 3 expansion projects to come at Thunder Horse.

I'd expect to see the first one being sanctioned this year and I think, I would say, from a development cost per barrel perspective, we're continuing to drive it down.

In our overall portfolio, our [D costs] per barrel are down by 20% over the last couple of years.

As I think, we said in Oman, we've actually delivered the -- or we will deliver the 900,000 barrels a day of new production for about 25% less capital than we originally anticipated.

And we're seeing those improvements in the Gulf.

We have developed these superfast tiebacks that we've really got in a groove on now delivering some of these tiebacks in months -- a matter of months.

So quite excited about what's possible.

Expect to see the first expansion project at Thunder Horse later this year.

And since, Oswald, you brought up Thunder Horse, I think it's probably something in your planning here.

As we look at the first quarter, there is a long scheduled turnaround of Thunder Horse that's 35, 40 days.

Yes, it's a great point, Bob.

And just as people do look out to the first quarter, I think -- well I think, we've said that production will be relatively flat in the first quarter as we take on BHP and so on, we will lose probably close to 100,000 barrels a day of high-margin production compared to the fourth quarter.

And about half of that is because of M&A.

And that's things like Bruce, Keith and Rhum disposal in the North Sea, the Magnus disposal in the North Sea, swapping out at Kuparuk in Alaska.

And about the other half comes from, as Bob says, a turnaround -- a long-planned turnaround not unexpected at Thunder Horse, which will take Thunder Horse down for between 30 and 40 days.

So we'll see.

We will lose about 100,000 barrels a day of high-margin barrels in the first quarter, and thanks for reminding me of that, Bob.

On Mexico, you are right.

I think we are right now around 450 and a little bit lower than we expected, which was 500.

The reason is frankly, we are very selective on the site quality and because we are now effectively market leader in terms of brand and offer in Mexico.

And that needs to continue and, therefore, we are highly selective on which sites actually we bring forward.

We still keep the target called 1,500 sites by 2021.

And in terms of earnings growth, yes, you should actually expect that earnings will grow from 2019 onwards, including 2019 as well.

So far actually, it has been more -- we have been building the scale in terms of volume.

And Mexico became our fifth largest country in our portfolio in terms of volumes, but not earnings.

But earnings will start to scale up from 2019 onwards.

Thanks, Os.

We'll take the next question from Colin Smith at Panmure Gordon.

Colin?

Another one for Tufan, really just around the guidance.

Given that Alberta is now following apportionment, the WTI-WCS differential has narrowed quite a bit and looks like it may be trading sort of $5 a barrel below the guidance number.

I'm just wondering 2 things: one, what do you think the longer-term outlook for that is?

And secondly, whether or not that sort of maybe marks the high point for earnings and cash generation for Whiting if we are going to be looking at lower margins going forward perhaps to the tune of $400 million a year?

That's the question.

Okay.

Great question.

Let me actually sort of start with the long term, then we can come back to why we are seeing WCS-WTI at the current levels.

But as you know, WTI-WCS effect is 2 components of it.

One is refining value -- a relative refining value, I should say.

The other one is the transportation cost.

And given pipeline restrictions, frankly, Canadian heavy will continue to be in rail economics going forward.

But let me answer sort of future question first.

I think if you look at our guidance, we actually said refining RMM will be 14 and the WCS-WTI 15 in our sort of target numbers 2021.

And that is still good, I would say, both of those numbers.

Because if you look at going forward, IMO coming in.

Effectively, that will increase the refining demand, distillate demand significantly.

And even with the new refining capacity coming in, I think refining margins will actually this year -- probably they will be lower than last year.

I'm talking about RMM as well as WCS-WTI.

But if you go to 2020 and 2021, actually IMO will support because of the additional demand coming in will support definitely RMM 14.

And actually WCS-WTI this year, because of Alberta reduction, all the inventories went down.

Probably this year, range will be more like 12 to 17.

But if you go to 2020, 2021, I think range of 20, 25 WCS-WTI are still supported because of IMO additional demand on distillate and also you should expect light and heavy differentials to open up.

Okay, great.

Just a couple more questions to go.

We'll take the next one from Pavel Molchanov of Raymond James.

First one on Venezuela, I believe that last November, you made an effort to reenter Venezuela after 8 years.

And any thoughts you have on the current political landscape and your plans for potentially reentering the country would be useful.

And secondly, on kind of back to the renewables investments, you made the point that it's still a bit of a rounding error in your total CapEx.

When realistically do you think renewables or low carbon investments can get to even, let's say, 10% of your total capital allocation?

Any timing on that would be helpful.

Pavel, hi, this is Bob.

So on Venezuela, I think the -- I'm not exactly sure when you were saying we were trying to reenter.

We have always thought that there is an industrial logic with gas in Venezuela coming into Trinidad with the LNG fields -- LNG plant.

So it's kind of a natural fillage of oilage, I think, in Trinidad.

And we made some exploration discussions really only around that.

I think everyone who looks at that resource base down in Venezuela and Trinidad would see that.

But it was not -- I wouldn't say it was a serious effort.

It was exploratory.

Regarding the pace of what is happening in Venezuela, we don't have any real insight.

I think whatever is going to happen is going to be complicated and probably take longer than probably if you listen to the news that there's going to be rapid change and things are going to turn around.

I think it's going to be very complicated, so we're just going to sit back, I would say, and watch.

And then on the pace of renewables, I mean, it's sort of we're going to remain a world-class investment company.

And what we want to do is make sure we have the flexibility because nobody knows the pace of the energy transitions.

We're doing a lot.

But I would -- I wouldn't say that we would be able to say how long this is going to take before it's 10% of our capital.

Right now, it's spending -- some of its capital, some of its other spending that we put in, some of its maintenance capital today and some of our existing operations.

So I don't know what the pace is.

And there are just so many different possibilities that this low-carbon energy transition will happen and we just want to be part of it, but not formulaic.

And maybe, Pavel, just to add to that.

You've asked a specific question about low-carbon businesses, but, of course, we are also spending significant amounts of money in reducing emissions in our existing portfolio.

So it may well be that we're at 10% already, not that we've looked at the specific capital in those areas, but we are investing in reducing emissions, which is really what the Paris climate change is all about.

So you may not see -- you'd take alternative energy business as a proxy for low carbon, but it's actually about reducing emissions and we're doing that across our whole system.

Good point, Brian.

Thanks, Pavel.

Okay.

We'll take the next question from Martijn Rats at Morgan Stanley.

I wanted to ask, Tufan, some more about refining margins.

Of course, we're seeing relatively healthy middle distillate market, but the gasoline market is in quite considerable oversupply.

And one of the things that I find a big conundrum, particularly, when it comes to also your comments around IMO.

Of course, as a result of IMO, we're going to get more middle distillate demand, we're going to have higher crude demands globally and all of that makes a lot of sense.

But in the process, we might be overproducing gasoline and gasoline already looks very, very weak and I was wondering what your thoughts were particularly about the gasoline market and how that impacts the rest of how you run the refining system.

What are you seeing in gasoline demand?

And also we're hearing stories about economic run cuts simply because of gasoline overproduction.

Is that something that BP is doing?

Are you looking at lower FCC run rates?

I mean, FCC margins are very, very low at the moment.

How do you think the balance between a strong middle distillate market driven by IMO with this particularly weak gasoline market?

At the same time, how do you think that is going to play out over the next year or 2?

That's a great point.

I think current refining margins, Martijn, as you know, they're driven.

I mean, they are low because of the gasoline cracks being very, very weak.

In fact, the weakest in the last 10 years actually are gasoline cracks.

So because of the high gasoline inventories, so going forward, I think that will continue to be issue.

But with IMO, I think, there is -- gasoline demand is actually growing.

So it is not a demand growth issue and we actually expect that to grow -- continue to grow this year as well as next year and next couple of years.

So there is no issue on the demand side.

But refining utilization is historically high right now.

So normally, we are in a strange situation because high utilizations -- historically high refining utilization normally should drive margins to a better place.

But because of gasoline inventories, it is actually depressed.

What happened in my view, frankly, after the crude prices went down late 2014, we had a behavioral change on the drivers; '15, '16, '17 gasoline demand growth was significant.

But if you go before that, actually refining margins have been driven by distillate cracks more than gasoline cracks.

We came back to that situation in a more polarized way, I should say, and going forward, I think this trend will continue.

And -- but as a result, most of the refineries in the world already that's happening, they will run at distillate mode.

And that should actually, obviously, reduce the gasoline production in relative terms.

I still believe this year, I think, we expect refining margins to be lower than last year because of gasoline mainly.

But 2020 and '21, we are still comfortable with our target numbers, as I mentioned before.

Second part of your question, sort of do we cut the runs?

I always talk about competitively advantaged portfolio and that's what we have been actually driving last couple of years.

And therefore -- and what competitively advantaged portfolio does for you, it's actually while others are cutting their runs, we don't need to.

And that's the situation we are in at this point.

Frankly, in 1Q, as you know, refining margins are low for -- we didn't have to have any economic sort of related cuts in our system.

Another point about our system, it is more distillate-oriented system.

Half of our yield is actually distillates and in the current environment, that is obviously an advantage.

Okay, Thanks, Martijn.

Thank you for the question.

We'll take the penultimate question from Thomas Adolff at Crédit Suisse.

Two short questions for me, please.

Firstly on the disposal plant, Brian, can you please talk about the contingency buffer you have on the $10 billion?

For example, have you identified, say, $15 billion or $20 billion to deliver on the $10 billion, so we can kind of consider this a fairly low risk target?

Secondly, for Bernard, perhaps you can give us an update on exploration, perhaps comment on the performance in 2018 and what the key wells are for 2019?

I'm particularly interested in the pre-salt Brazil where you've got a few licenses.

So Thomas, thanks for that question and, of course, the $10 billion number is clearly a risked number.

So we have a much bigger suite of options than the $10 billion to make sure that we deliver the $10 billion.

The only thing I can point you to is track record.

I think we've done about $80 billion now of transactions over the last 8 years since 2010.

And pretty much hit the guidance on those, I think maybe the end of last 2017, we may be at $400 million short on the final figure, but actually it was more to the one particular project rolling over.

So we're pretty confident.

We wouldn't have put the figure out there -- certainly the board -- we discussed this at the board at length, and we're pretty confident in that figure.

And it's a risked figure and clearly has a portfolio suite larger than the $10 billion.

And Thomas, on exploration, I think, with a relatively modest program in 2018, 2 discoveries that we've announced both in the Gulf of Mexico, both extremely valuable tiebacks.

So that was good.

2019, we'll probably see a program about double the size of what we did in 2018.

Key wells across the world in places, as you say, like the pre-salt in Brazil and the Gulf of Mexico in the North Sea, in Azerbaijan, in Trinidad, so -- and also in Mauritania and Senegal, so a big year for us out ahead, and I think we'll take the results as they come and wish us luck.

Okay.

Thanks very much.

We're going to take the last question from Peter Low at Redburn.

Peter?

Just one quickly.

You said you weren't seeing any OpEx cost inflation Upstream.

But you have 7 potential FIDs in 2019.

Are you seeing any signs of cost inflation emerging when you go to contact new projects?

I guess, I'm particularly interested in LNG, where there seems to be a lot set to move forward this year.

Peter, thanks for your question.

7 potential FIDs, this year, one's already done, which is good, Atlantis Phase 3 sanctioned right at the beginning of the year.

And no is the answer to your question.

We are not seeing inflation in either the CapEx or the OpEx end of things.

We continue to push for better solutions, industry standard solutions.

We continue to push for standardization within our own company and across the industry.

We continue to push for cost to come down and even in LNG, as you point out, we are seeing that.

We've had some very competitive response to tenders on Phase 1 at Tortue, for example.

And we continue to drive more collaboration with our suppliers to figure out ways where we can collectively lower the cost base at the industry and hopefully share some of that rent so that we both maintain a competitive environment.

So I think, the answer is no and we are a firm believer through our transformation agenda that we will continue to drive further and further capital productivity into the business and we for one continue to believe that there is enormous waste still within the sector and we see that as a great opportunity.

And that's what our transformation agenda is 100% focused on.

Thanks, Bernard.

And thank you, Peter.

Okay, that's the end of the questions.

IR is, of course, available to follow-up on any other questions you have over the coming days and weeks.

And we'll, of course, also be visiting many of our investors over the coming days.

We also look forward to welcoming, I think, a number of you at the sell-side lunch today, which is in about 57 minutes.

So good luck with the travel.

On that note, let me handover to Bob for a few closing comments.

Thank you.

Thank you, Craig.

I hope you're not coming from the city.

That will be a stretch, but thank you.

And thank you, everyone, for your questions today.

As usual, they're very good and they're very thoughtful.

And we really appreciate that.

I think just a few comments.

I think you're hearing from us the confidence about the momentum we've got across the company, a strategy that we believe is serving our shareholders very well.

You'll have seen the company change over the past several years.

The strategy is allowing us to flex and adapt both not only the portfolio within a capital framework, it's quite disciplined.

And I think also, not just responding to the energy transition, but helping to advance it along with others.

Clearly, as demand in the world grows for energy, so does the need to reduce the emissions.

And we see ourselves again with others as part of the solution to that great dual challenge.

We're going to take a practical and pragmatic approach to both sides of this challenge, the demand side as well as emission reductions.

And to do that, we know we must remain highly attractive investment for you all.

We're going to continue to reach out and talk to you this year.

We've got a lot of news to share with you as we go through the year.

Right after this call, we've got 5 teams heading out around the world, and we're going to talk to as many as 40% of our shareholders, I hope.

But your time is very valuable, and I think I'll end it there and just say, a very big thank you from all of us.