英國石油 (BP) 0 Q0 法說會逐字稿

Good afternoon, ladies and gentlemen.

Good afternoon to all of you here in London, and good morning to all of those in the United States.

They are connected live to us for this presentation and question-and-answer session.

We're delighted that we're meeting with you face-to-face here in London, and we also have the opportunity of a live-link with New York.

In London I have with me Byron Grote, well-known to all of you;

Tony Hayward, my successor, CEO designate;

John Manzoni;

Vivienne Cox who is in the audience here, and Bob Dudley, along with other members of the leadership team.

And in New York we have Bob Malone as our host, along with Iain Conn, David Allen, Andy Inglis and other members of the US leadership team.

I'm delighted that Andy Inglis has recently been appointed to the board to lead the E&P segment taking over from Tony Hayward.

Before we start, I would like to draw your attention to two items.

Firstly, I would like to draw your attention to the words on this slide.

We may make forward-looking statements which are identified by the use of the words will, expect and similar phrases.

Actual results may differ from these plans or forecasts for a number of reasons such as those noted on this slide.

Secondly, as this slide points out, the presentation today contains some non-GAAP measures.

A reconciliation of these non-GAAP measures to the nearest GAAP measures can be found on our website.

As you know, my friend and long-standing colleague, Tony Hayward, was recently named by the board as my successor.

Tony and I have worked closely together for at least a decade and a half, and I'm excited about him leading the Company.

We have already begun our transition.

Tony has the skills and experience to lead the Company to further success over the coming years.

He will also have the support of a very able team we have built over the last few years.

Now I was thinking the other day that this is my 47th results presentation as CEO.

These events have been events I have actually always looked forward to, a sort of report card as we have built a truly great company.

Now some report cards were better than others, but by and large when you step back, you can see what has been accomplished.

There has been a lot of noise and talk about BP this last year.

A lot of this has obscured many of the great accomplishments of our staff around the world.

Finally, let me say that it has been a real privilege to have had the opportunity to lead BP in a period when it has become an international company at the forefront of the energy industry and to work with so many talented people both inside the Company and outside it.

And I include all of you if I may.

I'm sure that there is plenty of occasions to thank people in the next six months until the end of July for the opportunities that I have had and for the support I have received.

Now back to today.

Today and over the coming months there is work to do and we need to get to it.

I will start as usual by reviewing '06 in general.

After which, Byron will take us in detail through the 4Q and full-year results which were disclosed in our SAE this morning.

Then I would like to talk about the strategic positioning of the Company and the operating priorities we are pursuing.

Our focus today is on E&P, which will be covered by Tony and by Bob Dudley, the CEO of TNK-BP, and on refining and marketing which John Manzoni will discuss.

After that, I'm going to put it altogether in terms of guidance for the forthcoming year, and after the Q&A session that we're going to have, the leadership teams in London and New York will be available for further discussions.

So first to the results.

In '06 we delivered a replacement cost profit of $22.3 billion, up 15% over last year, and this is equivalent to $0.1111 per share, up 22% over '05 showing the additional benefits of share buybacks.

The post-tax operating cash flow was $28.2 billion, up 5% over '05.

The quality dividend to be paid in March will be $0.10325 per share, up 5% on the prior quarter and 10% higher than last year.

We distributed $23.2 billion to shareholders, including $15.5 billion in share buybacks, thereby reducing share as an issue by around 6%.

We realized $6.3 billion of disposals, and our financial condition is strong with gearing ending the year at 20% at the bottom of our target range, 20 to 30%.

Now although we had record results, several incidents have occurred in the US that have negatively impacted on performance and hurt our reputation.

We had two spills in Alaska.

The startup of the Thunder Horse field was further delayed with knock-on impact on Atlantis, and there were allegations of improper trading activities in the United States associated with the propane market.

We have taken actions to investigate these issues, to learn from them and to respond to them.

The report of the Baker Panel on US refining, which I commissioned following the Texas City refinery incident in '05, is unique in its subject matter, breadth and clarity.

As we have made clear, BP commits to implement the panel's 10 recommendations.

BP is now consulting with the panel on how best to do this across our US refineries and how to apply the lessons learned elsewhere in our operations.

As the report technologist, BP has made significant changes to its process safety systems since the accident at Texas City.

But we can do more, and we will do more.

It will make a difference to BP and to the industry as a whole.

I believe we're making good progress and are in the early stages of transforming BP into a leader in process safety as the panel recommends.

Our '07 plans already includes significant investments on integrity management, and I will discuss these later.

There were, as I mentioned earlier, many positives in '06.

Across the group, our staff continued to perform strongly.

Their efforts enabled us to achieve a number of milestones.

Our reserves replacement ratio using reserves calculated in accordance with SEC guidance was 113% on a combined basis of subsidiaries and equity accounted entities, excluding the effects of acquisitions and divestitures.

We have elected to move solely to the US Securities and Exchange Commission basis of reserves reporting to simplify disclosures and to allow for easier comparison to competitors.

We continued our strong track record with 10 new discoveries including Kaskida, Titania, Urano, and in the Uvat area.

We secured a new access option in Pakistan, an initial presence in India and in Oman which was announced last month.

We started nine new upstream projects, notably the Baku-Tbilisi-Ceyhan pipeline and the gas codesense project from In Amenas in Algeria.

We started Texas City safely and have so far achieved a production rate of about 250,000 barrels per day.

We commissioned the first LNG receiving terminal at Guangdong, China.

We made significant progress in alternative energy by building momentum in wind and solar through capacity increases, and we announced plans to invest $3 billion at the Whiting refinery in the US to process heavy crudes from Canada.

So, in summary, record results, a number of significant milestones, but some major incidents.

Let's now have Byron take us through the key aspects for 4Q and the full results for '06.

Byron?

Thank you, John.

Good day.

I will now elaborate on our fourth-quarter and full-year results starting with a summary of the trading environment.

Overall the trading environment weakened significantly during the fourth quarter.

I will now look at each of our indicators in turn.

After increasing over most of the previous two years, our average oil realization declined in the fourth quarter to around $56 per barrel, although it is still 5% higher than in 4Q '05.

By contrast our average gas realization has been relatively flat since the second quarter.

Our 4Q gas realization of around $4.40 per 1000 cubic feet was 30% lower than the quarterly peak experienced a year earlier.

Taking both oil and gas together, our total hydrocarbon realization was 10% lower than in 4Q '05, but still 12% higher on a full-year basis compared with last year.

Our refining indicator margin in the fourth quarter was $6.30 per barrel, 17% lower than in 4Q '05 and around half the peak level seen over the past two years.

Finally, although not shown on the slide, retail margins in 4Q were significantly lower than both the prior quarter and a year earlier.

Turning now to the financials, I will focus my comments on our fourth-quarter results shown at the top of the slide.

Our replacement cost profit was $3.9 billion, 12% lower in absolute terms than 4Q '05 and down 6% on a per share basis.

Our profit, including inventory gains and losses, was $2.9 billion, down 22% compared to last year.

These figures include charges from nonoperating items, which were around $200 million in aggregate in 4Q '06.

I will describe these items in more detail when discussing individual segment results.

Fourth-quarter operating cash flow of $5 billion was 17% higher than a year earlier and up 24% on a per share basis, reflecting the benefit of share buybacks.

The $0.10325 per share dividend announced today, which will be paid in March, is up 5% on the prior quarter and 10% higher than a year ago.

The Sterling dividend is down slightly year on year, reflecting the sharply weaker dollar.

Whilst we recognize the effect that the exchange rate has had on the Sterling dividend, let me remind you that this is a dollar business, and we manage the financial framework of the group on that basis.

Despite the softer 4Q environment, our full-year replacement cost profit of $22.3 billion is 15% higher than 2005 in absolute terms and up 22% on a per share basis.

We also generated 5% higher operating cash flow than in 2005.

I will now summarize our segment results, starting with Exploration and Production.

In E&P we reported a pretax profit of $5.1 billion for the fourth quarter compared with $6.6 billion in 4Q '05.

This reflects lower gas realizations and lower volumes, the continued impact of sector-specific inflation, greater integrity spend and higher non-cash costs.

Non-operating charges for the quarter improved versus last year, mainly due to the relative change in the valuation of embedded derivatives relating to our North Sea gas contracts.

Excluding nonoperating items, our underlying result was $5.2 billion.

Reported fourth-quarter production of 3.84 million barrels of oil equivalent per day declined 5% relative to 4Q '05.

However, taking into account the impact of disposals and lower entitlement in our production sharing contracts, production was broadly flat.

The TNK-BP fourth-quarter contribution of approximately $180 million was much lower than 4Q '05, reflecting the absence of last year's divestment gains and the adverse effect of lagged text reference prices which I highlighted in last quarter's webcast.

Turning now to Refining and Marketing, we reported a fourth-quarter profit of just over $300 million.

Excluding nonoperating items, our underlying result was $600 million higher than a year ago.

This reflects higher refining throughput at Texas City and the absence of the significant rationalization costs taken in 4Q '05, along with a smaller charge from IFRS fair value accounting.

These positive factors were partly offset by higher turnaround costs, greater integrity spend and lower refining and marketing margins.

Our 4Q result in gas power renewables increased to $470 million.

This includes a significant contribution from nonoperating items mainly related to gains from disposals.

Excluding nonoperating items, the underlying result was down $200 million versus last year.

This reflects lower contributions from our NGL and gas marketing and trading businesses, as well as a smaller fair value accounting gain.

In Other Business and Corporate or OB&C, the fourth-quarter underlying charge was just under $100 million.

This brought the full-year charge to around $900 million in line with the guidance that I provided you last February.

Looking to 2007, we expect a similar annual charge for OB&C of around $900 million with an uncertainty band of plus or minus $200 million.

Consistent with previous guidance, we expect the effective tax-free on earnings to be around 37%.

This compares with a 35% rate in 2006, which was impacted by a number of once off items.

This guidance is based on the assumption of similar market conditions as in 2006.

The rules of thumb that some of you use to model our results have remained largely unchanged.

As in the past, these should be considered simply as broad directional indicators, which are more useful on an annual basis than for quarter-on-quarter comparisons and for price moves within a much narrower range than we have seen over the past few years.

Returning to the 2006 results, this slide compares our sources and uses of cash for the past two years.

Cash inflows in 2006 were more than $34 billion.

Operating cash flow exceeded $28 billion, and disposals added more than $6 billion.

Uses of cash remain consistent with our strategic intent.

We have reinvested nearly $16 billion of this cash back into the businesses and also increased total shareholder distributions by 22% to $23 billion.

Our net debt ratio ended the year at 20%.

The 4Q increase reflects normal year-end working capital and tax phasing.

Consistent with our commitment to distribute 100% of our excess free cash flow to investors, we bough back $15.5 billion of shares in 2006.

We also issued the last tranche of shares related to TNK-BP.

The net effect was a 6% reduction in shares.

Buybacks are continuing in 2007.

Since the start of the year, $1 billion of shares have been purchased under our closed period buyback program.

We now have fewer shares outstanding than immediately prior to the ARCO acquisition in April of 2000.

That concludes my presentation of the results.

Now back to John.

Byron, thank you.

Those were the results, but they should always be seen in the longer-term context.

Strategy is the starting point.

During the last decade, we have operated a strategy which has enabled us to shape our business direction, respond to the external environment and make portfolio choices.

It is based on economies of scale, quality of assets and the responsiveness to market trends.

It has enabled us to deliver distinctive growth across a number of dimensions.

Since 1995 our oil production has grown almost threefold to 3.9 million barrels of oil equivalent per day, and production per share has increased by a factor of 1.5.

At the same time, the share of gas production has more than doubled, and we are now the second-largest gas producer amongst IOCs with production of 8.4 billion cubic feet of gas per day.

A major part of our success has been the number of discoveries and reserves added through exploration, along with the lowest finding cost per barrel in the industry.

This has contributed to our reserves more than doubling to 17.7 billion barrels of oil equivalent.

Our footprint is much larger.

The number of countries in which we produce more than 100,000 barrels per day has increased from three in '95 to eight in '06, and we now have significant positions in the deepwater Gulf of Mexico, Trinidad, Angola and Azerbaijan while maintaining our strong presence in Alaska and the North Sea.

We have also established a significant footprint in Russia with investments of around $10 billion through our joint venture TNK-BP.

Consistent with our strategy over this period, we have divested assets generating over $56 billion of proceeds, of which $25 billion was in respect of E&P assets.

These numbers include the divestment of the non-core olefins and derivatives portfolio in petrochemicals, whilst retaining the PTA and acetyls business where we are market leaders with advantaged technology.

In the downstream we have also increased our footprint since '95.

Our total refining capacity has grown roughly by 40%, and the average refinery size has increased from 120,000 barrels a day to 215,000 barrels a day.

We have a portfolio of advantaged and complex refineries in some of the most profitable markets.

We are restless in our pursuit to bridge resources in consumer markets with our downstream presence in 100 countries catering to some 30 million customers a day with a leading competitive position in most of the major markets where we operate.

We are also the largest gas marketer in the United States and are building a new energy business in alternative energy.

Between '95 and '06, our market capitalization more than quadrupled, and our share price outperformed the FTSE Oil Share Index and the SMP.

To summarize, our portfolio choices driven by enduring strategic principles have created a very strong company with a distinctive asset and reserve space well-positioned for the future.

Over the same period, there has been a significant evolution in the energy markets.

World energy markets have seen important changes over the last decade, although there are probably elements of continuity.

Most notably, prices have obviously increased sharply.

In '95 dated Brent averaged $17 a barrel, and Henry Hub traded for $1.66 per million BTU, and BP's refinery indicator margin was about $2.30 a barrel.

Since '95 world oil consumption has increased by about 14 million barrels a day, about 20%.

Half of that growth was met by new non-OPEC supplies primarily from growth in production in former Soviet Union countries.

OPEC's share of world oil production is virtually the same today as it was in '95.

In addition, OPEC's surface capacity in '95 was about 3 million barrels a day as it is now.

Global proved oil reserves have increased over this decade by about 17% or roughly 170 billion barrels to 1200 billion barrels, including an increase of nearly 60 billion barrels in non-OPEC reserves.

Natural gas reserves have also increased by about 25%.

So there is no shortage of hydrocarbons in the world.

Turning now to '06.

In '06 the world economy grew just under 4%, somewhat faster than in '05.

This continued to support modest oil demand growth of around 1% despite continued strength in oil prices.

For '07 we expect global economic growth to moderate somewhat.

Global oil demand growth should be slightly above the '06 figure.

In '06 the year-on-year growth in non-OPEC volumes resumed reaching .6 million barrels per day, close to the 10-year average.

Unlike '05 hurricanes in the Gulf of Mexico did not disrupt supplies.

Elsewhere production continued to grow in Angola, Russia, Azerbaijan, Canada and Brazil offset by declines in the North Sea and other mature provinces.

Non-OPEC supply is expected to expand by about 1 million barrels per day in '07.

Crude oil prices rose steadily in the first half of '06 due to a variety of factors, including concern over risk to supply and low OPEC surplus capacity.

By October, however, OPEC members announced a new round of production cuts in the face of rising inventories and falling prices.

By year-end '06 OPEC surplus capacity was near the 10-year average of 3 million barrels per day, despite ongoing production losses in Nigeria.

The net result of these dynamics was that the Brent oil price averaged over $65 a barrel, up 19% from the '05 level, although the decline in oil prices, which started in the second half of '06, continued in January.

We continue to believe that there's good medium support from prices to average above $40 a barrel.

As we have said previously, this presumes no major sustained downturn in demand, which could result from the deep and long global recession.

Over the longer-term, the range of possible price outcomes remains uncertain.

BP has a strategy that is designed to be robust to a very broad range of outcomes.

Turning now to gas prices.

Price movements in the world's major gas markets were mixed in '06.

US natural gas prices declined, while UK prices rose only slightly.

Meanwhile, markets in which gas contracts are indexed to crude prices such as Japan and Germany saw continued price increases.

Prices in the US retreated in '06, falling 16% from '05 levels in the face of mild winter weather and high inventories.

Looking ahead, US gas consumption is expected to grow modestly on the back of continued increases in gas-fired power generation.

While the outlook for domestic supply over the medium-term is stagnating, LNG imports are expected to increase significantly.

At high crude prices, the US market has demonstrated a tendency to balance at prices close to parity with residual fuel oil.

Everything else being equal, we expect this relationship to hold as long as prices stay above $40 a barrel.

And finally, refining margins.

Refining margins continued to be strong in '06.

BP's global indicator margin averaged around $8.39 a barrel in '06, down just 1% from '05's record level and still about double the 10-year average.

Over the past two years, product demand growth has slowed in the face of higher oil prices, but refining capacity continues to be tight, particularly conversion capacity to upgrade low value fuel oil.

For the next couple of years, the refining environment continues to look robust particularly for upgraded sites.

Capacity growth is unlikely to exceed demand growth significantly until towards the end of this decade, thereby supporting higher than average margins.

Capacity growth could then accelerate with new builds in the Middle East and Asia putting pressure on margins beyond 2010.

So within this context, what are our priorities for this year?

Tony and I believe that the events of '05 and '06, along with the lessons learned from them, suggest that above all else we need to concentrate on two things -- safety and performance.

Safety is fundamental to everything that we will do.

We will embrace with equal commitment each of the three dimensions of safety -- personal safety, process safety and the environment.

Our aspiration is to be an industry leader in each.

We have a good track record of improvement in personal safety, and our performance continues to improve.

During '06 seven members of our work force including contractors died in work-related incidents.

Every fatality is a tragedy, but the number of fatalities is reduced to the lowest level in nearly 20 years.

Of note is the fact that there have been only two vehicle-related workforce fatalities, showing significant improvement on driving-related incidents following the implementation of our driving safety standard.

We're committed to achieving zero fatalities in our operations.

The recordable injury frequency rate in '06 was the lowest in our history.

In '06 actual spills and integrity-related major incident frequencies have declined by about 23% and 34% respectively on a like-for-like basis.

At the same time, the reporting of integrity-related high potential incidents has increased by about 20%, a good sign showing that we're improving reporting of all incidents at their highest potential so that we can learn.

Process safety management, the second dimension of safety, is not new to BP.

The Baker Panel has reinforced its importance, and we have already committed to implementing the panel's recommendations.

John Manzoni, Tony and I met with the panel two weeks ago to consult on how best to do this across our US refineries and apply the lessons learned elsewhere in our global operations.

We are in action as the report technologist.

We're taking a number of specific actions to prove the integrity of our plants and operations.

We're implementing the control of work and integrity management standards across the group and building on our existing safety management system called Getting HSE Right.

A new group-wide system called Operations Management System is being implemented.

We're reaching a higher sustaining level of integrity management spend as we implement the new integrity management standard.

In '07 our investment is expected to increase by around $1 billion over '06.

Our spend on US refining assets has been increased by $500 million to an annual average of $1.7 billion over the next four years.

These costs are included in our current plans.

We are starting to see improvements in our performance with reductions in major incidents and increased reporting of high potential incidents as I have already mentioned.

The various integrity-related actions will deliver increased operational efficiencies.

John Manzoni will talk about that in a moment.

The third dimension of safety is the environment, for which we have a good track record.

Greenhouse gas emissions from our operations decreased last year with real and sustainable reductions of over 1 million tons delivered in '06, keeping us on track to achieve our commitment to offset around half our operational emissions growth through energy efficiency measures.

A hallmark of BP for a very long time has been its performance drive.

Under Tony's leadership, BP will in the course of the next couple of years refocus on the material actions required to ensure we're getting the best from our investments.

In particular, we expect Texas City to process around 400,000 barrels a day by the end of '07, and Thunder Horse is expected to come onstream by the end of '08.

A number of upstream projects will be coming online in '07 and '08, and Tony will discuss those next.

Startup of new projects, along with improvements in operating performance, will enable us to deliver strong financial performance.

So I would now like to turn to our business segments and their future plans and priorities starting with E&P and with Tony.

Tony?

Thanks very much, John.

Good afternoon, ladies and gentlemen.

What I would like to do in the next 30 minutes or so with the help of Bob Dudley who will update you on TNK-BP is to demonstrate that although the last 12 months have been a difficult period both for us as a company and you as investors, there are many things that went right and that underpin our confidence in the future of our E&P business.

Our reserves continue to grow, and we have increasing confidence that our production profile will continue to grow well into the next decade.

As many of you have heard me say on previous occasions, our strategy begins with a focused exploration program.

In 2006 we continued our strong track record with 10 discoveries from 17 wells.

Notable successes included the Kaskida discovery in the deepwater Gulf of Mexico and the Titania and Urano discoveries in the Ultra-Deepwater of Block 31 in Angola.

In Russia TNK-BP continued a successful exploration program with a number of significant discoveries in the Uvat area in West Siberia.

We have also had significant success in securing access to new options for the future.

In Oman we recently signed a production sharing agreement to appraise and develop the Khazzan/Makarem fields, a very large tight gas resource which we believe can be developed using the same technology as we are currently deploying at our Wamsutter field in the United States.

In Pakistan we rewarded three offshore exploration licenses covering around 20,000 square kilometers offshore in the Indus Delta and have recently signed the heads of agreement for cross-assignment into a further two licenses covering another 10,000 square kilometers.

In India we established an initial presence through the Birbhum coalbed methane license in West Bengals.

We were also successful in extending our very significant acreage position in the deepwater Gulf of Mexico, winning over 100 blocks covering more than 2200 square kilometers in two Gulf of Mexico lease sales.

So, as we assess 2006, both exploration and new access matched our long-term track record of success.

In 2007 we expect to invest around $750 million in core exploration, broadly in line with 2006 and a reflection of the continuing depth of our exploration portfolio.

Our reserve replacement over time demonstrates the ongoing success of our exploration and renewal activities.

As John has already highlighted, we have elected to move to the SEC basis for reserves reporting.

On this basis, excluding the effects of acquisitions and divestments, our reserve replacement in '06 was 113%.

Averaged over the last five years, we have replaced over 114% of our reserves and have had a track record of 13 years on this basis of greater than 100% reserve replacement.

Full details in respect to our reserve replacement will be published in our annual report next month.

Let me now give you an update on our major projects.

The first thing to say is that despite the problems with Thunder Horse and the knock-on impacts on Atlantis 2006 was on balance a successful year for project delivery.

The highlights were, of course, the BTC pipeline and the East Azeri development which came onstream in June and October of last year.

The ACG fields are currently producing at around 650,000 barrels of oil equivalent a day on a gross basis and will ramp up to over 750,000 barrels a day by year-end.

Overall the combined projects started up ahead of schedule, including East Azeri which came on almost four months ahead of our schedule and around six months ahead of a typical industry schedule.

Elsewhere we saw the startup of In Amenas in Algeria, the cannonball development in Trinidad, the Temsah development in Egypt, and Dalia, the second hub in Block 17 in Angola.

Taken together, these four profit centers currently produce around 700,000 barrels of oil equivalent a day net to BP.

In 2007 in Angola we're planning to start up Greater Plutonia, Rosa and Phase II of Kizomba A all by year-end.

In the deepwater Gulf of Mexico, both Atlantis and the King/Subsea Project are on track to start up by year-end.

In Trinidad Red Mango is also expected to start up before year-end.

In our North American gas business, we have just announced a major expansion of the San Juan coalbed methane project, which will contribute for the first time in 2007.

Looking to 2010 and beyond, we have a deep slate of major projects that continue to progress into development.

In 2006 we took the final investment decision and moved seven major projects into development and conducted active appraisal programs on a further 30 future developments.

Let me now turn to our existing profit centers, which to remind you are Alaska, the North Sea, North American gas, Latin America, Egypt and the Middle East.

Even after adjusting for the effects of disposals and of price on production sharing contracts, production in 2005 and 2006 was lower than we had been forecasting.

The reasons for this are higher-than-expected levels of downtime, the failure to achieve targeted improvements in operating efficiency and delays in the execution of infill drilling activity in an overheated supply chain.

These problems primarily impacted production in the North Sea and Alaska.

In the North Sea the key issue has been our ability to execute multiple work fronts and to manage the interfaces effectively at a time when the supply chain is under extreme pressure.

Over the last year, we have invested considerable effort to prioritize and focus activity and establish a reliable foundation for the future.

The resource-base is robust, and appraisal results on the Clair field and the recent acquisition of acreage adjacent to the Andrew field has further increased the opportunity set.

Following on from several recent field startups, including Clair and Rhum, the future is further underpinned by a series of major projects, including Scarv in Norway, the redevelopment of Valhall, expansion of Clair, the Harding area gas development including the Devenick field and additional development in the West of Shetlands.

We expect to make the final investment decision on all of these projects over the next 12 to 24 months.

In Alaska last year we lost around 25,000 barrels a day primarily because of higher-than-expected downtime at Greater Prudhoe Bay.

Despite these problems, we continued to have a very substantial light oil business that over time we expect to transition to heavier more viscous oil and eventually a major gas business supplying gas to the lower 48.

This year's performance in the North Sea and Alaska is clearly disappointing.

We have identified key areas of focus for future operational improvements and have taken specific actions in this regard.

That said, our forecasts do not assume significant near-term improvement in operational performance in either of these areas.

It is important to note that across the EPC portfolio the major reservoirs continue to perform as expected.

The issue is not the quality or quantum of the resource base, but rather it is operational performance in a couple of key areas, affecting the rate at which we are translating resource into production.

It is the strength and quality of the overall resource base that gives us confidence in the long-term.

The rest of the EPC portfolio continues to perform well.

Our North American gas business has a resource base of more than 5 billion barrels of oil equivalent and currently produces around 450,000 barrels of oil equivalent a day.

The use of key technologies in our coalbed methane and tight gas assets, combined with long-term rig and well service commitments, have allowed us to level load activities and reap the benefits associated with repeatability and continuity.

This has resulted in an average reserve replacement ratio of more than 100% over the last five years.

In Argentina with our Pan American Energy joint venture, we continue to see the benefits of the application of BP's technology and management processes combined with the local operating capability of our partners to the very significant resource base.

We have grown overall production by 12% per annum since 1999 with gas production growing at 14% per annum, including the development of deep gas that had not been previously accessed.

In Egypt we continue to make solid progress in developing a major new gas profit center.

In 2006 we signed a framework agreement to participate in the development of the second LNG train at Damietta.

We also continued our appraisal of the Raven discovery and in the last few weeks have made another significant gas discovery, Giza, which further increases our resource base.

Let me now hand over to Bob Dudley, who will give you an update on TNK-BP.

As many of you know, I have been closely involved with the Company as a director since its inception in 2003, and I'm pleased to report that TNK-BP continues to perform very well.

Thank you, Tony, and good afternoon, ladies and gentlemen.

It is good to be here, and as I began a brief note about governance, I am here represented TNK-BP which has four principal shareholders -- BP and the Alpha, Access and Renovo groups.

BP owns 50% of our shares, and our Russian owners between them hold the remaining 50%.

Note that the financial results I will refer to are in accordance with US GAAP, and the reserve statistics are like other Russian companies on a Society of Petroleum Engineers or SPE basis.

Therefore, there will be differences between the numbers I outlined and BP's reported share of TNK-BP results.

Now first some context.

The formation of TNK-BP was announced four years ago this month.

The Company is a leading Russian oil major and produced some 1.94 million barrels of oil or energy equivalent in 2006 comprised of 1.75 million barrels a day of liquids and around 1.1 billion standard cubic feet a day of gas.

These figures include the 50% of another Russian company, Slavneft Nevitt, which TNK-BP owns jointly with the Gazprom company, Gazprom Nevitt, or formerly Sibneft.

We employ around 70,000 people are present in almost all of the major hydrocarbon basins in Russia with most of our production reserves concentrated in West Siberia.

Our proved liquids reserves at the end of 2005 on an SPE basis were 9.2 billion barrels, and we expect 2006 annual reserve replacements before divestments to be confirmed at over 100%, an objective we have achieved each of the last three years.

To date we have not booked significant forward gas reserves, but we have a four-year track record of growing gas sales.

We are an integrated company with five refineries and some 1600 retail outlets in Russia and the Ukraine, which are critical to maximizing our margins in Russia, and we are also building profitable marketing businesses in both lubricants and bitumen.

Now everyone knows the business environment in Russia is challenging, but TNK-BP does operate successfully as a member of the Russian oil sector, and I believe remains well positioned to build on this position.

Since the formation of the Company, this strategy is unchanged, and our results in 2006 extend a sound and healthy track record.

In the upstream, the Company continues to bring resources through to reserves and then to production.

Our 2006 organic production growth, including our 50% interest in Slavneft Nevitt, was greater than 2% on a barrel of oil equivalent basis.

We have delivered greater than 9% production growth annually on average since 2003, far above the original forecasts and more than double the Russian industry average.

TNK-BP has replaced more than 100% of our production with new reserve each year from 2004 onwards, and in 2006 we secured extensions of our two largest productions licenses for the supergiant Samotlor field to 2038.

Since 2004 we have accessed new licenses containing an estimated 5 billion barrels of oil equivalent of risk resources and continue the successful exploration and appraisal program.

In 2006 alone the Company secured 23 new licenses, and our exploration appraisal drilling success rate was over 60%.

In the downstream we continue to enhance margins.

Last year TNK-BP completed the major upgrade of the Raven refinery which allows us to produce European spec products.

We retail under two separate well established field brands, TNK and BP, and we are expanding these retail activities having rolled out a new TNK brand offer at 68 sites in 2006 with approximately 150 more planned in 2007 focusing on our three primary markets of Moscow, St. Petersburg and Kiev.

And the BP retail brand also continues to be very successful, enhanced by the launch of BP Ultimate Fuels this past September.

The Company is also quietly developing the gas business, and we have announced plans to increase associated gas utilization through investment of more than $1 billion over the next five years.

As part of this, we entered into a 50-50 partnership with SibOil, a Gazprom subsidiary for gas processing in our core West Siberian production area.

In parallel, we continue building a foundation for major new gas projects in Rospan and Kovykta.

Both are large resources, which will require major capital and technological investments for the long-term.

Kovykta particularly seems to attract much attention, and it is worth noting that no reserves have been booked for this project.

The Company continues on a path of sustainable investment for longer-term growth, and the portfolio is evolving accordingly.

The slide shows the simple inputs and outputs of CapEx and production.

As we foreshadowed at the time of the Company's formation, we have reshaped the portfolio, and in 2005 and 2006 we completed the sale of $4.5 billion of upstream and downstream assets to increase focus and take advantage of very favorable market conditions.

And, on the acquisition side, just last month we purchased the remaining 50% of the Vanyoganneft from Occidental for $485 million.

We know this asset very well and its attractive synergies with our core Samotlor area and offers some 1.4 billion barrels of oil equivalent resource potential.

Our initial production growth driven by asset optimization and well work is now being complemented by the application of improved waterflood management to underpin production.

And our initial view of the improved recovery potential from our reservoirs is being borne out.

And you may recall that every 1% in recovery factor of our five largest fields adds some 750 million barrels of oil equivalent to our reserve base.

In 2007 we expect to increase CapEx spend to around $3.4 billion, of which around half will be invested in existing fields where we plan to increase our drilling and sidetrack activities significantly.

Despite the maturity of the core fields, we expect to see production broadly flat to 2009 growing thereafter with the contribution of new greenfield developments.

We shall also continue our long-term programs to improve HSE and integrity performance, particularly in refineries, pipe lines and gas utilization.

The balance of the capital program is in greenfield developments, exploration and appraisal programs and downstream investments.

And over the last year, we have taken a conscious decision to rephase some of our greenfield developments.

This will ensure that our activity is aligned with our organizational capability and the supply chain and that we execute it in the most efficient way possible.

We believe this is the right way to create long-term value.

As these projects move through to development, we will create a portfolio capable of delivering sustained growth based on continued exploration success, new greenfield oil developments, and best practice of mature field management, all underpinned by tailored technology application.

The major gas fields offer additional long-term options when the necessary commercial frameworks can be put in place.

We continue to build for the long-term with a substantial resource base of more than 20 billion barrels of oil equivalent of non-proved resources at the end of '05.

In 2007 our development focus will be in the Uvat area of West Siberia, the giant Verkhnechonskoye field or VC field in East Siberia, and in Uvat we are constructing roads, pipelines and field infrastructure progressing the first production hub and continuing our exploration and appraisal program.

On VC we together with our partner, Rosneft, are carrying out additional appraisal activity and are progressing an early oil scheme to link the field with the East Siberian Pacific oil pipeline which is now under construction.

We also continue a focused appraisal and pilot program in the Bolshekhetsky area.

In exploration we continue to spend on new access and exploration which has averaged more than $250 million annually since we commenced operations, and our focus is in Orenburg, the Uvat and Bolshekhetsky areas of West Siberia and in East Siberia.

Access costs are very competitive, averaging only $0.09 per BOE on a risk basis.

These projects are predominantly oil, and as I have said already, we have very large and long-term options in gas.

Our Kovykta regional project is now delivering gas to local customers, and we continue to appraisal full field developments at both Kovykta and Rospan.

Both will require alignment with Gazprom.

We continue to work with this, and despite the occasional headlines, I am optimistic about progress.

Since the joint venture, which created TNK-BP, was announced in February 2003, BP and its Russian partners have committed the company to delivering production growth and introducing new technology to the business.

We have done this, and we have also built for the future, developing a conveyor belt of greenfield projects and a track record of successful exploration.

The Company is also delivering on its commitments to improve corporate governance to increase transparency and provide minority shareholders with the ability to share in the profits of their business.

And I know we're making a real contribution in Russia in several other ways.

We are one of the largest taxpayers in the country, in 2006 paying more than $20 billion in taxes, duties and levies.

Ultimately the goal of building a world-class and successful Russian company is dependent upon people.

We face the same capability challenges as everyone in the industry.

We have a talented work force and are committed to their development with some 150,000 man days of formal training having been delivered since 2003.

We are also able to tap into BP by way of (indiscernible) to accelerate skills, development and broaden experiences.

So putting aside the ever presence headlines about Russian companies, TNK-BP has come of age as a Russian oil and gas company.

This is the fourth successive year of consolidation, delivery and progress of the Company, and in that period we have built a stable and robust and attractive business.

I remain optimistic about the future and our contribution to our shareholders -- BP and Alpha and Access and Renova -- all working together committed to the long-term success of the Company.

Thank you and now back to you, Tony.

Thank you very much, Bob.

Let me now discuss the overall level of investment in the E&P segment.

This chart shows the level of capital investment over the last three years and the projection for 2007. 2006 capital investment was around $12 billion, excluding our $1 billion investment in Rosneft.

It included around $1 billion impact from sector-specific inflation.

In 2007 we expect capital expenditure to be around $13 billion.

The exact level will depend on the dollar exchange rate and our continuing ability to offset around 3 to 4% of the sector-specific cost escalation.

We continue to see very strong inflationary pressures in all parts of our supply chain.

For Exploration and Production within BP, we have seen price increases to some 14% in 2006 in the marketplace, a level we expect to continue into 2007.

This brings the overall sector-specific inflation that we have experienced to more than 35% over a three-year period.

We have offset around 11% of these capital cost increases over the three years through a combination of technology, demand management and supply chain management, aggregating demand and making longer-term commitments to our suppliers.

Let me give you some examples.

In 2006 the market rate for offshore rigs rose an average by around 44%.

Because more than half of that fleet was on long-term contracts, we mitigated this rise to an average of around 34%.

Similarly we have secured more than 80% of our US onshore rigs on long-term contracts with a limited number of suppliers.

Also shown on this chart is BP's share of TNK-BP amp and Pan American Energy's capital investment.

Neither is reported as consolidated BP capital, but both are important components of our overall economic investment.

Both of these operations are bias to brownfield development of onshore oil and gas.

Consequently we are able to generate high incremental volumes in these areas for relatively low capital investment.

Pan American Energy and TNK-BP are able to fund investments from their own cash flow.

On this basis total E&P investment in 2006 was $14.8 billion, and we expect that to increase to around $15 billion in 2007.

In the face of the continuing very high levels of cost pressures in the industry, we're determining to take a disciplined approach to our capital investment program.

This is about focus, exercising rigorous quality through choices, progressing only the most material opportunities and ensuring that we do not pursue options where there is not the capability to execute efficiently.

We will manage the pace of major projects to ensure that we are not drawn into long-term commitments made in the current overheated market and where necessary we will slow down to preserve long-term value.

Like others in our industry, we're seeing the effects of the current high oil price environment impact the cost of people, supplies and services.

From 2004 to 2006, we experienced cost escalation of around 7% per annum, of which we were able to mitigate between 1% and 2% through technology demand and supply chain management.

The primary reasons for the increases have been general wage escalation, especially in the petrochemical disciplines, as well as increases in logistics, engineering and seismic services.

We expect that we will see continued sector-specific cost escalation of around this level over the medium-term until supply and demand rebalance.

As with capital expenditure, a focus on supply chain management is an important element of our program to mitigate market cost escalation.

Across the business, we're generating significant savings by aggregating demand, making longer-term commitments to suppliers and where appropriate locking in rates.

To give some examples, in the Gulf of Mexico long-term contracts with options to renew have meant we have the use of seismic vessels for most of 2007 at 2005 prices.

Similarly, we have also single sourced 80% of our marine supply vessel requirements for five years with inflation capped at 3%.

In Alaska indexed agreements for trucking services in 2007 will result in cost increases of 2% for BP versus market rate increases of 8%.

The desire for a greater share of the higher rent available in this environment is not only restricted to suppliers of goods and services, governments have already moved to raise taxes.

The UK is a prime example, but over the last 12 months, tax take has also increased in Alaska and Venezuela.

Together these have an approximate annual cash impact of around $800 million in the current environment.

Furthermore, in this environment, our barrel entitlements on the production sharing contracts have been reduced, and development costs across the portfolio have increased.

Consequently we expect to see continued rising depreciation per barrel.

Before I talk about future production, let me remind you of the evolution of our portfolio over the last six years.

Over the last six years, we have divested a significant number of assets which had reserves of around 2 billion barrels of oil equivalent and production of around 530,000 barrels of oil equivalent a day in 2001.

These divestments were made on strategic grounds to improve the quality of the portfolio, and we realized around $14 billion of pre-tax cash proceeds and around $4 billion of pre-tax profits.

Over this time period, the retained portfolio has grown from 2.9 million barrels of oil equivalent a day to 3.9 million barrels of oil equivalent a day, a compound annual growth rate of around 6%, driven by the acquisition and subsequent growth of TNK-BP.

Underlying growth in the new profit centers has been relatively constant at around 13% per annum driven by the delivery of 33 major projects and has more than offset decline in the EPCs.

I would now like to give you new guidance for our expected future production rates.

Relative to our projections of February last year, our production forecast has been impacted by five things.

Firstly, we further increased our focus on safety and operational efficiency and will in some cases deliberately slow the pace of our activity in order to improve its safety and efficiency.

Secondly, we are using a higher price assumption of $60 rather than $40.

This reduces 2007 by around 100,000 barrels a day and 2009 by around 300,000 barrels a day.

We are using a higher oil price, not because we think the oil price will be $60, but because it is a more conservative basis on which to project volumes.

Thirdly, we made divestments in 2006 that will reduce 2007 production by 130,000 barrels a day, around 60 from TNK-BP and around 70 from the remainder of the portfolio.

Whilst we will continue to continue to review the portfolio and make adjustments in line with strategy, we have now completed the major portfolio high grading and would not expect future divestments of production at this level.

Fourthly, the delay of Thunder Horse in Atlantis and the deepwater Gulf of Mexico impacts 2007 by around 150,000 barrels a day and 2008 by 100,000 barrels a day but has little impact by 2009.

And fifthly, as Bob has already mentioned, TNK-BP has taken steps to match the pace of greenfield development with organizational capability.

This reduces BP's projected volume from TNK-BP by around 90,000 barrels of oil equivalent a day in 2010.

We're also allowing for operational efficiency issues, a reduced ability to execute effectively at a time when the industry supply chain is operating at full capacity and for the unexpected.

And, as I have mentioned, we're deferring some activity due to an overheated supply chain, which we believe will deliver increased value.

Lastly and most importantly, we have learned much from our experience over the past two years, and I'm incorporating these lessons into the more conservative guidance that I'm giving today.

The key remains that our reserve and resource base is strong.

The issue is the timing of production.

So our new guidance is more conservative than in the past, and we believe conservatism is the right path to take at this moment in time.

In 2007 we expect production to be broadly flat between 3.8 and 3.9 million barrels of oil equivalent a day and to grow thereafter.

This takes into account the 130,000 barrels a day impact on 2007 of divestments made in 2006.

On the basis of a price assumption of $60 a barrel in our account portfolio, we see production at more than 4 million barrels of oil equivalent a day by 2009 and more than 4.3 million barrels a day by 2012.

Our portfolio is lengthening, and we will be able to sustain growth further into the future.

I would now like to turn to our resource space, which underpins the potential for sustainable growth.

This slide, which I first used last year, describes the movements in our resource base over the five-year period beginning in 2002.

You should note that the data shown here is on an SEC basis and, therefore, not directly comparable to the data we showed on last year's slide.

Over the time period, we produced 7 billion barrels of oil equivalent and moved 8 million barrels into proved reserve for major projects and infield activity.

In the top left, we added around 7.2 billion barrels through exploration and on the top right 8.3 billion barrels through appraisal and reservoir evaluation activity.

And finally, you see the impact of A&D across this period.

So to summarize, over the last five years, excluding acquisitions, we have added 15 billion barrels of oil equivalent to our non-proved resource base and 8 billion barrels to proven reserves.

We have extended our total resources and reserves to production ratio from around 34 years to around 41 years whilst maintaining a proved reserve life of more than 12 years at the same time as we have grown production by around 500,000 barrels of oil equivalent a day.

I cannot overemphasize the importance of our efforts to improve the recovery factor on the 200 billion barrels of oil equivalent hydrocarbon in place across our portfolio.

To date we have produced 38 billion barrels, an average recovery factor for the portfolio of just 19%.

Producing the 19 billion barrels of proven reserves will increase the recovery factor to 28%.

Moving to the currently foreseen recovery limit would yield a further 41 billion barrels.

This is equivalent to an additional 29 years of production at current rates and will take the recovery factor for the portfolio to 49%.

In addition, there is a significant volume of hydrocarbon which is currently unrecoverable using today's technology.

We believe over time we will be able to extend existing technologies and develop new technologies which will help us access part of this.

These include recovery of viscous oil in Alaska, tight gas in North America and low salinity waterflooding, which has widespread applicability across much of our portfolio.

Simply put, as we continue to increase the technical limit, a 1% improvement in recovery equates to a 2 billion barrel prize.

So if I can summarize the E&P segment, 2006 was a disappointing year.

We experienced operational problems in Alaska and the North Sea and delays to Thunder Horse in Atlantis in the Gulf of Mexico.

All of these occurred in an environment where the supply chain is stretched to breaking.

Despite these difficulties, we managed to stay focused and continue to make solid progress in the implementation of our strategy.

We continue to see the benefits of a focused exploration strategy with a number of significant new discoveries in 2006 and important new access in a number of areas.

We continued our track record with 13 years of reserve replacement of 100% or more.

We expect production to grow to more than 4.3 million barrels of oil equivalent a day by 2012 at $60 a barrel underpinned by a slate of major projects that are advancing steadily, strong performance from TNK-BP and a growing opportunity set arising out of successful exploration, new access and our strong incumbent positions.

As I have indicated, we face some major challenges with operational issues to overcome in Alaska and the North Sea.

Continued upward pressure on costs is putting earnings under pressure, especially as oil and gas prices are no longer rising at the pace seen over the past three years.

Outside of my priority of safety and operational integrity, we have taken the decision to slow down in a number of places in order to manage costs in the current environment and to ensure that we execute in the most effective way possible.

Government take continues to edge up.

However, we believe we're as well-placed as any company in our industry to meet these challenges.

We have a strong and growing resource base in our major incumbent positions, which is being progressively unlocked through the deployment of focused technology programs.

With a renewed focus on the safety and operational execution, I am confident that we have the basis for sustainable long-term growth.

Ladies and gentlemen, thank you very much.

Let me now hand over to John Manzoni.

Thank you, Tony.

Ladies and gentlemen, good afternoon.

I would like to briefly describe the activities of refining and marketing with a particular focus on 2006 and 2007.

I would like you to take away three main messages from the next few minutes -- that we're focusing great effort on safety and integrity; that we're building out from a very difficult 2006 -- improvement should continue through 2007 into 2008, driven mainly by Texas City -- and that we are continuing our disciplined execution of strategy, and the business has been improving all the time.

I must begin with the recent publication of the Baker Panel report on Texas City.

The report was issued on January 16.

The panel provided a set of recommendations and insights which will help to accelerate our journey toward process safety excellence.

This has been a major focus for our organizations, especially over the last two years.

We have many actions underway as a result of the Texas City incident of 2005, including setting up a new integrated operations management system initially across our US refineries but later more broadly.

We are now in the process of reviewing the panel's recommendations, and many of these are fully consistent with the actions that we have already begun.

We have committed to fully implementing those recommendations, and we will build them into our work programs in a considered way, which will ensure sustainable improvement to our process safety performance.

We have already signaled increased integrity spend in our US refining system.

It has been increased by $0.5 billion to an annual average of $1.7 billion over the next four years, including turnarounds, maintenance and integrity projects.

All of these projects are expected to improve safety, reliability and availability over the long-term.

Stepping back, we have learned fundamental lessons from the Texas City incident.

Process safety, along with personal safety in the environment, is a major focus.

It is the first priority for our organization, and it is a long-term journey.

Returning now to 2006 and 2007, this slide shows the volume and type of feedstock processed at Texas City in 2005 and 2006 and the forward plans for 2007 and 2008.

Throughput more than halved in the second half of 2005 as Texas City was shut down due to a loss of steam related to Hurricane Rita in September of that year.

We took the opportunity to fundamentally improve standards, engineering, practices and procedures of the plant as a result of the shutdown. 2006 was a low point in Texas City throughput as we began recommissioning the first process units incorporating our new standards.

Since the shutdown, over 15 million man-hours have been worked at the refinery, refurbishing and recommissioning process units, as well as retraining personnel and introducing new procedures and standards.

As you know, crude processing started in April of 2006, building to around 250,000 barrels a day by the end of last year.

Most of the feedstock currently being processed is light sweet crude.

Looking forward, we expect the first half of this year to be similar to 2006 in terms of the type of crude processed, but we expect the percentage of high-value products -- that is gasoline, diesel, jet and aromatic feedstocks shown on the chart here by the Orange line -- to increase through the year as major upgrading units are recommissioned.

During the fourth quarter of 2007, we plan to restart the refurbished second train of the refinery, bringing the total crude throughput to around 400,000 barrels a day by the end of this year.

The second train process is mainly high margin, heavier sour crude.

This should significantly increase margin capability in 2007 as the overall proportion of sour crude into the refinery rises from around 15% to around 60% by the end of this year.

In terms of financial impact, Texas City lost around $1.1 billion in 2006, excluding the costs associated with litigation.

Based on the schedule of startups underlying this chart and depending, of course, on the refining margins through the year, these losses are expected to be at least halved in 2007.

Learnings from Texas City have had impact on availability beyond Texas City itself, and that is shown on this chart.

The slide shows total refining system availability from 2004 to 2008. 2006 is a low point.

While we would normally expect system availability to be around 95%, the low point reached in 2006 was just 82.5%.

This figure reflects reduced availability in many parts of our system in 2006.

One example of the broader impact is how we have applied new standards and work processes around turnarounds, which have increased turnaround time in some cases by up to 30% in 2006.

We expect to learn as we go forward, reducing the impact of new procedures on future turnarounds.

Our expectation is to be back at normal availability during 2008.

For Texas City and for the system as a whole, 2006 was the point of maximum financial impact.

We will focus on building back from that point through 2007 and into 2008.

I want to make a brief comment on our refining portfolio strategy and investment plans.

This chart shows a view of our strategic positioning.

We continue to believe that the US is in an advantaged location for refining capacity in the medium-term due to the import supported margin structure. 55% of our capacity is in that location.

After location, we see two other sources of advantage.

First, complexity.

The chart shows BP has more complex refineries than others, allowing us to make high specification products from cheaper crudes.

And second, size and scale allowing us to access economies of scale.

So we have advantaged refineries in advantaged locations.

Our strategy is to continue to invest into the complexity and upgrading capability of our refining portfolio.

This allows us to capture better unit margins when margins are high and also ensures the portfolio remains robust should the overall refining margin weaken from the exceptional levels seen recently.

And we also continued to adjust the geographical position of the portfolio to optimize our exposure to the expected margin outlook.

We have recently announced the sale of our Coryton refinery here in the UK.

At the same time, we're working options to improve the positioning of our European portfolio to meet diesel demand in this continent for the future.

We have a significant suite of investments planned which will further strengthen the quality of the portfolio.

These investments include the $3 billion investment at Whiting, which will enable the 400,000 barrel a day refinery to process 85% heavy Canadian crude compared to less than 25% today.

But there are others, including the commissioning of a coker at [Castillion], site reconfiguration at [Byon] oil and then hydro-treating investments at NEREFCO, all expected to be completed by the end of 2008.

Overall between now and 2012, our planned investments should enable our refining portfolio to process 65% high sulfur crude, up from 52% today including Texas City, as well as increase the gasoline and middle distillates production by around 100,000 barrels a day.

So from an advantaged set of assets, we have plans to continue investing to ensure its position remains at top quartile.

And those investments are specifically targeted at ensuring the portfolio is robust in the event of softening refining margins.

Turning now to our marketing businesses, the strategy is focused on three priorities, and I will touch briefly on each.

First, we continue to invest into the quality of our offers to maintain our margin generation capability.

For example, in 2006 retail same sales store growth grew ahead of market at 4%.

Ultimate Fuel continued its growth to represent 10% of the branded volume with its margin contribution almost twice that in markets where it is sold.

And net marketing contribution with our 15 largest business marketing customers grew by 15%.

These examples are important indicators of our continued focus on offer quality, which is especially important as product prices continue to rise.

Our second priority is to focus our capital employed by decapitalizing many of our retail markets to franchises so that we can maintain a high-quality branded presence but deploy our own capital into other opportunities.

During 2006 we reduced the number of company-owned sites by almost 900, which is about 10% of the portfolio and released around $800 million of cash.

We will continue along this journey in 2007 and I expect around $700 million of divestment proceeds depending on the exact timings of the many transactions involved.

And thirdly, we are continuing our drive for efficiency, which is critical in any circumstance but especially so in the current high-priced world.

In February last year I outlined a two-phase program intended to deliver at least $0.5 billion by 2008.

This slide shows some measures of progress on that generally.

We are firmly on track and even a little ahead in some parts.

Phase I is a rationalization program across our marketing businesses shown here by reduction in headcount.

This underpins delivery of cost efficiencies, and we believe we are ahead of our Phase I target.

We expect to reach full run-rate for these reductions during this year.

Phase II is the design and implementation of improved systems for our marketing businesses.

We are making good progress, and the first rollouts are planned to occur early in 2008.

These are expected to deliver additional efficiency, as well as improved capability as we roll them out.

The combined impact of our investment and marketing capability and cost efficiencies results in the steadily improving ratio of gross margin to distribution and administration costs across all of our marketing businesses as shown on this chart at the bottom.

Finally, here is an outline of our investment patterns for this year.

Organic CapEx is planned to be around $4 billion up from $3.1 million in 2006.

As you can see, most of the increase is in refining.

This is focused on integrity, Texas City refurbishment and the upgrading projects that I outlined earlier.

Spend in the marketing businesses is broadly constant, although this year it does include some early planned investments in biofuels manufacturing capacity.

I expect disposals this year to total around $2.5 billion and comprise mainly of our Coryton refinery and continued retail decapitalizations.

And finally, to return to my three main messages, I have touched on each.

First, we are focusing on improving the safety and integrity performance of our entire system, and we have built-in expenditure to do so.

I'm looking forward to having Texas City back on the schedule that I have outlined today.

This will be a major strain to financial improvement during the year, along with continued delivery of the efficiency programs.

And lastly, we are continuing the disciplined execution of strategy both across the refining portfolio and our marketing businesses, which should continue to improve our business all the time.

Ladies and gentlemen, thank you and back to John.

John, thank you very much.

Given the time constraints today, I will only provide a brief update on Gas, Power and Renewables.

We gained considerable momentum during '06 and see significant growth opportunities in '07 and beyond.

In particular, gas remains an important part of our portfolio.

We will continue with our strategy of capturing a greater share of the growth in global demand for gas.

Our LNG marketing and training business continues to grow substantially.

We are the second-largest producer of gas amongst the IOCs.

We are the world's largest marketer and trader of gas among the IOCs.

In wind we are on track to develop around 450 megawatts of wind capacity by '07.

We have established one of the largest development portfolios in North America through the alliance with Clipper and our Greenlight and Orion acquisitions, and in solar our capacity grew by 100% to 200 megawatts in '06 and is expected to grow to 300 megawatts by the end of '07.

We announced last week that we have selected the University of California at Barclay and its partners, the University of Illinois and the Lawrence Barclay National Laboratory, to establish the BP Energy Biosciences Institute.

Now Vivienne will be happy to take any specific questions on Gas, Power and Renewables after our presentation.

We also plan to hold an investor event to discuss progress and alternative energy later this year.

Now putting all this together, in '06 the total group capital expenditure was about $16 billion, in line with our guidance last October.

For '07 our organic CapEx is likely to be around $18 billion as we continue to increase investment in all our segments, including alternative energy.

Continuing sector inflation is expected to add over $1 billion this year.

In addition, we expect our share of the CapEx for associated companies to be around $2 billion in '07.

If you add these back to get a feel for the investments made by the group as a whole, you get a level of around $20 billion in '07.

The exact level of capital expenditure will, of course, depend on a number of things, including the actual level of sector inflation that we experienced this year and any one-off investment opportunities which further our strategy.

Our dividend policy remains unchanged.

It is to grow dividends per share progressively.

In '06 dividends per share grew by 10%.

During the period '01 to '06, the dividend per share in dollars grew at an average of 12% supported by the share buyback program.

Since '01 we have undertaken buybacks worth $39 billion.

Our per share measures of value have been enhanced, an important outcome of our strategy to grow and distribute sustainable free cash flow and our primary emphasis on shareholder value growth.

Our approach to the level of gearing is also unchanged.

We continue to believe that a gearing band of 20 to 30% provides an efficient capital structure and the appropriate level of financial flexibility.

We started '06 below this level due to the proceeds from the sale of Innovene and have stayed in the 15 to 20% range for most of the year.

We ended '06 at the bottom of the gearing band at 20%.

Overall '07 will be a year to get back on track.

We expect improved financial performance starting from 4Q '07 as new E&P projects start to come online and Texas City continues to ramp up.

Specifically we expect production to be in the range of 3.8 to 3.9 million barrels of oil equivalent per day under an oil price assumption of $60 a barrel in our current portfolio.

Organic CapEx of around $18 billion, total group costs to grow in line with sector inflation and distribution policy to remain unchanged.

To summarize, our main priorities are safety and performance.

We hold high-quality assets consistent with our strategy.

We are committed to act on the lessons learned from our US experience and are implementing the recommendations of the Baker Panel, and we have a robust financial framework.

Ladies and gentlemen, thank you very much for listening to those presentations.

As soon as I have sat down, we would be delighted to take questions, and I will give you further guidance in a moment.

What I would like to do is to take some questions here first in London, let's say four or so, and then I want to turn it over to Bob Malone to field questions in New York, and then finally I will go on to the Web and take those questions and we will keep recycling.

So let's take -- first, if you could identify -- I know you, but could you identify yourself please and give your affiliation.

Tim Whittaker, Lehman Brothers.

Lord Browne, you mentioned you have completed 47 results presentations, and I have attended most of those.

I did want to thank you for your insights over that time and also congratulate you for your achievements.

Thank you.

I have a question you for you and a question for Tony.

The question for you, John, is over that time, maybe you could share with us what do you think the biggest lessons that you have learned, and for Tony, I wonder if you could summarize what are the factors that you think differentiate BP compared to what to us sometimes look fairly similar competitors and, therefore, what you will focus on going forward?

It is probably the wrong time to summarize all the lessons learned.

But I think one -- if I am not pushing to avoid the question, one of the lessons I have learned is that you always continue to learn lessons.

You always continue to learn lessons, and I think that is very important indeed.

I think that due reflection perhaps is another time.

I think that I would also say that the lesson I have learned is that there is no such thing as smooth progress.

There cannot be smooth progress.

There will be ups and there will be downs, and as I said, the 47 results presentations -- I have always look forward to them, but some report cards are better than others and some things take a bit longer to work out.

That is my second point.

My second third point is one of timing.

It is very important to remember that some things simply take longer to work out than you might have first expected.

I think that is an important lesson.

It remains to be seen whether things are good and bad.

I am confident one thing I have learned about BP is that the team is very, very strong, continues to be strong, continues to be renewed, has a great new leader and has great assets to work on.

I can give you a long list, but I will keep it short.

I would say, firstly, our consistency is strategy over a very long period of time, which has created particularly in our resource business an unequaled set of opportunities going forward.

So we have tremendous opportunity in our resource base and conventional hydrocarbons in a series of major profit centers you are all well aware that will see growth in this Company for a long time to come.

Secondly, I would say the clarity of our financial framework, which we have been equally clear and equally consistent with over a long run of years.

And thirdly, the quality of the people.

I think we have got the best team in the industry.

Neil McMahon, Sanford Bernstein.

Two questions.

The first is, really given the very much lower growth projections going out through the end of the decade and into next decade and the higher costs that seem to be coming through now in terms of appreciation, why have you not looked towards more unconventional resources such as oilsands, especially as next decade when you look at some of the major projects such as Kovykta and Rospan and delays potentially on the Alaskan gas reserve base, that could make that portfolio into the next decade somewhat lumpy given when those projects come on and unconventional resources would help smooth that out.

And then secondly, what actions, organizational or otherwise, have you got in place to try and improve the operational efficiency uptime of the assets in the North Sea, Alaska?

What can we look for there?

I know you have not been that optimistic this coming year in terms of improvements there, but what are we going to look for going forward?

I think on the oilsands we have had this conversation often, and the issue about the oilsands is project quality.

We have looked and looked, and the things that we can see that are available today do not compete with opportunities we have in our current portfolio.

And it is as simple as that.

We don't sort of say we don't do oilsands because they are oilsands.

We look at the quality of the project, the investment opportunity.

How does it compare with our existing portfolio?

And the opportunities that we can see that are available today do not compete with the opportunities we have in our existing portfolio.

I think on the matter of Alaska and the North Sea, I think they are rather different things.

They resulted in the same result -- unsatisfactory operating performance.

In the North Sea, it has been very much about the ability to execute our infill drilling programs effectively and efficiently at a time -- in the time that we said we are going to.

We, frankly, have been trying to do too much at a time when the supply chain is under incredible pressure.

So what we have done is we have rebased the activity there to scale it back to a position where we believe that we have the capacity and capability both in our organization but most importantly in the supply chain to be able to execute efficiently.

That is the key thing.

Alaska is, of course, different.

It has been to do with the issues of last year really.

Prior to this recent year 2006, Alaska had a very long track record of very consistent delivery, higher pricing uptime and very consistent delivery of its forecasts.

Clearly last year was a hell of a challenge, and we have taken big steps, particularly in the matter of investment into integrity for the future.

But we believe we have a business in Alaska for 50 years.

So we need to take a long run view as to what is required to sustain it over a 50-year period, and that is what we have been doing.

May I just add just a few points?

First of all, nowadays we cannot talk to you about planning and development costs because it's not a proper measure.

But then a lot of people do look at it, it is a little old-fashioned, but I think long run it says that this portfolio has some very significant strengths.

Of course, F&D costs are rising, but the issue is one of comparative rise.

The second point is I think on our guidance that Tony has given you about production this is a floor.

By the very way it is put, it clearly must be drawn to that conclusion.

This is a floor.

And so let's see what happens above that.

The third point Tony made is that in any event the portfolio has lengthened out.

So it allows us to combine some big producers with infill activity, and there is a mix of both, which will take place in the future, which is decidedly conventional if you call deepwater conventional nowadays.

Can I just take this one and then I will come over here.

Jon Rigby, UBS.

Two questions, one on PSCs.

I think as I understand it there is about 300,000 barrels a day that you're assuming out in 2009 in your production forecast 40 to 60.

Can you just go through what is permanent, i.e. burn through of cost oil all going through our factors and, therefore, would not come back if it was not $60, it was $40.

And what can come back?

And the second is on your production guidance for startups, etc.

I did notice as you were going through a number of the projects in '07 you said end '07, end '07, end '07.

To my mind there are a couple of projects there I'm pretty certain will be on well before the end of '07.

Does that feature in the way that you set up your production forecast, i.e. that you have not put anything in for those very large projects before about the end of '07, or is it just something you don't want to highlight in public about exact start dates?

Let me start with the second one.

What we have done is we have reflected our experience over the last two to three years, and our experience over the last two to three years has been the challenges of a stretch supply chain, which we have talked about, and the challenges of the unexpected, which you cannot deal with when the supply chain is as stretched as it is.

So our guidance is our guidance.

It reflects the learnings of the last two to three years.

In the matter of the 40 to 60, John, I think it is almost impossible to answer the question.

As you know, these things are extraordinarily complicated, but fundamentally it would be if prices were $40 here on out versus $60, then the gap is 300,000 barrels a day in the round.

Okay?

I will take one more question there, and then we will come back here later.

Ed Westlake, Credit Suisse.

You have talked about the robustness of the opportunity set, and you've had some exploration success -- Kaskida in the deep Gulf of Mexico;

Angola, you have got tight gas and you're talking about Alaskan heavy oil.

Can you talk us through sort of what type of oil price you think given the current rig rates, steel costs, it would take to develop some of these projects and what type of gas pricing in the terms of tight gas?

Well, we continue to test everything down to $30.

It is not a fixed point, but we look at all sorts of things.

So across our portfolio I would say that in the '30s things are going to make cost of capital plus.

And that is with today's costs.

That is with today's costs. (multiple speakers)

So it is not cost adjusted down, which might well occur if the price of oil dropped or the price of gas dropped.

Okay.

Now, Mr. Malone, I would like to go to New York if I could.

Good morning and perhaps you could field some questions there.

Good morning, John.

We will start in the back row.

Yes, ma'am?

Nicky Decker, Bear Stearns.

I think in the past we have heard you say that you do not need to buy anything in order to achieve 4% production growth.

Just wondering maybe if you could talk about your thinking now about acquisitions?

Thank you.

Acquisitions are nothing but simply a way of executing strategy.

Our strategy remains unchanged.

We're still having growth inside the firm.

If you take a longer run approach to it, as I said in answer to the first question, timing can never be accurately forecast.

So we have tremendous resources.

We're adding to those resources, and certainly for the fundamental foundation of the firm, we have I think the power for the future.

Now if circumstances direct and opportunities come up, we will examine what those opportunities and what those circumstances provide.

But right now we have no present intention of doing anything significant.

We have to wait and see as the world develops.

But it is not ruled out, and it is not ruled in.

I will take the next question, please.

Dan Barcelo, Banc of America.

Earlier in the year you've had some major success, particularly deepwater, particularly lower tertiary.

I did not know if you're able to expand on that at this time.

And also perhaps a little bit more of an outlook on your deepwater exploration outlook going into 2007.

And then I guess a little bit following on, how do you balance the higher cash flows that deepwater will provide against perhaps a faster decline rate?

Thank you very much.

I would like to send this question back to Andy Inglis, the new head of E&P, who is in New York.

Andy, why don't you answer the questions.

Very good.

I think the technology is working.

In terms of the tertiary, I think the most important thing here is to continue to high grade the opportunities there and actually find the very best.

I think that is what we have been doing through the process.

We're very pleased with our discovery at Kaskida.

We do believe it represents the best that we have today, and we will continue to look at opportunities to high grade.

I think going forward in the deepwater through '07, I think we're going to keep a very balanced portfolio between the Paleogene and lower tertiary and the Miocene.

So you can see it is probably pursuing about 50% in both arenas.

And I think that gives us a solid set of opportunities going forward.

The Miocene is probably developed on a slightly shorter timeline, but it gives us that long-term opportunity of the Paleozoic Paleogene.

And then the question on higher cash flows versus (multiple speakers) rates.

Mark Gilman, The Benchmark Company.

My congratulations also to you on a distinguished career.

I wonder if we could get a little clarity on reserve adds for 2006, and in particular, and I will try to state this diplomatically, in shifting fully to an SEC basis of reporting your reserves, it raises certain issues and questions that on a sort basis you probably have not had to deal with directly up to this point.

Are you comparatively confident that in making this shift all potential revisions have been taken into consideration to properly reflect the considerably more stringent standards underlying SEC versus reserve reporting?

Thank you.

I would like to pass this to Byron Grote.

I need to be clear.

We have been reporting reserves for our US filing purposes under SEC rules for a very long period of time.

What we have done is chosen to provide you two different bases for evaluating reserves.

One that is impacted by changes in prices.

One where we were doing the evaluation relative to long-term prices that we expected for oil and gas.

We have gone through a very rigorous process with the SEC.

We are confident of very tight control process, and we have no concerns whatsoever.

Bob, another question.

Paul Eckley, State Farm Insurance.

Perhaps a question for Bob Dudley.

You mentioned that you want to match the pace of the greenfield development with the organizational capability at TNK-BP.

Could you provide a little more background on that, please?

When we founded the company we had very little exploration work and new projects in place, and we had built a conveyor belt of new projects that are coming along almost stretching the limits of both our organization and the Russian service industry.

So we have prioritized those out, increasing capital spending 30% this year to about 3.4 billion.

We will level that out and pace our oil and our gas developments on that schedule.

We have the same supply chain and organizational capabilities and stresses as the rest of the industry around the world.

We're going to prioritize those projects in the right order.

We have got a lot of them to do.

If I could add, I think Bob is being quite modest in how he is describing the challenge.

It is just worth remembering that no one has done a greenfield development in Russia since the fall of the Soviet Union.

That is getting on for 20 years ago was the last time any greenfield development projects was undertaken in Russia, and it means a lot of the skills need to be refreshed.

Great.

Thank you very much.

I'm going to come to the telephone.

There is one question from Bob Kesler of Simmons & Simmons.

Bob, can you hear us?

I can.

Can you hear me?

Yes, very well thank you.

You've guided to lower production versus prior expectations all the way out through the end of the decade.

Part of that, of course, being price-related.

I'm curious though what your confidence level is now when achieving 100% organic reserve replacement going forward, say, at $60 a barrel whether a function of entitlement effects on PSE contracts or slower movement towards sanction on projects in an overheated construction market.

Both would seemingly suggest a slower ramp in reserves.

Any adjustment to forward guidance then on production replacement?

I think we would see it certainly being above 100%, Robert.

We continue to add to reserves both through major projects and through the expansion of -- and the conversion of resources to reserves in our existing positions, and I would expect that to continue.

So no change at all to our beliefs that we will continue to have more than 100% reserve replacement through the period.

Thank you, Bob.

Can I come back to London and to the middle block now.

We will reverse around starting with you, sir.

Jason Kenney, ING.

Two questions for John Manzoni if I may.

You mentioned or it was mentioned that BP is expecting robust or higher than average margins to 2010 at least, yet a couple of your competitors in the recent weeks have mentioned that they see margins going significantly south before the end of the decade.

So what is it you are seeing that perhaps they are not?

Is it delays in new capacity, say, in the Middle East or in Asia, or is it higher demand?

And then secondly, presumably there's a significant gain on the sale of Coryton, and I just wondered if you had an indication of the book value that you are carrying for Coryton?

Maybe that is Byron.

The margin outlook that we see, Jason, is do -- I think we've got warm whether, we've got higher (indiscernible) and still the margins are relatively high today in the medium-term.

It is really not to do with installation capacity.

It is to do with upgrading capacity.

It is the tightness of upgrading capacity that we see holding the margins up now, and it is the pace at which new upgrading capacity can be built, which is going to over the course of the next couple of years bring it down in our view.

As I sit and talk to you today, we just have had a January which was really extraordinarily high.

Now different refiners will experience different margins, and they are already experiencing different margins, and again it depends upon the level of upgrading any particular refinery will see.

So even today, as we look across the world, the upgraded refineries are seeing good margins, but there are several refiners who are really suffering quite badly today.

So it's about the upgrading spec capacity.

Jason, consistent with accounting policy, we would not recognize a gain on the sale until we actually have completed the transaction.

So you will see that in the first quarter or the second quarter.

There is a substantial gain associated with it, but as I said, we will be reporting that as a non-operating item in the first quarter or second quarter.

If I can, Jason, I think the guidance we give on margins, I doubt while -- and I do like to try and agree with our competitors where we can -- I think we may be splitting hairs.

It might be a year, and the question is one of tone about how low.

Clearly I think not sustainable at this level forever, and I think that is the big message because of the increased conversion capacity, which is coming in primarily in the Middle East and Asia.

Now we go back.

Neil Perry, Morgan Stanley.

Tony presented a whole page on the cost pressures from revenue cost to government take and accelerated personnel inflation.

Given the production growth expectation you now have, do you think you have enough growth to offset those increased cost pressures, or are you looking out at a prospect of earnings decline at flat oil prices?

And my second question is, what made BP the company it is now is largely step changes through acquisitions; what has been disappointing if anything in the last six or seven years has been the organic element.

You are now spending less than next on substantially less than Shell or less even than Chevron.

Do you think you're actually investing enough into the capital budget in order to reinvigorate the organic growth rate?

I will start with the capital if I can.

The answer to that is, I clearly believe we are otherwise we would not be doing what we're doing I suppose.

I do think it is important as you make comparisons you need to be careful about the comparisons that are made.

Two of the important volume growth areas for BP are Pan American and TNK-BP, which aren't part of our conventional capital budget.

They are also places where we can bring on production for very low F&D, very low.

If you look at our five-year F&D, it is about $6.00 a barrel.

The end-year F&D was $8.00 a barrel.

In those places we are looking at $4.00 or $5.00 a barrel, which is probably very different from some of our competitors.

So I think you really do need to look at the capital intensity that the portfolio that you're considering requires to make it move forward.

So that is sort of capital.

Now I have forgotten your first question I'm afraid because I did not write it down.

What was it?

I was just talking about the -- you talked about the pressures on the margin, and then I was asking whether or not your growth in the immediate future at flat oil prices would be enough to offset that, or are you looking at earnings decline?

Of course, it depends what the cost pressures will be going forward.

We don't know that.

We continue to strive to offset them.

So I think the answer is I cannot give you a precise answer to that I am afraid.

Can I give you a little comfort, and that is this.

What we're missing at the moment is two very big revenue generators, which are in the process of being made revenue generators.

One is Texas City, which clearly has to go into complex upgrading of heavy oil; otherwise, it really is just a breakeven refinery.

And that is going to happen.

We have said that in '08.

And secondly, Thunder Horse, which is going to be repaired, and that will happen in '08, too.

So these will be very big uplifts to the -- all other things being equal -- to the financial condition of the firm.

So that is really quite an important point.

We're missing two things that we perhaps should otherwise have, and they are not hear yet.

Let me keep going around here.

Mark Iannotti, Merrill Lynch.

A question for Tony and maybe a quick one for John.

Tony, you talked in your presentation about the vast resources you have and the difficulties in recent years on converting those resources to production.

Thinking back to 2006, on some days you have announced delays to production projects.

Your market cap has -- your share base has fallen by more than the market cap of many of the companies, service companies that are helping you develop these projects.

With that type of context and also the comments you made about expectation for continued CapEx and OpEx inflation in the industry, is there any way you would think about taking your service providers back in-house?

And a question to John Manzoni.

John, can I just confirm what you said about Texas City?

You lost $1.1 billion in '06 on similar refining margins to '07.

You're saying you would cut that loss in half?

That is the guidance you're giving on Texas City for '07?

I think not taking service providers back in-house, but what we have been doing is building greater capability to provide closer oversight of our supply chain.

So greater capability at the frontline to oversee the activity, rather than actually bringing it back in-house.

When we recruited 2500 people into E&P last year, a lot of it was in the operational space to provide oversight, engineers, project engineers, supply to provide oversight of projects and operators to provide oversight of operations.

I said yes, we lost $1.1 billion in '06, and we should at least halve those losses in '07.

I would expect that is on the basis which is a slightly more conservative margin assumption than we experienced in '06 as we look forward.

Is there another question to take?

One more.

Yes, sir.

Paul Spedding, HSBC.

I have a question for Vivienne Cox.

I would be interested to know whether there has been any change in BP's thinking about the timing of perhaps getting Shah Deniz gas into Europe?

I'm thinking specifically of concerns about the security supply coming from Russia and also the EU's attack on the incumbents.

I think if it is okay, I will answer this one.

The first thing to say is that we clearly have had a few hiccups with the first well on Shah Deniz.

The second well we will be on in the next couple of weeks, and the field will ramp up through the remainder of the year into 2008.

Phase I develops a relatively small proportion of a very big resource as you probably know.

We suspect that the demand in the region will soak up a lot if not all of the future opportunities.

There are significant opportunities to expand, not only from the proven reserves that we have today, which will come on stream in 2012/2013, that sort of timeframe, but also deeper gas, which we are pretty confident is there.

But I think our view is that there's a lot of market between Azerbaijan and Europe that is hungry for gas.

So the likelihood of actually having real molecules from Shah Deniz make their way to Europe I think is quite remote personally.

Thank you.

Can I go back to Bob Malone and ask if there are more questions in New York?

Jason Gammel, Prudential.

I was hoping you could elaborate a little bit further on the nonconventional natural gas opportunities in United States at Wamsutter and the San Juan Basin.

Perhaps addressing in terms of how you expect this to mature from resource potential into reserves?

And then also could you address whether your more aggressive investment in these areas is related to technological advancements or if it is simply a reflection of higher expectations from normalized natural gas prices in the US?

Let me deal with that one.

This really has been about deploying technology to unlock a hitherto quite challenging resource base, and we have done two things.

The first thing we have done is to take seismic technology, which we perfected in the deepwater of the Gulf of Mexico back onshore and deployed it to understand the distribution of high and low permeability layers in the Wamsutter reservoirs, and it has been very effective.

So we are beginning to be able to map in a way that was not possible previously where to drill.

So rather then drilling on a grid pattern, we are actual able to target wells, so that is the first thing.

We actually know where the higher porosity permeability rock is.

The second thing has been some real breakthroughs in terms of completion technology, which has increased flowrates very significantly, particularly fracturing technology which has increased flowrates very dramatically.

And then the third thing we have done, we sort of wrapped it altogether into a very systematic programmatic approach committing to long-term recontacts and reaping the benefits of repeatability and continuity.

So, in the course of last year, with the same rig fleet, we were able to drill 50 more wells than we drilled the previous year, simply through driving efficiency through continuity and repeatability.

So I think it is an example of the application of technology to unlock what was hitherto a very challenging resource base, and it speaks to the point I was making in terms of the scale of our in-place resource base and what you can do with it if you get the right technology lined up against it.

So it is a technology play, not a revised gas price play.

I was just answering Jason's final question.

Let's have another question from New York if we could.

Tim Hurckes, John Bristol.

Mr. Hayward talked about increasing the recoverability up to 49% with current technology.

I was wondering if that is at the current oil price range of the 40 to 60 that BP is using or if different prices are needed?

No, it is in a current sort of range of prices.

So, as I said, we test everything down to 30, and most things would work in that range.

So it does not require a different assumption around price.

It is simply the deployment of the technology we have available today.

Thank you.

Another question, Bob.

John, Mark Gilman again.

I was wondering if you could perhaps give us a little additional insight regarding what specifically about Coryton lead to the choice of that as a divestment candidate?

Secondly, just a little bit more specifically.

Could you give us an idea what if any production impact will occur this year and in 2008 associated with the replacement of the gathering lines at Prudhoe Bay?

Let me ask John Manzoni to talk about Coryton and Tony to talk about Alaska.

Mark, to deal with the Coryton issue, as I have described, we are looking at fixing our portfolio to meet our projections of the marketplaces of the future.

And what is happening in the European continent is that the diesel and distillate markets are growing very strongly and the gasoline markets are declining.

Coryton is primarily a gasoline-making machine.

It can be made to make distillate, but that would take investment and others may be prepared to put that investment in, and I am sure they are, but we have better things to do.

We have more optimal choices to make with our investment dollars.

So the combination of those two things to allow us to shape our European portfolio, which is currently sitting around the top of the second quartile, I think if we could get it focused on the distillate better that would be a plus for us in our portfolio, and that was really the -- it is a strategic rationale behind what we are trying to do with our European portfolio.

On Alaska, there would not be any impact.

So we have already put in place bypass lines.

We did that as part of the program last summer, so, as we change out the oil transient lines, the bypass lines will be operating.

Bob, I will be back to you for a final round.

Let's come here if we can to the block over here.

We will start with you, sir, and then across and then back.

Gordon Gray, JPMorgan.

Two quick questions please.

One, firstly, given the difference in average cash margin between Russia and the rest of your portfolio, can you give us some confidence that your reserve replacement rate ex-Russia is also running comfortably above 100%?

And secondly, Bob, within Russia, do you have any plans or does TNK-BP have any plans for further downstream integration in capturing that margin?

Tony, first.

On reserves replacement, you have to obviously look at reserve replacement over run of years.

You cannot look at any particular year.

But if you look over run of years, then the reserve replacement is in line with where we are producing.

So if I take sort of a three to five-year-period, 25 to 30% of our reserve replacement is from Russia.

That is consistent with 25 to 30% of our production being from Russia, and the corollary is true.

Both high margin downstream.

In Russia we just completed the upgrade of two of our refineries in Russia for the first time, and last year it became more profitable to refine and market in Russia.

So we're going to expand further in the downstream in retailing, but you won't see major refining upgrades from TNK-BP anytime soon.

Thank you, sir.

Colin Smith, Dresdner Kleinwort.

Just going back to the stress in the service industry, I wonder if you could comment from your perspective as to whether or how quickly you think the lack of capacity there is being addressed and perhaps touch on what that might mean for CapEx on a couple of years beyond 2007?

Thank you.

I would like to pass this to Andrew Ingles who has to executively manage a significant amount of procurement.

Andy, what are the trends?

I think the trends are emerging.

There is clearly a lot of new build going on, and you can start to see that impact on some of the things which can be built more quickly.

Land rigs in the US, I think we're starting to see a softening of that.

So I would expect that to start to repair in some of the larger models, which is probably not until the end of the decade.

So clearly we are seeing the service industry respond to the tightness.

There is new capacity coming in.

We have seen these cycles before, and it is repeating itself.

I think the one probably issue that the industry needs to continue to work on is the human side of it is getting the manpower in place, so it will be trained so that we can operate efficiently.

But I genuinely believe we're starting to see the industry respond, and I think that trend will continue through the end of the decade.

Next row back.

Matt Lanstone, Goldman Sachs.

A quick question on decline rates and then one on CapEx.

Last year you talked about an underlying decline rate in the E&P portfolio of around 3%.

Could you confirm what sort of percentage decline rate you are assuming in your current guidance?

And then on CapEx, on Whiting is $3 billion going to be a reasonable budget given the inflation we have been talking about over and over during the presentation, and can you give us some feeling on phasing of that spend?

And then finally, can you talk about the CapEx outlook beyond 2007 maybe even just for 2008?

Okay, thank you.

Tony, decline.

John Manzoni, Whiting and (inaudible) CapEx.

Yes.

For the reasons that I have articulated, decline rates have been higher than we forecast.

We said 3%.

They have actually been between 4 and 5%.

And on the basis of our experience, it would be inappropriate to believe we are going to do anything better than that.

So our experience is projected into the future.

So on the Whiting side of that same question, much of the Whiting capital investment in heavy steel was actually preordered and so didn't see the height of the inflation that we have seen in the upstream business during the course of 2006.

I think that that will rise slightly as we go into 2007.

But 3 billion plus or minus the normal engineering tolerances at this stage in the project is really a good estimate for the Whiting project.

Maxim expenditure.

It ramps up.

We shall spending during the course of 2007 and maxim expenditure goes through nine and 10 and the projects -- or eight and nine and the project starts up in 2011.

So on CapEx for the future I would expect a gentle rise in our activity.

We certainly won't be reducing the amount of activity we are doing commensurate with the scale of the firm.

The real question is pricing it, and I think from everything that Andy Inglis has said and what Hayward said in his presentation, it is actually wrong of us to try and guess what industry-specific inflation will be in '08.

We need to go through '07 first to see how the trends that we think are complicated and will probably change direction some time between now and the end of the decade how they actually develop.

I think we are putting our money as it were where our mouth is by making sure that we don't procure very long-term contracts for things where we think actually there will be a weakening of the market in due course.

So let's take another one.

Sir, behind you.

Lucas Herrmann, Deutsche.

I wonder if I could ask two questions.

The first is around or comes back to production guidance, and looking forward down to '09, I think some of the larger projects that one would have expected to drive growth but relatively clear.

But you talk about more than 4 million barrels in 2009, and there's almost a ramping growth between 2009 and 2012.

I know it is a long way off, but I just wonder if you could give us a better idea of quite what it is that drives the more meaningful growth should we say between the nine and 12 period given by that time you should have Thunder Horse, Atlantis, Plutonia, etc. on stream.

How much of it is base effect?

How much of it is about TNK-BP coming back?

And the second question, completely different, was on payout ratios and the dividend.

I just wonder whether you could give us some indication of either the level of payout ratio that the company would perhaps be comfortable with, either from a -- well, I guess payout ratio from a P&L basis.

But otherwise the extent to which you would be willing to should we say go cash negative as a consequence of funding your dividend?

And I guess that dares in mind balance sheet restraints.

(multiple speakers).

Let me see if I can do some generalities on the production.

Firstly, I think you heard Bob say that we expect TNK-BP to be flat through the end of the decade and not really to begin growing again until beyond 2010.

The growth that we are seeing is clearly driven by the growth in the new profit centers.

That chart that I showed that has that long steady 13% year-on-year growth, that is going to continue.

And we have taken a more conservative view on our EPC decline.

So if you sort of put all that together, I think you will get the profile that I talked about.

The EPC is clearly getting smaller, so it will have less of an impact.

The NPCs are continuing to grow at the same rate, so do the math.

It sort of works I think.

Byron, talk about power resin if you will please and dividends?

The Company takes its dividend decisions on the basis of a number of factors.

It certainly does not look just at the environment we see today.

It looks to more conservative environments that may develop over the course of time and with an eye towards the sustainable growth pattern of the firm as well.

What I would say is that we believe, as we look across the sector as a whole, that we are being very generous in our dividend payout that relative to underlying earnings or relative to operating cash flow, BP paid out higher dividends in 2006 than anybody in the competitor set.

And that competitive positioning is obviously yet one other element that is considered in this process.

If you look at the period from, let's say, in '95 to today and you look at the match of earnings and dividend growth, they are pretty well in balance.

I think the long run approach to dividends is very, very important.

On the question of cash, we do worry quite a lot to make sure that if the price of oil dropped or something happened, some stress occurs at the company that actually there would be sufficient cash to cover the dividend.

This is very important to us, indeed, because it is part of the enduring obligations of the firm.

We regard the dividends as a fixed cost which must be considered as we go forward.

So that is our attitude to that.

Can I go back to New York now and see if there are any other questions there, and then we will carry on in London.

Bob?

John, no further questions.

Great.

Well, there's active questions in this particular block over here.

Let's carry on.

Peter Nichol, Tristone Capital.

A couple of questions if I may.

Yesterday Anadarko commented on the impact of the Algerian windfall tax and their operations.

I just wondered if you could quantify any impacts on earnings or reserves from that?

And the second is going back to oilsands and obviously the $3 billion investment in Whiting, do you see the Whiting investment as a means or potential opportunity to reverse into the oilsands in due course, or does your view on the oilsands lead you to believe that the real opportunity set is going to be in the downstream margin arising from the production rather than upstream?

Thank you.

Tony?

As you know, our principal business there is gas, and the sale of gas is not subject to this particular tax.

There will be a very minor impact, very minor impact, less than $10 million on our operations in In Amenas, very small.

I think as to Whiting, we obviously have confidential contracts for the purchase, long run purchase of heavy crude oil from Canada, and that is what we're doing.

We are buying the crude oil.

Obviously it is good for the producer and good for us if we can make the right deal.

This is not a step to reverse into the upstream.

Someone else is doing that, and that is where the positioning is.

Now, let's sweep around.

Sir?

Neil Morton, Man Group.

It is a question on E&P organization.

Several years ago, in fact, the last time that BP deemphasized production or point production targets, there appeared from an external observer's perspective an issue of information bottlenecks, i.e. bad news not being passed up the line.

Now I don't know if that still persists, but Tony Hayward suggested recently that the guys at the top of E&P were not listening well enough to the guys at the bottom.

I just wondered what organizational changes perhaps you would suggest to improve matters?

I don't think we're thinking organizational changes.

My comments, which were rather inaccurately reported but widely reported, were not in anyway referenced to quality of information with respect to where we were on production.

I can tell you everyday of the week pretty well where we are on production.

I get a report every week.

And, as I have said, the issue we have had is not about forecasting per se.

It has been about our ability to plan and execute activity.

Let me -- we are all happy over there.

I'm going to come back over here, sir?

Jon Wright, Citigroup.

I had a question, I suppose there are two elements to it.

The first is for Tony.

BP today recommitted to distributing 100% of free cash flow to investors.

Should we expect the mechanism to be exclusively buybacks as it has in the past, or are you open to consider other options?

And secondly for Byron, I understand you have about now 10% of your shares in treasury.

I wonder if you could give us an indication of when or if those are intended to be canceled?

I think -- who would like to do this?

I tell you what, we will come from Byron.

Why don't you take the whole question?

Okay, fine.

This is something that we review on a regular basis as to whether or not the use of any excess cash flow to buy back shares in a conventional market program is the right way.

What we have concluded and continue to believe is that it is.

And the most important thing to do is to have, as Tony mentioned earlier, a very clear financial framework and one that you maintain over an extended period of time, not jumping back and forth trying to follow whatever is the most exciting convention of the day.

As far as the treasury shares go, we have put them in treasury and there's a limit of 10%, so there will be molten no more going in there.

Because we believe that it provides potentially some option value.

It is not because we have any particular idea in mind.

We treat them when we are just sorting out our per-share metrics equivalent to as if they had been canceled.

So we're going to leave them there because we don't believe it makes any difference one way or the other, but has potentially some small option value associated with it.

I would just like to -- I'm sure the board would like me to do this -- to clarify one more time the distribution of cash.

We have a progressive dividend policy.

We regard at least today's dividend as a fixed charge to the firm.

Very important to consider.

We progress it over time.

Secondly, excess free cash flow that is above reinvestment in the firm and the payment of dividend is dedicated to stock buybacks.

That is where the board is at present, and there's really no more information I can give you on that.

Now, sir?

[Maurice Saculli], [Axim Investment Managers].

It has been mentioned before that Russia is becoming a more difficult place where to do business.

I have two questions there.

First, do you think that this environment will remain as it is or will worsen further?

And the second, are you considering it to change in anyway or to adopt your existing strategy to these changes?

Can I turn to Bob about the environment, the most knowledgeable person I think certainly in the executive here.

Well, I think it is fair to say that many countries around the world are complex to operate in.

Russia is another one.

We have been operating there for four years.

We are not operating on a project by project basis.

We're a Company that is woven into the oil sector there and doing it quietly and successfully, and no indication to me that that is going to change.

There will be lots of headlines.

There will be lots of noise.

We will go through lots of license reviews and compliance issues, but the track record is, despite all the speculation over the last three or four years, we're doing very well as a company.

Regarding entertaining changes to the structure, it is a matter for the shareholders.

I represent both sets of shareholders.

Both sets of shareholders are committed to what we do everyday.

Long-term plans, capital investments are rising, and to me that is a good indication of their intent to stay firmly committed to the business.

I cannot speak on behalf of the other shareholders, but I can on BP, we intend to retain our shares.

I'm informed by the other shareholders that they, too, intend to do that, but they are their shares not ours.

But that is apparently their -- that is their presence intention.

I would just add on the development of Russia, what I welcome very strongly is our deepening relationship both with Rosneft and Gazprom.

Tony outlined some of the steps.

With Rosneft we have a very important joint venture in Sakhalin, which was signed a couple of months ago.

We also are a shareholder in Rosneft, and we have great cooperation in that regard.

We have other joint ventures in formation with Rosneft.

With Gazprom, we have a joint venture of gas processing.

Also, we are joint owners of an oil production company called Slavneft, and we have other activities developing.

These are new things that have developed really quite recently in Russia and I think a very healthy sign for the future.

I think, ladies and gentlemen, we have exhausted ourselves.

Thank you very much for coming, and thank you for your questions and answers.

Thank you, New York, for being with us.

It is a great pleasure to have everyone in one place at one time.

Thank you very much for coming.