英國石油 (BP) 2017 Q4 法說會逐字稿

Great.

Okay.

All right.

Well, a very big hello and welcome to BP's Fourth Quarter and Full Year 2017 Results and an update on BP's strategy.

I'd like to thank everyone for joining us here in person in London, here in the room, as well as all of you out there online around the globe.

And we have quite a few people signed up, so a big welcome.

I know it's very early in the morning or late in the evening for some of you, so a particular thank you to you.

I know the markets, in general, are a little bit turbulent, so I hope we can give you some good news today.

Just to remind you, we are a very long-term industry, and we will keep advancing through the -- any rough waters that the markets send us.

And I just would reflect on -- I think the markets are about the same level as they were in the 1st of January, just overall.

So before I begin, I need to draw your attention to the cautionary statement.

It is long and detailed but necessary, so please have a read of it when you have a moment.

I'm not going to.

So here's the agenda for today.

And you'll hear from me first with an overview of our progress against the strategy we laid out a year ago.

Brian will then take you through the financial results for the fourth quarter and also update you on the strategy looking out to 2021 and beyond.

Lamar will focus specifically on our approach to the energy transition and what BP is doing across our businesses to adapt and position ourself for a lower-carbon future.

That will provide you with some wider context for the updates from Bernard and Tufan on how the Upstream and the Downstream plans and the portfolios are evolving over the medium term as well as what we're doing to create and deliver long-term growth prospects.

We'll then take a short break, and we'll return, and I'll provide a summary before moving to Qs and As.

So let's start with an overview of our strategic progress in 2017.

At the start of the year, we told you 2017 would be very important for the company, a significant year of disciplined execution and growth across the businesses.

I'm very pleased on how we've delivered on the commitments, which you will see in some of the highlights on this slide.

You might recall, we said we would start up 7 major projects in the Upstream this year.

To be honest, some people weren't sure we could do that, but we've brought each project online, on average, on schedule and under budget.

These projects, along with the ramp-up of 6 start-ups in 2016, have contributed to a 10% year-on-year increase in BP's reported production.

It's been many years since we've done that.

We're on track with our plans for 800,000 barrels of new major project production by 2020, and we've also strengthened our portfolio, creating growth for the future.

We had our most successful year in exploration since 2004, with around 1 billion barrels of oil equivalent discovered this past year.

We had our best reserve replacement ratio in over a decade, estimated at 143%.

And we sanctioned 3 new projects in Trinidad, India and the Gulf of Mexico.

We've also seen strong growth in the Downstream.

In fact, one of our best years in history in terms of earnings, with our marketing and manufacturing businesses together delivering around $1 billion of underlying earnings improvement in the year.

They've done that through continued volume growth in premium fuels and lubricants; the strong performance of our refining operations, averaging more than 95% availability across the year; and earnings growth of over 10% in fuels marketing.

We now have around 1,100 retail convenience partnership sites around the world, and we have plans to continue to grow our retail network across existing markets as well as new markets, such as India, Indonesia, Mexico and China.

We also grew our alternative energy business, with availability around 95% resulting in strong operating cash flows in 2017.

We went back into solar but in a new way, in a partnership with Lightsource.

This is a very exciting development for us.

We're combining our scale, our relationships around the world and expertise in major projects with Lightsource's expertise in developing solar projects.

Overall, 2017 has proved to be one of the strongest years of operational delivery in recent history, and this is also reflected in our full year financial results.

Our underlying replacement cost profit of 16 -- $6.2 billion, more than double that of 2016; an underlying operating cash flow of $24.3 billion, excluding pretax oil spill-related payments; and a gearing of 27.4%, comfortably within our 20-year and 20% to 30% target band.

In addition, our organic capital expenditure was $16.5 billion.

Total divestments and other proceeds were $4.3 billion.

And we made pretax Gulf of Mexico oil-spill payments of $5.3 billion.

And we distributed $7.9 billion of dividends to shareholders, of which $6.2 billion was in cash.

As you saw in our announcement in October with the strong underlying performance and our confidence in growing organic free cash flow, we recommended a share buyback program in the fourth quarter 2017.

Buying back shares through the fourth quarter offset the scrip dividend issued in September, or the DRIP in the U.S., and that commitment remains.

Our 2017 performance was achieved in an environment that improved throughout the year but which still remains challenging.

So far this year, Brent's oil prices averaged almost $70 per barrel, up from an average of $54 in 2017, a year which was hard to believe the first average annual increase since 2012.

The gradual decline in inventories over the past 6 months or so, together with heightened geopolitical uncertainty, has driven prices up.

But our expectation is that some of this recent strength could be short lived, and then prices will moderate over the medium term.

In terms of outlook, the base case of our 2017 energy outlook expects that global energy demand will grow.

It will grow by up around 1/3 over the next 2 decades.

Virtually all of that demand is to come from emerging economies, notably China and India, driven by rising prosperity.

And the rate of growth will then slow down compared to past decades as the energy transition evolves, and there's increasing attention on energy sustainability and efficiency.

On the supply side, there is a shift to an abundance of resources, with natural grass -- gas growing faster than both coal and oil; oil demand continuing to grow over the next 20 years or so, with the prospect of a plateau further out; and renewables growing faster than any other fuel but from a low base.

Spencer Dale, our economist -- Chief Economist, will have more to say on the macroeconomic environment later this month when we launch our updated energy outlook.

But for now, it's clear to say this is a time of transformational change.

There's a challenge to produce more and more of the affordable energy that society needs.

That involves modernizing and embracing new advanced technologies while being disciplined on capital investment, lowering production costs and continuing to unlock new resources.

And then there is also the challenge to produce energy that's less carbon intensive to help meet the world's climate goals.

The key to this dual challenge is to recognize it's not a race to renewables; it's a race to lower greenhouse gas emissions.

And as fast as renewables and clean energy can grow, faster than any fuel in history, the world is going to require gas and oil for some decades to come to fill much of its energy demand.

In BP, we have been committed to the low-carbon transition for a long time, and we've gained a lot of experience along the way that we're putting to good use.

We're reducing our own emissions through operational emission-reduction activities.

We're improving our products to enable our customers to lower their emissions.

And we're creating low-carbon businesses to complement our existing portfolio.

There's a lot of uncertainty around the pace and the direction of change, probably more than at any time I can recall, but we have a strong and a flexible platform to build on, giving us the ability to adapt quickly in any environment.

With the experience we have, the portfolio we have created and the flexibility of our strategy, we can embrace low-carbon future in a way that enhances our investor proposition.

You'll hear more detail from Lamar later on what we've been doing around advancing the energy transition.

Now turning to our investor proposition, which you can see on the slide.

It's the proposition we set out last year at our strategy update, and I'd like to take a few moments to remind everyone of the key elements of that: safe, reliable and efficient execution is essential; a distinctive portfolio fit for a changing world; and growing returns through value-based disciplined investment and cost focus.

These all underpin our aim of growing sustainable free cash flow and distributions to our shareholders over the long term, and I'll take each of these in turn in a bit more detail.

So first and foremost is safe, reliable and efficient operations.

It's a core value and our #1 priority.

Our focus, as we have said before, is on being systematic, disciplined and process driven, and that has seen a continued downward trend in process safety events.

We are also focused on learning, investigating safety incidents and using leading indicators to monitor and strengthen the controls we have in place to prevent future incidents.

We're looking increasingly at how human behavior influences safety and also, how we can take people out of harm's way by using new technologies such as drones and crawlers and autonomous vehicles.

We have plenty of evidence that if done right, these approaches not only improve safety, but they also lower operating costs and improve business performance.

We see this coming through in our strong operating reliability numbers, which was 95% in both the Upstream and the Downstream in 2017.

Overall, we work hard at focusing and simplifying how we work, embedding a culture of accountability and improving our execution, creating an environment where our people feel empowered to adapt and drive delivery, both in terms of safety performance and also business outcomes.

It is this focus that underpinned our confidence last year that we would deliver all 7 major projects by the end of the year and why we're confident we'll do the same with 6 major projects scheduled for 2018.

This includes Shah Deniz Phase 2, part of the Southern Corridor; a big megaproject, one of the most complex projects we have ever undertaken.

It spans 6 countries, involves 11 shareholder companies, with 176 million man hours worked since the FID was taken 4 years ago.

Shah Deniz Stage 2 is on track for start-up in 2018.

It's on time and under budget, with 0 days away from work due to injury last year.

Now a second element of the proposition is what we believe is a distinctive portfolio.

Over the past several years, we have continued to actively high-grade the portfolio through focusing on quality, optionality, creating innovative commercial opportunities and acquiring assets and positions that are accretive to our underlying business.

What you see today is a portfolio that's global, its integrated business with a strong and distinctive set of assets, brands and relationships.

It's a business portfolio that drives value creation today and has deep and flexible options to support future growth.

In other words, I think we are resilient to a changing environment, and we're moving in a direction that plays to our strengths.

In the Upstream, that means growing our gas and advantaged oil portfolio, with assets that are low cost or high margin and building on an already-deep resource base.

Including our equity production in Russia, we are a 3.6 million barrel per day company with an estimated 18.4 billion barrels of proved oil equivalent reserves, providing us with 13.7 years of reserve life.

Across our total Upstream resource base of 48 billion barrels, we have sufficient opportunities to deliver quality growth through the next decade and beyond without the need for acquisitions or further exploration.

Of course, we will do some of those.

Around 2/3 of our portfolio is leveraged to price, either through direct or indirect oil and gas indexation.

But importantly, this is balanced with production from fixed price or similar contracts, which provide a base of steady, resilient, long-term cash flow.

We also have a strong and differentiated Downstream business, which some of you may be familiar with, if you joined Tufan and his team at his Investor Day at our Downstream technology center in Pangbourne last June.

The portfolio today is a high-quality group of competitively advantaged businesses, and it covers marketing, manufacturing and our integrated supply and trading function, creating an integrated and value-optimized business.

A differentiated and high-returning marketing business is underpinned by strong brands and a distinctive premium offer and has an increasing exposure to growth markets.

And in manufacturing, the refining portfolio is geographically balanced, good access to advantaged feedstock, such as heavy Canadian crudes in North America; while in petrochemicals, our latest technology allows us to deliver industry-leading cost and environmental performance.

I've already mentioned our move back into solar.

It's a significant addition to the wind and biofuels businesses in our alternative energy portfolio.

We have one of the largest operated renewables portfolios among our peers, and we are selectively investing in emerging new businesses and technologies to ensure we stay at the forefront of changing global needs and the energy transition.

A lot of people working on this at BP.

Another highly distinctive aspect of our portfolio is our strategic partnership with Russia's largest oil company.

Rosneft has a strong portfolio of current and future opportunities onshore and offshore with assets in all of Russia's key hydrocarbon basins.

We've developed a relationship with Rosneft in recent years to create what is a unique and advantageous position for BP in one of the largest and lowest-cost hydrocarbon resource basins in the world, with access to huge markets, both East and West.

Our 19.75% shareholding in Rosneft, together with 2 board seats, does allow us to influence the strategic direction of the company as well as benefit from a diversified set of existing and potential projects in the Russian oil sector.

In 2017, BP's share of production from Rosneft was around 1.1 million barrels per day.

We also received $314 million of dividends, supported by the recent changes in the dividend policy there to pay out at least 50% of IFRS net profit.

In addition to that equity position, we are building some material businesses that is generating incremental value through stand-alone joint ventures in Russia also and internationally.

We currently have interests -- some of you have asked this question.

We currently have interests in 3 joint ventures in Russia.

The Taas JV, in which we have a 20% interest, is developing oil and gas condensate fields in East Siberia.

Field's currently producing about 25,000 barrels a day, and expansion is expected to start up this year in '18 and raise production to over 100,000 barrels a day by 2021.

We have a 49% interest in the Yermak JV, which is conducting an onshore exploration in West Siberia, holds about 7 exploration licenses.

And we've reached agreement to form a new joint venture for the Kharampur field, in which we will have a 49% interest.

Most of the regulatory approvals are in place, and we don't see any barriers for the deal closing later this year.

Outside of Russia, we have a 10% interest in the Zohr gas field in Egypt with ENI, in which also Rosneft holds a 30% interest.

And a third aspect, and an important one to the relationship, is technical cooperation to benefit Rosneft's performance and the performance of our JVs, particularly in environmental technology.

We're cooperating on health, safety and environmental issues, including providing these services on a contractual basis to Rosneft.

We share a lot in the areas of health, safety and the environment.

In addition, we're developing and applying new methods of production to improve the mature oil fields as we did with TNK-BP as well as refining.

Obviously, we work within the sanction requirements.

We always will.

Over time, we expect to continue to work with Rosneft to further build, I think, an important partnership across a range of activities, but we'll always work within these laws.

Now the third element of a BP proposition here is our focus on returns, as Brian will tell you.

Returns have been a challenge for our industry as a whole in recent years with heavy investment through high-priced, high-cost cycle that we've been through, followed by the challenging times of bringing costs down in a lower-price environment.

And for BP, we had the impact of portfolio changes and our own significant build phase.

So what do we mean by focusing on returns?

So first, as you'll have heard me say many times and Brian, it is a continuous drive to simplify and reduce our costs without, in any way, compromising on safety.

Second is to be very disciplined on capital investment in both the Upstream and the Downstream.

We maintain strict investment hurdle rates of return ensuring we only progress the best options forward.

And then once sanctioned, we also optimize full-cycle returns on each project as they progress through the life of the project.

Third is the active optimization of the portfolio itself.

We manage for value over the long term, seeking new ways to grow returns inorganically.

Two recent examples are the transaction in the Norwegian North Sea to create Aker BP and the merger of BP and Bridas to create Argentina's largest private integrated oil and gas company, Pan American Energy.

So fourth, very important, building mutually beneficial relationships that allow you to operate further down the cost curve.

This can be with resource holders in the most competitive basins or with business partners with complementary capabilities, as we're doing with Kosmos Energy to develop our offshore discoveries in Mauritania and Senegal.

We are now seeing the benefits of the significant build phase of the past few years becoming evident in the bottom line.

As our Upstream and our Downstream businesses' earnings grow, cash grows, return on average capital employed, or ROACE, more than doubled in 2017 versus a year ago.

It's up to 5.8%, obviously still a long way to go.

We have a big balance sheet.

As volumes and margins continue to go across our operating businesses, we expect our ROACE to recover steadily and exceed 10% by 2021.

So you've heard a lot from me, but let me briefly sum up before I hand it over to Brian.

As you'll see from the results in a moment, our 5-year plan is delivering results.

We have rebalanced organic sources of supply, sources and uses of cash.

We have a clear set of strategic priorities that are shaping how we will continue to generate value in a rapidly changing world.

In the Upstream, we are focused on growing oil and gas in a way that offers us advantages in terms of margin and value, which contributes to our ambition to advance the low-carbon energy transition.

In the Downstream, we continue to develop our advantaged manufacturing and marketing businesses, focused on maximizing value from the existing and new and emerging markets.

BP has been through a lot of change over recent years, but it's shown it's resilient over recent years through its focus on simplification, cost and capital efficiency and strong underlying financial performance.

We're modernizing how BP works using technology to work more efficiently and digitizing our processes.

We're also looking to the future and showing characteristic BP innovation and leadership when it comes to the dual energy challenge of more energy but lower emissions.

We're doing this across our operating businesses and by leveraging our existing knowledge from the developments of our alternative energy businesses.

And we're investing in new emerging companies and technologies through our venturing arm as well as creating new low-carbon business models.

We are 1 year into a 5-year plan, but we have real confidence across BP and a strong platform to build on.

With that, I'll hand it over to Brian now, who will take you through our financial results and the framework.

Thanks, Bob.

Starting with the environment.

Brent crude averaged $54 per barrel in 2017 and $61 per barrel in the fourth quarter, up from $52 per barrel in the third quarter and $49 per barrel in the fourth quarter of 2016.

So far, as Bob highlighted, this year, Brent crude has averaged around $70 a barrel.

Henry Hub gas prices averaged $3.10 per million British thermal unit in 2017 and $2.90 in the fourth quarter compared to $3 in both the third quarter of 2017 and the fourth quarter of 2016.

BP's global refining margin averaged $14.10 per barrel in 2017 and $14.40 per barrel in the fourth quarter compared to $16.30 in the third quarter and $11.40 per barrel a year ago.

Turning to the summary of BP's earnings in the fourth quarter.

Underlying replacement cost profit was $2.1 billion compared with $400 million in the same period a year ago and $1.9 billion in the third quarter of 2017.

Compared to a year ago, today's result benefited from a stronger environment with improved oil prices and refining margins.

It also reflects progress against -- across our businesses with higher production volumes in the Upstream and continued underlying growth in the Downstream.

Looking quarter-on-quarter, oil prices improved in 4Q, and Upstream production grew with the ramp-up of major projects.

This was partially offset by exploration write-offs, seasonally lower refining margins and a weak oil supply and trading contribution.

The fourth quarter dividend payable in the first quarter of 2018 remains unchanged at $0.10 per ordinary share.

In Upstream, the fourth quarter underlying replacement cost profit before interest and tax of $2.2 billion compares with $400 million a year ago and $1.6 billion in the third quarter of 2017.

Compared to the third quarter, the result reflects higher liquids realizations along with higher production from major project start-ups, partly offset by higher exploration write-offs.

Fourth quarter reported production was 2.6 million barrels of oil equivalent per day, 18% higher than a year ago.

Looking ahead, we expect first quarter 2018 reported production to be broadly flat with the fourth quarter, reflecting continued ramp-up from 2017 major project start-ups, offset by the exploration of the Adma concession and other divestment and portfolio impacts.

Turning to Downstream.

The fourth quarter underlying replacement cost profit before interest and tax was $1.5 billion compared with $900 million a year ago and $2.3 billion in the third quarter.

Compared to the third quarter, the result reflects stronger refining performance, with availability at 96.1%, the highest in over a decade, more than offset by a slightly below break-even performance in oil supply and trading, seasonally lower industry refining margins and fuels marketing results, more turnaround activity and, of course, the absence of earnings following the divestment of the SECCO joint venture in our petrochemicals business.

Looking to first quarter of 2018, we expect higher discounts for North American heavy crude oil but lower industry refining margins.

We also expect turnaround activity to be lower in refining but significantly higher in petrochemicals.

Turning to Rosneft.

Based on preliminary estimates, we've recognized $320 million as BP's share of Rosneft's underlying net income for the fourth quarter compared to $140 million a year ago and $140 million in the third quarter of 2017.

Along with a high Urals price, the estimate reflects a one-off legal settlement in Rosneft's favor and adverse foreign exchange impacts.

Our estimate of BP's share of Rosneft's production for the fourth quarter is 1.1 million barrels of oil equivalent per day, a decrease of 2%, reflecting participation in non-OPEC oil production cuts.

Further details will be available when Rosneft report their fourth quarter results.

In Other businesses and corporate, we reported a pretax underlying replacement cost charge of $390 million for the fourth quarter.

This was higher than our guidance of $350 million as a result of adverse foreign exchange impacts.

The adjusted effective tax rate for the fourth quarter was 27%.

This reflects a benefit from the reassessment of the recognition of deferred tax assets.

The full year adjusted effective tax rate was 38%.

Now moving to cash flows.

This slide compares our sources and uses of cash in 2016 and 2017.

Excluding pretax oil spill-related costs, underlying operating cash flow was $24.3 billion for the full year, with $6.4 billion generated in the fourth quarter.

This includes a working capital release of $2.7 billion for the full year, with $1.2 billion being released in the fourth quarter.

Organic capital expenditure was $16.5 billion for the full year, with $4.6 billion in the fourth quarter.

Divestments and other proceeds for the full year totaled $4.3 billion, with $3.4 billion received in the fourth quarter, including total proceeds of $1.5 billion following the sale of our SECCO business in China and around $800 million from the initial public offering of BP Midstream Partners.

Pretax Gulf of Mexico oil spill payments were $450 million for the fourth quarter and $5.3 billion for the full year.

Net debt at the end of the quarter was $37.8 billion, and gearing reduced to 27.4%, within our 20% to 30% gearing band.

In October, we announced that going forward, the issuance of scrip dividends will be offset by share buybacks.

And as Bob mentioned earlier, in the fourth quarter, we bought back of 51 million shares at a cost of $340 million.

This offset the dilution impact from the second quarter scrip dividend issued in September.

Now turning to our guidance for 2018.

We expect Upstream full year 2018 underlying production to be higher than 2017, driven by the continued ramp-up of 2017 major projects as well as the 6 major project start-ups we have planned in 2018.

Actual reported production will depend on divestments, OPEC quotas and entitlement impacts.

We expect organic capital expenditure to be in the range of $15 billion to $16 billion, reflecting the continuing focus on disciplined spend.

The total DD&A charge is expected to be higher than 2017, reflecting the start-up of major projects and continued growth in Upstream production volumes.

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

In the current environment, the adjusted effective tax rate for 2018 is expected to be above 40%.

Our balance sheet remains robust, and we will continue to target a gearing band of 20% to 30%.

So taken together, we have made strong progress in 2017 in rebalancing sources and uses of cash and expect free cash flow to grow through 2018 and beyond in a constant-price environment.

In 2017, underlying operating cash flow more than covered organic capital expenditure and the cash dividend in the year at an average Brent oil price of $54 per barrel.

The organic cash breakeven for the group was $46 per barrel or the equivalent of $53 per barrel on a full dividend basis, including scrip, and that was ahead of where we anticipated we would be with the plan.

Within a disciplined capital frame and with continuing growth in operating cash flow from the Upstream and Downstream, we expect the organic breakeven for the group to average around $50 per barrel on a full dividend basis in 2018.

Looking further out, as we've said before, this is expected to reduce steadily to $35 to $40 per barrel by 2021.

As mentioned, with the share buyback program in place, we expect to offset the scrip dilution in 2018 over the course of the year.

Looking ahead, our intent will be to offset any ongoing scrip dilution through further buybacks over time.

The shape of the program will not necessarily match the dilution on a quarterly basis but will reflect the ongoing judgment of factors, including changes in the environment, the underlying performance of the business, the outlook for the group financial framework and other market factors, which may vary from quarter-to-quarter.

With momentum in the business and growing free cash flow, we would then aim to ensure the right balance between deleveraging the balance sheet, distributions growth and disciplined investment, depending on the context and outlook at the time.

So in summary, the group's organic cash flows are back in balance.

Our disciplined capital frame of $15 billion to $17 billion remains robust.

For 2018, we expect to be in the lower half of that range of around $15 billion to $16 billion; and through 2021, do not expect to exceed $17 billion in any 1 year.

We will ensure we remain robust to the downside in the event oil prices were to drop below $50 per barrel.

Turning to inorganic sources and uses of cash.

With the Deepwater Horizon court-supervised settlement program winding down, a post-tax charge of $1.7 billion was taken in the fourth quarter, relating to business economic loss claims.

This charge will be paid out over a multiyear period, and we now expect Gulf of Mexico oil spill payments to be just over $3 billion in 2018.

Around $1.2 billion has already been paid out in the first quarter for the scheduled criminal settlement payment, which now concludes the payments around the original criminal settlement.

$550 million will be paid in the second quarter relating to the civil settlements.

And looking ahead, oil spill cash payments are expected to step down to around $2 billion in 2019 and around $1 billion thereafter.

Divestment proceeds in 2018 are expected to be in the range of $2 billion to $3 billion per year, with proceeds weighted towards the second half of the year again.

Longer term, we expect divestments to remain in the range of $2 billion to $3 billion per year as we optimize and high-grade our portfolio and, of course, create flexibility within our financial frame.

Our balance sheet remains strong, and we expect gearing to remain within the 20% to 30% band over time.

Alongside growing earnings and free cash flow, we expect long-term returns to improve, as Bob laid out.

Return on average capital employed was 5.8% in 2017, up from the low point of 2016 as we progressed rebalancing of the group at lower oil prices.

We remain confident the returns will continue to steadily improve over the period, exceeding 10% by 2021.

The group's financial framework remains resilient.

Our strong Upstream and Downstream businesses are growing operating cash, capital is trending to the lower end of our frame, and we continue to focus on our cost and efficiency programs across the group.

This, in turn, is driving increasing free cash flow and improved returns, supporting growth in distributions to shareholders over the long term.

Thank you.

And with that, I will now hand over to Lamar.

Thank you, Brian.

You heard earlier from Bob about the dual energy challenge.

I'd like to return to the topic and share with you our approach to the energy transition and how we're doing this in a focused and disciplined way as part of the broader financial framework that Brian just outlined.

Now, as a global energy business, we face this dual challenge that Bob spoke of, meeting society's need for more energy while, at the same time, working to reduce carbon emissions.

Our industry is changing faster than I think any of us can remember, certainly in my career, and the energy mix is shifting towards lower-carbon sources.

It's driven by technological advances and growing environmental concerns.

But in an uncertain and changing world, the key is for our strategy and our investment choices to be resilient to a range of future outcomes.

Now, as Bob outlined earlier, how we do that is by setting clearer strategic priorities and vigorously pursuing these.

We also, of course, consider the timing and implications of changing patterns of demand and use this to plan around distinct horizons: things we're doing in the near term to make the business more resilient, as Brian talked about; things we're doing into the next decade and beyond to deliver growth; and things we're starting to do to secure our energy future over the much longer term.

Now let me share with you how, as a group, we're embracing the energy transition and outline how we are investing through this multi-decade period.

Today, as you know, oil and gas accounts for almost 60% of all energy used.

That means companies who provide these energy sources, along with their consumers, have an important role to play in the energy transition.

Our ambition is to provide more energy while advancing this energy transition, and we are taking action.

Our approach, reduce, improve, create, which Bob mentioned earlier, consists of the 3 distinct elements.

First, reducing the emissions from our own operations.

Now I need to be clear here, this is a complex subject, and our total emissions may well grow in the coming years as our production grows.

However, we are actively looking for ways to limit the growth of emissions everywhere we can, with a focus on reducing our operation -- our emissions at an operational level, and that's what we're talking about when we say reduce.

Now there are a couple of examples.

We're integrating energy efficiency into the design of new projects.

We designed our Khazzan gas operation in Oman to be inherently efficient and very low in emissions.

It has a central processing facility, so that removes the need for processing equipment at each wellhead, and this is a common source of methane emissions.

We're also improving the equipment and the processes in our existing production.

Our work to reduce flaring is an example of this.

We're a founding member of the World Bank's Global Gas Flaring Reduction initiative.

We're a member of its Zero Routine Flaring by 2030 efforts as well.

And to underpin our efforts to reduce our own emissions, we plan to set operational emissions targets, including for methane, and you'll hear more on this in the coming months.

Secondly, we are improving our products within the -- with the development of advanced fuels, lubricants and chemicals.

That enables our customers to lower their emissions.

Providing lower-carbon products to our customers is one of the biggest contributions we can make.

Around 80% to 90% of CO2 emissions from oil and gas products comes from their consumption.

Now we're in action on this as well.

BP fuels with ACTIVE technology uses an innovative formula designed to help engines run smoothly and efficiently by fighting dirt and buildup in a car's engine.

We're the largest producer of renewable natural gas fuel for U.S. transport, making fuel from agricultural and food waste.

And our PTAir product, used to make items such as clothes and plastic bottles, has a carbon footprint about 30% lower than the average European PTA.

And we've just launched a carbon-neutral PTAir in China.

The third element includes growing our established renewable portfolio and creating low-carbon businesses by investing in high-tech low-carbon start-ups and developing new business models and offers.

We can complement our existing hydrocarbon and renewables businesses this way.

Now I want to take a little bit more time to run through the work we've been doing in this area.

We have established a clear platform for building our low-carbon and digital businesses through our established alternative energy business but also, as I said, through start-up companies and increasingly, integrated solutions.

That helps accelerate and commercialize new technologies, products and business models.

Now as I laid out here a year ago, across this platform, we've identified 5 key focus areas.

Those areas are: advanced mobility; bio and low-carbon products; carbon management; power and storage; and digital.

Now these were deliberately selected as they're aligned to our commitment of advancing the energy transition, and they provide opportunities that are also aligned with our core businesses, allowing us to exploit portfolio adjacencies and build resilience within existing operations.

And each one of these focus areas has the potential to become material businesses in the future.

Our approach is enabled by strategic partnerships, large-scale products -- sorry, large-scale projects, venturing and experimentation.

We are investing with discipline and expect to spend around $0.5 billion annually from within our financial framework.

And as a founding member of the Oil and Gas Climate Initiative, or OGCI as it's known, we are also an active contributor into its $1 billion investment fund as well as co-investing alongside it.

Now turning first to our renewables portfolio.

Renewables, I don't have to tell you, are the fastest-growing form of energy.

They account for around 4% of all energy demand today.

And by 2035, we estimate that they could grow to more than 10% of total energy demand.

That's a rate of growth not seen in recent history.

And as you know and as Bob mentioned, we've already established and have a growing low-carbon business in what we call alternative energy.

The business has a significant portfolio across 3 platforms: renewable fuels, renewable power and renewable products.

And in renewable fuels, we operate 3 world-scale sugarcane ethanol plants in Brazil, producing some 750 million liters of ethanol per year.

But we're expanding the reach of this business.

And in November, we announced a JV with Copersucar to own and operate a major ethanol storage facility in Brazil.

They are the world's leading sugar and ethanol trader.

Our biopower business, which is -- sits within renewable power platform, exploits adjacencies here.

It generates enough electricity from the waste sugarcane to power our 3 ethanol plants while exporting the remaining 70% to the local electricity grid.

And in the U.S., our wind energy business has 2.2 gigawatts of gross capacity about -- across 14 sites.

Now Bob already mentioned our investment in solar energy through Lightsource BP.

We estimate that solar could generate up to 10% of total global power by 2035, and we see significant commercial potential in targeting this demand growth together with a partner which has aligned aspirations.

Lightsource BP is a global leader in the development, acquisition and long-term management of large-scale solar projects and smart energy solutions.

The company has developed 1.3 gigawatts of solar capacity to date and manages some 2 gigawatts of solar assets.

That's about the equivalent of powering about 0.5 million homes.

Now Lightsource BP aims to develop a 6-gigawatt growth pipeline focused largely in the U.S., India, Europe and the Middle East.

Renewable products is the third and emerging platform within the alternative energy portfolio.

And through our Butamax JV with DuPont, we're working to commercialize technology that converts sugars into an energy-rich biofuel, known as a bio-isobutanol.

Now this could be used as a direct drop-in advanced biofuel or a high-value building block for a wider range of products.

I'm happy to say operating performance across our alternative energy businesses has been very strong in 2017, and these platforms increasingly allow us to grow our integrated value chain offers.

Now we're also developing new low-carbon and digital businesses, and our portfolio of opportunities today includes a pipeline of more than 35 active investments with more than 200 coinvestors.

We're already leveraging these investments successfully with about 12 technologies in use within BP now.

Now in the advanced mobility area, we're pursuing opportunities across a number of broad themes, including electric vehicles, batteries and charging; new mobility models, such as carpooling and ridesharing; and vehicle autonomy.

We are exploring the development and production of new bio products for natural gas, fuel, lubricants, plastics and chemicals and other lower-carbon products.

That's something many of our customers are increasingly asking for.

Our alternative energy and Downstream manufacturing and marketing operations provide a great platform for commercializing these type of products.

Now we've already had some success in this space, for example, with Fulcrum biojet, PTAir I mentioned and Clean Energy in the U.S.

Now in the area of carbon management, we're working to improve carbon emissions performance at an operational level and enable customers to reduce or offset their emissions through carbon markets.

We're investing in new technologies and exploring the application of carbon capture, use and storage.

And in addition, our trading business, IST, is increasingly active in originating and trading carbon credits.

With about 1/7 of the world's greenhouse gas emissions now covered by carbon pricing systems, we anticipate further growth in this area.

We are also looking for opportunities to invest in low-carbon power and storage, in particular, where portfolio synergies like gas and renewables help to build further opportunities across our existing core businesses.

As discussed in our 2017 energy outlook, nearly 2/3 of the growth -- projected growth in world energy demand over the coming decades could come and probably will come in the form of electricity.

Finally, in the digital space, we're looking to new digital platforms, including block chain, quantum computing, cognitive computing, to improve efficiency and productivity, obviously, in our own operations but as well to transform our customers' experiences.

We recently invested in a company called Beyond Limits.

It's a leader in artificial intelligence and cognitive computing, and we're working together to apply technologies developed and pioneered in space to the extreme environments that we operate within, such as deepwater exploration and production.

Now to summarize.

BP is in action, with a clear strategy and a set of businesses that are focused on a lower-carbon future.

Our commitment to help -- helping drive the energy transition is embedded in the core of our business strategy.

The key for BP is for our strategy and our investment choices to remain flexible to a range of scenarios, scenarios which ultimately drive our 4 strategic priorities.

We believe that maintaining a balanced portfolio and a disciplined investment framework will enable us to be responsive to the evolving energy landscape.

In 2017, we made important progress building on our existing foundations through our investment in Lightsource BP, Clean Energy, Fulcrum, Butamax, among others.

And as we look to invest around $0.5 billion annually in these areas, each opportunity is subject to our rigorous investment framework.

Now in the early stages of incubation, we don't expect immediate profits; however, where they pass materiality and return thresholds, we will look to take the investments forward, growing and commercializing them.

So with that, I'll pass you over to Bernard, so he can talk about the strategic progress in the Upstream.

Bernard?

Thank you, Lamar, and good morning, ladies and gentlemen.

Today, I'll provide you with an update on the 5-year plan that we laid out last year with a summary of what we delivered in 2017, what this means for our plans up to 2021 and beyond.

Our strategy is simply stated.

First, quality execution, this is our biggest lever, be the best at what we do where we work, and this starts with, as Bob highlighted, executing safely; second, growing gas and advantaged oil, growing both gas and oil, but only those barrels that are advantaged, be it low cost or high margin, creating a portfolio that is resilient to whatever the price environment; and third, returns-led growth, investing with real discipline in higher-quality opportunities that grow value by generating increased cash flow and higher returns.

Last February, consistent with this strategy, we set out clear guidance for our plan to 2021, and the key metrics are highlighted on this slide: 5% production growth; $13 billion to $14 billion per annum of organic capital expenditure; resulting in about $13 billion to $14 billion in pretax free cash flow in 2021.

Now in 2017, we took significant steps, I think, towards these goals with a very strong year of delivery.

First, at the beginning of the year, we set out, I think as Bob said, ambitious plans to start up 7 major projects.

All 7 were successfully delivered, on average, on schedule and under budget.

In total, from the beginning of 2016 to the end of 2017, we installed more than 500,000 barrels of oil equivalent per day production capacity from our major projects, a very significant year of delivery as we marched towards our 2020 guidance of 800,000 barrels per day.

Second, we grew production 12% versus 2016.

This was ahead of our plan, with production growth accelerated into 2017.

Underlying growth was 8%.

Third, we said we would maintain discipline and invest between $13 billion and $14 billion of organic capital per annum.

In 2017, we invested $13.8 billion of organic capital.

Importantly, we continue to maintain a laser focus on the efficiency of our spend, and I will share a little bit more on this later.

Fourth, all of this helped us generate $6.9 billion of pretax free cash flow, an increase of around $8.5 billion on 2016.

And finally, we made 3 final investment decisions and took a number of steps to strengthen our portfolio for the long-term value growth.

Examples include in Azerbaijan, where we agreed a 25-year extension to the ACG production-sharing agreement out to 2049; we also extended the In Amenas production-sharing contract in Algeria; in Brazil, where we accessed the prolific Santos basin and signed a letter of intent with Petrobras to jointly identify and evaluate business opportunities, Tufan and I just came back from there last week; on the other side of the Atlantic, where we accessed new acreage in Côte d'Ivoire; and just last month in Sao Tome and Principe; and in Norway, where our Aker BP joint venture continued its remarkable growth through acquiring Hess Norge.

We also had a good year of exploration.

As Bob said, we announced 6 discoveries across Senegal, Egypt, Trinidad and the U.K. North Sea.

We discovered around 1 billion barrels of oil equivalent for the year, which is our largest discovered resource in exploration since 2004, with Yakaar in Senegal being the industry's largest discovery of the year.

Our performance in 2017 was underpinned by continued strong functional execution, helping us get the most out of every dollar we spend.

Unit production costs continued their downward trajectory and are now down 46% since 2013, exceeding our 40% target, with costs at their lowest level in the Upstream since 2006.

Execution of our drilling programs continue to improve.

In 2013, around 1/4 of offshore wells drilled were top quartile according to industry benchmarking.

Now over 60% are top quartile.

This is one of the factors which has helped reduce unit development costs in drilling by 34% since 2013.

Our projects -- project costs, as measured by Independent Project Analysis, IPA, have improved significantly and are well below the industry benchmark.

We also continue to actively manage our base business, a source of enormous value.

Our 5-year base decline, from 2012 to 2017, was 2.6%, below our 3% to 5% guidance.

And in 2017, we actually grew the base by 0.6%, a great outcome driven in large part by our investment in new digital tools, a key part of our modernization agenda.

Let me now expand on our plans going forward.

With the delivery of the 7 projects in 2017, we are well on track now for the 800,000 barrels per day of production in 2020.

The majority of the projects are already under construction and are, on average, under budget and on schedule.

Today, we now extend this high-quality growth from projects to 2021, where we expect 900,000 barrels per day.

And importantly, this production is expected to come with the same 35% higher cash margins, on average, than our 2015 base portfolio.

Turning to our ambition for free cash flow growth.

In 2018, we intend to build on last year's delivery with another year of disciplined growth.

We expect underlying production growth of between 5% and 7%.

Reported growth will be lower than this due to portfolio effects, including the expiry of the Adma concession and our dilution in Pan America Energy, ACG and the Magnus field.

We expect our organic capital expenditure in 2018 to be $12 billion to $13 billion, below our guidance, while maintaining our growth targets.

This is driven by improved capital productivity, importantly, not in absence of growth options.

It is about getting more out of each dollar with a disciplined focus on returns.

We said we would make the changes stick whatever the oil price, and we are committed to doing that and continuing, I would say, to push for further improvement.

We expect to start up around 6 major projects and take a number of final investment decisions on projects, including developments in Oman, India, Trinidad and the North Sea, high-quality projects that we expect to further underpin growth through 2021 and beyond.

Taking these together, we expect pretax free cash flow growth in 2018 to be higher than 2017 without any help from the oil price.

This underpins our confidence in the progress we are making to deliver our target of $13 billion to $14 billion in free cash flow by 2021.

Now to the longer term.

As we shared in Baku in 2016, we firmly believe, and Bob mentioned earlier, we have the capacity for quality growth out to 2030 without the need for acquisitions.

And that belief only strengthens with time as we interrogate each barrel and, importantly, continue to improve our functional performance.

To help maybe, let me start with some numbers, and let's look at the middle of the next decade, 2025.

As you would expect, our base will decline over that period; and for now, let's remain within our traditional 3% to 5% guidance.

Let's take a scenario, and it's just a scenario, whereby we wish to overcome this decline and grow by, let's say, 1% from 2021 to 2025.

In that scenario, we expect to progress around 4 billion barrels.

To maintain quality, each barrel must continue to meet our investment hurdle rates.

Today, we know from our area development plans -- detailed area development plans that we have 6 billion barrels in our hopper that exceed our 15% IRR investment hurdle.

And as a reminder, our hurdle rates are 15% for greenfield and 20% for brownfield or infill at $60 per barrel.

This 6 billion barrels is more than enough for growth in both volume and, importantly, returns, and none of this depends on future exploration success.

Beyond this, we have another 2 billion barrels that sit between 10% and 15% that we will continue to improve; and of course, many, many barrels beyond that.

So we have a very large set of diversified investment opportunities that give us confidence that we can grow this business while growing returns without the need for a major acquisition.

On the right of the chart, you can see how we test each investment decision to ensure it is accretive to cash margin per barrel or accretive to DD&A or both, and this is all about driving higher returns into the business.

Now that was some numbers.

Let me just add a little bit of color.

The map shows a number of the identified options which extend growth through to 2025, orange being gas and green being oil.

Two high-margin oil basins, with price leverage that you're all familiar with in our portfolio, are the Gulf of Mexico and the North Sea.

And in our plans right now, the combined production of these 2 basins will be higher in 2025 than they are today without any new exploration.

We intend to deliver this through some but not all of the projects you see listed on this slide and in-filled drilling opportunities.

We've identified around 130 operated high-margin wells we expect to drill by 2025, a real testament, I think, to the deep incumbent positions we have in these basins and the materiality of the options that creates.

Oman Khazzan and the Lower 48 are examples of huge gas resource bases with long, steady cash flows.

The Khazzan project has competitive development costs, around 2/3 below our average, and competitive cash margins.

The combined scope of Phase 1 and 2 involves drilling about 300 wells with a plateau of around 180,000 barrels per day net, which we expect to maintain through the next decade.

In the Lower 48, we have around 40 tcf of identified resources.

And within this, we have identified around 1,300 wells we can drill in high-quality plays with rates of return above our 20% hurdle.

We have a further 3,000 wells that sit just below the hurdle rate that we continue to work.

This gives us the option to grow production from around 300,000 barrels of oil equivalent today to in excess of 400,000 barrels a day by 2025, all depending upon investment levels.

And the opportunities include advantaged oil plays in the Mid Continent and the Greater Green River and highly economic natural gas plays in the Haynesville and the San Juan Basins.

And as Bob said, we will continue to explore in pursuit of gas and advantaged oil but with real discipline.

The objective is to discover barrels which are better than the barrels we have today as well as to keep our facilities full.

Our innovative alliance with Kosmos is expected to continue to build a leading position on the Africa transform margin.

And this year, we plan to conduct tests in the Santos basin in Brazil and in Nova Scotia as well as explore near our hubs in the Gulf of Mexico, in Trinidad, in the North Sea, Egypt and Indonesia.

And I hope this gives you a sense of the confidence we have in the resource base and in the ability of the resource base to sustain quality growth through the next decade.

Before ending, I would like to update you on our modernization and transformation agenda, which we discussed last February.

The benefits are now coming through to the bottom line, materially improving performance as well as changing how it feels to work in the Upstream, our 2 objectives.

APEX, our production optimization tool, has now been deployed in 21 assets across 7 regions.

It acts in many ways like the digital twin of our production system.

Since deploying APEX, engineers have added more than 30,000 barrels per day of point-in-time production through optimization of well-operating parameters.

What used to take hours now takes minutes, with more than fifteen-fold reductions in production simulation run times.

In our Lower 48 business, we codeveloped a pad optimization mathematical model with a Silicon Valley start-up.

This is the first time it has been applied in the oil and gas industry.

When initially deployed on 180 wells and 5 pads, it reduced emissions by 74%, increased production by 20% and reduced cost by 22%.

Using machine learning, we aim to deliver more effective and focused inspection programs.

We used 40 years of historical, inspection, operating and weather data from 1,300 miles of piping to help predict where corrosion is and isn't likely to occur.

This is helping to improve reliability, increase production and increase the efficiency of our inspections.

We are also harnessing the power of continuous improvement.

In our global operations organization, 2,700 separate projects were completed last year, saving or mitigating around $330 million and adding or protecting around 55,000 barrels per day of production.

There are lots more examples, as you can see on this slide, but overall, I remain excited by both the delivery but, very importantly, the potential that lies ahead in this agenda.

And as we said in Baku many times, there is indeed more to come.

In summary, I think our strategy is clear, and it is working.

2017 has been a very strong year of delivery with progress on all of our key metrics.

2021 delivery has been materially, I think, de-risked, and we are ahead of plan.

And we continue to underpin growth beyond this with a growing discovered resource base, a laser focus, importantly, on the efficiency of our capital spend and an ambitious agenda to transform the way we work.

Ladies and gentlemen, thank you for listening, and let me now hand it over to Tufan.

Thank you.

Thank you, Bernard.

Good morning.

Today, I will provide you with an update of progress against strategy and the key metrics I set out last year.

Let me start with a reminder of our strategy, which is to deliver underlying performance improvement and growth to expand earnings potential and improve resilience and to further build competitively advantaged businesses across Downstream.

Between 2014 and '16, we delivered $3 billion of underlying earnings growth.

And as I laid out last year, our plans are for further delivery of more than $3 billion by 2021: more than $2 billion from profitable marketing growth; and more than $1 billion from advantaged manufacturing.

We expect to deliver between $9 billion to $10 billion of pretax free cash flow with returns of around 20% in 2021, and we do all this with a continued focus on efficiency and simplification and with safety as our core value.

Indeed, in 2017, we delivered our best overall safety performance on record.

In addition, we are developing new products, offers and business models to support the transition to a lower carbon and digitally enabled future.

So let me now take you through the progress in 2017.

The disciplined execution of our strategy continues to deliver results.

If you look at the chart on the left, you can see 2017 earnings stood at $7 billion, around 60% higher than 2014 despite an adverse environment impact of around $0.9 billion from narrower North American heavy crude oil differentials known as WTI-WCS.

We continue to see the exposure to North American heavy crude as a competitive advantage, and looking forward, expect this differential to recover from its relatively low 2017 level.

You may actually have seen that this differential has already widened last month or so.

The result for 2017 reflects $0.7 billion of underlying earnings growth, bringing total earnings growth to $3.7 billion since 2014.

And if you look at the chart on the right, it shows the drivers of this growth.

As you can see, 2017 was another year of strong performance from our marketing and manufacturing businesses.

Together, they delivered around $1 billion of underlying earnings growth, putting us ahead of plan to deliver the more than $3 billion growth we expect from these businesses by 2021.

Our supply and trading business delivers material and rateable earnings with some volatility across the years based on market opportunities.

In 2017, we saw a lower contribution than the previous year, although still in line with 2014 earnings.

And across all parts of Downstream, we continue to maintain a rigorous focus on cost management and efficiencies.

We have ongoing efficiency programs in place, which more than offset inflation and continue to improve our ratio of cash cost to gross margin.

Last year, we spoke about the key drivers of earnings growth across each of our businesses.

Let me now share the progress we have made.

In marketing, we delivered further growth with earnings standing at almost $4 billion in 2017 and returns remaining highly attractive in excess of 30%.

In fuels marketing, we continued our track record of double-digit growth with underlying earnings in 2017 growing by $0.3 billion to $2.4 billion.

In fact, if you look at since 2014, we have grown fuels marketing earnings by more than 50% at constant currencies.

In retail, the most material element of fuels marketing, we continue to strengthen our differentiated offer.

We now have 1,100 convenience partnership sites, a growth of more than 220 in 2017.

The success of this highly differentiated partnership model is reflected in our nonfuel retail gross margin, which stood at more than $1 billion in 2017.

And since the launch of our latest Ultimate fuels with ACTIVE technology in 2016, premium fuel volumes have grown by 20%, improving by 6% in 2017 alone.

Our retail business is differentiated through our strong market positions, brands and distinctive customer offers.

This differentiation enables our growth in existing markets and supports plans to expand our footprint in new material markets such as Mexico, India, Indonesia and China.

Indeed, in Mexico, we now have more than 130 operational sites after becoming the first international company to enter the deregulated fuel retail market last year, and we plan to grow to around 1,500 sites by 2021.

And in China, we recently entered into joint ventures with Dongming Petrochemical to establish a leading branded retail fuels and convenience business.

This is part of a focus growth strategy to expand our retail presence in China from 700 to around 2,500 sites.

We also continue to grow B2B fuels and Air BP businesses.

In our global Air BP business, which has strong market positions and good exposure to growth markets, earnings grew by 5% in the year.

Our lubricants business is also differentiated.

It has some of the strongest brands in the industry and has a brand presence in around 120 countries.

In 2017, we delivered earnings of $1.5 billion with highly competitive return on sales of more than 20%.

Our lubricants business has good exposure to growth markets and a growing premium segment, which delivered continued underlying earnings growth in 2017, although offset by the adverse lag impacts of increasing base oil prices.

Indeed, premium lubricants volumes grew to 44%, more than 1 percentage point increase versus 2016.

And in the fourth quarter, we saw a return to year-on-year earnings growth with key growth markets earnings increasing by 9%.

Through the strength of our BP Castrol brands, we are also establishing a global partnership with Renault-Nissan Alliance, the largest global automotive carmaker.

In addition to the continuation of Renault Formula One sponsorship and the supply of fuels and lubricants by BP, the partnership will also include a strategic collaboration for advanced mobility solutions.

In addition, we renewed partnerships and supplier arrangements with Ford, VW and Volvo.

All of this further demonstrates the quality, sustainability and robustness of the growth opportunities in our lubricants business.

Turning to manufacturing.

Underlying earnings have grown by $0.8 billion in the year: $0.7 billion from refining; $0.1 billion from petrochemicals.

This growth reflects the continued delivery from our multiyear Business Improvement Programs, BIPs.

And as you can see, we have made significant progress against our plans of more than $1 billion growth by 2021.

Delivery has been underpinned by strong operational performance in both refining and petrochemicals.

In refining, we continued to deliver against our key programs of reliability and efficiency, advantaged feedstock and commercial optimization.

Reliability was strong with Solomon availability of more than 95%, as Bob mentioned earlier, and our Whiting refinery achieved record levels of throughput in 2017.

We also processed record levels of advantaged feedstock, increasing to 43% of total throughput versus 37% in 2016.

Through our commercial optimization program, we delivered additional value from our assets by capturing opportunities from crude selection through to yield optimization and constraints removal.

And we delivered further efficiency benefits, for example, maintenance, planning and scheduling efficiency improvements.

All of this supported an underlying improvement of more than 15% in our net cash margin per barrel, which is a metric that measures refining competitive profitability.

In petrochemicals, reducing cash breakeven is key to improving resilience to environmental volatility.

We have now reduced our cash breakeven by more than 40% versus 2014 through improved operational performance, industry-leading technology upgrades and efficiency gains.

This improvement was completed a year ahead of the schedule that I previously shared with you.

This delivery of underlying earnings growth and double-digit returns in petrochemicals positions us well to capture growth and investment opportunities in an attractive and growing market.

We are also making strong progress on free cash flow and pretax returns.

As you can see from the chart on the left, free cash flow has grown by $1.1 billion to $6.6 billion despite an increase in growth-related capital investment and pretax returns of more than 18%.

Our best on record are fast approaching our target of around 20%.

Indeed, a 2021 plan assumptions, 2017 free cash flow would have been $6.9 billion with returns of more than 19%, all of which makes our business even more resilient to the environment.

If you look at the chart on the far right, you will see that we have further reduced the BP refining market margin to deliver 15% returns from $12 per barrel in 2016 to $11.5 per barrel in 2017.

This was achieved despite the impact of narrower North American heavy crude oil differentials.

This means we are able to sustainably deliver strong returns even at industry refining margins below the historic range.

Now let me move to the longer term.

I am excited by the opportunities that we are working on in the Downstream to advance the energy transition in support of the reduced improved create framework that Lamar spoke about.

First, reducing our carbon footprint in our operations where we are already in action.

For example, at our PTA plant in Belgium, technology improvements allow us to achieve greater energy efficiency, reducing our power usage by 30% and leading to an overall greenhouse gas emissions reduction of 14%.

Second, we continue to innovate and improve our products.

We have developed lower viscosity lubricants, helping improve the efficiency of vehicles.

In addition, our BP fuels with ACTIVE technology use an innovative formula designed to fight engine dirt and increase fuel economy.

And in the third area of creating new low-carbon businesses, we use the strategic frame shown on the slide to develop new customer offers and transition our business to a lower carbon future in the 3 focus areas of advanced mobility, bio and low carbon products and digital.

This is the frame actually Lamar talked about in the focus areas.

We see significant opportunities to create new low-carbon businesses, and we are pursuing numerous initiatives.

Let me now play a short video to share just some of the progress we have made.

(presentation)

As you can see, there's a lot already in play.

We expect these initiatives and the other projects we have in the pipeline to create new business models and additional future revenue streams for Downstream over the longer term.

Let me now summarize.

Our strategy continues to deliver results.

2017 was our best safety performance on record.

We delivered around $1 billion of underlying earnings growth in our marketing and manufacturing businesses and $1.1 billion of free cash flow growth with returns of more than 18%.

This strong 2017 delivery puts us ahead of plan to deliver more than $3 billion of underlying earnings growth by 2021 and between $9 billion to $10 billion of pretax free cash flow with returns of around 20% in 2021.

Looking forward, the opportunities from our differentiated businesses and the new business models give me great confidence in Downstream growth momentum to 2021 and beyond.

We have expertise, knowhow, innovation and partnerships to deliver this.

Thanks for listening.

Now we will have 15 minutes break.

After the break -- by the way, refreshments are outside.

After the break, Bob will briefly summarize, then we will move to Q&A.

(Break)

Okay.

Ladies and gentlemen, it would be -- we have a reunion right in front of the webcast camera.

We have a reunion right in front of the webcast camera with you guys.

So ladies and gentlemen, I have to ask you to sit down.

I'd be okay if you stayed and talk, but we have thousands of people down the line in both hemispheres in Europe.

Welcome back, everyone.

Welcome back, everyone, here in the room in London.

Before we move to the Q&As, I'd like to take just a minute or 2 to summarize a few points just to get us back into the summary here.

First, I would like to thank -- thank you all for your interest and your attention.

It's been a very long haul.

We've showed you lots of data information, charts and slides, and I hope we've provided you a lot of useful information about the business and our direction.

I could happily report -- may be temporary, but I can happily report market seem to have stabilized, futures in New York are actually a little bit positive in the S&P.

So calm down, everybody.

And BP is green on the screen, which is a nice surprise.

We've just completed our strongest set of full year results for some time, and the momentum we have in the business is giving us a lot of confidence in the year ahead.

And beyond that, Bernard and Tufan laid out things going well into the next decade.

So our goal here is to keep growing sustainable free cash flow and distributions for our shareholders over the long term, and we believe we're in the right shape to do that now.

It's taking a long time, but I think we're in the right shape to do that now.

And as you've heard from Brian, we're back in balance and our financial frame is not just robust, it gives us room to maneuver when we see the right options.

You've also heard in some detail about our medium and our long-term plans and options in our core oil and gas business with new opportunities in low carbon.

We're open for all kinds of questions about that future.

We're in a great shape to act where we see the opportunity and generate value for the people who own the company.

It's what you all represent.

We'll also do so safely, first and foremost, and we're going to maintain our discipline.

You'll always hear that from us.

The world is changing very, very fast, and there's a lot of uncertainty about exactly where the future looks like and what it looks like.

But this is when I think BP really comes to the fore.

I don't believe there's another company of our size and scale that can adapt and manage change better than we can.

We've been tested under fire a lot.

We've been doing so for a long time with a lot of success.

BP is a global integrated energy business, has over 100 years of experience of meeting society's demand for energy, which has all changed during that 100 years as well.

So this is nothing new.

We've got an outstanding team.

We've got clear and flexible plans, great options and a very bright future.

And thank you all for listening.

Staying with us now, over to you for questions here in the room and on the line.

We'll take questions here in London, and we'll also have phone calls from the line.

So Theepan, you're in the front row, go ahead.

Theepan Jothilingam from Exane BNP.

A few questions, please.

Just one point of clarity on, I think, the prices, Slide 23, and the free cash flow per share.

Just wanted to clarify, for 2018, is there any sort of working capital contribution or move there?

Secondly, coming back to Macondo and the cash outflows, perhaps we can just talk about the line of sight, the confidence.

I know we've had revisions, the update in January.

Could you talk about where we are in terms of the business economic losses and where you see the court settlement process?

Can we see line of sight in terms of closing?

Then just on the Upstream.

It's great actually to see the data on unit costs and operational efficiency for 2017, and we see the progress on projects.

I want to know what the price is in terms of the unit costs for 2018 and where operational efficiency can be 2018 vis-a-vis '17.

Brian, Slide 23.

Yes, yes, so Slide 23, wherever Slide 23 is.

Actually, for the plans for this year, we've got a slight working capital build.

So it goes in the opposite direction.

So that number is pretty well underpinned.

So there's sort of no issues around that.

On Macondo CSSP, I mean I can go through great detail.

I don't plan to now.

Yes, I think it was all in the release that we put out last year.

I think the way to hold it around business economic loss claims is we've taken a further provision this quarter.

It's based on what happened in the fourth quarter, which we've been over before where all the claims that came through were 10x the average of the whole life of the facility.

And we had a particular negative ruling effect where about $0.5 billion of claims that had previously calculated to 0 came back into the facility as a result of the 495 overrule by the Fifth Circuit.

So take those things in the round, bell claims have gone from 147 -- 149,000 is where we started, were down to less than 600 claims now to be processed.

So I think in terms of materiality, that gives you a flavor of what's there.

We've done our best estimate again based on all the information we have, and we've fully provided for that.

But we can't give you any further certainty than that other than to say there's 600 claims of the 147,000 still left to process.

We have taken a provision against what we think those 600 claims will be, so we're not completely sort of unprovided.

And there is a provision across what we expect the final litigation portfolio looks like as well, and we're provided for that.

I think, Brian, just to remind everyone the frame, so we make it easier for you to try to model this.

We always keep the Gulf of Mexico separately and we'll meet the obligations with divestments rather than the rest of the frame that we describe organically, so that you can actually see our response and specifically.

Theepan, thank you.

On operating efficiency and on unit costs, I think our plan through to 2021 has continued unit cost reduction in that plan, as it does have continued operating efficiency improvement.

Remember, we define operating efficiency across 4 chokes, not just the plant, but the wells, the export system and the reservoir.

We were actually ahead of plan on our operating efficiency metric in 2017 versus our internal target.

And over the next several years, on both unit costs and on operating efficiency, we expect to see further improvement.

And without giving a specific target for 2018, 2018 will be no exception.

Now I'm going to go back and forth with the line here so that people will stay with us on the line.

So Jason Kenney from Santander, I think up in Edinburgh.

Jason?

Two on the Downstream, if I may.

Firstly, I just wondered if you'd give us an update on Australia and the Woolworths deal and any implications financial or otherwise of a delay there.

And secondly, what kind of EBIT should we be thinking about in terms of new regional retail positions such as Mexico or China over maybe the next 3 or 4 years?

And then separately, just can I get a bit more information on Senegal and Mauritania?

Just when do you think that could be productive or supported for cash over the next 5 years?

Tufan.

On Australia question, Jason, is, first of all, we don't actually agree with ACCC's position that this is -- this deal is going to lessen the competition in the market significantly, and we are evaluating our options for the next steps.

Secondly, in terms of impact, you shouldn't expect any impact on our 2021 numbers because we have other options that obviously we are working on.

So I wouldn't expect any impact on our external targets.

On the new markets, I think -- I don't want to give any EBIT at this point, but those markets like Mexico is a good example.

Some of them may be sort of inorganic entries, then they will have their own profile on it, but I think something like Mexico.

Frankly, to start with, last year, we were in negatives as you may expect.

And now we are scaling up, and with scale, profitability will improve gradually.

That's how you may want to think about those markets.

So I think further we go -- in Downstream IR Day, I actually gave you a sort of how much of the fuel's marketing improvement will come from there.

It is not necessarily one of the biggest contributions in this frame, but contribution will be much bigger beyond 2021, obviously.

Okay.

The other -- M&S.

Mauritania & Senegal.

Jason, I think in Mauritania and Senegal, we've had 2 exploration phases now.

Phase 2 has just completed.

From those 2 phases of exploration, we have the potential for 2 LNG developments at scale.

The first being -- and the most immediate being Tortue.

And the second being from a combination of the Teranga and [Mersu] and the most recent discovery, Yakaar, in Senegal, a very giant resource base.

We've submitted an appraisal plan for the second part; that will take some time.

With regards to Tortue, Jason, 2 governments are working together on the intergovernmental cooperation agreement.

The key milestone, we need to get that done in the next period of time here to maintain momentum, and there are promising signs on that, so that's good.

We completed pre-FEED engineering.

We've got Tortue down in our project list here, starting up towards the back end of 2021, and we could see an FID for Tortue probably over the next 12 months or so.

So if you -- we have a lot -- sorry, Jason, go ahead.

I was just going to say thanks very much, that's perfect.

Okay.

So I'm going to ask you all to identify yourselves for people on the webcast, 1, 2, 3, for starters.

Okay, 1, 2, 3.

It's Jason Gammel with Jefferies.

I've got 2 for Bernard actually, please.

First of all, on base declines, significantly better than expectations on results there, and I think you even mentioned growth in the base of 0.6%.

Can you talk about what, from a process standpoint, is leading to this outperformance and perhaps even identify some of the assets that will be accounting for the outperformance?

Second, great result in terms of reserve replacement.

I was hoping that you could perhaps identify the areas that had the largest contribution to the reserve adds and then also perhaps identify any of the reserve add that was just related to the price effect and the year-over-year improvement in prices.

Very good.

So thank you, Jason.

On base decline, it -- I think in our business, we do tend to look at the big new shiny things and, of course, small changes in the existing base business, as you point out, bring about enormous value.

Growth of the base in 2017, and it was growth, I think has come from a number of dimensions.

I think focusing the mind, needs must, I think, is a very important contributor here.

In Alaska, the team have held Prudhoe Bay essentially flat for 3 years in a row at about 280,000 barrels per day while we have actually removed drilling rigs.

So as the capital, in many ways, has taken away, the focus of the team to optimize what they do has been intense and simply managing the gas, managing the optimization of the fields, a fantastic example.

Performance improvement in the Gulf of Mexico in 2015, the cost of an Atlantis well was about $100 million.

Today, it's about $62 million.

That's at the same rig rate, Jason.

So actually, what has been reduced there is the amount of time dramatically to drill these deepwater wells, allowing us to do more activity.

And obviously, there is technology.

We pump 1 billion data records a day, each day, into our proprietary data lake in the cloud where people have access to that data and using the digital trend that is APEX, allowing them to optimize production.

In Trinidad, we thought we had a problem in the start-up of Juniper that we thought might shut us down for about -- part of the system down for about 2 weeks.

We ran a simulation in APEX in 15 minutes.

That told us that the challenge that we had was actually not a challenge, and we were able to eliminate that 2 weeks of production.

So growing the base, I think, is a fundamental source of value and an area that I think we continue to see momentum in the years ahead.

In terms of reserves replacement ratio, 127% organic in the Upstream in 2017, a good year, a great performance by the teams.

We've had reserves included or added from places like the drilling program that we see ahead of us in Abu Dhabi.

We have reasonable certainty on the next phase of Khazzan.

So Train3 in Khazzan is in there.

But there's also things in there like the Gulf of Mexico, where we actually added material barrels in 2017 on the back of the seismic and algorithm breakthroughs that we had with the high-performance computing center that we've talked about, where we added 1 billion barrels of [stoip] to the Thunder Horse and Atlantis fields, maybe 200 million barrels or so of resources at Atlantis and real proved reserves being added at Thunder Horse, purely from our ability to use that high-performance computing center to crunch an algorithm, which was proprietary and put it together with some cool seismic acquisition technology.

So it had a number of things in there and yes, there was some price in there, but actually, it wasn't material when you look at the overall 1.2 billion barrels of reserves that were added.

It was probably less than 10%.

Okay, Christyan, Lydia and then Bertrand on the phone.

It's Christyan Malek from JP Morgan.

Three questions on capital framework and then apologies, one on sort of strategic.

First, on gearing, do you have -- and how important is it for you to lower your gearing to the bottom of the range?

You talk about 20% to 30%.

I mean, if you found interesting and new opportunity, would you be prepared to move back up the range?

Or is there sort of a level you'd want to achieve first?

And then on CapEx, I notice you've gone to $15 billion to $16 billion for this year.

To what extent is that delta towards the low end of the range a function of sort of sort of the CapEx efficiency that you've talked about or sort of refraining from necessary sanctioning and all the efficiencies that you wanted to?

Just want to understand what's driven that move to the low end of the range in percentage terms if you can.

Three, on cash flow.

So in Q3, your income was $1.87 billion.

Your cash flow work -- and actual ex Macondo working capital, $5.2 billion.

In Q4, your income went up to $2.1 billion, yet you've delivered exactly the same cash flow.

What exactly is sort of the drag on that cash conversion?

Because it feels to me that you've had -- given you've had better Upstream, better pricing, Downstream's sort of underperformed, understanding that mix in conversion.

And apologies, finally, from a strategic perspective, the synergy mandate, this transition you're talking about, are you willing to spend dollars in terms of moving into this transition?

So would you scale up through solar?

Is there a cap on what you'd spend on M&A?

Or is this all going to be organic?

Shall I?

Can I?

Sure.

Yes, so gearing is 10% to -- 20% to 30% has been with us for a long time apart from a period here of -- during Macondo, post 2010, we went to 10% to 20% because the fairway narrowed a little bit and we had liabilities that were significantly beyond the capacity of the balance sheet potentially before we had the big settlements.

Now we're back into 20% to 30%.

That is a huge amount of flexibility.

And 30%, to be clear, has never been a ceiling as we moved towards it last year, as we laid out to you that we would in the second and third quarter.

And as the proceeds came in, in the fourth quarter, that's come back down again and gearing's come down.

Actually, gearing, it's a helpful part of the frame.

The more important thing is the amount of funds you're generating over the extended debt book because that's what drives your rating.

So in that respect, there is a lot of flexibility within our gearing frame.

So it's not something which very easily comes into particular focus.

And as I said, net debt came down through that sort of back end of the year.

Capital frame, it's $15 billion to $17 billion is what we've set.

And we've set between now and 2021, $17 billion's the ceiling, $15 billion may not be a floor depending on where the environment is.

This year happens to be with the projects that we have lined up and where we are, the capital is.

We're going to spend a little bit more capital inside Downstream.

Bernard's got a little bit more capital efficiency coming through so the range of $15 billion to $16 billion feels pretty good.

We do know that when we put a range out, you'll typically take the high end of the range in your spreadsheet.

So we just thought we'd help you with the high end of that range.

Rather than you put in $17 billion in, it's not going to exceed $16 billion.

So we may as well sort of give that to you now.

On operating cash -- I've been round this too long.

On operating cash flow, there is, of course -- and we remind you of this every year, if -- you almost need to take about $1.6 billion out of the fourth quarter and remove it from the first quarter and add it back to the fourth quarter, because those of you who don't know the history of the economic union inside Europe and what Germany did to achieve all the requests of EMU, we have a $1.6 billion to $1.8 billion cash payment goes out early as mineral tax at the end of every year and then it reappears in the first 6 weeks of the next quarter.

So if you shuffle that $1.6 billion backwards and you strip out the working capital, I think you'll see the cash flow underlying is on a positive trend, 3Q through 4Q.

And more importantly, if you look at it year-on-year, the rules of thumb would say it should increase by about $2.5 billion.

It's actually increased by $7 billion.

So I think all that says is everything you see coming through in the way the projects and in Downstream is driving underlying operating cash.

Let me just touch the strategy question.

I think it'll be a combination of organic and inorganic, but it will feel more organic.

And the reason I say it is that what we're trying to do is most of the ideas we're working on right this minute have high connectivity to the existing businesses.

Yes, it may take some small investments, and we're making these types of investments now like Lightsource.

But if you think of Lightsource, then that potential grows organically in potential concert with Bernard's business and possibly even down the road in the Downstream businesses.

So they're high adjacency, high connectivity, but we'll have to make some selective inorganic.

I think the feel that we're trying to give right now is a wide aperture approach, high connectivity to what we think our DNA is; inorganic moves that are small in scale versus large in scale.

Then we can control, throttle and brake pedal as these ideas develop over years, decades possibly.

The objective is that they will have economic value to the shareholders.

That's a guiding star through all this.

We may make some investments, but they've got to have that potential, and tying it in with trading, too.

Yes, I mean, what we want, we do want competitive investments in the energy transition space that compete for capital straight up with Upstream, Downstream.

Conventionally, that may take a little bit of time, but those things could come in the years to come.

Lydia?

Lydia next, and then Bertrand Hodee on the line.

It's Lydia Rainforth from Barclays.

Two questions, if I could, and both of them related.

The first one on discipline of CapEx and the investment decisions.

Has that process changed in the last 2, 3 years in terms of actually making sure that the changes that have been made actually stick and that we don't just go back to the oil price is a bit higher, we can spend a little bit more?

And then related to that, and I appreciate you are only 1 year into a 5-year plan, but given the growth in free cash flow you expect, given where oil prices are, at what point -- what do you actually need to see to trigger that idea of growing cash returns to shareholders?

Brian, I'll start, and then you can -- it's become a habit in the company.

Capital discipline, cost control is now a habit in the company, and actually, this whole team allocates the capital.

It isn't like the Downstream gets some, the Upstream gets some.

Actually, we all debate it ourselves together, which has, I think, now become a habit as well.

And that's an important one because allocating capital in a company like ours is so important.

And then we need to keep that discipline and that framework that Brian described uppermost and foremost, not only with just this team, but our teams that work in all parts of the business.

Yes, and then in terms of distribution to shareholders, I think we've been very clear, actually, right through the oil price correction as the oil prices came down for the last 3 years, that the first part is you scrip offset, which we've now done, that's in the fourth quarter.

And there is no question this year, as we see the environment improve and given that we've got things back into balance of $50 a barrel, But we don't want to get a little bit ahead of ourselves at this point in the cycle given if you look at the outlook and as you see expenses roll down as you outlook, that we laid out for you and we look at the back end of this year, we could see potentially softening in oil prices, probably still above $50 a barrel, but there's no question this year there will be a conversation around distributions and how best do we get those back to shareholders.

Lydia, thank you.

Bertrand on the line from Kepler.

First, on -- in Upstream, you gave a production guidance of an underlying growth of 5% to 7%.

But Bernard also mentioned some potential offsetting factors like Adma-Opco, Pan America in Argentina, ACG.

What -- so what could be the reported production outcome if -- especially if Adma-Opco were not renewed?

And the second question is around the potential list of FIDs that BP expect to take in 2018.

What could be those?

Bertrand, on your question around 2018 production guidance, as we said, 5% to 7% underlying growth expected this year.

As Brian said in his slide, reported production will be slightly higher than 2017.

So we will trend to that.

I would -- in our plan, Adma expires on the 8th of March, and we have, as you said, Magnus, PA and ACG.

The combination of those is probably in the range of 120,000 to 140,000 barrels per day in 2018 versus 2017.

So you will see a headline growth.

You'll see strong underlying growth, and I hope that, that gives you a little bit of a sense of the difference.

In terms of the FIDs that we expect to see in the year ahead, we expect to FID Khazzan Train 3, the extension of our Khazzan business, which has been very, very successful.

We expect to FID a large compression project in Trinidad, 2 subsea tiebacks in the North Sea and the next 2 projects in our series of developments in India.

And there may be more beyond that.

Okay.

Just one follow-up, if I may.

About the potential expansion of Adma-Opco, what are your plan here?

Well, the Adma-Opco, the concession times out in early 2018.

We've been in discussions like many, many companies have been in Abu Dhabi.

We would like to work there, and ultimately, it'll be a decision by Abu Dhabi itself on which companies they want to join that.

We're in the ADCO concession, of course, and that goes out for another 40 years.

But we'll wait and see, Bertrand.

Now we're going to start with Jon and then one here, and then one here, identify yourself.

Then I'll go over here.

1, 2, 3, okay.

So Jon?

Can I ask -- it's Jon Rigby from UBS.

Can I ask 2 questions?

The first, I guess, people have asked this question around the round and maybe the answer ends up being the same.

But I noticed you frame your outlook at a $55 real price, which seems like a reasonable outcome or outturn.

But you talk about your business working at $35 to $40 by 2021.

So if I was a board of director and the executive, I'd be thinking about what options and things I should be doing with that implied free cash flow generation, which is pretty enormous by 2021.

So rather than talk about what you do this year or next year, can you talk about what you're thinking about in 2021 if indeed you get to that point and both those things happen?

The second question is I'm not sure if I'm drawing 2 dots together and jumping to a conclusion, but it seems to me being in the Upstream, very successful in being quite innovative with partnerships.

So either way, you've got opportunity but not the skills, or you've got the skills but not the opportunity.

You sort of marry those 2 together with a partner that fits.

And when I look at your U.S. Lower 48 business, it seems to me you've done a huge amount of work from an operational point of view to get it right up top tier.

But because of its very high gas exposure, and I take the point that the gas wells can generate high IRRs, but the real prize it seems to me is liquids.

So is there any opportunity strategically around that position that you have to move that business on materially over the next few years, if you could?

Jon, we -- if we are in a world where our breakevens are down to $35 to $40, and we're in a $55 world, we will generate huge amounts of free cash flow.

I think what we need to do is get your confidence about the discipline and the direction we're on, and then we'll have all kinds of options that the company can do among many things, gearing come down, further distributions to shareholders, all kinds of strategic options are out there for us.

So I'm not actually worried about that.

I think that will be a good world for us to be in, and that's the direction we're heading in.

But rather than saying we're going to do this or that with that extra free cash flow, it's probably too immature -- too early but the board does, with the management team, constantly talk about that future.

And then Lower 48, I mean, I think it's a great team, and we've got all kinds of options there, too.

Yes, I think Jon, much is made obviously of the Permian and the oil and the liquids, as you said.

But I think there is some reality also in what the returns are potentially in that business, and we will, of course, look at all of the opportunities and we do.

We screen all of the new opportunities there today.

But I would just maybe give one small example, just to give you a sense of how you don't have to be in a liquids basin to generate enormous value.

In 2015, we had very little acreage in an area called the Bossier or Haynesville Shale, and we identified this opportunity called SoHa, South of Haynesville.

Over the last 2 years, we have quadrupled our acreage position in this play, which is independently assessed as being possibly the most lucrative gas play in the United States.

We have gone from 0 rigs to 6 rigs drilling in the play.

The 2017 drilling program generated in excess of 40% rate of return at $3 Henry Hub.

We went from 0 to about 35,000 barrels a day of production in the space of 18 months and can see that production growing to over 100,000 to 150,000 barrels a day in the next 4 or 5 years.

400 drilling locations identified and probably, Jon, more than half of the capital in the Lower 48 business going into that play alone because it is so lucrative.

So yes, much is made of liquids, and certainly, we look at liquids, Lamar, all the time and look at those opportunities.

But just to give you an example how the model that when we separated the business was intended to work, which is the more independent mindset of go, capture acreage, appraise, develop quickly and create enormous value is working in South of Haynesville.

So we'll continue to look at liquids as opportunities.

They feel expensive when they come on the market, and when we can do the sorts of things that we can do, I won't give you an excess cost per acre, but I can tell you it is minuscule compared to some of the numbers that are created for other values.

And 40% rate of return is 40% rate of return.

So it's just another bit of color on the Lower 48 program.

Here, one?

Thomas Adolff from Credit Suisse.

I've got a few questions.

Firstly, just on your resource base, you've got a big resource base, in fact, the world is resource abundant.

Some of it is stranded because of fiscal terms, because of technology, and I wondered as far as fiscal terms are concerned, be it in Angola or other parts of the world, what sort of discussions are you having to kind of really unlock this -- these barrels?

And also, if you can comment on 20K psi technology.

Is it -- does it work now or does it not work?

And given that you're resource rich so is the world, is your disposal plan of $2 billion to $3 billion biased to Upstream resources in the context of a resource-rich world?

And then I guess finally, my question is if there's one key takeaway from 2017, where you went "Wow", the wow factor, for each one of you, what would it be?

That's a lot of questions.

Well, a comment on stranded assets because I -- or stranded reserves.

One, you said resources, which is right.

Reserves are not stranded.

They are economic and they're determined by the definition of being reserves because they're economic.

And reserves and resources move in and out of categories all the time.

Resources, it's not only going to be fiscal terms, it will be technology that will unlock a lot of these reserves and resources.

And one of our strategic foundations is advantage resources.

So for us, that means low-cost resources.

So our intention is with these resources to make sure they're low-cost and they will be economic, otherwise we won't actually call them resources but, Bernard, do you want to add?

Well, I think you're absolutely right, Bob.

And I think one of the things that we spoke about in the presentation there was that it's not just as we interrogate each barrel in that 48 billion barrels, but the functional performance improvement each day that we get better at drilling wells, building projects, managing base reservoirs, turns a barrel that is uneconomic into an economic barrel.

So that is be the best at what we do where we work is a key element of our strategy.

In terms of fiscal, I think the new President in Angola is sending some very positive signals about the changes that he's trying to make in that country.

I think they're needed, and I think we will look at opportunities differently going forward.

So that's great.

I think, Bob, in Alaska, the fiscal changes potentially around what has been achieved with the Trump Administration around gas, which many people might have thought of this as a big stranded asset may actually come to light in terms of commerciality.

So I think governments are understanding.

Certainly in Egypt, we have a lot of support in helping make projects economic that can replace imported LNG, same is happening actually in Libya.

So we are seeing changes, but probably the biggest change is within our own hands, as Bob says.

Right here in the front row, then we'll go over here and then we'll come back, that's okay.

It's Brendan Warn from BMO Capital Markets.

I guess back on the Lower 48 and the U.S. tax change and you have touched on it, and now that we've sort of rolled forward to 2021 numbers, I mean, when -- where does that business still fit within the portfolio?

And when do you start to see it actually generating free cash flow back to the parent?

And how are you thinking of it in terms of positioning?

And then just further on that point of fiscal change, I mean, since obviously the U.S. tax reduction, I mean, where does that country now rank?

Has it moved up in the positioning?

I mean, how much more attractive has it made investing into the U.S?

Maybe I'll let Bob comment on the U.S. investment climate.

But in terms of the Lower 48, Brendan, I think it's a great question.

The U.S. Lower 48 business generated cash for the parent in 2017 for the first time in many, many, many years.

And that is a testament to the leadership of Dave Lawler and his team in the Lower 48 business.

We talked about this in Baku.

We have a continual debate, and I think it's an appropriate debate in the company about the right balance between growth in a volume sense, growth in a returns sense and cash flow growth.

And in many ways, we were having that conversation rather early.

I think the entire industry has moved to that conversation, which I think is the right conversation.

So it is and Lamar and I debate this a lot, when you have opportunities ahead of you, 1,300 wells that generate economic return at $3 greater than 20%, you would have to argue that is a good business proposition.

At the same time, we want to ensure that it doesn't become a cash sink for a decade, much as it had for many, many years in the past.

So that is a debate that we have ongoing all of the time.

The good news is that the team continue to bring forward options, which are making that in some ways easier and in some ways harder because they're actually bringing more and more opportunities whether it be in the San Juan.

We recently accessed some very cheap liquids in the swoop area.

So that's the debate, Brendan, that goes on continually.

But for the first time in 2017, we actually generated a dividend, so to speak.

And then, Brendan, about -- you asked about the American business system now with lower taxes, what does it mean.

This is important for BP because we have been, over the last decade, America's largest energy investor, $90 billion of capital over the last decade.

That's separate and aside from the $65 billion of obligations with Macondo.

So if you take what was one of the highest tax rates in the OECD at 35%, take it down to 21%, this is, of course, enormous value to business in many ways.

Net present value to BP is affected by this despite these short-term charges and things that everyone's trying to sort out.

So it's important for us.

There's no doubt we'll increase investments.

I imagine I can speak for, because I'm around, a lot of the U.S. business community, the regulatory system in the United States is suddenly so much easier.

It was becoming an avalanche of regulations in every directions, permitting required, sequential federal and state and now they're in parallel.

Decisions are going to be made faster and if they're not made faster, then the infrastructure programs we're talking about won't happen.

So from a business community standpoint, it's quite transformational.

There will be a lot of capital attracted to the U.S. because of it, in my opinion, just speaking from a BP's perspective.

I realize I forgot your one question, which we might come back to where you said, what is the wow factor for all 5 people.

But that's sort of 5 questions.

So we'll -- it depends on the time.

So let's start here 1, 2, 3, and then we'll come back.

Oswald Clint at Bernstein.

I'd like to go back to the Upstream, please, Bernard mentioning the growth platform materially ahead of schedule here.

So maybe talk about what's delivering that?

Is it just excess service capacity that's helping and that might stop in the future?

But ultimately, with OpEx coming in below your target, with base decline rates better, with U.S. delivering a bit more, feels like you should be maybe increasing your 2021 free cash flow estimates at this point.

Is there something stopping you from pushing towards the higher end of that number or potentially increasing it?

And then second question, sorry, was, Bob, you mentioned this last year I think, about $8 billion into solar over the last decade and not much really coming out of it so far, so we're going back into solar.

Maybe talk about the KPIs or the milestones you're putting in place with these joint ventures and investment opportunities to ensure there's profit coming out and you can get out in time before we end up with such large numbers again.

On the first one around the improvements that we're seeing in the discipline and the environment and the whole conversation about inflation coming back into the system and what happens at $70 oil, we just keep going back, Oswald, to a very fundamental place, which is that we believe that there's an enormous amount of waste, and therefore, an enormous amount of opportunity in the Upstream oil and gas sector as a whole.

We believe that 75% of the savings that we've made to date are sustainable, and that about 25% are due to what you would call deflation, unit rate deflation.

But we don't see that 75% stopping there.

We see more and more opportunity.

To give you an example, the cost of a subsea well, the equipment, is down by 56% since 2012.

It used to cost about $97 million a well.

Subsea equipment now costs about $47 million a well.

Now is that because there's excess capacity in the system and suppliers are having to reduce their prices?

There will be an element of that, but it would be, I think, misleading to think that's why that cost is down so dramatically.

The cost is down so dramatically because we're taking a very different approach to what we're doing.

We're using industry-led solutions, which is a fundamental part of the strategy, which is taking equipment that is available on the shelf rather than building bespoke equipment.

We've reduced the cost of our inspections in that equipment by 60%, simplifying an umbilical scope in Shah Deniz phase 2, reduced the cost by 42%.

We've moved to global competitive sourcing, which is simply expanding our supplier base, maybe outside of the oil and gas sector, maybe outside of countries that we normally go to, heading to China for flanges, for piping.

65% reduction in the cost per meter of flanges and supplies.

So I think there is enormous potential.

I think the savings that we've made are largely sustainable, and we're not stopping there, and we have more to do.

And that's why you'll see us continually pushing, particularly on the capital angle.

In terms of the target and whether we are ready to change that target, I think it's too early.

We're early days.

There's a lot -- many years ahead of us.

We'll probably give an update on the Upstream towards the end of the year, and we might provide a further update at that stage when we have more of a year under our belt, but probably too early, but I'd rather be in the position we're in today than the alternative.

And on the solar point, you'll recall back in the 2000s, the company made big bets and developed over time businesses in biofuels and wind, but solar was one of them.

And in fact, around 2000, BP had the 3rd largest solar company in the world behind Sharp and Hitachi.

Gosh, has the world changed.

So we manufactured it and started in the U.S. We moved to Spain, we moved to India, we moved to China and it just -- solar cells became commoditized and panels.

That's not what we're doing today.

We learned that lesson really well.

So we are working where really inexpensive solar panels can be combined with project developers who develop these projects very carefully, and devs teams has been working on this where you develop -- there's a margin, you sign power contracts, you then combine that with places around the world where we're working with natural gas.

So I can see Lightsource BP developing solar projects now in Oman, in Egypt, in India, in combination with natural gas operations and our IST trading, electricity trading and optimizing around the different fuels.

That's the model we have.

It's a pretty capital-light model.

And I think it can be expanded greatly.

So that's our direction in solar.

And we've invested -- committed $200 million to it.

That's very different than building those big plants that we learned a lot from.

Yes...

.

Chris.

No.

Irene.

Irene Himona, Societe Generale.

My first question to Brian.

So as you progress in the delivery, clear delivery of the 5-year plan, how should we think about the group's sensitivity, earnings or cash flow, to the external environment, oil price, refining margin?

Is that changed?

Not necessarily today, but as you deliver the new barrels with a 35% higher margin, is that sensitivity changing?

My second question concerns the focus you all highlighted on modernizing BP, employing the new technologies, digitalization, predictive maintenance, et cetera.

And I had 2 related questions.

One is I don't have a clear picture as to whether that effort is systematically implemented through a process that aims to actually deliver that modernization across your assets over the next n years or whether it is more of a fragmented-opportunistic approach.

And the second related question, from a risk management perspective, these are new technologies.

How should we think about the risk?

Are we adding a new layer of, perhaps, unknown or less well-understood risks on top of the traditional risks related to those new technologies?

So on rules of thumb, we'll be updating those this quarter.

But you can still use something along the range of, and it's going to be a range, $3 billion to $3.5 billion pretax set against $10 barrel movements for oil.

And on a post-tax basis, we don't normally give you guidance, and Craig will be horrified for me to even go there, but again, $2 billion to $2.5 billion.

It's a broad range.

Measuring is the numbers we're using.

But $2 billion to $2.5 billion on a post-tax basis.

I mean, it will depend -- the reason why we don't do it is because, of course, as you've seen this year, the tax can move around a huge amount intra quarter.

But on a run year over the year, they're probably good numbers to use for now.

On your technology question, it's a really interesting question.

I don't think anybody's ever asked that before.

It's a combination of both, Irene, which is systematic programs, but we actually studied a lot of how other companies have done this and how they don't do it very well is suddenly mandate a modernization program.

What we've done is we've created pockets, maybe it sounds like it's fragmented, but people who have shown what they can do, pilot it and shown amazing results, then the uptake starts occurring all across the company, nobody wants to be left behind.

And it disrupts your existing IT systems.

So we've tried to think about this both in a human-nature way, avoiding the big company "Here's how you must do it," and let it organically grow and spread.

And it's spread that's one of my big ahas, by the way, for 2016 and '17 is how this has spread and the amazing enthusiasm of people when they see tools.

And young people in the company love these tools, it's a big aha for a big oil company.

So, of course, we have to systematize it as we're doing Upstream and Downstream, but I think letting it spread on its own sometimes is remarkable with standards and with reliability.

Yes, but I was going to say, Bob, just to add on that, because actually, my aha or wow for this year is the quality of the people that we're now hiring.

They come in and they just assume that this thing, whatever their thing is, will tap into all of your systems and they can app develop themselves and they'll disrupt and innovate.

And we learnt about 6 years ago that we'd have to have an IT frame that would enable them to still be able to do that but keep the company safe if you think about the cyber threats that sit out there and what we do around data lakes.

But I'd be in the same place -- I think we're all in the same place actually.

The people we're now bringing in, the quality of these people, it's a wow to the positive and it's also wow to the wow, because it is quite extraordinary.

Fair enough.

That's helpful, Irene.

Okay.

Right there and then 1, 2 -- 2, okay, 3, okay.

It's Chris Kuplent from Bank of America Merrill Lynch.

I've got 2 quick ones for you, Brian, and then 1 for Bernard, if I may.

It looks like 2018, Brian, will be the first year in a long time when depreciation will run ahead of CapEx.

Is that sort of going to track each other as we go and look forward into 2021?

And then secondly, I hear you, you don't want to commit on explicit language regarding shareholder returns.

But if you were to prioritize, what is going to happen first, the cancellation of the scrip or the buyback running ahead of the quarterly scrip rate or a DPS increase?

And the question for Bernard is one of my favorite projects seems to have made a return on to your slides.

So I just wanted to hear how Pike has made it onto advantaged oil?

Actually, I'll let Bernard go first.

Go ahead.

Go ahead.

I'd like to hear the answer to that question as well.

DD&A, it's going to tick up a little bit through 2018, it will probably flatten off in '19, '20.

And the tick-up is, of course, the new production that's coming on stream, the new reserve adds, is obviously increasing DD&A.

So there'll be a marginal uptick into '18, '19; flattening off in '20, '21.

On shareholder, there's -- we've had this conversation in the board, we've had a lot of conversation with our shareholders about the scrip.

I think the first test for us, Chris, was -- and it's great that people are now asking well, why do you need the surplus cash, because 2 quarters ago, they were saying you couldn't pay the dividend.

So now people seem to think we can pay the dividend, and not only have we done that, we've offset the scrip.

Clearly, people would now like to know what we'd like to do with any surplus cash beyond that.

We've had extensive conversations with the board every quarter around the dividend, which we've done through this whole oil price correction and with the delivery of the 10-point plan in 2014, we'll continue to do that.

But I think it's important that we offset the scrip.

About 45% of our shareholders will take a scrip uptake.

So right now, there is no intent to cancel.

We do understand, though, that there's a friction cost associated with issuing shares and those shares then being repurchased.

We think that's worth it given, a, our shareholders want it, and even in a benign quarter like 4Q, we had a 15% scrip uptake.

There are tax advantages for ordinary shareholders, so we want to make sure we maintain that.

The key is that we then offset it.

And I think having the financial flexibility as to how we self-set that through the year and you'll find that today we'll be back in the market buying.

I know people sort of said, "Well, you stopped on a certain date in December," well, yes, because we bought back all the scrip.

So we'd offset the dilution, which is what we said we'd do.

We're then in a closed period.

Today, we're back in an open period; we'll be back in the markets again.

So it'll be managed over the year and it creates some financial flexibility for the corporation.

But there's been no conversation around canceling it given the feedback we get from shareholders that they like it, but they want it offset going forward.

Thanks, Chris.

On Pike, it's a project that's out there, that's on the possible list out to 2025.

I think I'd say a couple of things about it.

First is, I think that the reason that it's on the slide is a testament to the great work that Devon, the operator, has done in driving the breakeven of that project down, I think towards the lower 40s.

So it's actually a quality resource.

That probably has further optimization to be done on it.

So I think first thing I would say is that it's -- given the quality of the resource and I think the fantastic work that Devon have done, the labor costs in Canada falling dramatically over the last several years, I think it starts to enter into the competitive frame in terms of a break-even basis.

The second thing I would say is that it is part of the 6 billion barrels that I referred to, but not every project in that 6 billion barrels is required.

We said we need about 4 billion barrels if we chose to grow at 1% out to 2025, and we have about 6. So there will be choices within that.

And Pike may indeed be one of those choices.

But I think Devon have done a great job in driving that breakeven down, and I think we are not yet at a stage as to whether we say that's in the base plan for the business or not.

We're running a little overtime.

So we're going to take 2 questions and then we're going to let you go.

It's Martijn Rats at Morgan Stanley.

I want to ask about one of my favorite projects, which is Zohr, in the sense that I do remember that when you announced the transaction, there was an option to buy more of it, which I think probably has expired.

And I haven't seen an announcement you've taken it up.

So I wanted to ask why you decided not to take up the option to buy more.

And secondly, I wanted to ask about the ROACE target of more than 10% by 2021 in the spirit of slightly more transparency on tax.

I believe this ROACE target is pretax.

Could you…

Post-tax.

Oh, that is all -- okay, so that question answered itself.

Post-tax.

And with Zohr, there was another chance to take up an option of another 5%.

We debated it, debated it, looked at it in our capital frame.

We still think it's a really good project.

It was a deeper well drilled, and we just said, you know what, we've got this set of projects that we're investing in this year, it would have taken on a good healthy capital obligation from past costs as well.

And so we have stepped back from it, and I'm sure Eni will have someone take that up, no question about it.

Last question, sir?

It's Rob West from Redburn.

I'm going to move from questions about projects on your chart to a project that is not on your chart, which I don't actually know is a real project or not.

It's Kirkuk in Iraq where I've seen in the press that there's an MOU for you to double production.

I don't know if it's real.

I don't know if you can comment on it, but could you in principle and what's holding you back?

The second one is on the just incredible reliability.

I'm not sure whether to be excited by it or a little bit afraid of it because once a number gets to 95% sort of level, you start wondering can it keep going up?

And if that improvement in reliability has been driving the decline rate down, where are you seeing the decline rate for this year?

Is there a bit of bounce back there?

That's the second one.

And then just finally, really quickly on solar, I love the answer you gave about integrating it with the gas business and freeing up those molecules in Algeria to send them down the pipe to Europe.

But the thing I was going to ask you is how much of this move back into solar is about cost?

Because when you see the cost of wind, which is where I've always thought about BP being more traditionally focused, we're at $0.05, $0.06 a kilowatt hour, and some of these sunny countries, you're getting solar out for $0.02 to $0.03 and is that part of what's tempted you back in there over wind where you're more traditionally focused?

Let me take the last one because we were just talking about solar.

So you're right; solar costs are coming down.

The ability to generate electrons in a country and then put the natural gas to power plants, which is often where it's needed, is part of this.

Wind, we've been -- we have a big wind business in the United States, very big wind business, across 16, 14 wind farms.

We have been cautious about getting involved in offshore wind because of salt in the gearboxes and working over those big turbines because -- but that technology is changing.

So we're getting more interested in wind offshore.

So give us some time.

We want to get that right.

I think we've been right so far to wait.

Kirkuk, Bernard and I talked about this the other day.

We have a long history in Iraq.

We work in the Rumaila field, which probably puts 40% of the treasury into the country of Iraq.

They've restabilized things up North.

We've had an agreement to study the Kirkuk field since 2013.

They've asked us to come back in.

We'll see.

We know a lot about that.

We're certainly not going to jump in with commitments until we fully understand it.

But I would take it as a signal that Iraq as a country is getting its feet back on the ground again, pulling it together, with the idea that it can offer new and different investment opportunities.

So we'll see.

We'll see.

And it would be great if Iraq could do that and if we played a role in that and it was economic and we're careful, that would be a good thing.

Your other question...

Reliability and base decline.

Rob, it's a good point.

Theory says there's 5 percentage points opportunity and we're unlikely to get to 100% reliability.

We do see further opportunity in plant reliability, but you're absolutely right; it's not going to be significant but important.

But when one door closes, you need to open another door and the door that we are opening in this space is around operating efficiency.

We look at 4 separate chokes in our production system.

The plant, the number that we just referred to, is one.

But there is also the export system and we saw what happened in (inaudible) in 4Q.

There's also the wells and the reliability of the well system, and there is also the reservoir itself as to whether it's producing at its capacity.

We define operating efficiency very rigorously across all 4 chokes, 95% times 4 gives you an 80% type number.

So we are actually focused very heavily now on driving our operating efficiency up, which obviously expands our scope, which more broadly particularly, I think, into wells and into export.

We have internal ambitions to grow that operating efficiency number over the next several years.

Like everything, it's got its challenges, but that's where the opportunity lies.

So maintaining plant reliability at 95%, maybe growing it hopefully to 96% and importantly in our key assets is important and shifting the conversation into all 4 chokes and measuring the reliability of the entire system, which is what operating efficiency is, is the next opportunity to impact base decline.

And in the Downstream, we shouldn't forget the availability of the refining system at 95%.

It's benchmark of all the Solomon index, I mean, that's a great set of results of Tufan and the team.

And there are cases in refining, if you maintain them and operate them well, that you can maintain 95% reliability for years done right with the right turnaround.

So that's an industry standard to get the right assets that we will strive for.

So ladies and gentlemen, and let me say, again, to everyone on the line from all over the world and there's quite a few on the line, I see hundreds, in fact, thank you very much for your time.