BP p.l.c.

Good afternoon, everyone, and thank you for joining us today. Welcome to BP's 2011 Results and Strategy Presentation.

We are very pleased to have you with us whether that's in person, over the phone or on the Web.

For those here in our new venue at Canada Square in East London, you will have seen behind me our safety evacuation guidelines. There are more details in the safety briefing card handed to you at the reception.

We are not planning to test the alarms today so if you hear it, please proceed as advised by the instructions. And may I ask you also to turn off your mobile or cellphones now.

Thank you.

With me onstage I have Brian Gilvary, who I am very pleased to introduce as BP's new Chief Financial Officer; and Iain Conn, our Chief Executive of Refining and Marketing. In the audience we have our Chairman, Carl-Henric Svanberg, and members of our executive team, who will host the breakout sessions after this and join us for the question-and-answer session later.

Now before we start, I'd draw your attention, careful attention to our cautionary statement. Please read it carefully.

During today's presentation, we will reference to estimates, plans and expectations that are forward-looking statements. The actual outcomes could differ materially due to factors we note on this slide and in our regulatory filings.

Please refer to our annual report and accounts, 20-F and fourth quarter Stock Exchange Announcement for more details. These documents are also available on our website.

Now today, we are going to return to the plans we laid out to you in October, the 10-point plan to grow value. We aim to leave you with an even clearer idea of the path ahead.

2011 was a successful year of recovery, consolidation and change, and we reached an operational turning point in October.

2012 will be a year of milestones as we build on those foundations and as we move through 2013 and '14, we expect to see the financial momentum building as we complete payments into the trust fund as our operations start to show the benefit of our actions.

Our 10-point plan provides the roadmap how we will play to our strengths and be safer, stronger and simpler and more standardized. How value will be driven by growth in both underlying volume and margin from a portfolio of the right size to generate the operating cash flow to both reinvest in our project pipeline, as well as reward shareholders as we have announced today with a 14% increase in the quarterly dividend.

We believe this will help us see the true value of the company recognized.

So let me outline today's agenda. I'll start with an overview, and then Brian will take us through the 2011 results in detail.

I will then report on progress in the U.S. before outlining our plans for the upstream, including showing you a video of a new initiative in the technology sphere that will be important for our industry.

I will then briefly touch on TNK-BP and alternative energy before Iain covers plans for the downstream.

After a brief summary of the first part of our webcast, we'll end and we'll break so that those here at the venue can regroup. We'll have 3 breakout sessions that will be held in rotation.

Those cover specific sources of value group that we want to tell you more about. Mike Daly and Andy Hopwood will cover our plans for long-term investment in the upstream.

Bernard Looney and Bob Fryer will discuss our upstream operating model and major projects, and Iain Conn and his team will explain how we are moving our downstream business forward.

45 London Time or GMT, we will gather back here and restart the webcast for concluding remarks and discussion, and we expect to be finished by around 5:30 London Time.

safety, rebuilding trust and growing value. I believe we have made good progress on all 3.

We set up a new safety and operational risk organization and reorganized our upstream into 3 global divisions of exploration, developments and production, which allows us to strengthen consistency and capability. We will be showing you more of the activities of the divisions in the breakouts later.

Now I believe trust is built by doing what you say you will do, and we have continued to meet our obligations to the Gulf of Mexico communities. We are back to drilling wells in the Gulf of Mexico, applying our voluntary standards that go beyond regulatory requirements.

And we're looking forward to value growth; there has been great progress.

In 2011, we resumed the dividend payments. Our organic reported reserves replacement was above 100% again.

Globally, BP was awarded 55 new exploration licenses in 9 countries last year, making it 84 over the last year and a half.

We believe this resulted in more net acreage than accessed by any of our peers in 2011, and it is a powerful indicator of how confidence has been restored in BP to work around the world after the events of 2010.

In October, we reached an operational turning point, already evidenced in the increase in production volumes that you have seen us report today for the fourth quarter. We have made substantial progress with our divestment program, which we will come back to later in more detail.

And we have completed transactions that expanded the portfolio in the strategically important geographies of India and Brazil. And our downstream business achieved a record year for earnings.

So that was the story for 2011. But before we look ahead, let's just remind ourselves of some important context.

There are a number of clear trends in the energy world as we highlighted in our recent energy 2030 outlook. We expect aggregate energy demand to rise by up to 40% by 2030, nearly all of it from emerging markets.

By 2030 we expect oil, gas and coal to have similar shares of global demand. We expect gas to grow at around 2% per year, double the rate of oil growth.

But we expect oil to continue to dominate transport fuel.

Renewables are expected to grow the fastest of all at around 8% per year, but even so, we estimate only 6% of the 2030 energy mix will be supplied by renewables.

We also see that North America has the potential to become energy self-sufficient by 2030. This is driven by the shale gas revolution, but also by a growth in biofuels and domestic production from deepwater, shale and heavy oil.

I believe our strategy is aligned to these big trends and positions BP well for the future. We will continue to invest in deepwater, gas and renewables.

And we're investing in growing markets, for instance India and Brazil, as well as in North America and elsewhere, and we're using our global reach to leverage technology and learning wherever we see the greatest opportunities.

Against such trends, the oil price environment has been uncertain and volatile, and gas prices continue to reflect regional supply/demand dynamics, with spot pricing in the U.S. remaining heavily disconnected from oil prices but more aligned in Europe and Asia.

In 2011, refining margins improved for a second consecutive year as demand for oil products continued to drive growth, driven by the non-OECD markets.

And the outlook remains difficult to predict. It requires us to be very clear about our strategy and only participate where we can compete, no matter what the environment holds in store.

I believe BP can do this. We have the scale, the focus, the distinctive trading capabilities and the access to growth markets, which brings me back to our 10-point plan.

In October, we put forward 5 points to expect and 5 to measure. I said we would focus relentlessly on safety, play to our strengths and be stronger, more focused, simpler and more standardized.

We promised to create more visibility and transparency to value.

In terms of measures, you will see continuing activity in portfolio management. In October, we announced an intention to pursue a further $15 billion of divestments, making a 4-year total of $38 billion by the end of 2013.

Meanwhile, we expect to see new projects coming onstream with operating cash margins around double the 2011 upstream average by 2014. That's at $100 per barrel.

It does exclude TNK-BP.

You can expect us to generate an increase of around 50% in additional operating cash flow by 2014 compared to 2011, approximately half from ending the Gulf of Mexico trust fund payments and around half from operations.

We plan to use around half of that extra cash for reinvestment and half for other purposes, including shareholder distributions, and all of this will be underpinned by a strong balance sheet.

deepwater, big gas value chains and giant fields.

And we have a world-class set of downstream businesses focused on fuels, lubricants and petrochemicals. We have several world-leading technologies, from advanced seismic imaging to lubricant formulations and proprietary processes for petrochemical manufacturing, to name just a few.

And we also have long experience of building and maintaining relationships, some of which are more than 80 years old. We saw the importance of this in the aftermath of the Gulf of Mexico oil spill as many governments, regulators, customers and suppliers around the world have stood by us and worked with us through this difficult phase.

As we set out in October in our 10-point plan, there are now clear near-term measures of how we will grow value. 2012 will be a year where we see increasing investment and delivery in many key milestones.

The year will be marked out by an increase in exploration wells, from 6 in 2011 to 12 in 2012. There'll be 6 new project startups and 8 rigs at work on BP-operated fields in the Gulf of Mexico.

We expect capital investment to grow to around $22 billion and to progress our program of planned divestments.

In Refining and Marketing, we plan to complete delivery of $2 billion in underlying performance improvement versus 2009, and we will complete our payments into the Gulf of Mexico trust fund in the fourth quarter.

Then in 2013 and '14, as investment continues, we also expect to see greater financial momentum coming through in our operations. A further 9 new project startups with average operating cash margins from the new projects in 2014, double relative to the 2011 portfolio.

The upgraded Whiting Refinery is planned to come onstream, and divestments are expected to have reached $38 billion. All of such by 2014, you will see the expected rise in operating cash flow.

So looking at it in terms of a simple bridge, we start with the operating cash flow in 2011 of $22 billion. The growth comes from 4 key drivers.

As I mentioned, the completion of the payments into the U.S. trust fund accounts for roughly half of the expected increase.

Then we have the restoration of high-value production and growth from our new projects. This is partially offset by divestments and the environmental assumptions we factored in.

Added all together, we get an increase in operating cash flow in 2014 of around 50% at an assumed $100 per barrel.

Today's presentation aims to give you more confidence in our ability to deliver on this outcome. But before we do this, I want to touch on some of the more critical enablers of this 10-point plan; those that are related to safety, to technology and to people and organization.

First, safety. Here are some figures to show how we are performing.

We measure even the smallest release of hydrocarbons and track them carefully. We call each one a loss of primary containment.

In terms of safety, the number of incidents in which there has been a loss of primary containment has fallen once again. That is positive, but of course even one incident is too many.

Also on this chart, you can see the progress we're making in improving personal safety, which is measured through the recordable injury frequency rate. Aside from the exceptional activities of the Deepwater Horizon response, steady progress has been made over this last decade.

We've also continued to implement the recommendations of the BP investigation into the 2010 incident. It's called the Bly Report.

Examples include the strengthening of the technical authority's role in cementing and zonal isolation and establishing key performance indicators for well integrity, well control and rig safety critical equipment. We continue to make progress against the other recommendations.

Now beyond these markers of progress, we've also done a lot of work in the way we organize ourselves with respect to safety and risk management. These are the 5 strategic priorities for our agenda in managing safety and operational risk.

All of them are delivered through our operating management system, or OMS, which is the standard system we use to drive systematic management and continuous improvement.

The safety and operational risk function provides independent insurance, audit and oversight to ensure the system is designed and operating correctly and works in partnership with the line management to ensure we're focusing on the right priorities.

To give you 2 examples, leadership determines the safety culture of the firm, and our action plan here includes requiring leaders to spend time in the field, observing and inspecting. Organization, on the other hand, includes defining the competencies required in safety critical roles and assessing individuals and job candidates against them.

There will be more on how we are applying OMS in the breakouts.

Technology is another key enabler of the 10-point plan. Critically it enhances safety and integrity, but it also creates value.

We have focused approach to technology, with 16 major technology programs selectively targeting points of competition within our industry across the areas shown on this chart. You will see another new one later in a short video clip.

In 2011, we have increased our research and development spending to over $630 million, leveraging this expenditure through collaboration with others. We also spent a similar amount applying this know-how through field trips, field trials, pilots and other deployment activities.

You may have already seen some of the ways in which technology is working for us on display outside and in a short while, we're going to introduce you to a new initiative we hope will help us unlock greater potential in our deepwater portfolio.

safety, respect, excellence, courage and working as one team. And for those of you here with us in London, you can see more of these outside the room as well.

We've also evolved our approach to performance management and reward, requiring our employees to set personal priorities for safety and risk management, focus more on the long term and working as one team.

And that seems like a good note for me to hand over to Brian, who'll take you through the 2011 numbers.

Thank you, Bob. It's a pleasure to join you today for my first set of quarterly results.

I'd like to start with an overview of fourth quarter financial performance. Our fourth quarter underlying replacement cost profit was $5 billion, up 14% on the same period a year ago.

The result benefited from higher upstream realizations and a lower tax rate, partially offset by weaker refining margins and higher costs. While upstream production volumes fell relative to the fourth quarter of 2010, operational momentum improved relative to the previous quarter, with an increase of 170,000 barrels of oil equivalent per day.

Fourth quarter operating cash flow was $5 billion, including $1.2 billion of post-tax Gulf of Mexico oil spill expenditures. For the full year 2011, underlying replacement cost profit was $21.7 billion, up 6% on 2010.

Today we also announced a 14% increase in the dividend to $0.08 per ordinary share payable in the first quarter.

Turning to the highlights at a segment level. In exploration production, underlying fourth quarter replacement cost profit before interest and tax was $6.9 billion.

Liquids realizations increased 29% year-on-year, in line with marker grades. Gas realizations also improved, reflecting the value of our LNG portfolio.

Production for the quarter was 3.487 million barrels of oil equivalent per day, 5% lower than the fourth quarter of last year but 5% higher relative to the third quarter.

Turnaround activity reduced from a peak in the third quarter, and we also resumed Gulf of Mexico drilling activity, with 5 rigs operating by year end. Production also benefited from the startup of the Pazlor field in Angola.

Costs were higher in the fourth quarter compared to the same quarter a year ago. We deepened our engineering and technical capabilities, including the independent safety and operational risk function.

Integrity-related spending was high, and rig standby cost in the Gulf of Mexico continued into October and November. Higher decommissioning provisions and greater production activity in Iraq drove an increase in DD&A.

Relative to the third quarter, underlying earnings were also impacted by a loss in the gas marketing and trading business.

For the full year 2011, replacement cost profit before interest and tax was $29.4 billion, an increase of 6% year-on-year. Full year production was $3.45 million -- barrels of oil equivalent per day, 10% lower than 2010 or 7% lower after adjusting for the effects of acquisitions and divestments and price effects on our production sharing agreements.

Looking ahead, production in the first quarter of 2012 is expected to be broadly similar to the fourth quarter of 2011.

Turning to TNK-BP. Our share of net income was $1 billion for the quarter, benefiting from higher production and realizations year-on-year, partly offset by increases in local transportation tariffs.

Cash dividends in the quarter were $1.7 billion, bringing the total for the year to $3.7 billion. In future we will report TNK-BP separately, providing greater transparency of our upstream business outside of Russia.

I view TNK-BP as a long-life, self-funding source of free cash flow with significant future growth potential.

Now turning to Refining and Marketing. For the fourth quarter, the Refining and Marketing segment reported underlying replacement cost profit before interest and tax of $760 million compared to $740 million in the same quarter last year.

We are now reporting the 3 businesses within the segment separately, delivering the increased transparency we signaled to you with the 3Q results.

Firstly, turning to fuels. Compared to the same quarter last year, the fuels business saw a 9% fall in refining marker margins, balanced by an improved contribution from supply and trading and benefiting from access to lower-cost WTI-priced crude grades in the United States, in particular in the Midwest.

Compared with the previous quarter, the U.S. fuels environment was particularly challenging.

U.S. refining margins reduced by more than 40% in the quarter, and differentials between WTI and Brent crude fell sharply from their third quarter highs.

However, globally we saw continued strong operations with Solomon availability at over 95% in the fourth quarter.

Earnings from our lubricants business in the fourth quarter were impacted by an increasingly difficult marketing environment, characterized by high base oil prices and weaker demand. This was largely offset by supply chain efficiencies and the strength of our products and brands.

Turning to petrochemicals. Compared with the fourth quarter of 2010, our petrochemicals business was also impacted by weakening market conditions as additional Asian capacity came onstream at a time of weaker demand.

For the full year, Refining and Marketing delivered a record underlying replacement cost profit before interest and tax of $6 billion, made up of $3.6 billion in fuels, $1.3 billion in lubricants and $1.1 billion in petrochemicals. Looking ahead, the level of refinery turnaround activity is expected to be broadly similar in 2012 compared to 2011.

Moving to other business and corporate, we reported a pretax underlying replacement cost charge of $620 million for the fourth quarter, an increase of $140 million versus the charge of a year ago, primarily reflecting high functional costs related to the strengthening of our operations. This was more than offset -- this more than offset an improvement in the foreign exchange effects.

The full year charge of $1.7 billion was in line with our February guidance. In 2012, we expect the underlying quarterly charge for other business and corporate to average around $500 million, although this will remain volatile between individual quarters.

The effective tax rate for the fourth quarter is 30%, bringing the full year rate to 33%. In 2012, we expect the tax rate to be in the range of 34% to 36%.

The increase is driven by changes to the geographical mix of income, together with the anticipated impacts of the disposal program.

Turning to the costs and provisions associated with the Gulf of Mexico oil spill. In the fourth quarter we recognized a $4.1 billion credit, reflecting a reduction in the pretax charge for the incident, bringing the full year total to a reduction of $3.7 billion.

The 4Q credit reflects the settlements with Anadarko and Cameron, partially offset by an increase in the provision for spill response costs plus a charge for the ongoing quarterly expenses of the Gulf Coast Restoration Organization.

Under these settlement agreements, Anadarko paid BP $4 billion in November, which was subsequently paid into the trust fund, and Cameron paid BP $250 million last month, which will be reflected as paid into the $20 billion trust fund in the first quarter. As a result of these accelerated contributions, the $20 billion commitment to the trust fund will have been paid in full by the end of this year.

The total charge taken for the incident at year end was $37.2 billion, reflecting the credits that I just described.

Pretax BP cash outflow relating to oil spill costs for the year was $8.9 billion. As we indicated in previous quarters, we continue to believe that BP was not grossly negligent, and we have taken the charge against income on that basis.

Turning to our divestment program. In October, we raised our divestment target by $15 billion, which now brings the total to $38 billion, as Bob described.

In the fourth quarter, we received $1.6 billion of divestment proceeds from the completed sales of our interests in LukArco, Vietnam, the Wytch Farm field in the U.K. and the Pompano field in the Gulf of Mexico.

These brought the cumulative total of divestment proceeds since the start of 2010 to around $20 billion. At the end of the year, we also had agreements in place covering a further $1.8 billion of divestment proceeds, including the sale of our natural gas liquids business in Canada, bringing the total of completed and announced divestments to date to over $21 billion.

Turning to full year cash flow. This slide compares our sources and uses of cash in 2010 to 2011.

Operating cash flow was $22 billion in 2011, which includes $6.8 billion of Gulf of Mexico oil spill-related expenditures. Divestment proceeds in 2011 were $8.9 billion, and $6.2 billion of disposal deposits brought forward into 2011 as short-term debt had been released or repaid.

We spent $12 billion on inorganic CapEx in 2011, which included the purchase of upstream Brazilian assets from Devon Energy, the joint venture with Reliance Industries in India, our biofuels acquisition in Brazil and the deepening of our natural gas asset base in the United States.

Total cash held on deposit at the end of the year was $14.1 billion. Our year-end net debt increased to $29 billion and our gearing ratio to just above 20%.

In order to retain financial flexibility, we are targeting gearing in the bottom half of our new 10% to 20% range, and this will be achieved over time.

Organic capital expenditure in 2011 was $19.1 billion, in line with our revised October guidance. In 2012, we expect capital expenditures to increase to around $22 billion as we invest to grow in the upstream.

Our DD&A charge was $11.1 billion in 2011 and in 2012, we expect this to be around $1 billion higher due to new higher-margin projects with higher finding and development costs and an increase in decommissioning costs across our portfolio.

We expect underlying production in 2012 to be broadly flat, excluding TNK-BP. Reported production is expected to be lower than 2011 due to divestments which we currently estimate at 120,000 barrels of oil equivalent per day.

The actual outcome will depend on the exact timing of divestments, OPEC quotas and the impact of oil price on production sharing agreements. TNK-BP production is expected to grow by 1% to 2% per annum over the medium term.

So in closing, I would like to provide an update on the medium-term financial framework for the group. We are increasing capital expenditure to grow the firm by investing in our areas of strength, as Bob described.

With the improvements in operating cash flow we have outlined for 2014, we are now confident in committing to a progressive dividend policy going forward and have today announced an increase in the dividend of 14% to $0.08 per ordinary share payable, as I said earlier, in the first quarter. Future increases will be contingent on improved cash flow delivery, balanced by the need to retain financial flexibility and our continuing obligations to the Gulf Coast.

Our commitment to reduce gearing to the lower half of the 10% to 20% range over time is supported by the $15 billion of additional strategic divestments we announced in October. In addition, we aim to maintain a strong liquidity buffer given the current uncertainties and economic outlook.

After meeting these objectives, share buybacks still remain an option as a flexible mechanism to return cash over the longer term once uncertainty is reduced and gearing has reached the lower half of our target band. That concludes my remarks.

Back to Bob.

Thanks, Brian. Now let's take a look at the progress since the oil spill and spend a few minutes on the upcoming legal process in the U.S.

On the Gulf Coast, beaches and water are open and the seafood is as good as ever. 2011 was a great year for tourism.

In many areas of the Gulf Coast, visitors filled more hotel room and spent more money than ever before, and these figures are from a number of state and regional tourism organizations.

Our main effort is now on recovery. Active shoreline cleanup is essentially complete, while patrolling and maintenance operations continue.

To date, we have spent over $14 billion on spill response. We have already committed $1 billion for the early restoration of the natural habitats along the Gulf and in December 2011, state and federal trustees unveiled the first set of early environmental restoration projects.

By year-end 2011, we had paid over $7.8 billion to meet individual and business claims and government payments. And also by the end of 2011, we had paid over $15.1 billion into the trust fund, which is now over 75% funded and this includes the settlements already mentioned by Brian.

Of course, we still have a challenging period ahead of us. The legal processes around the incident are complex and uncertain.

Let me explain what we do know.

As I've said before we're ready to settle, if we can do so on fair and reasonable terms, but we are preparing vigorously for trial. The trial will allocate fault across the parties for the casualty and resulting oil spill.

The judgment is expected to assign percentages of fault among the participants in the well operation and on the rig. The United States Department of Justice is a party plaintiff and will represent its case for liability under the Clean Water Act.

This slide shows a time line for the civil trial. It is called MDL 2179, and MDL stands for multi-district litigation.

Now the future dates shown here are, of course, subject to change. MDL 2179 will start on February 27 and will be tried in 3 phases, each addressing a different part of the incident and its consequences.

The whole process is likely to last into 2013, with breaks between the phases. Judgments can, of course, be appealed, taking us even further beyond this time frame.

Over the coming weeks before the trial, the judge will continue to issue rulings to prepare the case for trial. And as we have stated from the outset, we do not believe BP was grossly negligent.

We have confidence in our case, and we look forward to presenting our evidence when the trial begins.

We believe the evidence will affirm what every official investigation to date has found, that the incident resulted from many causes involving many parties. We can expect considerable media attention to this case in the months ahead.

The early weeks of Phase 1 will be dominated by various plaintiffs, including the Department of Justice presenting evidence to support their claims, followed by Transocean, before BP gets to present its case and its evidence.

However, we prefer that this case not be tried in the media. We believe the appropriate place to do that is in the federal court in New Orleans.

We will make every effort to keep you, our shareholders, informed of the proceedings as appropriate to the legal position.

firstly, the progress we're making in changing the operating model; second, how we are reshaping our portfolio, both divesting and acquiring, and I want to explain what this change is in service of and what is the endpoint we are striving for; third, I want to set out the milestones that demonstrate momentum towards expected operating cash flow growth by 2014; and then fourth, I want to look at beyond the next 3 years to the longer-term investments we're making, to the future we see beyond the next 3 years.

Now the move from a decentralized asset structure to a fully functional organization has been the biggest organizational change we've taken on in the last 20 years. It's hard work, but it's going well.

We now have the functional organization lined up with every dimension of operational delivery and with full line accountability, from our global approach to exploration and appraisal to a global approach to our major projects.

This allows us to optimize activity choices effectively and execute them more reliably and efficiently. For example, we have a single global rig fleet operating to a single set of standards.

Bernard and Bob will provide more insights during their breakout session, and you'll see how we are reinforcing risk management and generating efficiencies from more systematic and standardized design, engineering and procurement practices.

Let's take a look at how we manage the portfolio. I want to be very clear about this.

We have some very simple objectives here. First, we want to own assets where we have a distinctive capability and can therefore achieve advantaged returns.

Second, we aim to achieve a size of the upstream that is small enough to generate growth and operating cash flow and large enough to enable us to take on the energy challenges and needs of returns, of governments and doing it for decades. Third, we intend to deliver the funds to live within our financial framework.

We're planning divestments of up to $30 billion in the upstream over 4 years and have announced $16 billion so far. We've also acquired very promising acreage in the deepwater in Angola and Brazil, entered a growing gas market in India and deepened our unconventional asset base in U.S.

gas and the Canadian oil sands. We have massively strengthened our exploration portfolio for the latter part of the decade.

We've traded smaller, mature assets with declining cash flows for those which can grow, and we've concentrated geographies and assets to focus management attention. And we've increased the group's exposure to the growth markets, where we believe exposure along the value chain maximizes returns.

India is a good example, where our reliance position supports a downstream gas JV and our petrochemicals portfolio overall in Asia.

Total resources, excluding TNK-BP, have grown by around 16% in the last 4 years. That's despite total proved reserves falling by 1 billion barrels of oil equivalent as we divested assets.

The prospect inventory has nearly tripled, clear evidence of the portfolio's increasing potential.

And we're also consciously creating a portfolio that plays to our strength, with a balance between world-class deepwater assets capability and a portfolio of giant oil and gas fields, which are both conventional and unconventional.

This balance diversifies our production, which is now around 50-50 oil and gas, excluding TNK-BP, and also the balance between high-margin, capital-intensive deepwater operations and longer-term, lower-margin but less capital-intensive investments.

This leads me to unconventionals. Although unconventionals have been a part of our portfolio for decades, we have significantly strengthened our position over the past 5 years.

We have been and we will continue to be very targeted about how we deepen in U.S. unconventionals, where we have a bias to liquid-rich gas and also where we can export our technology to other regions of the world.

Mike and Andy will expand on these points during their breakout session.

first, disciplined investment at scale to support growing demand; second, a major step-up in exploration; third, a good balance between short- and longer-term investments; and fourth, enough critical mass to retain the benefits of scale and standardization.

There will be underlying volume growth, but as we've said it is value growth that we are after, which means growing both volume and margin.

first, our base operations; secondly, the new wells drilled in existing operations; and then finally, our 15 major projects in the upstream that will start between 2012 and 2014.

The unit cash margins are expected to improve significantly with the new projects, having around twice a unit operating cash margin of our 2011 portfolio by 2014 at $100 a barrel.

Our new projects are progressing well, all now centrally managed in our Global Projects Organization. And by the end of 2014, we plan to start up these 15 major projects.

That's 6 startups this year, with 9 more in 2013 and '14. The majority of these projects in our higher unit margin cash areas of Angola, the North Sea, the Gulf of Mexico and Azerbaijan and is how we will deliver a unit operating cash margins I just mentioned.

The projects mix is also diverse, with around 2/3 of the projects being oil developments and 1/3 gas, and roughly half of these projects will be operated by BP. Most of the onshore projects in the North Sea and the Gulf of Mexico are subsea tiebacks to existing facilities, which allows us to build on previous investment made in the existing infrastructure.

And Bernard will say more about the execution of these projects in the breakout session.

Now as you know, the Gulf of Mexico remains a very important part of our future, and getting safely back to work was a critical milestone for us. We now have rigs working on exploration and appraisal, major projects and drilling and completion work on our existing fields.

We have 5 deepwater rigs working, with a further 3 planned to start up this year, subject to regulatory approval.

Exploration and appraisal are important to us and also to the future energy security of the U.S. And we're planning to spud the Gila exploration well in 2012 and anticipate ongoing appraisal programs on Kaskida and Tiber.

In major projects, we've reached the final investment decision on Mad Dog Phase 2, our first for an operated standalone facility in nearly a decade in the Gulf of Mexico and a giant field in its own right. We also have Galapagos, Na Kika Phase 3 and Mars B major projects starting up over the next 3 years.

In production drilling, we have resumed drilling and completion activities at Thunder Horse and Atlantis, and we plan to restart the Mad Dog rig operations by the end of 2012. Clearly, there will be a lag between completing the activity and the related production showing up.

Our focus is on value, so looking to 2012, we expect to see growth in operating cash, driven by the unit cash margin improvements already mentioned. And as far as volume is concerned, we expect underlying production to be broadly flat, setting aside TNK-BP.

This is the net effect of growth from new projects, reduced outages and a new production from India offsetting the base decline. We expect production from the Gulf of Mexico to be somewhat lower than 2011, with natural decline progressively offset by new production activity now that we're back to drilling.

We expect Gulf of Mexico production to return to growth in 2013.

We're also planning another extensive turnaround program in 2012, although we expect overall production outages to be lower. Bob will cover the details of this in his breakout session.

We expect reported production in 2012 to be lower than 2011, and the actual outcomes of that will depend on the exact timing of the divestments, also OPEC quotas and the impact of oil price on production sharing agreements.

We expect the divestment impact to be around 120,000 barrels of oil equivalent per day in 2012, with around 70,000 barrels of that coming from divestments which are completed in 2011 and another 50,000 barrels of oil a day equivalent from divestments expected to close in 2012.

We will continue to update you on these divestment impacts as the year progresses and as Brian said earlier, we expect TNK-BP production to grow organically at 1% to 2% in the midterm.

Now in terms of investment, we're expecting to increase our investment in the upstream to around $16 billion to $17 billion this year, up $2 billion to $3 billion on 2011. This is driven by doubling of exploration drilling and the increase in the major projects and the ramp-up of activity in the Gulf of Mexico.

Now let me turn to the horizon beyond 2014. We have a strong pipeline of exploration prospects and project opportunities that will generate new resources and projects well into the next decade.

Near term, we have plans in place to ramp up exploration activity over the next 2 to 3 years. Our experience in managing the subsurface, combined with advances in seismic imaging, is continuing to redefine and grow the size of our giant fields.

This is underpinning major new investments, such as Mad Dog Phase 2 and the giant Clair Ridge projects here in the U.K., to name just a few.

Gas use as a fuel will continue to grow steadily in the global energy mix. We have world-class gas projects that we expect to bring onstream before the end of the decade linked to price-leveraged markets.

And all of this is enabled by a commitment to technology, a theme which I'll return to shortly.

This shows the pipeline of projects in detail. You can see that we have some major projects coming through behind the highlighted projects on the right side.

These projects will start up in the next 3 years, and there's a very strong inventory of material exploration projects shown on the far left.

There's roughly 40 projects there out beyond. These are aligned with our strengths in deepwater, gas value chains and giant fields.

Deepwater will remain a core building block of our portfolio through the end of the decade. And in the gas value chains, we have world-scale projects in Azerbaijan, Tangguh in Indonesia, in Egypt and in Trinidad and we are appraising another in Oman.

In the area of giant fields, we will have significant cash flow coming over decades from our unconventional Canadian heavy oil projects and big unconventional gas fields around the world.

Looking forward, we will be growing our overall capital investment into the upstream, led by doubling our investment in exploration. We will invest for near-term gas generation and create options for longer-term value growth.

And around 2/3 of our investment over 2012 to 2014 will underpin the delivery of the operating cash up to 2014, and we'll do it in a safe and sustainable way. The other 1/3 will go on creating future projects, including exploration.

The investment will be split broadly equally between the deepwater, the gas value chains and the giant fields. And finally, there is no doubt in my mind that our new operating model will improve the execution quality and capital efficiency.

Earlier, I mentioned the importance that technology plays in the world of energy. I'd like to make a departure from our usual format and show you something that we are very committed to and will be important for us in the years to come for safety and safely unlocking new deepwater resources.

Over the last few years, we have had considerable success in exploring deeper plays in some of the established basins, specifically the Paleogene of the Gulf of Mexico, the Tiber and Kaskida fields, the Oligo-Miocene of the Nile Delta, that is the Raven and Satis fields and the pre-Fasila reservoirs of Shah Deniz and the Caspian in Azerbaijan.

Each of these plays has developable oil and gas today, but each also has a material upside that sits beyond the industry's current capability due to the high pressures of the reservoirs. To address this undevelopable resource, today, we are outlining a project to develop a high-pressure capability to drill, develop and produce resources beyond 15,000 pounds per square inch, or 15K psi, and we call it Project 20K.

Let's look at a short video to give you some appreciation of the challenge and the opportunity this project represents.

[Presentation]

You can see the challenge and the valuable opportunity that this will unlock. We have great people working on this and I believe it will not only open some of BP's existing resources, but perhaps a greater prize will be the new resources it will unlock in exploration and development.

We anticipate doing this, both as BP and in partnership with NOCs. Much of the technology will apply on and offshore and therefore be of help in the Middle East, Mediterranean, Russia and the Gulf of Mexico.

Like many advances in industry developments of this type, capability will take some time. We'll keep you posted on progress.

So to sum up, our upstream business is going through significant changes. And while we still have some way to go, we can already see tangible benefits.

Our new operating model is in place, with safety and operational risk embedding in the divisional organization accountable for operational performance. We are standardizing, choosing our activity carefully and improving how we work to get this done.

We continue to sharpen our portfolio, having already announced divestments of around $16 billion of assets in the upstream, with plans in place for up to $30 billion in total. And we've made strategic acquisition in businesses positioned for growth, and we'll continue to do so if good opportunities arise.

We have reloaded our exploration prospect inventory through record licensing. Upstream will contribute significantly to the group's expected 50% increase in operating cash by 2014.

This will be from higher-margin major project startups, come from new wells, as well as efficiency in our base business. And finally, we're increasing investment through the medium term, investing in the areas where we can add the most value by playing to our strengths.

Now let me give you a summary of TNK-BP, which continues with its consistent track record of delivery despite the challenges. TNK-BP offers BP a distinctive position to access Russia's extensive hydrocarbon resources.

It is now Russia's second largest oil producer, with BP net production of almost 1 million barrels of oil per day and nearly 5 billion barrels of oil equivalent in terms of proved reserves, and it is Russia's third largest refiner and now has an established international presence.

The ongoing shareholder dispute has had minimal impact on the operational and financial performance of the joint venture and since its formation in 2003, TNK-BP has delivered 4% organic production growth. In 2011, BP's share of net income was $4.2 billion and dividends received were $3.7 billion.

And since acquiring 50% of TNK-BP for around $8 billion, BP has received around $19 billion in dividends, so historically around $2 billion a year. And at the same time, TNK-BP has been a solid corporate citizen and has paid around $160 billion of taxes, duties and levies since its formation in 2003.

Looking to TNK-BP's future, it has a material opportunity set and we expect organic growth, as Brian said, of 1% to 2% per year in the midterm. And the efforts to manage production declines in brownfields will continue through the focused application of new technologies, such as BP's Bright Water technology, with an upscale treatment program being planned.

And the ramp-up of the Verkhnechonskoye and Uvat fields will underpin growth to 2015, and longer-term growth will come primarily from the developments on the Yamal peninsula, Russkoye, Suzun and Tagul.

In the downstream, TNK-BP will invest and continue to invest for higher fuel quality improvements, refining yield improvements and marketing expansion over the next 3 years.

2011 marked expansion into selective advantaged international opportunities with access in Venezuela and Vietnam. We see the growth potential in the portfolio, and we continue to be pleased with TNK-BP's performance.

And finally, a few comments about our alternative energy business before handing over to Iain to cover the downstream. BP has been in various segments of renewables over the last 35 years to understand and be positioned for the global trend of long wavelength renewables growth we highlighted earlier.

The portfolio is now tightly focused on several specific operating and technology assets. In biofuels our operating assets are focused in Brazil, where we own and operate 3 mills in prime cane locations and plan to continue investing in advantaged land, mills and logistics.

Our biofuels technology assets include our U.S. cellulosic biofuels business and other advanced biofuel developments, notably biobutanol.

And in renewable power, or wind, our operating assets consist of over 1,000 turbines in 13 wholly owned and joint venture U.S. wind farms, which have been developed since 2007.

We have an advantaged land position which underpins our ongoing wind development and construction program. This land position does have analogies to upstream exploration acreage.

And we plan to continue to grow our alternative energy business with an increasing footprint of operating assets, and the business is now positioned for a steadily improving income and operating cash flow contribution.

So with that, let me turn it over to Iain for the downstream.

Thank you, Bob, and good afternoon. It's a pleasure to be talking to you again about Refining and Marketing.

We had an in-depth look at the segment at our Investor Day on the 30th of November and therefore, I'm going to focus today on a few key aspects we covered at that time, talk in more detail about our results for the segment as a whole and remind you where we are on our journey. In the breakout session, we'll provide more detail about our results and strategic progress by value chain business, in line with the increased transparency that we've provided you with today.

fuels, lubricants and petrochemicals. We're delivering returns in each of these business models at or near the top of the competitive range and today, we provided you with further transparency of each of this businesses, including 5 years of history.

In November, I used this slide to outline what our world-class downstream business involves. It all starts with a platform built on safe and reliable operations and leadership in process safety combined with excellent execution.

Next, the portfolio must be of high quality competitively, with assets of the right scale, location and configuration and having leading technology and brands.

In each business, the value chain must be operated and optimized in an integrated way. This all drives competitive cash margin capability which, in turn, leads to differentiated utilization and cash flows.

Growth of the business comes from growth in margin share in established markets and exposure to growth market positions. Finally, all of this must be within a disciplined financial framework, with active portfolio management to ensure a tight focus on quality positions.

So how are we doing? This chart's familiar to you.

It shows the improvement in underlying pretax earnings relative to our history. The dark line shows our historical relationship between refining margins and profits.

Having returned the business to historical performance levels in 2009, the yellow band represents our goal of improving underlying pretax RC profit by a further $2 billion per annum by the end of this year relative to '09. Plotting our profit and refining marker margin on this chart, you can see that in the 2 years of 2010 and '11, it shows we've delivered $1.3 billion of that improvement.

2011 was a particularly heavy turnaround year, and the underlying performance improvement is actually higher when the approximately $200 million of increased turnaround burden in 2011 versus 2009 is taken into account. We therefore remain confident that we're on track to deliver the aggregate $2 billion of performance improvement by the end of 2012.

As of the end of 2011, in total, since 2007, we've now delivered over $6 billion per annum of pretax underlying improvement. Let me now turn briefly to competitive performance.

You're also familiar with these charts. They show BP's estimates of our competitive performance versus the R&M segments of the other super majors, adjusted to be on a comparable basis, using the same methodology we've used for the last 5 years.

In terms of post-tax ROACE, BP has achieved another goal with returns approaching 10% in 2011, the best since 2006, when refining margins were nearly 40% higher at $16 a barrel. BP's now moved from being the worst performing company in the sector from 2004 until 2008 to being one of the better performers on this measure.

On the right, you can see underlying net income per barrel of refining capacity. This is a measure of relative portfolio quality and while there, of course, is a mixed effect, most of our competitors also do have large lubricants businesses and some petrochemicals.

The fourth quarter was a very challenging time for the fuels business in our sector. Despite lower refining margins, including the collapse of Gulf Coast and Midwest margins in particular, and the narrowing of the WTI/Brent differential, our fuels businesses remain profitable in 4Q.

Overall, I'm pleased with our competitive performance, which, once again, is beginning to demonstrate the relative quality and resilience of our portfolio. Brian outlined our 4Q performance earlier, and let me just provide you with some further commentary on how R&M's individual businesses fared for the full year of 2011.

Here you see an updated version of the chart that I showed in November. On the left, you see the performance history of the individual businesses updated with 2011's actual results.

In 2011, R&M's underlying pretax RCP was $6 billion, a record year for the segment and above 2004 levels despite lower refining margins. Under the graph, you'll also see for the first time the 2011 pretax average operating capital employed, including goodwill -- that's a mouthful -- split out by business model.

This shows the total capital employed on this measure of $56 billion, giving pretax returns relative to this measure of 11% overall for the year. As you can see, the fuels business carries 80% of this capital employed.

This is significantly driven by the oil price effect on working capital. On the right, you see the business environment index back to 2004.

The fuels business delivered $3.6 billion of underlying pretax RCP compared to $2.2 billion in 2010, an increase of 62%. Refining margins were $1.60 per barrel higher.

Solomon refining availability were similar to 2010 at 95%. Marketing volumes were down 4% year-on-year due to demand effects, and marketing margins were also lower.

Although we did see improved refining margins and improvement in the WTI/Brent spread, there were many offsetting challenges such as the higher price for sweet crude globally. Our oil trading and supply activities returned to a more typical level of contribution after a poor 2010.

Overall, 2011 was a good year for the fuels business, with material year-on-year momentum.

In terms of strategic progress, the Whiting project remains on track for coming onstream in the second half of 2013 and today, we announced the intention to sell our LPG marketing businesses serving the bulk and bottle markets in 9 countries. This continues our journey to focus down on our logical core set of positions in which we believe BP to be the natural earner.

We'll provide more detail of this in the breakout session.

Turning to lubricants, underlying pretax RCP was $1.2 billion, down 11% year-on-year and in line with 2009 levels. Volumes were also down by 4%.

Base oil prices, you can see on the right, rose by over 30% during the year, contributing material pricing pressure and providing a very challenging environment when combined with the general slowdown in economic activity. Against this backdrop, our brands and the business performed well.

In petrochemicals, underlying pretax RCP was $1.1 billion, down 9% year-on-year. Margins were up 5% from 2010 although ended the year at very low levels, having started the year benefiting from particular strength in paraxylene.

Production was down 6% year-on-year as a result of operational issues, including a direct strike by a tornado at our Decatur, Alabama facility.

So now I'd like to turn to earnings and operating cash flow momentum. We showed the picture on the left in October.

I've simply updated it for 2011 actuals. It shows our pretax earnings growth relative to a 2007 baseline in a constant 2009 refining margin environment.

Having materially improved our earnings position since 2007, we continue to have confidence in the pretax earnings growth of the portfolio through to the end of this year and out to 2014. This earnings momentum comes from sustaining returns from the base, improving cash margin capability, including the impact of the Whiting modernization project coming onstream, and through extending our positions in growth markets.

This earnings momentum at a constant environment is the major driver of our operating cash flow growth between 2011 and '14 as we contribute to the group goal.

On top of earnings, which flow through to operating cash flow growth, we are constantly looking for ways to improve the efficiency of working capital use in the business, particularly in fuels. In terms of actual pretax returns, as you can see from the red line, we nearly doubled them from 2008 to '11, and we expect them to continue to expand through earnings growth, portfolio simplification, including the ongoing U.S.

divestments and the proposed LPG sale announced today, and through active improvement of capital and working capital efficiency. R&M remains a material contribution -- material contributor to the group's cash flows today and to the forward growth in operating cash flow into the future.

So let me summarize. BP has a highly competitive downstream portfolio which is becoming truly world-class.

Success is defined by safety performance, excellent execution, intense focus on the quality of the portfolio and through exposure to growth. The 2011 underlying pretax RCP of $6 billion is an all-time record for BP and has been achieved in far from the best market conditions.

R&M remains on track for delivery of $2 billion of improvements in pretax underlying performance by the end of 2012 relative to '09 and represents a material contribution to the growth in operating cash flow for the group by 2014, notably through the Whiting project coming onstream in the second half of 2013.

As Brian outlined earlier, we continue to invest with discipline. 2012 organic capital expenditure is expected to be about $4.5 billion, slightly higher than in 2011 as the activity levels in the field of Whiting ramp up.

We continue to be active in the management of our portfolio, and we'll provide more detail on our portfolio activities in the breakout.

Finally, we've provided you with further transparency on the performance of the fuels, lubricants and petrochemicals businesses so you can get a better feel for our performance and momentum. For each of the businesses, you'll be able to track and measure our progress through our profits, operating returns on either capital or sales and through key operating metrics.

In summary, 2011 represented a good year for R&M, and I'm particularly proud of the team which delivered it.

Let me now hand you back to Bob.

Thank you, Iain. Let me just conclude by summarizing this first part of today's presentation.

So looking out to 2014, you can expect to see the delivery of many milestones. These include downstream earnings momentum reaching $2 billion of improvement this year versus 2009; upstream performance improving as we return to work in the Gulf of Mexico and the margin mix of our portfolio improves; the Gulf of Mexico liability is being clarified; trust fund payments ending this year and the Whiting Refinery upgrade coming onstream in 2013; and the startup of 15 new upstream projects over 2012 to 2014.

The 10-point plan will continue to provide the background, backbone of our program for value creation of what you can expect and what you can measure. And as the months go by, we will be able to show you how we are progressing against these expectations and indicators of performance.

BP is moving forward. The year of consolidation is now behind us.

Safety and risk management are our continuing priority. 2012 will be a year of milestones, with financial momentum building in 2013 and '14.

And we expect around 50% improvement in operating cash flow by 2014 compared with 2011. Long run, we'll be increasing investment to grow the firm, but we'll also continue to actively manage the portfolio to add value.

Gearing is targeted to reduce to the bottom half of the 10% to 20% range over time. And our attention is to grow distributions over time in line with the improving circumstances of the firm.

45 London Time for the Q&A session. And in the meantime, you will find the breakout materials available on the website.

Now for those of you here in the room, I'll now hand over to our Head of Investor Relations, Jess Mitchell, to explain the arrangements for the breakouts. Thank you.

So hello, and welcome back to the wrap-up and Q&A session. My voice is back a little bit.

Here in London on the stage we have Brian Gilvary and Iain Conn, we introduced earlier as part of the earlier preliminary session; and the executive vice presidents of our Upstream businesses who just presented 2 of the breakouts. Mike Daly is at Exploration; and Bernard Looney, Developments; and Bob Fryar, Production; and Andy Hopwood has overall responsibility for Upstream Strategy and Integration.

And also in the front row with us we have Byron Grote, who is our Executive Vice President of corporate business activities, as you all know. Dev Sanyal, BP's new group Chief of Staff; Fergus MacLeod, group head of Strategic Planning; and Jess Mitchell, who you met earlier, head of IR.

You will now have an opportunity to put your questions to all of us. We are webcasting this final section of the presentation today.

And for those joining us for the first time on the web and telephones who did not see our previous message, here is our usual cautionary statement. Please read it quickly and thoroughly.

Once again, I refer you to the remarks I made earlier, which are now posted on the website. So with that, we'd be very happy to take your questions and direct them at any one of us.

Let me start in the deep end. I'll move this direction first, deep end first.

I want to discuss sort of the financial framework actually. Big oil investors increasing, you're thinking of cash generation, particularly post CapEx.

Three things I'd like to talk about. One, just short-term capital investment for 2012.

Can you talk about what type of increasing CapEx there is for, sort of, integrity increased safety? Secondly, I think from the discussions today, clearly, you've got many choices to make, particularly around your portfolio, the balance between Deepwater and, I think what was referred to as long-term investments are unconventional.

Could you talk about the shape of investments going forward between Deepwater and unconventional?

And then lastly, I guess, on the payout, you're generating more cash. I was wanting to know how one should think of payout going forward?

Should you look at payout ratios relative to earnings, gearing or in a cash generation? One could argue today with your gearing levels slightly above the targeted range, the potential for a settlement and perhaps an increase in the dividend could wait.

So I know lots of questions there, but it would be great if I could have some answers.

Right, that is a lot of questions. First on CapEx and the amounts that we're spending on S&OR.

Right now, we are embedding what we do in all our projects normally. We're not separating out, I would say, integrity spending.

This year we had 47 turnarounds. We'll have 37 planned for 2012.

Some of those may be turnarounds that we wouldn't have done in the past, but there are undoubtedly things that will keep our assets operating longer and more reliably. I am going to, as we go through these questions, throw pieces of this to the management team and Bernard.

And, Bob, if you want to comment quickly on the additional spending, specifically related to S&OR and how you'd look at that.

Yes. I would just -- so with respect to integrity, we invest in really 2 areas.

We've talked about -- talked about the turnarounds. Secondly, we invested in maintenance, which helps us in our integrity efforts.

Turnarounds, I'd say, the spending's going to be pretty much on a pro rata basis. We're 47 last year, 37, so we'll see a bit of decline there.

On maintenance, we'll step it up a bit because one of the things we are working to do is to make sure that our assets are safe and they're reliable, and so that does mean increased investment in maintenance overall. But I think year-to-year between the turnarounds and maintenance programs, I would say from 2011 to 2012 it would be flat.

And I would add to it, Bob, we do roughly have an estimated $400 million for integrity's CapEx in 2012, and that would be across the entire company. Well, the number is -- yes, for upstream, $400 million, that's right.

Now the Deepwater long-term make-up of the investments going forward, I'm going to ask Andy to comment on this because he is working with strategy. He can give you a good summary.

Easy answer. So we've said about 1/3 of our medium term investment is going to be into Deepwater.

The other 2/3 is about 1/3 into gas value change and 1/3 into Deepwater. The other aspect of the investment is about 60% of it is really focused on delivering 2014 and the remainder beyond.

I mean clearly, the percentage of unconventionals will grow as the resources get developed and we bring on, particularly the Canadian resources. But of course, it's less capital intensive, so it's pretty hard to break it up.

On our approach to how we think about dividends going forward and distributions, I'm going to ask Brian to comment on some of the ratios that we'll use going forward.

Yes, the key metrics we use in [indiscernible] gearing, which is what's being cleared up putting a target up. The key is to make sure that we strengthen the balance sheet over the next 2 to 3 years.

And the destination point we'll give in 2014 is within the bottom half of the new lower band. Remember the old band was 20% to 30%.

Of course, Macondo, we moved that from 10% to 20%. It's sitting just above 20% now, and the trajectory down that low half will be a bit lumpy as quarter-by-quarter.

But we're confident now in terms of the operating cash flows that are coming through in 2014 in terms of what we promised around 50% of additional cash. And the disposal proceeds packages will see net debt be driven down and the gearing coming into that range.

Now before we take a question, we've had some very, very patient people who have been very silent on the webcast, and we have got a set of people of who have asked questions. So I'd like to ask Doug Terreson if you can hear me, and if you can go ahead to ask your question and then we'll turn to Irene.

And on these points, Bob, you highlighted earlier today progress on safety and trust and value growth, which I think represent important areas of emphasis for BP going forward. So my question regards the cultural or transformative effect that these efforts may be having on the company, and specifically how you envision them translating into greater competitive advantage for BP.

The competitive advantage. I think that safety is good business.

What we're doing -- and I'll ask Bernard to comment on some of this. Safety is good business.

What we're doing in terms of putting in place our voluntary standards and the things that we're doing to change how we approach drilling and working with contractors is certainly going to change BP going forward as we work in the offshore around the world. I think it's good business.

I think it will move the dial on the industry. It's the right thing to do.

And, Bern, you can make some comments on some of the things we're doing in this area.

Yes, thank you, Bob. We talked earlier, Doug, today about, in some of the breakouts about this.

And I think this point about safety being good business is just something that we continually harp on. And I think we think about it in 2 ways.

I think first of all, investment in safety and having that being the priority is about the prevention of a major accident, such as the Deepwater Horizon. That's something that none of our shareholders want, none of us want to ensure ever happens again.

So that's a good reason to invest. But I think as importantly, it is this issue that a safe business is an efficient business is a reliable business.

An example where we're investing a lot of time today is around the reliability of our blowout preventers and those that operate on our rigs. And we're doing that because we want to make that system safer and to make it more reliable.

But the upshot of having a safer and more reliable blowout preventer is a more efficient well operation. So I think this concept that actually investing in safety, and it is investment either through capability, the systems that we have or the plant that we have is not alone is it right in terms of safety, it's right in terms of our business.

And I think as we do this, we see more and more of this and this is what Bob is leading and we as a team believe in.

Now let me turn to Irene, and then I will go back to the web because there's a fair number of questions. So, Irene?

Irene Himona, Societe Generale. I have 2 questions, please.

So first of all, Bob, you give us guidance or a target for cash flow growth to 2014, but you only provide an indication of CapEx for 2012. In an environment of $100 flat, what cumulative capital expenditure should we anticipate to deliver the 50% cash flow growth?

My second question concerns the new project start-ups, which you mentioned have doubled the cash margin of the existing portfolio. And as you said, this is because of higher funding and development costs and higher depreciation charges.

I guess my question is when we look at profit margins, i.e. earnings in an environment of $100, should we also anticipate an improvement in P&L margins and indeed in return on capital employed?

Okay, there's a number of things here. First on the CapEx levels.

We haven't given specific guidance, but I would not see CapEx rising between $22 billion today for the year 2012 -- somewhere between $24 billion and $25 billion is a likely number for 2014. So you can work out the cumulative numbers in there.

Angola, Azerbaijan, the Gulf of Mexico and the North Sea. And you want to comment further on the increased margin from those projects, Bernard?

Well, I think there is -- some of these projects do carry high DD&A, that's why they do carry higher cash margins. I think earnings may not grow quite as fast as the cash, but I think we will see underlying improvement in both.

And our focus today, Irene, is on ensuring that these projects come online, that they operate reliably and efficiency, and that's the focus of the organization, the 15 of those. And I think as Bob said, you'll see the 50% in cash, and you'll also see underlying earnings improvement through that.

And in terms of the return on average capital employee that we'll see going forward, of course it depends on the oil prices. We laid down this target of $100 in 2014.

All of this will depend on how the downstream evolves. We've had a 10% return in our downstream this year.

It will depend partly on the environment going forward. And our upstream projects will continue to increase their returns on the business.

I know that we said it externally, but this year our return on average capital employed in the upstream has been roughly 20%, and we would expect to see those kind of returns in this pricing environment as well in 2014. Let me turn to the web.

Sorry, I've been distracted with a couple of technical messages here. Mark Gilman from Benchmark.

Just 2 questions, if I could, please. On Iraq, there's been some question as to whether the -- that government is current in terms of payments and entitlements to you, vis-à-vis both cost recovery as well as service fees.

Could you comment on where things stand for you there, and whether Iraq is making positive, negative, neutral contribution to earnings and cash flow at this point?

My second question relates to the Eagle Ford. It appears that over the past, I guess, 24 months, you have amassed a considerably larger position in that trend.

I wonder if you could just be a little bit more specific in terms of where and what it cost you to get into that position?

Okay. Couple of things on Iraq.

You'll know that it was about a year ago, a little over a year ago, we reached the production target, the initial production targets which began the cost recovery cycle for us. And so we have been steadily and have recovered our additional investment through recoveries of crude cargoes.

We're current. We're up to date.

There's always a little bit of a lag as we spend CapEx there, but we've been very pleased at the pace of the developments in Iraq. The field now, the Rumaila field is producing about 1.45 billion barrels a day.

So it is positive for us.

On the Eagle Ford, I'll ask Bob and Andy to comment, but you are right. We have been shifting our focus very quietly, without fanfare, to the liquids rich areas of unconventional gas.

And we have a sizable position in the Eagle Ford, some of which is very rich in liquids. Andy?

Yes, you're right, Mark. As we've migrated the portfolio both in the divestment and investment sets, we've got a position now with about 6 tcf of resources in the Eagle Ford spread over about 450,000 acres.

We have -- we don't divulge the specific deals that we've done down there, but what we do have is a working relationship with Lewis Energy, whereby they operate the field and we work in terms of identifying the soft surface. And as you said, Mark, it's going very well.

So I'll keep over here Jon, Jon Rigby. And then I'll move over here.

Bob, you talked earlier on about how you saw, sort of, an optimal level of production around, I think, 2.5 million barrels a day x the TNK-BP portion of the business.

2.3 million.

2.3 million, sorry, excuse me. Already giving you some growth.

Does that seem to imply or would that imply that over the medium and longer terms of 2014 as you stabilize the business, that you would expect BP to grow at a slightly -- underlying the slightly faster pace than maybe what your aspiration was 3 or 4 years ago? And then would that mean also that your business model changes a bit in that you recycle cash back through the business and look to be buying back stocks structurally, so adding value to shareholders by churning your portfolio more aggressively and probably being a structural buyer of stock as well?

Well, we've been very careful not to set production targets. We want to get off that treadmill.

We do want to create value. So while we have described a portfolio that gets down to around 2.3 million barrels a day x TNK-BP, which will give us enough cash to be able to invest in projects return to shareholders.

If we don't continue divesting beyond the target, what you would expect is to see growth, and not to give you a target for that, but you would expect to see growth. It doesn't mean, though, that we won't, and I believe we will, continue to focus divestments of mature assets to be able to replace them in the growing assets.

So I think you'll see the portfolio movements, which may or may not lead to the growth. In terms of recycling cash flow, that is what we want to signal, is that we'll generate sufficient cash, operating cash flow.

We'll have choices of what to do with the operating cash flow. It could be dividends.

It could be continuing to pay down debt at further levels. It could be some acquisitions, although we're not on the acquisition hunt, particularly, or it could be buybacks.

Right now is not the time for us to go be out buying back stock, but we'll continue to debate with our shareholders. Our shareholders have a big mix of opinion on whether it should be dividends or buybacks or mix.

It's quite extraordinary.

Does that mean that conceptually, the life cycle of an E&P asset within BP needn't necessarily be from being awarded and licensed right away through to plateau production? You could be adding value before you even get to plateau production and moving on in terms of the assets that you're holding.

That's exactly right. And what you will see us do from time to time is if we have of a big position in exploration in a project for development, you'll see us sell it down to be able to recycle and reduce -- selling things down that traditionally, we might not have done earlier.

It could be all or it could be parts. So all of those things are on the table, but I think it's a good way to describe it.

The mindset that we, at the industry, may have had for a while, I believe is changing, and we're certainly changing within BP. Before my voice is lost, may I ask Lucy, Lucy Haskins is here from Barclays.

And just a follow-on on the dividend. What was the kind of changes in the company circumstances that did make you feel comfortable about lifting?

And why 14%?

14% is a very precise calculation of going from $0.07 a share to $0.08 a share for the quarter. And we felt like the improving circumstances that the firm would allow us to do that, the operational momentum that turned in October, getting our assets back running and the cash flow from that allowed the board to make the decision that this was the right thing to do.

We've had investors who stayed with us through really tough times in the past, and it's time to start rewarding them. And I -- well, I think I'll just leave it at that.

[Question Inaudible]

I mean, people have different ways of defining progressive dividend policy. We would define it as a progressive dividend policy that our intention is to, with the improving circumstances, move up a dividend in line with underlying earnings.

And that there are a lot of factors in it and future decisions in oil price. There are a number of things, and we'll come to that later in the year, next year before we make a decision.

Progressive can also mean don't lower the dividend. And so the pace and trajectory of dividend increases is not something we're saying today.

But I think a progressive dividend policy in line with the improving circumstances of the firm is probably the best way we can describe it.

Yes, Lucy, I think it's just premature to be talking beyond this quarter. We saw the operational turning point that Bob described in October.

We've seen settlements with some of our partners. So the circumstance that the firm have improved, it would signal that we now have the confidence around the cash flow targets that we can signal a $0.01 dividend increase today.

Beyond that, I think it will be premature to talk about what the future may look like.

I wanted to ask about the exploration program scenario that it was maybe the key core competency for BP historically. Clearly, you've been through a period of abnormally low activity.

And my question would be with the resized portfolio, what would you view as an optimal exploration program either in terms of number of wells or really preferably the amount resource you're exposing yourself to? And given that we've been through a period of abnormally low activity, would you expect a ramping activity from that optimal level for the next couple of years?

And then maybe what that would mean for overall spending on exploration?

Great. Well, I mean, I agree with you.

I think we have, through this last decade, been underinvested, perhaps I would say that. Optimal size, the size we're going to is to try and get to a sort of situation where we have the order of 20 real oil exploration tests a year.

Now last year, we managed 6. And this year we're heading for 12.

Of the 12, only 5 of them are operated, so there's some uncertainty in that, out of our control to a degree. But we have a portfolio that will sustain the order of -- I think, in the notes previously we said 15 to 25.

Clearly, the middle number is 20.

How do we judge? That's one metric.

I mean, the other is the scale of BP, even the shrunken BP, the slightly smaller BP that we have today, exploration has not been the sole renewal mechanism for a long time. And that we'll continue.

So we're not going to be producing -- finding 1.3 billion 1.4 billion barrels of oil equivalent a year. But half that, coming from exploration, seems to me to be a good, sort of, aspiration.

How long it will take us to get us back to that sort of level is going to take some time.

Well, I'm just going to add to that. I'm not sure people recognize the quality of the set of licenses that have been acquired in the last year.

About 55 licenses in 9 countries, whether it's Angola, Namibia, Australia, Azerbaijan, Trinidad, North Sea Gulf of Mexico, the list goes on. This has really loaded the exploration pipeline of prospects now.

And Mike and his team now have an enormous amount of work in the next few years. And I'm very enthusiastic about the potential of it.

I can't help smiling. My colleague at the end of the table, that Bernard, who's going to be drilling all those wells.

We have reloaded the portfolio and it will -- the consequences of that will flow through. But equally, we will continue to access things.

I mean, I think in the past, we've got to a good portfolio and then we stopped. And that is -- clearly, once you stop, it's very difficult to get back.

And this is something that, I think, we've learned the hard way.

I think it's fair to say we have not lost exploration talent in the company.

Oh, absolutely not.

We'll be able to deal with them.

The young talent in the company is much better than the old talent, believe me.

It's Iain Reid from Jefferies. Bob, can I ask you a question about Macondo and any potential settlement?

You said, obviously, BP has said since the outset that they don't think they're grossly negligent. So can we assume that whatever settlement you agree with the Department of Justice, you can't go $1 over 1,100 per barrel in order to reach that?

Or is there some way of potentially, kind of, folding out in with something else, which raises the number which kind of doesn't imply that? Or is that too much to ask?

Well, it is. I understand your question.

It really is too much to ask because you said when we settle. I think there's a whole lot of variables here.

We don't believe we're grossly negligent. We would like to settle a very -- a variety of things, if it's fair and reasonable.

But at the moment, we're really working hard vigorously for the trial ahead. So it's really hard to answer your specific question.

We can assume though you wouldn't settle if it was any sign of gross negligence in that settlement number?

We firmly believe we were -- are not grossly negligent. And I think there are a lot of variables around what you would determine numbers on in terms of fines and penalties.

It's really not appropriate for me to talk about it. It's not the right thing.

Let's go. This gentleman right here before, then we'll go way over there and then back to Jason.

I've got 2 short questions. It's Martijn Rats from Morgan Stanley.

First of all, I noticed -- I might get this wrong, but on a number of occasions, you talked about production x TNK-BP. And it seems a bit more emphasis on parameters x TNK-BP.

I was just wondering whether underlying, there is a slightly different view in how you see your relationship with TNK-BP, or you've just become the receiver of the dividend, or is there still a more operational role to play?

And the second question that I had still relates to the CapEx question that Irene was talking about. Obviously, there has to be a balance or there is a long-term relationship between spending on exploration and spending on development, and obviously all of CapEx is going up.

But you're talking about a much more aggressive growth in the exploration spending. Aren't we then -- are we talking about eventually a similar level of growth in developments spending, because ultimately, the 2 have to be linked?

If you're spending a lot of more in exploration, will we see continuing strong growth into the next decade?

So a couple of things on TNK-BP. One of the things that we promised in this 10-point plan was more transparency on value.

So we've laid that out with lubricants. We've laid that out with petrochemicals.

And what we have found to our investors is when you talk about the upstream and combine our Upstream business with TNK-BP, which has 3 refineries, and we roll it all up, it has sometimes not helped investors understand the business. So it's -- you shouldn't read anything into it other than that.

We're just separating it out for transparency, and that includes reserve replacement, production, all that. We just want to make it very clear to you.

I think it will make it easier, but there's no hidden message in there that somehow that we're going to separate this out or have any intention to do so.

CapEx on exploration. It is our intention -- what's not built into our plan is exploration success, specifically, but I think we will have some.

And then we will have great choices to make. And at that point, we will make choices of do we spend money on these developments?

Do we sell down other things? Do we sell down some of the exploration's success?

And so it is our intention to maintain a capital discipline that makes sure that we have enough operating cash flow and free cash flow for our shareholders for distributions. So if we were in the old model that John described where you explore and you carry and you will develop everything, what you describe is probably true, but that's not our intention.

Let's see, right back there.

Paul Spedding from HSBC. It's a sort of 2 questions on the Paleogene.

I think many of us regarded that as a potential source of the next generation of U.S. deepwater growth.

And I'm interested to see that you are at last getting back there. I'm intrigued to see for you to comment on what sort of level of drilling activity you were to see in the Paleogene in terms of wells per year.

The second thing I'd be interested in is that, I think our perception in the city is that it is not a high recovery reservoirs in that play. And you talked about how technology can boost recovery in some of your other reservoirs.

I wonder if there are any technologies that are on the horizon that could help boost recovery from Paleogene-style reservoirs?

Okay, very good question. Mike, talk about the drilling levels.

So as I think you heard in the breakout, we will be restarting during the -- we've restarted with Kaskida, so that's a Kaskida appraisal well. The remainder of the year, we hope to start Gila.

And -- all right, we will start Gila and Tiber. Tiber appraisal and Gila exploration.

Once we have the 8 rigs that Bernard is got coming up and running, then 2 of those will be dedicated to E&A, and we expect to be able to continue to drill out our exploration inventory 1 or 2 wells a year. And that will depend partly on expiry dates of the portfolio and partly on the amount of success that we -- the pace we put forward into appraisal.

I think that whole thing comes back to your point about the amount of capital we wish to expose to. So there's a choice ahead of us about exactly that.

As for the lower recovery rates, we have got very large oil in place here. And there are 2 issues, the usual 2 issues.

Some of the oil is a little viscous, and so we have to figure out how we're going to deal with that. And at places, some of the rocks are a bit tight and other places it's not.

So in the long term, frac-ing that stuff may be an option that we explore.

But it's -- I think the lure of it is the very large oil in place. And even if with the recovery factors in the teams or lower 20s, you're still talking of very large resources.

But your point about technology is absolutely spot on. You heard the first phase of that today with the 20K project.

And that seismic imaging always allowed us to find more within the fields.

Absolutely. I mean, our ability to see through 4 kilometers of salt is remarkable.

And it continues to get better and the frequency of our seismic continues to get better. So those barrels will move over time, absolutely.

And I just recommend you to talk to a couple of the guys who have joined us here, Kevin Connolly and his team. I mean, they are on to this and they're very interesting people to talk to.

Jason?

It's Jason Kenney from Santander. So 2 questions, if I may.

On the exploration side, do you think there are any particular holes that you would like to chase, maybe East Africa or exploration in Brazil perhaps?

And then secondly, we spoke about this earlier, Mike, briefly in the breakout session. I'm interested if there's any wider views from the management team, is how BP looks to recapture or capture the NAV gap.

It's obviously been lost over the last few years, particularly given the material progress you're making in FIDs, expansion of projects. Sometimes in the city, I don't think it's as clear as a new discovery when you double the reserves in an existing development.

And I wanted to know how you can really emphasize that to some investors to show the value that has been added through that process.

We clearly aren't in everything. And some of it --it's a bit of the same answer about quality through choice, that there are 1 or 2 things perhaps that you would look at and think, "Yes, we should try and respond to that."

And there are other things that actually, we're quite happy not to be in. And it's always -- the very nature of the game of exploration is always going to be that someone finds something that you don't and then people say, "Oh well, you're not here, you're not there."

We are in a lot of places. And I think we're pretty happy with the portfolio we've got now.

But we're not totally happy with it, and there will be -- we will continue to change it. So this is sort of not answering your question, but answering your question, Jason.

Recapturing NAV. I mean, the response we gave to Jason [ph] in the session was that by being more transparent and talking about the giant field appraisal programs that we've got, we've sort of exposed a whole bunch of value that people haven't really seen before, appreciated the growth in Mad Dog, the growth in Clair and the growth, potentially, in east and other fields that we haven't talked about today.

And so that's a sort of -- recognition of that is a growth enough. That was our answer.

I think that is the right answer. And some of the things we do in terms of reimaging along the way with fields that allows the size of these fields to grow fault blocks that we didn't see before, couldn't reach has just been the history of our industry.

You'll see, we keep adding reserves. We've had a reserve replacement ratio this past year without a whole lot of additional work that we normally would be doing in the Gulf of Mexico.

Traditionally, you are right. We haven't been particularly transparent on the increase in reserves as a result of, say, seismic imaging or reservoir modeling work.

Sometimes we have partners. It's just not been our habit.

And maybe to take your point, we can be a little bit more transparent about it. I know that this year, Jess's team will have some upstream in Investor Day.

We haven't set a date for it yet. But maybe we can take some of that on and be more transparent about that, both the track record and the things we think are possible, not to put you on the spot, Jess.

Peter Hutton, RBC. In the interest of transparency, can I talk a little bit about India?

It's a year since you announced it's 7 billion. It's been approved.

7 billion is not much shorter to the 8 billion that was the original investment in TNK-BP, but we saw a lot more after that. What matrix, what information can you, will you be providing that allow investors to, sort of, chart the progress and the operating momentum in that side of a key strategic investment?

So we look at India as one of the countries that has one of the fastest-growing thirsts for energy. Energy in India would grow at 6% a year, and it is woefully short of natural gas.

So the current pricing in India is about $4 in McF. Believe it or not, spot cargoes are being imported into India.

As of yesterday, it's $17 in McF. So we see this being a real land of opportunity.

So the Reliance deal took on 22 large blocks of the east coast of India where there's exploration prospects. We knew we were moving into the D6 field that was on rapid decline.

Always knew that was the case. But around it, there are a lot of satellites.

So we've been working and have made proposals to the government on the development of satellites. Just this last week, a proposal, I believe, has been made by the Indian government itself to increase the gas prices, $7 in McF in 2014.

We've also set up a 50-50 joint venture for gas marketing. And that would include bringing gas into India, as well as marketing gas inside the country.

Now we'll have to think about how we describe all those different pieces going forward.

But this was never going to be an investment. It was going to be for tomorrow right away.

This is going to be one that's longer term. And given the growth of energy demand in India, very few companies are going to be able to have that sort of acreage position with that kind of potential going forward.

And we'll report on it as best we can quarter -- I don't think quarter-by-quarter is the right thing. We remain very enthusiastic about both the relationship with Reliance and the prospects.

Lucas Hermann, Deutsche. I just wanted to ask you a little bit about the Gulf of Mexico production.

I mean, it strikes me that one thing, one area more than any other is going to be key to your achieving a 2014 target, and it's simply the restoration of production in the Gulf. So 3 aspects, I guess.

The first is the progress that you've made of late, is that in line with the expectations you have? How much P&A work is there for you to do short term that prevents the development and build of barrels in the near-term?

And what level of production do you actually need to achieve in your $100 environment in 2014 as an annual average to broadly deliver the targets you're achieving relative to -- where is production today, Bob, as an average? 200?

In the Gulf of Mexico?

Yes.

It's above that. And we haven't been, for a lot of reasons, disclosed, sort of, every place that we operate with the individual productions.

There are a couple of things. I think -- and I'll ask Bernard to comment on the well work that's going on, because we're not just digging wells now.

I think it's important to remember when we met at the third quarter results, it was not clear when or if we were going to get back to work in the Gulf of Mexico. The third quarter, it was very clear that we had been working with voluntary standards, and we were going to get permits back.

And we said we expected by the end of the year to have 5 permits running. And much of the early activity was catching up with plug and abandonment activities.

So here we are in February. We've got 5 rigs running.

We've got a lot of that work out of the way. 2 of the 5 rigs are working on P&A.

But we've come a long way, and we shouldn't take for granted the progress that's been made with regulator and our, sort of, care and diligence here. We are now down, about 1/3 of the way down through the appraisal well on Kaskida, which is a deep, deep, important appraisal well for us.

So a lot of progress. And before, Bernard talked about what the rigs are actually doing today and the prospects for 2012.

The Gulf of Mexico field generally decline relatively quickly. You have to keep going, and we and the entire industry, entire industry, with the drilling moratorium there, set us back in well work, so that decline is there.

We're arresting the decline in 2012, came back to work and then in 2013, we'll see growth again. And I don't see us going below 200,000 barrels a day in 2012 before we start back on the growth.

The question was what do you need to produce in 2014 to achieve that target? Where are your -- what is does plan say you need to be at, Bob, to achieve the kind of cash flow you need, because that is the single component that makes the difference.

Well, let me come back. Let's talk about what the rigs are doing.

We'll come back to that.

So, Lucas, the opportunity in the Gulf of Mexico is -- we're opportunity rich. And as you know, we're exploring, we're appraising.

We've got rigs doing projects work for projects that will come online in a couple of years. We've got wells doing immediate production work, and we've got rigs doing P&A work.

So as a breakdown today, we have 5 rigs operating in the Gulf of Mexico. Two of them are operating on P&A activity.

One of them, as Bob said, is drilling at Kaskida. One is just completing a production well, which we bought online in March or April, and one is drilling a water injector at Thunder -- or Atlantis.

And water injection is just the same as oil; it just comes a little bit later. In terms of the 8 rigs, going forward, we will shift that activity set throughout the year.

As Mike said, by the end of the year, we'll have -- 2 of those rigs will be working on exploration and appraisal activity, good for the future. We'll have 2 rigs operating on Thunder Horse.

We'll have 2 rigs operating on Atlantis. We'll have a rig focused on Na Kika, which is near-term production, as well as longer-term project work, and we'll be restarting a rig on Mad Dog.

So you'll see the level of activity on P&As not necessarily disappear, but certainly reduce dramatically over time. And you'll see that then being translated into full year effects in 2013 and 2014 when we get the real benefit of full year effects of having the rigs doing what we want them to do.

And I think one thing is really important to add to this, Lucas: to say that the Gulf of Mexico is the one thing for us. We're very confident we're going to move the dial and get back going there.

But it's part of a big portfolio. And what we do in Angola and the North Sea, I would say in terms of generation of operating cash flow is just as important to us as the Gulf of Mexico.

And I think -- and so -- and we've got lots of good prospects in terms of production growth in Angola and North Sea also. Sorry, I'm losing my voice.

But those are -- 65% of our operating cash flow in the upstream comes from 4 places: Gulf of Mexico, Angola, North Sea, Azerbaijan. And so we're very confident at this point, all those areas will be coming through for us.

I think it is okay for us to say we'll be back to pre-Macondo levels by 2014.

Back to pre-Macondo levels by 2014?

For the Gulf of Mexico.

When you look at what underpins that operating cash, it's operating cash growth 2014, what it assumes -- what underpins that is pre-Macondo rates in 2014.

It's Neill Morton, Berenberg. I had 2 unrelated questions.

The first on gas value chains. We're pretty close to FID on the second phase of a Shah Deniz.

Can you perhaps clarify the likely, sort of, gas evacuation route? They all seem sort of fairly chaotic as we approach the deadline.

And then just secondly, on the downstream in light of, sort of, increased transparency and value creation. Would you ever consider, sort of, ceding partial ownership of your Lubricants business?

So Shah Deniz, Phase 2. The moving of gas from the markets in the Caspian to Europe is a complex process, just like it was in the building of the BTC pipeline out of Azerbaijan, the initial Caspian gas pipeline through there.

The rigs will come up into Turkey, and then it is which direction does it go across Turkey to link in with Europe? Right now, there are 3 competing proposals.

And we, working with SOCAR, have even developed a fourth proposal. And I think very good progress is being made and has been made in the intergovernmental agreements between Turkey and Georgia and Azerbaijan.

And that was a key step here. And I'm hopeful, because it is complicated, that we'll be able to announce with SOCAR and Turkey and European -- the different projects that are being supported in -- for the gas lines something in the next 6 months.

But this is a complicated process that, like all big oil and gas pipelines, just take a lot of time. And it really feels like it's coming together now.

And it is also fair to say, you may see as chaotic from the Shah Deniz shareholders, they also see it as a lot of options, and that's going to be good for value. And also, the ability now over the great constructive discussion that's being had to be able to build out from Baku in successive steps within Azerbaijan across Turkey and then into Europe has got to be a really pragmatic and sensible way of developing this resource.

Your question around Lubricants. Here's Ian.

I just think I would turn it around and say, "Why would you?" This is a business that delivering 15% to 20% pretax returns and has grown 30% per annum over the last 5 years.

I'm not suggesting it's going to carry on growing at that rate, but it's material, and it's top of the sector. Technically, we've got a tiny bit of it listed on the Mumbai Stock Exchange, which you can always go and have a look at.

But unless we were deeply desperate for cash, I can't imagine why we would.

I think, given that it's 5:30, I see some people have already had run out to catch airplanes. Is there any other last question?

We've actually lost some people on the web. Gone too long.

So ladies and gentlemen, first, thank you very much for spending today with us. It's a big investment of your time, and we do appreciate it.

I hope you found the time well spent, and I know I speak for all of the executive team here and the others who have joined us today, we actually enjoy showing you what we do and the plans for the future. So thank you.

We do continue as a company to meet our obligations for our many employees working hard everywhere. I think it's fair to say the period of consolidation is over knowing there's some uncertainty still out there.

Now is the time for us at BP. It's time to deliver.

It's time to make good on the investment, the growth plans that we have, grow the value, and we're going to do that by playing to our strengths as a company. And that means about making many choices, whether it's exploration development, development of new technologies.

And we are choosing value over volume. We're going to measure it in cash flow rather than barrels.

We're going to choose strategic assets over nonstrategic assets. You'll see more of that over the years to come.

We are investing more in front-end exploration, and we are going to divest more mature assets. We think others can derive more value from that.

Our capital allocation probably won't go in that direction, that's why we're going to do it. And we are choosing not to be the biggest but over time, we do have an aspiration, dare I say it, to be the best.

We will be a safer and stronger and simpler BP going forward.

So as I said at the outset, our vision is to build an ever-stronger portfolio upstream and downstream. We want us to generate sufficient cash to invest both in our pipeline of projects and reward those who invest with us.

Those of you who do, thank you very much. And we'll return rewards.

I'm not crying. I'm just losing my voice.

So look, why don't I just draw a line under it and just say thank you for those who've stayed with us on the webcast. Thank you very much, and our very best to you here in London.

And ladies and gentlemen --

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