英國石油 (BP) 2010 Q4 法說會逐字稿

Hello, everyone, and welcome to BP's 2011 investor update.

We are very pleased to have you with us, whether in person, over the phone, or on the web, where I understand there is a large group.

For those here in London, you will have seen behind me, our safety evacuation guidelines.

We are not planning to test the alarm system today, so if you hear it, please proceed as advised and further details can be found on the handouts on your chair.

I am pleased to be joined onstage by Byron Grote our CFO, and Iain Conn, Head of Refining And Marketing.

And with us in the audience we have our Chairman, Carl-Henric Svanberg, as well as the BP executive team, who I will come back to and introduce in a short while.

And we also welcome Maxim Barsky, who has just walked in, as perfect timing as CEO-designate of TNK-BP and our long-standing and successful joint venture in Russia, and our guests from Rosneft, including Eduard Khudainatov, Rosneft's President and CEO, Pavel Fedorov, First Vice President and CFO of Rosneft, and the CEO's General Counsel, Larisa Kalanda.

As you know we have recently forged a significant new global and Arctic strategic alliance with Rosneft, so we are pleased to have them with us here today, as well as Maxim from TNK-BP, an important venture for BP.

Now let me begin with our usual cautionary statement.

During our presentation, we will be making forward-looking statements.

Actual results may differ from these plans and forecasts for a number of reasons, such as those noted on the slide and also in our SEC filings.

Please refer to our annual report of accounts and fourth quarter stock exchange announcement for the details and both of these documents can be found on our website.

Our agenda today is a full one, and I will start with a brief overview of 2010 and an outline of how we are moving BP forward.

Byron will then take you through the results for the fourth quarter and the full year of 2010, and then we will move into a detailed look at progress and future plans in each of our businesses, before taking your questions.

We had a difficult year in 2010.

It was dominated by the tragic accident in the Gulf of Mexico, in which 11 people lost their lives.

We remain deeply sorry for what happened, and its effect on the families and the communities that were involved.

We know nothing can restore the loss of these 11 men.

Often the response to a tragedy defines the character of an organization, and I am determined we will emerge from this episode as a Company that is safer, stronger, and more sustainable, more trusted, and also more valuable.

I believe that BP has a responsibility to meet its commitments in the US, which it will, and also has a responsibility to take our learnings deeply into the fabric of our organization.

It means changing the way we manage our operations and concentrating on the things that drive long-term value.

Safety, capability, technology, portfolio choices and relationships.

We are taking the opportunity to reshape our portfolio and our operating model, as well as working in new ways with national oil companies and many partners.

So let's look more specifically at the events of 2010 and our response.

Following the accident, we acted rapidly to fulfill our commitments as a responsible party, stop the oil flow, clean up the water and the shoreline, and that work continues.

And the response was of unprecedented dimensions.

At its peak, it had 48,000 people, 650 vessels and 125 aircraft.

And we have acted in many other ways to meet our obligations.

We suspended the payment of a dividend for three quarters of 2010.

We know this had a major impact on our shareholders.

We committed to pay $20 billion over 3.5 year period into a trust fund, out of which we were meeting our legitimate claims.

We initiated a $30 billion asset divestment program.

We fully cooperated with the US federal government and the states.

And we have made organizational changes, including setting up a new safety and operational risk function, and we have restructured the upstream segment of BP.

We have introduced a new performance management system across BP.

We are fundamentally reviewing the way we manage contractors.

And we are sharing and implementing our learnings globally.

Now beyond the Gulf of Mexico incident, BP's global operations performed well.

2010 was a year of good financial performance with strong underlying earnings and cash flows.

In the upstream, we continue to move forward on many fronts.

We're today reporting reserve replacements of 106%.

This is the 18th consecutive year above 100% for BP, and we replaced 470% of our resources.

It was a very good year for new access with many new opportunities added to the portfolio.

That trend was continued last month with the new access to Deepwater blocks in Australia, new blocks in Angola, and the BP-Rosneft Arctic alliance.

15 projects were progressed through final investment decision, or FID, and we achieved a very important milestone with the approved production target in Iraq in December.

In refining and marketing, we delivered $900 million of underlying performance improvement, mainly driven by improved US refining operations and our international businesses.

And we made good progress on our divestment program, and have significantly exceeded the book value on these sales.

Byron will perform more details on our 2010 results in a moment, but before we do that, I would like to say a few words about how we see the future of our industry and BP's role, going forward.

Two weeks ago, we shared our outlook for energy demand and supply through to 2030.

By 2030, based on our judgment of the likely path of global markets and energy demand, we estimate that the world could be consuming around 40% more energy than today.

As this chart showed, this need for energy will have to be made from many different sources.

We expect continued reliance on oil, but with new growth met increasingly by gas and renewables.

With many of the world's mature basins in decline, the industry will need to increasingly look to frontiers and new technology.

This will include the deep waters, the Arctic, as well as unconventional sources.

One of our roles as a Company is to help the world meet this increasing demand for secure, affordable and sustainable energy.

Our license to operate depends on us delivering it in a safe and responsible way.

We know that.

BP has many strengths to build on.

We have scale and reach that spans the globe, and a leading track record of exploring and opening up new frontiers.

Our portfolio of assets, I believe, is among the very best in the industry.

This portfolio, combined with the capability of our people, and with our relationships built over the course of decades, alongside our strong focus on technology, I believe positions us to play a key role in meeting that challenge.

We expect the growth in energy demand will be driven primarily by the non-OECD world.

Today, China's demand for energy is already larger than that of the EU and is about the same size as the US.

As you can see here, it is expected to nearly double in the next 20 years, while demand growth in the US and the EU looks set to be much flatter.

This picture requires us to think differently from the past, increasingly looking to the east to invest, while rationalizing our positions in the more mature OECD markets, as appropriate.

And you will have already heard of our decision about US refining.

Of course, this is an evolution that will take some time, but you can already start to see how these trends are influencing BP's decisions.

This brings me to the key part of our agenda today, BP's priorities moving forward.

2010 was an inflection point, challenging us to think about what changes we need to make to our business.

So moving forward, we have set ourselves three clear priorities.

The first is setting safety and operational risk management at the heart of the Company.

As investors, you should expect this.

We see this as a long-term approach bringing together how we manage risk, how we operate, how we partner with governments and contractors, and how we reward performance.

This will fundamentally reshape the way we work.

Secondly, we recognize that rebuilding trust is central to our continued license to operate.

In the first instance, we need to meet our commitments in the United States.

We also need to ensure that lessons are implemented across all of our operations globally.

Beyond this, we need to play an active role in sharing the lessons with partners and governments, to ensure such an accident can never happen again in our industry.

And importantly, our third priority is to deliver value growth for shareholders.

We have made a number of announcements this morning, and you can start to see some of the choices we are making to realize greater value.

We are resuming payment of a quarterly dividend, with the intention to grow the dividend level in line with the improving circumstances of the Company.

We are divesting non-core assets in the upstream, unlocking hidden value, while creating a portfolio with potentially stronger growth, from a smaller base.

We are divesting half of our US refining capacity, retaining those positions with the greatest competitive advantage, so as to improve returns.

We are creating long-term value by investing in strategic projects.

Our upstream portfolio is very rich in growth opportunities, with 32 project start-ups planned by the end of 2016.

And we are increasing our investment in exploration.

It is one of our distinctive strengths and the beans by which we turn prospects into value.

We are evolving the nature of our strategic partnerships with national oil companies and major resource holders, going beyond the traditional IOC model, such as our alliance with Rosneft and our joint venture with TNK-BP.

We are focusing on long-term value, by investing in the key inputs, namely, safety, capability, technology and the relationships.

All in all, we intend to focus on continuous reduction in risk, value as much as volume, and quality over quantity.

It is about choices for the future, rather than legacies of the past.

And as to the immediate future of 2011, it will be a year of consolidation for BP, as we focus on completing our $30 billion divestment program, meeting our commitments in the US, and bringing new rigor to the way that we manage risk.

These actions may increase some costs and reduce volumes in the very short-term, but we believe they are absolutely essential to growing value for shareholders for the longer term.

With the new direction we are putting in place at BP, come a number of new faces, so before I hand over to Byron I would take a moment to briefly introduce the BP team.

This chart shows much of the leadership team, highlighting those that some of you will get to meet, at least some of you, over the next few weeks on our annual investor roadshow.

So here in London today with me, we have Iain and Byron, who I have already introduced, who will be presenting shortly.

Representing upstream, we have Mike Daly.

He's responsible for exploration.

Bernard Looney, who heads up developments, Bob Fryar heads up production, Andy Hopwood, with overall responsibility for upstream strategy and integration.

Mark Bly heads the new safety and operational risk organization.

Lamar McKay here has joined us from BP America.

David Peattie from BP in Russia, I think he's out right now.

We also have with us Brian Gilvary, our deputy CFO.

Some of you will know these people well.

Steve Westwell, Head of Strategy and Integration for the group.

Sally Bott, our Head of HR.

Peter Henshaw is the new Head of Group Communications.

And a face all of you know well, Fergus MacLeod, who is Head of Investor Relations.

After the presentation, you will have an opportunity to put questions to all of us during the Q&A session.

Now let me hand it over to Byron, to take you through the fourth-quarter and full-year results.

Thank you, Bob.

And good day to all.

I will begin my review with a summary of the trading environment.

The table shows the percentage year-on-year changes in BP's average upstream realizations and refining indicator margin, for both the fourth quarter and the full year.

Our liquids realizations increased to $79 per barrel in the fourth quarter, up 12% on 3Q, and 16% higher than a year ago.

Our gas realizations increased slightly to $3.98 per 1,000 cubic feet, 2% higher than 3Q, and 8% higher than a year ago.

Taking both oil and gas together, our total average hydrocarbon realization was up 10%, compared to the fourth quarter of 2009.

Our refining indicator margin of $4.64 per barrel was slightly higher than the previous quarter, but around three times higher than the very weak margins seen a year ago.

From the first quarter of 2011, we will be using a new refining indicator margin, which we will call the refining marker margin, or RMM.

The refining marker margin uses regional crack spreads to calculate the margin indicator.

It does not include estimates of fuel costs and other variable costs.

It is similar to the approach used by many of our competitors.

Full details and historical comparisons, including an updated rule of thumb, are available through Investor Relations on BP.com.

Turning to the financials, adjusting for gains of $250 million for non-operating items and fair value accounting effects, our fourth quarter underlying replacement cost profit was $4.4 billion, the same as 4Q 2009.

The quarter's result benefited from a stronger environment, but was adversely affected by lower production and a significantly higher tax charge.

Fourth quarter operating cash flow was an outflow of $180 million.

Excluding Gulf of Mexico oil spill expenditures of $5.4 billion, underlying operating cash flow was $5.2 billion, down 28% compared with last year.

The lower operating cash flow was primarily driven by temporary working capital effects.

Next, I will provide you with an update on the costs and the provisions associated with the Gulf of Mexico oil spill.

In the fourth quarter, we have taken an additional pre-tax charge of $1 billion, primarily reflecting an increase in projected response and administration costs.

The provision carried forward on the balance sheet at the end of 4Q represents our current best estimate of those future costs for which a provision can be made at this time, subject to all the exclusions and uncertainties that we have described in the stock exchange announcement.

We believe that BP was not grossly negligent and we have taken a provision on that basis.

BP continues to believe that it has a contractual right to recover the partner shares of costs incurred.

And whilst no amounts have been recognized in our financial statements at this time, as of the 25th of January, $6 billion had been billed to our joint venture partners.

We will continue to review the provisions quarterly and will be adjusting it as new information becomes available.

Total cash payments of $5.4 billion were made in the fourth quarter, which included the second payment of $2 billion into the trust fund, as well as direct oil spill response costs.

Full-year cash expenditures related to the incident totaled $17.7 billion.

In exploration and production, after adjusting for a gain of $1.3 billion for non-operating items and fair value accounting effects, we reported a pre-tax underlying replacement cost profit of $6.7 billion.

Relative to a year ago, the result was impacted by lower production volumes and a loss from our gas trading and marketing operations.

It benefited from higher prices and lower depreciation.

Production was 3.67 million barrels of oil equivalent per day, 9% lower than a year ago, and 6% lower after adjusting for the effects of acquisitions and divestments of around 85,000 barrels per day, plus 40,000 barrels per day of entitlement effects on our production sharing agreements.

This reduction reflects a higher level of turnaround activity than in the fourth quarter of 2009, particularly in the North Sea and Angola, and the continued impact of the Gulf of Mexico drilling moratorium.

It also reflects the absence of the 40,000 barrels per-day benefit in the fourth quarter of 2009 related to the makeup of a prior period underlift, which we talked about a year ago.

After adjusting for entitlement impacts on our production sharing agreements and the impacts of acquisitions and divestments, full-year production was 2% lower, largely due to the impact on Gulf of Mexico production.

Looking ahead, we expect first quarter production to reflect the continued impact from disposals, the continued lack of drilling activity in the Gulf of Mexico, the impact from the shutdown of the Trans Alaska Pipeline System in January, and entitlement impacts on our production sharing agreements, if prices remain at current levels, partially offset by our first production from Iraq.

BP's share of TNK-BP net income was $850 million for the quarter, and we received a dividend of $790 million.

In refining and marketing, after adjusting for non-operating items and fair value accounting effects of $220 million, we reported a pre-tax underlying replacement cost profit of $740 million for the fourth quarter.

This is an increase of $730 million, compared with the fourth quarter of 2009, principally due to stronger refining margins, stronger operational performance in the fuels value chains, continued momentum in the international businesses, and continued cost efficiencies, partially offset by a loss from supply and trading activities.

The results were also impacted by certain one-off items.

Our operational performance in the fuels value chains continues to be strong, with Solomon availability at almost 95%, and refining throughput up 120,000 barrels per day versus the fourth quarter of 2009, partly due to lower turnaround activities.

The international businesses continue to perform well, with petrochemicals maintaining high production and utilization levels, and our lubricants business continuing to deliver earnings growth.

Underlying performance in the US was at breakeven for the fourth quarter, compared with a loss of over $600 million in the same quarter of 2009.

Looking ahead, we expect first quarter refining margins to be similar to the fourth quarter and the petrochemicals environment to remain robust.

BP's refinery turnaround activities are expected to be slightly higher than in the fourth quarter.

As I mentioned earlier, we incurred losses in the fourth quarter in our supply and trading activities in both the upstream and downstream segments.

It is worth noting that over the past few years the contribution from supply and trading has been volatile, both on a quarterly and on an annual basis, with 2008 and 2009 being particularly strong, and 2010 being unusually weak.

In light of the 2010 performance, we have made a number of structural changes aimed at reinforcing our ability to efficiently capture available market opportunities.

The long-term returns have been attractive to BP, and we continue to view supply and trading as a core business activity within the group.

In other businesses and corporate, after adjusting for non-operating items, we reported a pre-tax underlying replacement cost charge of $480 million for the fourth quarter, an increase of $160 million versus the charge a year ago, primarily reflecting adverse foreign exchange effects.

Turning to cash flow, this slide compares our sources and uses of cash in 2009 and 2010.

Operating cash flow, excluding post-tax Gulf of Mexico oil spill expenditures, was $29.6 billion, 7% higher than a year ago, mainly reflecting the benefits of a stronger environment, partially offset by lower production.

We received $6.2 billion of disposal proceeds for deals completed in 4Q, bringing the total to the year to $10.8 billion.

In addition to this, we held $6.2 billion in deposits for deals, which are expected to complete in 2011.

Total cash held at the end of the year was over $18 billion.

Our net debt at the end of 2010 was $25.9 billion, and our net debt ratio was 21%, 1% higher than a year ago.

The $6.2 billion of deposits for deals to be completed post year-end was reported as short-term debt.

As these deals close, net debt will reduce accordingly.

Consistent with maintaining a prudent and flexible financial framework for the group, we intend to target gearing within a lower range of 10% to 20% in the future.

The reduction of net debt to $10 billion to $15 billion over time, as we indicated in June, is consistent with the lower end of this range.

I will now turn to guidance for 2011.

First, we expect our organic capital expenditure to increase to around $20 billion in 2011, as we invest to grow.

Second, in 2010, we received $17 billion of proceeds for completed disposals, plus disposal deposits.

In 2011, we currently expect around a further $13 billion from disposal proceeds, taking the two-year total to around $30 billion.

Next, I remind you that under the terms of the Deepwater Horizon Oil Spill Trust, BP has committed to pay $5 billion of cash into the fund in 2011, 2012, and 2013, as well as meeting continued response costs.

DD&A is expected to be around $500 million higher than in 2010, due to the recognition of production in Iraq and increased production from fields with higher depreciation rates, partially offset by the impact from divested assets.

We have made significant progress in reducing our cash cost base over the past several years.

In 2011, we expect to see a slight increase while we refocus our activities, as Bob has described.

The average underlying quarterly charge from other businesses and corporate in 2011 is expected to be around $400 million.

As in previous years, this is likely to be volatile on an individual quarterly basis.

And finally, the effective tax rate for 2011 is expected to be in the range of 32% to 34%, slightly higher than in 2010.

Bob will provide production guidance for 2011 in his remarks.

In closing, I would like to outline the medium-term financial framework for the group.

We have resumed distributions to shareholders, while we increase investment to grow the firm.

This resumption of the dividend is supported by our continued success in the disposal program, and by the improving business environment, but balanced by the need to retain a significant level of financial flexibility at this time.

To provide that financial flexibility, we intend to maintain a significant cash liquidity buffer, as we have over the past six months, and reduce the gearing ratio to a range of 10% to 20%, as I mentioned a moment ago.

A quarterly dividend of $0.07 per ordinary share was announced for the fourth quarter, which will be paid in March.

As you would expect, the Board has been prudent in setting the new quarterly dividend level, recognizing the continuing obligation to pay $5 billion per annum into the Deepwater Horizon Oil Spill Trust, and the uncertainties that we still face.

The intention is to grow the dividend level over time, in line with the improving circumstances of the Company.

The scrip program, approved by shareholders at last year's annual general meeting, will be available for 4Q dividend recipients.

That concludes my remarks.

Now back to Bob.

Thank you, Byron.

Let me now update you on progress and safety and risk management in BP.

It is a vital focus for us.

Last year, as you all know, 11 contractors lost their lives on April 20.

Sadly, we also had three other contractor fatalities across our operations elsewhere in the world, making a total of 14.

The top chart here shows recordable injury frequency, which includes fatalities and lost time incidents.

It shows that the total number of recordable injuries increased last year.

This was mainly due to the number of people involved in the Gulf of Mexico response, where injuries occurred primarily during boom deployment and beach cleanup.

Overall, we've had a declining injury trend for 10 years, and performed in-line with industry benchmarks.

As well as personal safety, we have taken a lot of steps in recent years to improve performance and process safety.

Two measures are shown here.

The first is process safety-related major incidents.

In 2009, we recorded no such incidents, but in 2010 we had three, including the Gulf of Mexico explosion.

The losses of primary containment on the bottom right here are unplanned and uncontrolled releases of process material.

The trends for all of the metrics here show some progress, but there is much to do and we know that.

So what are we doing to put safe, compliant, reliable operations at the heart of BP?

We have clear priorities and a program of action.

The main priority is to strengthen process safety and reduce operating risks.

This requires the alignment of our organization from top to bottom, with a consistent set of standards and behaviors.

The primary mechanism to drive this consistency is our operating management system, or OMS, and we are continuing to embed this across the organization as a single system to be respected and followed by every operation.

And in human terms, we continue to focus on ensuring that we have a highly competent organization and a deep safety culture, where everyone speaks up and takes action when necessary.

We are rebasing our approach to performance and reward, to ensure every person at BP follows these priorities.

As I mentioned earlier, we have also created a more powerful safety and operational risk organization, which we call S&OR.

S&OR will strengthen our standards and processes, and has personnel embedded in BP's operating divisions, and they will be working alongside the line management to guide, advise, scrutinize, and if necessary, intervene.

The S&OR team is confirming implementation of the 26 recommendations from the Bly Report, approving critical personnel, reviewing risk mitigation plans and overseeing key decisions affecting operational safety.

Let me give you a little more detail, by looking at what this means in the upstream, specifically.

Within the Developments division, we have established a centralized global wells team, to make sure our wells are safe and compliant.

They are working closely with S&OR to advance standards, and ensure they are applied consistently.

We have five key areas of learning from the incident, which we are advancing.

These are prevention, containment, relief wells, spill response, and crisis management.

We are committing to share what we have learned, and we are bringing our capability and knowledge and, in some cases, equipment to groups, including the new marine well containment company in the US, and we are also cooperating with investigations and supporting initiatives to bring about necessary regulatory change.

Now let me turn back to the Gulf of Mexico.

Our Gulf Coast restoration organization is completing its response activities and working towards the longer-term restoration of affected areas.

BP assumes day-to-day management of further activities from the existing Gulf Coast incident management team at the end of March.

Around $5 billion has been paid in claims and government payments, and the natural resources damages assessment process is underway.

We continue to have a local presence through our offices and staff, and we have supported initiatives such as tourism and seafood testing and marketing to help rebuild the Gulf Coast reputation, and we have voluntarily contributed significantly to independent research and assistance initiatives.

This includes investing $500 million in the Gulf of Mexico Research Initiative, as well as other payments and grants.

While this activity continues, you will know that we are cooperating with a series of investigations, inquiries and hearings, and I believe it would be helpful to note some of those activities and the likely timeline.

We expect that the Presidential Commission will have completed their investigations and publish their findings by the end of March, while publication of the final report from the Marine Board is scheduled for later this Spring, and the National Academy of Engineers report is scheduled for the end of the year.

Less clear is the timing of the ongoing Department of Justice investigations, which are still expected to take some time to complete.

There are currently many active lawsuits against BP, and other parties, and these have been consolidated into two multi-district litigation proceedings, with most of the cases being consolidated under Judge Barbier in the Eastern District of Louisiana.

Discovery in these cases is ongoing, and the Oil Pollution Act test trials may be scheduled for later this year.

The limitation on liability trial is currently scheduled for early 2012.

So while there are still uncertainties as to how all of this will progress, we should start to be clear on the implications as we move into 2012.

As you have seen, we have thus far taken a charge of some $41 billion against income in expectation of potential liabilities, such as those I outlined a moment ago.

There are a few key points I would like to make to investors about this.

Firstly, we believe that the $20 billion trust fund, within the provision, provides a substantive facility to cover claims brought by individuals and businesses, government claims, as well as the cost of the natural resource damages claims.

Should the $20 billion turn out to exceed requirements, the balance of the fund will return to BP.

Secondly, our estimate of the potential claims under the Clean Water Act, which we expect to be the major category of fine, is also included in the $41 billion charge, as well as response and clean-up costs.

Further, as already noted by Byron, we continue to believe that BP was not grossly negligent and have taken the charge on that basis.

We would expect to be able to recover a portion of costs from partners, which is not reflected in our provisions.

As far as the impact on the cash requirement of the group is concerned, our commitment to the trust fund is spread over 3.5 years, ending in the fourth quarter of 2013, after which a significant amount of cash will be available for other uses.

So now, ladies and gentlemen, let me turn to our lines of business.

I will start with a focus on our upstream business, and then Iain will overview refining and marketing.

As Byron has noted, 2010 was, in fact, a year of strong financial performance, aside from the Gulf of Mexico oil spill and lower production.

However, we realize, we have to realize that the Gulf of Mexico oil spill was a pivotal moment for BP, and nowhere has this been felt more strongly than in the upstream.

We will be a different kind of Company in the upstream, going forward.

With the fundamental restructuring into divisions, the embedding of the new S&OR organization, redefining our performance setting and reward processes, and the systematic implementation of the lessons from the Bly Report, through our operating management system.

We are also taking this moment to make broad strategic change.

Our strategy remains to invest for growth, but our emphasis will be on value growth.

Going forward, we will deliver this in a number of ways.

We will continuously reduce risk.

We will evolve the nature of our relationships, particularly with national oil companies.

There will be increased spend in our highly value-leveraging activity of exploration.

We will actively manage our portfolio, looking to divest or sell down a portion of our assets, if they are more valuable to others than to BP, or to acquire, where BP can create significant value.

And finally, we will be investing in building our technology and our human capability.

You can read into this, that while volume is of course one indicator of growth, it will be deemphasized in favor of value.

So in this section, I am going to look at progress in 2010, with an update on the divestment program, a look at the makeup of the portfolio and the picture on reserves and resources, and a review of progress on major projects.

Then I will look ahead to 2011, including our increased program of turnarounds, and the outlook for activity in the Gulf of Mexico, and then production and CapEx guidance for 2011.

And I will finish by looking more broadly at the business, explaining our framework for growing value and using examples to demonstrate our confidence in the future of our upstream business.

So first, our divestments.

I want to be clear on the criteria we used in selecting assets for divestment.

It was first, to refocus our own portfolio for growth, and second, where assets would be worth more to others than to ourselves, thereby unlocking value for shareholders.

This latter point has clearly been demonstrated, I think, as our divestments have attracted disposal proceeds greater than external valuations and more than twice their book value.

The divestments represent around 15% of BP's current market value, and yet a much smaller portion of reserves, around 9%, and a pre-tax underlying replacement cost profit of around 7%.

In five countries, we divested all of our upstream interests, simplifying the portfolio considerably.

This means that our management can concentrate on regions where we believe we can grow value in a distinctive way.

But we divested none of our inventory of future major projects, so our long-term growth potential remains intact.

This slide shows the overall distribution of the asset value in our upstream business.

It excludes our shareholding in TNK-BP, which I'll talk about later, and it also excludes the Gulf of Mexico, where significant uncertainty for the industry remains.

Again, I'll come back and talk about that.

There are several important observations on this slide.

First, it shows just how much more focused our portfolio has become through the divestment program.

A feature of our value growth story will be to continue to divest where it is clear BP can not add unique value.

We will aggressively pursue the front end of value creation, but will be prepared to divest when others can create greater value.

Second, the chart shows the inherent scale, strength and breadth of our portfolio.

We have many material multi billion-dollar businesses.

Third, it also shows a set of currently smaller positions with significant potential to grow as we invest over the decade.

These include North Africa, the Middle East, Brazil, and Canada.

And finally, we will be exploring our new basins with the intent of moving them onto this chart in the future.

For example, our work in Australia, or with Rosneft in the Arctic.

A primary driver of value growth is how we manage the flow of resources from access to production.

The slides show how resources have progressed to reserves and then to production during 2010.

Year-on-year, our total resource base grew from 64 billion to 68 billion barrels of oil equivalent, and our inventory life has been extended from 43 to 48 years.

Resource additions resulted in a total resources replacement ratio of 470%.

Proved reserves were down slightly from 18.3 billion to 18.1 billion barrels of oil equivalent, but that is after divestments.

Excluding acquisitions and divestments, additions exceeded production for the 18th consecutive year.

Now this chart shows how the resource base and reserves are now distributed.

One point to note is that the portfolio has a bias towards oil, with around 65% of oil and 35% gas.

We need that bias to oil to capture margin and maintain our leverage to higher oil prices, and we want to complement that with a sizable share of gas to capture with growth.

The quality of our resource base in our subsidiaries is also continuing to improve.

Over the last five years, we have increased the reserve additions from higher-margin areas, such as Azerbaijan, Angola, the North Sea and the Gulf of Mexico.

I want to look in more detail at our access success during 2010.

We deepened in our existing positions in the North Sea, in the Valhall field, and in the recent UK licensing round, shale gas in North America and Canadian heavy oil.

We deepened in Azerbaijan through the Shafag-Asiman production sharing agreement, and intend to do so in Angola, through four new blocks in the Kwanza and Benguela basins.

We completed our access in Jordan, with ratification of the Risha concession and access to the North Arafura block in Papua Province, Indonesia.

Importantly, we moved into four major new basins.

First, Brazil.

It had represented a gap in our Deepwater portfolio, and our agreement with Devon, subject to government approval, now provides us with that access and we will continue to look for further growth opportunities there.

In the South China Sea, we accessed new acreage in the deepwater.

In the Arctic, we just announced our future work in the South Kara Sea with Rosneft.

In Australia, we are pleased to enter the new frontier Ceduna basin, and we had a significant discovery with the Hodoa well in the West Nile Delta concession.

Now let me summarize the progress we have made in our major projects.

All of this activity is now managed by our global projects organization, within the developments division, which was created this year to improve the quality of our project execution.

That organization has been hard at work, strengthening safety, driving standardization, managing risk, and building capability.

It has also used BP's scale to sign seven new long-term global supply agreements.

During 2010, we made final investment decisions on 15 projects.

A large number of the projects are in the North Sea, Angola, Azerbaijan, and the Gulf of Mexico.

As a result, over 2 billion barrels of oil equivalent of BP net resources are expected to be developed, with an expected total capital investment of $20 billion net to BP to bring them on stream.

Let's turn to 2011, and provide you with some guidance on volume output and capital investment.

One practical effort of our focus on safety and risk management will be an increase of almost 50% in planned turnaround activity in key areas, such as Alaska, the North Sea, Angola, and Iraq.

All of this is expected to have some short-term production impact, around 200,000 barrels of oil equivalent per day during 2011.

This is roughly 50% more than in 2010.

I have no doubt that this activity will have long-term benefits in terms of reliability, and as part of getting the foundation right for long-term growth.

You will know, one of the key uncertainties we face in 2011 is the pace at which activity and getting back to work will be restored in the Gulf of Mexico.

We are not unique.

The industry faces a similar uncertainty.

Production in 2010 was affected by the drilling moratorium and will carry over into 2011, as natural reservoir declines take effect.

In 2011, our focus is on restoring rig activity safely.

We have clear restart criteria, which includes meeting all new regulatory requirements, addressing each of the recommendations of our investigations under Mark Bly, and compliance with our own standards, ensuring we have the right capability in place, along with appropriate contractor management.

Our plan is to have four development rigs and one exploration rig resuming activity this year, although there is industry-wide uncertainty around the exact timing.

We also have stakes in activities that are operated by others in the Gulf of Mexico, including the Mars, Ursa, Tubular Bells, Galapagos and Great White fields, as well as appraisal, focusing on Freedom and Mad Dog North.

This uncertainty will clearly effect Gulf of Mexico production overall, and in 2011, we anticipate a further decline in production before returning to growth in 2012.

But this will depend on the timing of the restart.

However, the key point for future value creation is BP's resource base is unchanged, and we remain committed to its development.

So recapping on what I've covered here, production values are expected to be lower in 2011 than 2010.

That's as a result of divestments, lower production from the Gulf of Mexico, increased turnaround activity that is required to improve the long-term reliability of the assets.

As a result these factors, reported production in 2011 is expected to be around 3.4 million barrels of oil equivalent per day.

Now of course, the actual outcome will clearly depend on the exact timing of the divestments and the pace of getting back to work in the Gulf of Mexico, OPEC quotas, and the impact of oil price on production-sharing agreements.

The actions we are taking in 2011 will set the foundation for longer-term growth.

We are increasing our investment and plan a total of 32 project starts by the end of 2016.

These will contribute an expected 1 million barrels of oil equivalent per day, which will more than offset natural declines.

The scope for accelerated growth from this now smaller base is clear, but our team's focus in the near term is getting the inputs right.

We will not compromise the ongoing reduction in risk, reliability, systematic execution of the activities, these are ultimately going to be the primary drivers of value.

Now to support that growth, we are increasing our investment in 2011, and we expect organic investment in the upstream to be around $15 billion.

Our share of investment in TNK-BP will be around $2 billion, capital budgets.

Now, ladies and gentlemen, at this stage, I want to take a step back and explain more about what I mean when I say we are making broad strategic changes to grow value for the long-term.

I have talked earlier about changes in safety, risk management, the restructuring of the upstream organization, and the alignment of priorities and rewards.

We are also evolving the model of what an international oil company does.

Clearly, project scale and complexity, requiring access to financing, technology and capability continue to enable international oil companies to uniquely invest in our industry's challenges.

Deepwater projects are a prime example.

We remain deeply committed to this important resource.

We are also pursuing new kinds of relationships with national oil companies and major resource holders.

We don't see them as only competitors, but increasingly as partners, when our capabilities are suited to their needs.

And those partnerships will take different forms, according to the particular opportunities.

BP and Rosneft is just the latest example of a new kind of relationship, and I see that as mutual benefit in action.

This agreement typifies the way that we are following the global trends.

Growth in energy demand and economic activity is coming almost entirely from the emerging economies, especially the so-called BRICs, Brazil, Russia, India, and China.

The other way the model is evolving for us is a shift in emphasis from volume to value.

Of course, production numbers matter, of course.

But we need to see our assets in terms of value and understand how we, as a Company, can best create and realize value in those assets.

The focus in value also means that we will actively manage the portfolio and may not always participate in every stage of the life cycle of every project, as indeed, we have shown in the divestment program.

Let me show you how this value based approach has worked in one of our key areas, namely in Azerbaijan.

It is an example for many points here.

But value can be treated at every phase, through the exploration, appraisal, development, and production of the resources.

Our experience in Azerbaijan shows that successive waves of exploration, development, production build on each other, repeating this several times in each basin.

Incorporating learnings will enable us to unlock new opportunities and create unique value.

There are different points, as the value is created, where you have options to sell down, partner in other ways.

It could happen.

And arguably, the most value-creating part of an asset's life cycle, as you saw in the previous chart, is exploration.

BP is an explorer by instinct and tradition, and I think we're good at it.

This chart shows our history.

We have consistently found more than 600 million barrels of oil equivalent per year through the exploration drill bit throughout the last decade, opening up new plays in Angola, Trinidad, and the Gulf of Mexico, some of our key producing areas today.

We have also made significant progress in rebuilding our inventory of new plays, and I think this access momentum will continue to build.

We believe this will give us the potential to double our rate of exploration spend over the next few years with discipline.

There is enough choice to preserve the quality of our prospects, which can create the new producing areas for the next decade.

We may not choose to take every success through to production, and we may use success to bring new strategic partners to join us.

And I think that's value creation through exploration.

Let me review where we will focus our exploration activity.

Firstly, we will continue to explore where we have been successful in the last decade, in Angola, in Egypt, Azerbaijan, and the Gulf of Mexico.

Secondly, we will test five new provinces in the next few years.

These will be Libya, Jordan, Brazil, the South China Sea, and in Australia.

We see the potential prospectivity of these provinces as evenly balanced between oil and gas.

And then thirdly, for the longer term, we will test the exciting potential of the Arctic Continental Shelf and the Canadian Beaufort Sea, and now also in the Russian South Kara Sea.

And finally, the Gulf of Mexico.

We remain the leading leaseholder and we have a very strong prospect inventory.

We hold the leading position in the emerging Paleogene play, with two significant discoveries in the Kaskida and Tiber, and a strong prospect inventory to drill out.

When I look at the global opportunity set, I am excited about the big wells that we have ahead of us, as we test and drill out this strong portfolio.

So moving on from exploration to developments, we have a deep portfolio of high-quality projects.

We have made the final investment decisions on 24 projects, and a further 10 are expected to reach FID in the next two years.

We also have 16 additional projects which are under appraisal.

Let's look specifically at a few of the Deepwater and the gas projects.

BP does remain committed to the Deepwater.

We are the largest Deepwater producer amongst the major international oil companies and are determined to take the lessons of last year around the world with us and build on our know-how and capability.

I think we have a responsibility to do this.

There are four focus areas for our developments organization.

First, investing in the capability of our people.

Second, developing new technology.

Third, developing new arrangements with our contractors.

And finally, developing new engineering and operating standards.

We are currently progressing 19 Deepwater projects in the Gulf of Mexico and Angola, with an expected total investment of over $40 billion, and we expect to shortly confirm Brazil in that portfolio.

Though oil forms the majority of the portfolio, natural gas is set to be the fastest-growing fossil fuel in the next two decades, and I would like to highlight four particularly exciting projects.

In Azerbaijan, the second phase of the Shah Deniz development is one of the largest gas development projects in the world, with the potential to open up new sources of supply to the European gas markets.

In Oman, we are appraising Block 61, using our expertise in tight gas reservoirs.

In Egypt, the West Nile delta project reached a significant milestone in 2010 with the signing of a new concession.

And in Indonesia, we continue to explore and appraise potential resources to expand our existing Tangguh LNG facility, with a third train now underpinned and work underway to identify resources for a potential fourth train.

So pulling all of this together, here is an overview of the planned start ups by the end of 2016.

We plan to start up 32 projects which have the potential, as mentioned before, to contribute around 1 million barrels a day of production equivalent.

As I said earlier though, there may also be opportunities to create value at this stage of the project's lifecycle.

Turning to the third division of upstream production, we are focusing on three areas.

First, prioritizing safe and reliable facilities by continuing to invest in integrity and reliability.

Second, we are pursuing excellence in reservoir management.

And third, we are working on improving the recovery factors from our reservoirs.

Our operations in Iraq, I think, are a very good example of all of this.

The learnings we have gained in giant reservoirs in the US, in Russia, in the North Sea are now being transferred to the largest field in Iraq, the giant Rumaila field.

The Rumaila operating organization recently met a major milestone by safely achieving its improved production target.

This was achieved through the ramp-up in activity that began only in July, 2010.

Some 10,000 people are now working on Rumaila, over double the number at the beginning of 2010.

In 2011, we plan to continue to ramp-up activity, including a water infrastructure upgrade and engineering for a full field development.

And reaching the improved production target means we now start recovering cost and earning remuneration fees.

This milestone is good for Iraq, and it significantly changes the risk profile of our investment.

Now let's take a look at our business in Russia.

The relationship between BP and Russia has been forged over 20 years, and it is a relationship we intend to build upon.

Already, we have the largest position of any international oil company in Russia.

We have a unique, growth-oriented position in Russia, through our distinctive partnership in TNK-BP, and the long-standing partnership with Rosneft.

Let me first provide an update on TNK-BP.

Maxim is here, for answer questions later.

TNK-BP has a very strong onshore production base, of which around 70% comes from West Siberia.

This includes the giant Samotlor field, where we have been applying technology to sustain production for several years.

The transition to new greenfield projects began with the startups of the Verkhnechonskoye, Uvat, and Kamennoye fields in 2010.

These projects will underpin the continued growth for TNK-BP through 2015.

And in 2010, production growth was up over 2% greater than the national average.

Looking ahead, TNK-BP expects to see investment growing at an average growth rate of 11% over the next five years and production at 2%.

Longer-term growth will come from the development of new provinces, near the Yamal Peninsula.

TNK-BP is a core and significant part of our portfolio, and we expect it will remain so.

Let me now turn to the recently-announced alliance with Rosneft.

This is a further important step for BP, for the industry, for Russia, and for global energy over the long-term.

This is a long-term activity.

The agreement to seek a form of joint venture to explore and, if successful, develop three licensed blocks on the Russian Arctic continental shelf offers a new opportunity to access a world-class basin.

It utilizes BP's exploration skills and leading position in the Arctic region, which includes our 40-year track record in Alaska, and drilling off of Sakhalin, in Russia, with Rosneft.

The licenses were awarded to Rosneft in 2010, and cover approximate 125,000 square kilometers in a highly-prospective area of the South Kara Sea.

This is an area roughly equivalent in size and prospectivity to the UK sector of the North Sea.

The agreement also creates the first major equity linked partnership between a national oil company and an international oil company, and following completion of this agreement, Rosneft will hold 5% of BP's ordinary voting shares in exchange for approximately 9.5% of Rosneft shares, bringing BP's total shareholding in Rosneft to 10.8%.

We have also agreed to establish an Arctic technology center in Russia, and we have agreed to continue our joint technology studies with Rosneft in Russian Arctic, and we will seek additional opportunities, as we have with TNK-BP, for international collaboration with Rosneft, beyond our 50-50 joint venture partnership in Ruhr Oil in Germany.

So as we come to the end of the upstream section, I want to take a moment to highlight the role of technology.

It is a common theme running through all the upstream divisions.

We continue to exert discipline in selecting the technologies we pursued through our flagship programs.

Clearly, technology will be a key input to unlocking long-term value.

I believe we are an industry leader in seismic, both as acquisition and imaging, as well as in sand control, and we have made dramatic breakthroughs in the development of water flood technology and enhanced oil recovery.

These are just a few examples.

So to sum it up, our upstream business is going through a significant change, as it refocuses to drive safety improvements and operational risk reduction in everything that we do.

Our divestment program has created a portfolio which is substantially refocused.

We are shifting the emphasis from volume to long-term value growth for shareholders.

I think we are good at finding oil and gas, and we will take advantage of our growing, world-class exploration inventory to double exploration investment over the next few years.

We have high-quality projects, capable of delivering around 1 million barrels of new oil equivalent per day by the end of 2016.

We will continue to make choices about where we invest, and we will divest if others can add more value than we can.

And we will continue to evolve our relationships with large resource holders and national oil companies, and we will invest in technology and the capability of our people.

Ladies and gentlemen, that concludes my remarks on the upstream.

So now, let me hand over to Iain, who is going to talk about our downstream businesses.

Thank you, Bob, and good afternoon.

It is a pleasure to update you on progress and prospects for refining and marketing.

Given today's announcements, my presentation is divided into three sections.

Firstly, an update on R&M's performance in 2010 in the context of the goals I set a year ago.

Secondly, an in-depth description of our portfolio strategy, including further detail on the announcements we made this morning, regarding our US fuel value chain portfolio.

And finally, some indications of what you might expect from R&M in the future.

So let me begin by covering the R&M turnaround and our progress in 2010.

Our focus since 2007 has been on turning around R&M, with an agenda built upon the five priorities outlined on this slide.

These are unchanged.

Safety remains our top priority, and the events of 2010 only serve to underscore this.

Bob outlined the agenda for our safety and operational risk function, and we are in the process of implementing that agenda within R&M.

During 2010, R&M's safety performance was stable versus a very good 2009.

Personal safety was slightly worse than 2009, and process safety was better, with a 25% reduction in our severity-weighted process safety incident index, and all of R&M's major operations are now on our operating management system, OMS.

Organizationally, we continue to invest for the future, both in capability and core processes, as we consolidate the operating model.

Most of my presentation today relates to the last three priorities, the improvement in our earnings momentum and returns, the portfolio and it's simplification, and our efforts to improve our efficiency.

I'd like to begin with 2010, starting with competitive performance.

Used for four years now, the chart on the left shows our post-tax ROACE versus the super-majors, estimated on a consistent basis.

Having closed the gap in 2009, we estimate BP has remained near the top of the competitor set, and absolute levels are improving.

BP's ROACE in 2010 on this measure was over 8%, a significant improvement on 2008 levels, and an improvement of about two percentage points versus 2009.

On the right, for two years, BP's downstream has outperformed, in terms of net income per barrel of refining capacity.

As I said last year, we are not focused on being the largest player in any of our businesses, but of holding the highest quality portfolio and operating it well.

I believe this is beginning to show through in our competitive results.

Turning now to earnings momentum, this chart shows 2010 pre-tax underlying ICP of $4.9 billion versus $3.6 billion in 2009.

This is the highest absolute earnings level for R&M since 2006, but in a considerably worse environment.

By our estimates, the margin environment was slightly better than in 2009, giving $0.4 billion of the improvement, with the other $0.9 billion coming from underlying performance.

This improvement is about half of the goal to improve pre-tax profit by over $2 billion a year by 2012, which I set out last year, indicating that we are making good progress.

You can also see that the total underlying pre-tax improvements since 2007 is now approaching $6 billion per annum.

So how have the different parts of the portfolio performed?

This is the usual breakdown of profits and operating capital employed between the fuels value chains and the international businesses, including history back to 2007.

In the fuel value chains overall, profit has improved by $0.5 billion.

In fuels marketing and supply, earnings were down $4 billion, driven in large part by very poor oil trading performance, and also the marketing impacts in the US in the aftermath of the Gulf of Mexico oil spill incident.

Refining posted a profit for the first time since 2007, and improved by $1.9 billion year-on-year.

This was mainly driven by improvements in our US operations, while maintaining good performance elsewhere.

Refining Solomon availability was 95% in 2010, the best level since 2004.

Throughputs were up 140,000 barrels a day, and utilization rates globally were 91%, up over six percentage points versus 2009 and significantly above industry averages.

Refining, returning to profit in 2010, means we have achieved another important milestone of refining becoming breakeven in an environment similar to that of 2009.

In the international businesses, earnings improved by $800 million.

The largest contribution to this was in petrochemicals.

Even though margins were only slightly up versus 2009, demand recovery and new BP capacity coming on-stream drove a 23% improvement in production and total costs were maintained at below 2008 levels.

Lubricants and global fuels also had another good year, with further expansion of gross margin and good cost discipline, driving double-digit earnings growth.

Returning then to the segment level, and looking at 2010 through the three themes of improvement I outlined last year, which underpin the $2 billion per annum goal, starting at the bottom with growing margin share.

We delivered considerable growth in the international businesses, offset by oil trading, so we actually went backwards on this measure in 2010.

We made significant progress in both repositioning cost efficiency and from portfolio quality and integration in the fuel value chains, through better operations, higher utilization, and better optimization of the integrated margin.

We are ahead of our plans on both these dimensions.

The cost efficiency improvements were from across the portfolio, with large contributions from refining efficiency gains, business continuous improvement, and more efficient functional execution.

Last year, I described our goals to improve refining efficiency without compromising our investments into safety and plant integrity.

This is an updated chart, showing our goal for 2012 in orange and the progress we have made in 2010.

We remain on track with our plans for refining efficiency.

The efficiencies have come largely from improved planning and execution of all types of work, improved contractor management, and better sourcing of goods and services.

Looking now at cost efficiency overall, the green bars show costs indexed to 2004 levels, with turnaround costs split out at the top.

The yellow dot indicates costs normalized for energy, ForEx, and turnaround levels, and as we are now growing volumes, additional manufacturing variable costs.

As you can see, we have now reached our goal of 2004 cost levels on a broadly like-for-like basis.

We will continue to drive to improve unit cost efficiency, but as we have announced some planned large portfolio changes, comparing absolute costs with the 2004 portfolio will no longer be useful.

Looking forward, our turnaround costs are expected to be slightly higher than average in 2011 and 2012.

I'd now like to turn briefly to refining margins.

Byron has described our intention to move to a new refining market margin, or RMM.

Details are on the BP website.

Our expectation continues to be for margins to remain in a range more reflective of pre-2004 levels.

Taken with the recent realities of 2009 and 2010, our forward plans are currently based on an RMM range of $8 to $12 per barrel.

As with GIM, there is a good correlation between this new marker margin and R&M's pre-tax RC profit, as indicated by the dark green line.

The yellow band on the chart depicts our over $2 billion per-annum improvement goal by 2012, and I have plotted 2010 on the same basis, showing the $0.9 billion of improvement in the first year.

Finally, a word on investment levels.

The black line indicates CapEx, the green bars, net investment, with the dotted blue line, depreciation.

In 2010, CapEx was $4 billion, and proceeds from divestments of about $1.8 billion, leading to net investment of $2.2 billion, and in line with depreciation.

On average, for the last five years, we have also net-invested about in line with depreciation.

With strong operating performance and investment discipline, R&M delivered material net cash flow back to BP in 2010.

For 2011, with the current portfolio, you can expect CapEx to be slightly higher than in 2010, with a slightly lower level of proceeds from divestments.

The chart excludes any proceeds from the US divestments we announced today.

So, I would now like to summarize the journey to 2010, which provides the context for the portfolio decisions we have made.

This slide shows profit and return on capital employed, both pre-tax for the major constituent parts of R&M.

For each asset class, both 2008 and 2010 are shown.

Capital employed is reflected in the size of the bubble.

The chart is not adjusted for environment, and refining margins fell from an RMM of nearly $16 a barrel in 2008 to about $10 a barrel in 2010.

You can clearly see the quality of the international businesses, in orange, with absolute profit increasing by about $1 billion over the last two years and pre-tax return on operating capital in the 19% to 33% range.

These businesses are also capable of material growth.

Indicated in yellow, the earnings in the eastern hemisphere fuel value chains have fallen back by $1.3 billion, due to lower oil trading contribution and lower refining margins, materially offset by underlying improvements, delivering profit in 2010 of nearly $2 billion and returns of over 10%.

We have plans in place to further improve their performance.

Facing these same factors, US fuel value chains, in green, have made very significant progress, improving by $1.9 billion and moving into a breakeven situation.

This is a considerable achievement, and has been done while delivering materially improved safety performance.

This represents the huge efforts of a very dedicated team.

However, the reality is, that in a 2010 environment, the US fuel value chains remained breakeven.

I, therefore, would like to turn to the second part of my presentation, on strategy and portfolio.

The backdrop to our strategic choices is one of flat to declining demand for fuel in the US and Europe, with decline of fossil fuel demand accelerated by the penetration of biofuel.

It is also in the context of significant growth for fuel lubricants and petrochemicals in the emerging economies.

For the last 18 months, we have been considering the future performance potential of the whole portfolio in both relative and absolute terms.

In addition to meeting strategic hurdles, such as configuration and market location, integration and growth potential, we also expect our fuel value chain businesses to reach returns above cost of capital at the bottom of cycle conditions, and to make a material contribution to BP over time.

Although we have concrete plans to improve further all parts of the US fuel value chain portfolio, parts of it failed the strategic hurdles and current performance does not meet these financial goals.

This is the backdrop to the decisions we've announced this morning.

Therefore, our portfolio strategy in R&M is now to reposition the US fuel value chain, halving US refining capacity, improve the fuel value chains in other geographies, and access associated market growth and continue to grow the high-quality international businesses.

As indicated here, there are many active elements underpinning this strategy.

In the US, we have reached some major decisions.

As announced, we intend to exit the Texas City refinery and exit the southern West Coast fuel value chain, including the Carson refinery.

We will continue with our plans for the rest of the US fuel value chain portfolio.

Our plans for both the eastern hemisphere fuel value chains and for the international businesses are unchanged.

And I will provide more detail in a moment.

Starting with the US, and with Texas City.

The Texas City refinery is a very large scale asset, with a highly complex, gasoline-oriented configuration.

It is the third largest refinery in the United States, capable of producing about 3% of US gasoline production.

It has improved its performance in safety and operations significantly, and financially, by some $2.5 billion per annum over the last three years.

This has been achieved under the most intense scrutiny, and I want to thank and congratulate the team most warmly for that achievement.

However, Texas City is not strongly integrated into BP's marketing assets, and so fails the hurdle of integration, and has limited logistics in tankage flexibility.

BP would need to increase the footprint around Texas City to improve this.

Strategically, we therefore have concluded that BP should sell Texas City and exit before the end of 2012, subject to legal and regulatory approvals, including satisfying the authorities regarding the future fulfillment of our obligations at the site.

We have received a number of inquiries from competent operators, relating to Texas City.

Turning now to the West Coast.

In reality, the West Coast has two value chains, with a limited degree of overlap between them.

In the south, BP has a fuel value chain with Carson refinery at its core, and high marketing shares in Southern California, and related marketing in Nevada and Arizona.

However, the refinery has limited feedstock flexibility, is gasoline-biased, and will require investment in logistics, and/or configuration to improve this.

While this business has material potential for improvement, which we are pursuing, it will also require investment to take it to a new level of capability in a highly competitive market.

Given our plans elsewhere in the US, we have therefore decided to exit the southern fuels value chain and intend to complete this transaction also by the end of 2012.

Again, subject to relevant approvals.

Again, I wish to thank the team for their considerable efforts and achievements in safety, and the operational and financial performance improvements delivered to date.

Our northern position, by comparison, has the relatively modern 1970s Cherry Point refinery at its core, which is jet fuel and diesel fuel-biased, and into which we are making further investments, to ensure it remains the leading refinery in the Pacific Northwest.

The refinery is better located, and more feedstock flexible, being both pipeline-connected to Canada and also closer to A&S supplies.

The financial performance and integrated margin are better than the south, and will meet our criteria.

As a result, we intend to retain the northern part of the West Coast, as part of a US fuel value chain strategy, which focuses on feedstock-advantaged, product-flexible, highly-upgraded, well-located refineries integrated into advantaged logistics and marketing.

Exiting Texas City and the southern part of the West Coast will halve BP's US refining capacity and significantly improve the current financial performance of the US fuel value chain portfolio.

We are also investing to improve the Toledo refinery, with our partner Husky, and continuing to transform the Whiting refinery.

The Whiting project, shown here, is making good progress.

As the chart shows, this is a very large and complex project, and it's now about 60% complete, with all major lifts of key units completed in 2010.

The project startup has now been deferred slightly, from late-2012 to mid-2013.

This chart is a version of one I used last year, showing indexed pre-tax profit per barrel in the midwest against refining margins on the new RMM basis.

The yellow dot shows end-2010 conditions, indicating that even at relatively low margins, this project is expected to deliver approximately a threefold improvement in profitability and will contribute materially to improvement in our US fuel value chain position overall.

This comes from an increased ability to run heavy crudes, improve product yields, and location advantage, relative to the Gulf Coast, for Canadian crude.

So where do these major portfolio changes leave us in the US?

Post-2013, we will have half the refining capacity of today, interest in three refineries, with improved or transformed configurations, all of which have feedstock flexibility to run a range of crude oils, including heavy grades, and which are, on average, more diesel-capable than BP's current portfolio.

All of them have access to advantaged, focused logistics, and are integrated with marketing operations to support high utilization rates.

Our import-led terminals and marketing on the structurally-short east coast are also very well positioned.

Although smaller, we believe this portfolio will be competitively very advantaged in the United States.

I'd now briefly like to turn to the eastern hemisphere fuel value chains.

This portfolio, focused mainly around the Rhine, Iberia, southern Africa and Australasia, is comprised of well-located, integrated refining, which is generally of a high competitive quality and strong marketing positions.

We have been refocusing this portfolio, with the exits of retail in Greece and France, planned exits of marketing in five sub-Saharan countries, and the sale of non-core terminals and marketing assets.

This portfolio has material potential for improvement and growth, either through market growth, margin growth, or new access.

In terms of market growth, we are seeing continued profitable fuels volume and gross margin growth in China, Australasia, Turkey, South Africa, Poland, and Iberia, and opportunities to grow convenience retail in the Rhine geographies, Australasia, and the UK.

Unit margin growth is expected largely to come from configuration improvements to our refineries, and from some structural efficiency programs.

The configuration of Rotterdam, which will be BP's largest capacity refinery, post-exit of Texas City, has scope for upgrading, and we are currently evaluating options, including investment in a hydro-cracker.

Gelsenkirchen also has a number of projects being evaluated to improve an already excellent refining position.

Finally, in terms of new access, we continue to progress options to build on our other positions in Asia.

To complete the fuels value chain picture, where will we be positioned competitively in refining, after the changes we have announced and outlined today?

This shows the Nelson complexity and average scale of BP's global refining portfolio, post-2013, relative to the current position.

Post-divestment of the two positions in the US, and the transformation of Whiting, our average scale and complexity are both slightly lower than today, but still in the pack with our leading competitors.

This is before any further upgrading of Rotterdam.

Perhaps the biggest implications of the announced moves will be simply that BP will be the smallest refiner of the traditional super majors at just under 2 million barrels a day of capacity.

And the proportion of BP's capacity in the US market will fall from 50% of the portfolio today to just over one-third.

That concludes my remarks on the fuels value chains.

I would now like to turn to the international businesses.

Our lubricants business has been growing rapidly, and also delivering excellent returns for a number of years.

I want to explain the sources of growth, and why we are confident it will continue into the future.

On the right-hand side of the chart, you can see that the profit from our land-based lubricants activities has grown significantly since 2007, with an annual growth rate of well over 20% per annum.

The proportion coming from non-OECD geographies is about half of the total, or approaching half of the total, providing a long-term engine for volumetric expansion of the business.

Together with delivery of structural cost efficiencies, this has helped drive particularly high-growth rates recently, but we do expect to continue to see something approaching double-digit profit growth well into the future from volume expansion and mix improvement, underpinned by a strong technology pipeline and powerful brands.

In terms of margin, a healthy product pipeline and the right product mix are key.

And you can see on the bar chart underneath that BP's proportion of highest margin synthetic and premium sales is materially higher than the market average.

Finally, the rapid expansion of the business has not been at the expense of returns.

While delivering material growth, over the last few years, lubricants returns have risen to levels in line with smaller, but high-quality, competitors reaching top-quartile return on sales compared to the consumer goods sector in general.

Our strategy is to leverage technology and know-how, the Castrol brand, and strong marketing capabilities to access new market growth, while also enhancing the margin mix of our product portfolio.

The lubricants business is a great success story for BP and a major contributor to expected overall growth rates.

Turning now to petrochemicals, this slide shows the geographic locations of our main plants.

As you know, our focus is on aromatics, being PTA and paraxylene, acetic acid, and olefin's and derivatives in China.

Beyond delivering safe, reliable and compliant operations, our strategic focus has had four pillars.

Accessing growth in Asia.

Leveraging our superior manufacturing technology and efficiency to contract for further sales volumes, ensuring our plants in the US and Europe operate at high utilization rates.

Thirdly, managing fixed costs to ensure industry-leading returns, and fourthly, continuing to invest in technology and capability for the future.

Our production has been growing by about 3% per annum since 2004, as you can see from the bar chart at the bottom of the slide.

This growth has almost exclusively been in Asia, and principally in mainland China.

Our Asian production has nearly doubled over this period, and in 2010 was about equal to that of the US and Europe combined.

We have many projects under evaluation for further growth in China, the Middle East, and in India.

Profit growth has also been material, with the majority now coming from Asia, as indicated in the pie chart you can see at the bottom right of the slide.

Once again, this growth has not been at the expense of returns.

The chart on the left shows the high level of BP's return on sales versus the competition.

The petrochemicals business is a core part of the downstream portfolio and a key enabler of future growth and returns.

So in the final part of my presentation, let's now turn to what you should be able to expect from R&M, post-2013, when we should have completed the changes to the portfolio I outlined earlier.

Returning to the earlier format, but now looking at post-2012 performance for a range of refining margins similar to an RMM of $8 to $12 a barrel, you can see that the fuel value chains in both the US and the eastern hemisphere are expected to be of a similar quality, delivering 10% to 20% pre-tax return on operating capital, but with the US portfolio smaller than that of the eastern hemisphere.

The international businesses are expected to continue to grow and to deliver pre-tax returns in the 20% to 35% range through the cycle.

Taken together, this means that from 2013,all asset classes should be delivering absolute returns which are attractive, while also being material.

That deals with returns and materiality.

Finally, what about growth?

This slide shows, in the green bars, the pre-tax earnings of R&M, normalized to a 2009 refining margin environment.

The earnings growth has, not surprisingly, been very high, at over 50% CAGR during the recovery period from 2007 to 2009, and is projected to be about 15% to 20% per annum during 2009 to 2012, in line with the goals that I laid out last year.

This represents a material source of earnings growth for BP over that period.

Longer-term, with the investment in Whiting, planned enhancements to margin capture, and some growth in the fuels value chains, and the strong growth potential from the international businesses, we would expect the whole portfolio to be able to deliver sustainable and attractive long-term growth to BP.

The red line on the chart shows the recent improvement in returns.

Longer term, with the improvements I have outlined, we would also expect the portfolio to be able to deliver attractive pre tax returns, well above the cost of capital.

So to summarize, R&M has had another successful year, safety has been and will always remain absolutely the top priority.

We are well on track to deliver over $2 billion per annum of pre-tax RCP improvement by the end of 2012, and we had a good start in 2010.

Like-for-like costs have returned to 2004 levels, and refining achieved its goals of becoming breakeven in a similar environment to 2009.

In terms of portfolio, our goal remains quality before quantity.

We have announced some major changes today.

In the US, we will exit Texas City and the southern part of the West Coast, while continue to invest in Whiting and the other refineries.

This will halve our US refining capacity and reposition the portfolio.

Globally, BP will become the smallest refiner of the traditional super-majors.

In the rest of the fuels value chains, will book continue to enhance margin capture capability and access available growth.

And in the international businesses, we will continue to see material and sustainable earnings growth, and the delivery of highly competitive returns.

Taken overall, in the type of environment I have described, you can expect R&M, post-2013, to be capable of delivering sustainable growth to BP, with attractive returns well above cost of capital, and material earnings and cash flows to the group.

Thank you for listening, and let me now hand you back to Bob.

So, thank you, Iain.

Now before closing and summarizing, let's take a quick look at the highlights of our alternative energy business.

You saw earlier our view on the demand for energy to 2030, renewable energy will be the most rapidly-growing category.

BP has developed a very focused portfolio of assets in this rapidly growing, low carbon energy market, with a total investment of more than $5 billion since 2005.

And we do expect to invest a further $1 billion in 2011, as we believe that, as a leading energy company, we must participate in this future growth.

Our biofuels business will continue to be a strategic priority for BP.

It is a rapidly growing sector, with the potential to supply 5% to 10% of all global transportation fuels by 2020.

We plan to expand our Brazilian operations.

Our advantaged Brazilian sugarcane production compares well against all other non-conventional supply sources.

The supply costs of this are around $50 per barrel of oil equivalent.

We are also developing a position in the southeastern US for the production of lignocellulosic ethanol.

And US regulatory support for this new fuel remains strong, and we expect to sanction our first commercial facility in the next 12 months.

Additionally, we are advancing technology for biobutanol production, through our joint venture with DuPont.

Our other area of focus is low carbon power.

We now have 10 operating wind farms of scale in the US with a gross capacity of 1.3 gigawatts.

This business is now cash-positive and other wind farms will follow.

In summary, we are maintaining progress across our focused alternative energy portfolio, and we will continue to build out our asset base in step with this rapidly growing market.

Now, stepping way back.

In summary today, I hope you see that BP is a changing Company as a result of what happened in 2010.

I believe the changes will be for the better.

These are not just words.

You can see that from our actions, which are highlighted on the slide.

We will meet our commitments.

We are investing for the future.

More in this investment in safety and risk management, more investment in the emerging economies, and more investment in our core strength of exploration.

More investment in new projects, and investment in strategic partnerships.

More investment of the drivers of long-term value.

And yet, at the same time, we are not afraid to divest non strategic assets, both upstream and downstream, if that's the best path.

And we believe we can prudently restore a dividend stream to our shareholders.

We are a Company building on its strength and addressing its weaknesses.

It's a safer BP, an agile BP, a stronger BP, a Company that is a committed to rebuilding value in trust for the long-term and doing it well.

Ladies and gentlemen, that brings our presentation to an end.

Thank you for listening so very patiently.

We would now be pleased to take questions from you here, as well as, we have quite a number of people on the web and on the telephone, and we may go back and forth between them.

So, let me start with this gentleman right here on the end, and then this lady, secondly.

So, right here, first.

Thank you.

Good afternoon, gentlemen.

Theepan, from Morgan Stanley.

Could you talk a little bit about capital intensity?

It seems capital intensity is on the rise.

I was wondering if you could maybe help reconcile the split between the increasing costs around safety, the assumptions you're making in terms of cost inflation for the industry in 2011, and how much emphasis there is in terms of growth CapEx.

And I guess the follow-up question there is, in terms of a new BP, resetting the portfolio, I think you've talked about upstream value growth, where do you see capital intensity for BP going?

Particularly in the context of the peers.

Clearly, this is a year of consolidation for BP.

This is a year for us to get back on our feet, complete the divestments that we have.

You'll see that we are not divesting any of the 32 major projects that we have coming forward.

Some of the timing on the capital intensity will depend on the restarts in the Gulf of Mexico.

But you've seen major capital programs in the North Sea, Angola, further on in Azerbaijan.

And I think part of this year is for us to pace the divestments, pace the start up of the projects, and this is one of the things that we are -- we have had a lot of strategic debate inside the Company about whether we set volume targets, and the pace across those volume targets.

And then, of course, capital intensity and the capital that we progress on these projects depends on some of the decisions that we might have on whether or not we sell down parts of that development chain that we have.

So, it's hard to give a number today.

This is the first year, I think, of BP coming out of the crisis year in 2012 and resetting.

And we will have more guidance for you in the future on that.

Thank you.

It's Irene Himona, Societe Generale.

I had two questions, please.

First, Bob, you're shifting emphasis from volume to value.

Can you give us a sense of the metrics that you would like us to use, as outsiders, to measure that value?

Is it margin per barrel, is it return on capital?

In which case, are there some explicit targets on those metrics?

My second question, on the issue of safety.

Obviously, your predecessor had spent his three years in the position overhauling safety.

Having turned it upside down yourself, can you give us a sense of how big the gap is between BP, on that issue, and perhaps the best-in-class that you are striving to reach?

And how long might it take to actually get there?

Thank you.

I knew people would ask about the exact metrics of volume to value, because, of course, the oil industry has very often set volume targets out there.

That's a simple metric.

And what we are saying is, we have a strong portfolio of projects that are coming on-stream that we think will add 1 million barrels a day equivalent by 2016, which will more than offset natural declines.

But we are also signaling, and we will not give a figure of that yet, because it depends again on the restart times in the Gulf of Mexico for us and many in the industry, but what you will see over time is maybe some decisions to take steps where the volume won't be important, we may be able to unlock parts of that chain.

So, I think, to be honest, long-term, what we are going to do is create value by both a combination of returning value to shareholders, this could be through dividends, depending on the improving fortunes of the Company down the road, it could be share buybacks, or it could be divestments.

It will be a mix of these things, and that will all manifest itself in time in the value of the Company.

In terms of how big the gap is on safety.

We know that we have learned many things in the last year, and we know that the industry needs to learn many things from these events in the Gulf of Mexico.

We have made significant changes in our organization that are now being moved all the way down through the organization.

We've taken some of our best operating people that now work in the safety and operational risk organization.

You saw the charts on the trends of BP's results on safety over a decade.

The broad general trends track industry benchmarks over the decade.

But, we should not sit here today and make any comments, really, about the future with safety.

We will have to prove that by the way we operate our assets.

We are putting in place all of the organizational structure, the tools, the techniques.

We are bringing in expertise from the nuclear industry, the hazardous chemicals industry, into the Company to help us make sure we've looked at things right.

I think these are the things that you should expect us to do, but we'd actually rather speak with our lack of actions, in terms of incidents, rather than words, going forward.

And this will take time.

We have to rebuild trust and faith in the Company.

We know that.

One here.

Right over here, this gentleman, and then I will take a couple of questions from the web.

Hello.

It's Iain Reid, from Jefferies.

Bob, if you look at last year's presentation, you seem to have just moved the production growth numbers back a year, based on a pretty similar set of new start-ups.

How confident are you that you are really going to be able to get back to work in the Gulf of Mexico on the time frame that seems to be just a year, if you like, in terms of total delay, and how confident are you that BP won't be, if you like, singled out for perhaps slightly more restrictive actions, when it comes to approving your projects?

The Gulf of Mexico is just one area that we have, in terms of this portfolio of major projects.

So, that part of our portfolio in the industry has been pushed back.

But we have a very, very large pipeline of projects there, that you saw.

I do not believe that BP will be singled out for special treatment in the Gulf of Mexico.

We are cooperating today daily with the regulators in the United States.

Lamar McKay, who is here, is in contact daily with them on multiple levels.

I don't have the sense that BP will be singled out.

We, of course, are going to hold ourselves to a highest standard and not go back to work, until we are clear that we are ready to go back and ready to go back drilling, with our own standards as well as the regulatory standards.

I think that the investigations, and multiple investigations have come out and said that this is an accident.

Highly, highly low probability accident, that seven barriers failed.

Very low probability, that involved multiple companies, and the industry has a lot to learn about that.

It will change the way we do business.

We already know it is changing the way many oil companies are looking at these operations but I remain confident.

BP is committed to doing business in the US.

We are committed to our resource base in the Gulf of Mexico.

It's a very high quality resource base.

Jason, and then behind Jason.

It's Jason Kenney from ING.

Kind of a conceptual question, really, just to better understand your renewed focus on value.

If we can pretend that Macondo never happened, could you have envisaged accelerating five years of divestments into essentially 18 months, which is what you're doing, in order to unlock value for shareholders, or would you not have seen that pressure, unless Macondo had happened?

I'm just trying to understand the drivers behind why you can see value now, whereas you didn't try this process maybe two years ago, when there was -- at the beginning of a seller's market.

Well, Jason, you are right in one sense.

The Macondo incident created a liquidity issue for BP that caused us to respond, and we responded, and Byron's team responded, incredibly quickly to go out and divest assets and achieve prices that, quite frankly, surprised us, to a degree, in terms of the competition for buyers.

And I think that market is still out there.

We have got $8 billion worth of upstream divestments that we have identified and we will be working on.

We haven't announced anything around that.

And so, in events like 2010, our inflection points, in the sense that they do change what you have to do to respond.

It's a response to the challenges of 2010 that has led us to do things, that has made us realize that there are different ways of unlocking value from the portfolio.

Same, I think, may apply to the decision that we've made within and our downstream businesses to consider divesting significant footprint of our American refineries.

Jason, if I could just add to that.

Again, it comes back to volume.

A lot of these assets were being held in order to shore up the underlying production volumes of the group and maintain production levels close to 4 million barrels a day.

There was nothing inherently wrong with these assets, except that they were mature, they didn't have the longer-term growth prospects that the assets we have retained do.

They added a lot of complexity because of their size and their geographic breadth, that we were able to remove by disposing of them into a very lucrative seller's market at the current time.

Question behind, and then I am going to turn to the US with some phone questions.

Thanks, Bob.

It's Lucas Herrman at Deutsche.

Just following on with value, I just want to better understand what value through exploration means for you, because every year we are shown the hopper, and the hopper gets larger, but the production barrels haven't.

It's not struck me that you are an organization with excess capacity, and that you're not actually using your engineers to the extent you wouldn't.

So just value through exploration and putting more money into exploration, also tie back to that comment of effectively churning the opportunities more aggressively and more frequently, high-grading your own opportunities, exiting other opportunities that you may discover with the drill bit.

Basically, quite what does it mean, because if you look at the funnel, and if anything, value is bringing barrels through more rapidly, and that simply hasn't happened in this company, and many others in the industry.

That observation is not directed at BP alone.

Well, as many say, if you look at the independent oil companies, many of the smaller independents, they create a lot of value through exploration, the expertise of going in and finding something, appraising it, or sometimes selling it after discovery, or sometimes after appraisal.

That's the sort of thing that we haven't done before, as a Company.

So, being able to step in and consider, at least, the potential creation of value, through the exploration drill bit.

The other thing, I think, that a portfolio like that gives us, in terms of creating value, is we have a wide set of assets, exploration, developments, and the opportunity now to partner with national oil companies and other resource holders to open up new strategic options for us, in other ways that are different.

We have seen that, for example, in Germany, with Ruhr Oil, for example, we have sold that asset and instead we have joined with Rosneft in that partnership in Germany, which has, I think, helped create an alliance that has now opened up other opportunities for us.

The divestments that we have done, in Venezuela and Vietnam with TNK-BP, they will be able to add more value to those assets through our divestments.

These, I think, are strategic steps we've made to unlock value that we wouldn't have otherwise had, and created value to TNK-BP.

I think we are good explorers.

I think Mike and his team, and the prospects that we have, and the continued attention we have had from governments around the world who now would like us to work with them, because they believe that we have learned a hard lesson in the Gulf of Mexico.

They would like us to have us bring our expertise, advise them on regulation and what they should be doing in terms of prevention skill response, is actually opening up opportunities for us now.

We have seen, in some of the things that have happened in the last three months, that's been a factor in it.

And do you have the prospect inventory to double your exploration spend at this time?

And sensibly double that spend, rather than spend twice the amount, because you can?

Well, you are absolutely right.

You have hit on a key point of discipline in exploration spending.

And this will not be an overnight increase in exploration spending.

Mike and his team have a very disciplined approach to exploration, but I think we have constrained that for some time, so we will migrate up to a doubling in exploration spending, certainly not overnight.

But there is a very good inventory of exploration prospects, and we will not start drilling any of those until we are ready, in terms of the rig capability and our working with contractors to our satisfaction anywhere.

I have a question here from Joseph Tovey from Tovey & Company.

Are we hooked up to be able to take that question?

I hope so.

Good, Joseph.

We can hear you loud and clear, here in London.

And you are in New York?

Yes, unfortunately.

But we are enjoying the snow, and I hope that it results in good sales.

I did want to say, by starting my comments, that I very much appreciate the clarity and the specificity of the information that has been provided.

It is very helpful, indeed.

I just had several questions.

The planed disposition of the California refinery, the Carson refinery.

Is that also a comment on long-term view, with respect to the California economy and the regulatory scheme?

I'll just give a simple answer, which is no, but then I will let Iain expand on that.

Sorry, Joe, I was expecting a list there.

As Bob says, it is not to do with that.

There is a combination of things.

As we outlined, the fundamentals are changing, and I believe in Europe and the US, our industry is going to have to make choices, and there will be winners and losers.

For people to win in the integrated business, they will have to run integrated businesses built around highly-upgraded refineries and they need to be well-located and flexible.

For most refiners, they are going to have to upgrade them still further to achieve that, and they will have to invest in the logistics and marketing to do that.

We are already investing significantly into Whiting and, east of the Rockies, into Toledo with our partner Husky, and into Cherry Point.

And as we balance all the various pressures, and when we look at the fundamentals and the economic performance of the businesses today, we have concluded that we will not be able to spread ourselves so thinly as to invest in all of the assets to upgrade them, and we are choosing to do so in the ones that are most strategically advantaged.

So it is a strategic decision and has nothing to do with the Californian economy or the regulatory issues

Thank you.

Moving right along, if I just might, is it your anticipation that the biofuel issues are going to impact upon gasoline marketing and the refinery situation, with respect to gasoline, more than it will affect diesel and other motor fuels?

Yes.

Clearly we predict longer run biofuel penetration of 5% to 10% of the worldwide gasoline pool, probably the whole fuel pool, potentially.

I think that bio penetration will therefore impact on demand growth for fossil fuel, which again says you have to focus on quality, and in certain regions, I think it will impact it more.

And that does play into why we want to build out the Cherry Point refinery for diesel and jet capability, and why we are choosing to invest elsewhere and divest the southern part of the value chain.

And the last question, if I just might.

I noticed that you were expanding Rotterdam at a time when there seems to be at least a 15% over-capacity in North Atlantic refinery capacity.

Am I missing something obvious?

You are, slightly, in that we haven't actually decided to expand it yet.

I said that we are exploring what we might do to improve it.

It isn't expanding the capacity, and I think this is a really important point.

This is not a quantity game anymore in Europe and the US.

It is a quality game.

So what we are looking after here, is Rotterdam is exceptionally well positioned, it is tied into our integrated business through the Rhine and pipeline, and it is about upgrading the margin capture, not increasing the volume, and looking at increasing more diesel, and less gasoline.

I think that's the right approach.

Thank you very much.

Appreciate the help.

Thank you, Joseph.

Let me ask John, in the back.

Then I'll go back to the web.

We have a lot of questions--

Thanks, Bob.

I have three questions about runoff through all three, and maybe you can just choose in which order to answer them.

The first is just on the trading.

It looks, referencing your comment, I think, of about $1.4 billion down on trading and also retail, that maybe trading in 2010 was down $1 billion or more.

How much of that would you expect to come back, or are there some structural changes in the market, or that you think it won't all come back?

The second is on buybacks.

You've talked about value and clearly one of the value decisions will be the value of your shares.

And in the past, and I think some of your competitors talk about share buybacks as a flywheel, essentially it's almost like a blind buyback, and the references to spare cash that sits on the balance sheet.

Will you be a bit more nimbler about the decision to reinvest in buying back your stock?

And the third one, is I am conscious as I sit here, I am looking at one of the UK's largest companies with only three Executive Directors facing me.

That's quite unusual, even by historic standards at BP.

Is there a prospect that the executive side of the Board will be increased over time?

Thanks.

Byron, you want to comment on the trading and the buybacks?

I'll comment on the third question.

John, as I said in my remarks, the long-term performance from the supply and trading organizations, whether they are focused on gas and power, or oil and products, has been very good, and that 2010 was an unusually weak year, and we wouldn't expect that the sort of out-turn that we saw in 2010 would be something that would pursue into 2011.

I also pointed out 2008 and 2009 were particularly good years, so you're kind of seeing, from the top-end of things down to relatively weak performance, and one needs to calibrate in line with both of those dimensions.

So, we will continue to describe the trading performance, whenever it's a material deviation from the norm on a quarter-by-quarter basis and, as I said, we are taking steps to ensure that the cost structure is right and the focus is aimed at opportunities that will add value to the firm.

As far as buybacks go, since I've overseen the majority of those buybacks during my tenure as CFO, I think it's premature for us to be talking about how we would go about it, given that we've just restored the dividend as of today.

Clearly, if we find ourselves in the situation where the appropriate thing to do to add shareholder value is to distribute some of the cash via a share buyback program, we will certainly be cognizant of some of the errors that have been made by firms in the past.

And I think I would add, on the buyback point, is that the Company, with its dividend level had moved itself where was somewhat dependent on the high price of oil to maintain, and then during the commodity price cycles, there was a period there where they had to borrow to pay the dividend.

We clearly don't want to get back in that sort of range again.

And where there's an opportunity to both increase the dividend, depending on the changing fortunes of the Company, or consider buybacks, we do have a period of time to continue funding the trust fund in the US, so as Byron said, it's a little early to talk about buybacks.

On the Executive Director role, there is three.

I don't think that's actually that unusual.

But our Chairman is here.

You may want to comment, Carl-Henric.

I think it isn't that unusual, in companies in the UK, in terms of the number of Executive Directors.

But that is clearly a decision for the Board to make.

Care to --?

No?

Okay.Thanks, John.

Let me ask Pavel Molchanov, who is on the phone with Raymond James in the US.

Thank you very much.

Two questions, if I may.

First, on the refinery sales.

You mentioned that 2010 was actually the first year of profitability in a number of years for your refining business.

And yet now is the time that you are looking to sell it.

What is it right now that inclines you to sell it into what is really more of a buyers market for refining assets as opposed to waiting for continued improvement in the business?

Thanks, Pavel.

I think, basically, we have come to the conclusion that the outlook for refining margins is going to be similar to pre-2004 levels, rather than the brief period during 2005 to 2008 when we thought that it was Christmas.

This business is over supplied.

And therefore, it's again, I repeat, it is a quality game.

This isn't about suddenly deciding to get out, we are going to stay in the business, but it is about quality.

The reason we have decided now, is because we have concluded what we think the outlook looks like, but also very importantly, as I outlined before, we have concluded that we have to focus.

And we have to focus on the most advantaged positions and having got Texas City and the West Coast back into a place where they can be profitable in this type of environment, they are now very salable ongoing concerns, and it seems the right time.

Okay.

Follow-up is on TNK.Clearly, there is some disagreement between you and your partners regarding whether the Rosneft alliance is consistent with your contractual obligation under TNK.

I'm just looking to get some color for your perspective on this issue.

Yes, I think, in fact, as I am sitting here we just received some good news, I think.

It was an arbitration hearing about a few hours ago on the TNK and the Rosneft transaction, and the Court has ruled that we should move to an expedited tribunal process to be resolved by February 25.

This is good.

I think that this is something that will be resolved in a very reasonable business way between BP and the Russian shareholders of TNK-BP.

And I think that this is one more step forward.

There has been a lot of noise about it, I think a lot of it has been sensationalized.

The relationship is pretty good.

Maxim Barsky is here today from TNK-BP.

Eduard Khudainatov and the team are here from Rosneft.

I think I would watch again.

I wouldn't read headlines, I would just watch and see what happens.

And I think this will be resolved.

One more quick one on TNK, if I may.

Are you still looking to move to an IPO of the Company in the next few years?

That's up to the board of TNK-BP to talk about.

It has been discussed for a number of years.

Maxim, if you want to comment, you're welcome to.

But I think this is something that the Board has been considering.

But as far as I know, and I am not on the Board of TNK-BP, this is not an immediate agenda item for the Company.

Is that fair?

Maxim is here, and is saying that's correct, but, anything is possible.

Hi.

Oswald Clint, Sanford Bernstein.

Just a question, actually back on Russia.

TNK-BP did quite well last year in terms of production growth.

I think they were targeting 1% to 2% this time last year and it came in at 2.4%.

Could you talk about what's underlying that, and do you think it could do better than the 2% you're talking about over the next couple of years there?

Secondly, just on Canada, it's one of your smaller MPV bars, but you talked about it having the potential for significant growth and the integration with the refinery.

How could you get that growth?

Is that focused on the oil sands and can you lift that materiality?

And maybe just a quick third one, actually.

Just on the million barrels per day of extra production by 2016.

It does seem to imply, from today's production levels, really a 4% or 5% decline rate, maybe at the 4% level, just to get to offset declines by 2016.

Is that your underlying assumption there, and are you confident that you can work to those types of base decline rates?

Thank you.

Well, we have divested -- the assets we have divested have been declining assets, so we have always said our decline rates were between 3% and 5%.

The fact that we have divested assets with a decline rate, you can see that our decline rates are probably, going forward, are going to be at the lower end of that range.

But we will not give you an exact number.

On TNK-BP, we have had the new startups in Verkhnechonskoye, this is in Tabul, yet to come, Uvat and Kamennoye fields that resulted in the greenfields, the transition from the brown field stages now into some greenfield production that is coming on, and there is more.

I think a 2% estimate over the next five years is a good estimate, based on what we know about the water flood declines and the new greenfield projects.

And on Canada, we have a position in the Canadian heavy oils.

It is not Canadian, it is not mining, it is SAGD.

Some of our projects that we can develop going forward as part of linking the value chain of heavy oil into the midwestern refining.

The margins of that will move between the refining in the upstream, and that's why we see integration value of those refineries going forward.

We haven't made decisions yet with Husky, our joint venture with Husky, they've made a decision to start developing one of the projects up there, and we have another one in our inventory to decide yet whether to take it on or not.

Let me turn to Lucy Haskins, who is on the phone here in the UK, from Bar Cap.

Many thanks for the presentation.

Can I ask, in terms of your assumptions for 2011 and the 2016 projections, how much will Iraq contribute?

And also, how do you expect to actually book the profitability from those barrels?

Iraq -- Production is rising rapidly right now in Iraq.

It is a very complicated question to ask, how we will book the profit from those, and I would actually suggest you phone in to Fergus' office.

Lucy, we will treat it as we would other production sharing contracts.

It will have a significant level of the DD&A, and that was referenced in my earlier remarks.

But as Bob said, it's a complicated structure.

It's the first structure of its sort, so we will be the first ones reporting on that basis.

We have spent a lot of time thinking about the accounting-related aspects of it and believe that we have it right, and it will come through in a way that is not materially dissimilar to production sharing contracts, but will of course be built around its own contractual structure.

And so are we talking about, say 70,000 barrels a day for this year?

I think we are looking at 50,000 barrels a day for 2011, and then beyond that some growth.

And I guess beyond that it's sort of contingent, in terms of the spend you're putting in place effectively, and have you got a feel for knowing what kind of CapEx you wish to commit in each year to that part of the world?

You're asking us to look ahead about decisions we will be making on an ongoing basis, but as you say, Lucy, the production stream will be linked with the amount of capital that we are investing, and as Bob said earlier, the fact that we have now gotten through the initial production level of requirements means that we are recovering the capital that we put in earlier in 2010.

So, this is a project around which the risk factors are well-mitigated by the structure of the contract.

Sure.

And then where the results numbers you took in 2010 taken from Iraq, or did you wait until you've reached cost recovery before you start to think about reflecting those barrels in your reserve and resource basis?

We will save discussion about the specific contributions to reserves when we report under our annual report of accounts in about a month's time, Lucy.

Thanks very much.

Thanks Lucy.

Question, Alejandro?

Hello.

Alejandro from Merrill Lynch.

A couple of questions here, the first one is on the ideal size of the new BP.

Byron, you have been talking about some of the assets you disposed was because you were trying to prop up some of the production levels.

Is there an ideal level of production that you see for the Company going forward?

And when you look at this value creation is it that kind of level of production that the value creation will surround that?

I don't think we will say that there is an ideal level of production.

I think what we have is a set of assets with a portfolio of projects coming through that can add significant volumes by 2016 that will offset natural declines in the portfolio.

And then we will look at how to use that portfolio for other things, if we decide to do that.

I know everyone would like to hear a production target from us, essentially, but we are just not going to do that this year.

This is a year of consolidation for us, of building the foundations for going forward.

It will be clear, as we move through the year, but it is just not the right year for us to give a production forecast due to the timing of divestments, some of which have yet to be announced, as well as the startup and getting back to work in the Gulf of Mexico for the entire industry, and OPEC quotas and the high oil prices that are happening right now are impacting production levels for companies with DSAs.

All of these variables make that not simple to forecast, and we would rather not that today.

If I could, with your question, we have one on the web which I think is it relevant to your question.

What gives you confidence in the US government will not act to limit your role in the Gulf?I think the fact that we have responded the way we have, we have consistently said we'll meet our commitments in the Gulf, the relationships that we have daily with the regulators at all levels in the US government, I do not believe that the US government will take steps to limit BP's activities in the Gulf.

The pace of startup for us and the entire industry is, I think, the bigger issue.

Right here, and after this question, I will ask Paul Spedding from HSBC, and then after that Mark Gilman from Benchmark.

Peter Hutton from RBC.

In the past, we have tended to hear quite a lot more about US gas and the opportunities there, and the fact that it's been breakeven at $3 to $5 per barrel.

We have not heard very much on that today.

Is that because it did not break even at $3 to $5, or is that because it maybe falls the wrong side of the volume versus value criteria?

We have re-based our business in gas in the US, so that it is, returns its cost of capital at $4 an MCF.So, we haven't spoken about it today, because we have had a lot to talk about.

Actually there would've been a lot of other things we could talk about today, but there, clearly is -- the dynamics of the international oil and gas business have been affected greatly by the discovery of the resource base in North America, which has brought down margins broadly in gas in North America and has had a knock-on effect in terms of Europe, and the flows of LNG into Europe have been diverted from the US into Europe.

And this has had an impact all across the globe.

We have a very sizable North American gas business that we need to resize up for this reality of gas pricing.

And we have done that.

We have done a good job of that, and there are people here afterwards that you could ask about specific activities in that in that --

Paul?

Paul's gone.

Okay, Paul left.

Let me ask Mark Gilman from Benchmark, in New York, I believe.

Thank you, Bob.

Can you hear me all right?

I hear you loud and clear, Mark.

Just three quick questions, one for you, one for Byron, and one for Iain.

Bob, for you, I respect your confidence regarding BP not being singled out with respect to the Gulf of Mexico.

Should you feel that were to be a possibility, would you be willing to cede operator-ship, or perhaps bring in a partner that might not be tainted by the recent history?

For Byron, can you give me an idea under what circumstances and over what time frame, if my assumption is correct, that would you be willing to take the Company more towards its historical and conventional gearing structure.

And then finally, for Iain, I guess I am a little bit surprised that as part of an asset oriented review of the global refining system, that Rotterdam and your Australian units don't wind up being considered somewhat disadvantaged, given both market location and hardware configuration, and perhaps you could help me understand that.

Thank you.

So, Mark.

Our confidence in the US.

I don't believe we are being singled out.

So it would be sort of hypothetical to talk about, if we were singled out what would we do.

We have great operating capability in the Gulf of Mexico, with our offshore experience there, with a wide ranging number of fields, some of which we operate and we are involved in projects where others operate.

But we don't have any plans to shift the operator-ship of those assets.

With respect to your question about debt and gearing, I said that we're transitioning from a range of 20% to 30% down to a gearing range of it 10% to 20%.

We want to transition into the lower end of that range, because when you are at the lower end and you've got the flexibility to deal with uncertainties as they appear, and we would expect to get down there over the course of the next couple of years.

And Mark, on the refining question.

If scale and Nelson complexity were the only criteria for choosing what to hold and what not to hold, then you would be absolutely right.

We have just announced the sale of two of our largest and most complex refineries.

And the reason for this is that our strategic review is not just focusing on scale and complexity, because in our view that won't be good enough long run.

It's also got to be right place, with flexibility in feedstock and production, integration, into an integrated chain that allows you to lock in high utilization rates, and the ability to optimize the situation.

Now, we could've built that further around Carson and Texas City, but it would've meant further investment.

If you take the other two, Rotterdam is brilliantly located in the right scale, but it doesn't have the right configuration yet.

You're absolutely right, but it is integrated into our business.

And in the case of Australia, our Australian business is doing extremely well, and it's being pulled on by demand growth from China and other places.

We will look at whether we should upgrade those further, but they are in the right place.

So in simple terms, size and complexity, sorry, are not the only criteria.

Thank you guys.

Okay.

I have a question here on the web.

Can you please give us an update on your expectations on the authorizations from the Brazilian authorities for the acquisition of the Devon assets?

It's a good question.

We were down there in Brazil in November and met with the authorities.

They have asked us for additional information, primarily around spill response activities, and BP's commitment to investing in a country beyond just the offshore.

We provided that information, and we believe the next time that the commission who makes the decision will meet is in March.

We believe that is the next time it will have a review in its normal cycle of reviews.

Ed Westlake from Credit Suisse in the US.

Yes.

Good afternoon in London.

Two questions, if I may.

Just coming back to the Gulf, obviously in conference call commentary over here, people are concerned perhaps about some of the permanent requirements, particularly the containment requirements of NTL-10.

Do you think the industry and yourselves are ready today?

And if not, when will you be ready and what would we need to see?

That's the first question.

The second question is really around asset integrity.

Obviously, Alaska and the North Sea are still a meaningful portion of your NAV, what reviews have you done and how confident are you in the integrity of the assets, and broadly your overall portfolio, specifically, do we think that 2012 and 2013, we will see another period of high upstream turnarounds?

On the US and the signals that have come from the US that companies are not ready to go out and drill in the Deepwater, based on comments that have been made by the regulator.

The Marine Well Containment Company has been formed just recently, and we have just joined that, along with Exxon, Chevron, Conoco, and Shell.

And as part of that, we have an inventory of equipment and caps and materials that were developed from the oil and gas spill in Macondo that are now being brought into that.

It will have long-term research to develop new tools and techniques, and we are bringing what we have out of the warehouses to join them.

It will be up for the regulators to see if that is sufficient.

That along with plans and having rigs available to begin relief wells, should something like that ever happen, and again there is a very low probability that ever happens again.

I think it's a decision for the regulators.

It's a good question.

But you've got the best R&D and engineering capability in the industry has come together and recognized that you need to be able to respond with that.

That's one way.

And there's also a second company led by Helix, and 16 independent operators who have joined forces to be able to be ready for a response.

But I think that debate will go on for some time in the US.

It's not unexpected.

But do we feel that the US will not get back to work in the Gulf of Mexico?

I find that highly, highly unlikely, given the economic contribution that the oil and gas industry brings to the United States.

Roughly 400,000 jobs, direct and indirect that have been identified for that industry.

I just would be very surprised, following thorough review of the US, that the industry does not get back to work.

On asset integrity, we have gone through and looked at many of our assets, Bernard or Bob, I might ask you to comment on that, but we see 2011 as a 50% increase in turnaround as being unusual.

We don't see this continuing on.

We have ongoing asset integrity programs going on in Alaska and the North Sea and in Angola, but we don't see the levels of turnarounds continuing on beyond this year.

Bob Fryar is going to add a little bit.

Bob, I would just agree with that.

As Bob had said throughout the day, really the heart of the agenda is safety and operational risk.

A big part of that priority really is about strengthening process safety and reducing operational risk.

And the way we are going to do that in 2011 is to invest more in the assets, and this is all about investing in integrity management.

We think that 2011 will be as an increased year, compared to previous years, as we go forward, we will expect to see that step down a bit.

Thank you.

Question over here, on the right side.

Neill Morton at Berenberg.

I just wanted to clarify your comments on the dividend.

On the one hand, you made reference to the fact that perhaps the previous level was a bit too high, a bit too reliant on high oil prices.

Yet the statement today makes reference to growing the dividend in line with the improving circumstances, rather than perhaps earnings.

A golden scenario, whereby the $40 billion of provisioning proves too conservative, are you allowing yourselves flexibility to perhaps reset the dividend again, at a higher level, at a future date?

Thank you.

Certainly we would have the opportunity to reset the dividend level, going forward here.

Now to what level, I think that's -- I do not believe that we will reset the dividend at the level, given the cash flows of the Company, where we are reliant on high commodity prices.

That's really the message here.

And it's somewhere in between the scope to increase the dividend.

It's worth pointing out that we have an obligation -- previously, we were paying a dividend of roughly $5 billion a year -- $10 billion a year.

Keep in mind that we now have set a dividend level of roughly $5 billion a year, and we have an obligation to fund the trust fund in the US through the end of 2013 at $5 billion per year.

So you can see there, in terms of cash, there's a lot of heading into the trust fund in the US and should there be recovery from partners, should some of the $40 billion or $41 billion that we have provisioned come back to us, the scope, and also at the end of 2013, when we end the funding to the trust fund, there will be significant free cash projected available out there.

But the key word here is the fact that, today there is a huge amount of uncertainty about many things.

And until some of those uncertainties are clear, it's important to establish at a prudent level that we are confident that we can maintain through the medium term.

And that was the thinking that the Board went through, at the time it established the resumption of the dividend that was announced today

Let me take one more question from the telephone.

Blake Fernandez of Howard Weil in the US.

Good afternoon.

Thanks for taking my question.

I had a question on the $6 billion that you billed to your JV partners to date.

You referenced various investigations, inquiries and litigation that is pending.

Are any of those triggering mechanisms to prompt that payment, or are we looking at a situation that you are ultimately going to have to go to arbitration?

Well, we continue, as the costs come in, we will continue to bill the partners.

I think, as we have waited to begin an arbitration process until it was clear what some of the findings of the investigation will be, and some of the conclusions.

As those inquiries and the commission has come through, we do not believe that there is evidence to suggest that we are grossly negligent.

Therefore, we believe we will have recovery from our partners.

We have not initiated formal arbitration to do that.

That's one of the steps we would consider.

Settlement is another step that we would considering.

But we haven't initiated that, because of where we are in certain procedural matters with the hearings.

But I think over time, as the facts of the case continue to emerge, I think it will become clearer and clearer that we have a strong case for recovery from partners.

None of which is, again, included in our provisions.

Thank you, Bob.

Okay.

Thank you, Blake.

Ladies and gentlemen, it's 4.35.

Unless there is a one last question from this side or this side, I will take one from the phones and then we'll wrap it up.

Let me ask Bertrand Hodee from Kepler here in the UK, on the phone, and then we'll wrap it up.

Hello, gentlemen.

Can you hear me well?

We can hear you loud and clear.

I have a very quick question.

Can you confirm that out of this 1 million barrels a day of new production coming from 32 projects, that you rely on the fact that Iraq's volumes are not included.

They are not included, that's correct.

Thank you very much.

Okay, ladies and gentlemen.

Thank you very much for sticking with us.

You've all been very patient, and we will see you next quarter.