英國石油 (BP) 2005 Q4 法說會逐字稿

I apologize for that slight delay.

Ladies and gentlemen, welcome both to those of you who are here in person today and to those of you joining us today by webcast.

Before we start I'd just like to draw your attention to three items.

Firstly a word about safety.

There are no planned fire drills today, so if you hear a continuous alarm sound do please leave immediately via the nearest fire exit.

There are three exits clearly marked at the rear of the room.

You should then follow the exit signs into St. James' Square and assemble by the sign marked "Visitors" in the center of the Square.

Secondly, I'd 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 the slide.

Finally, as this slide points out, the presentation today does contain some non-GAAP measures.

A reconciliation to those non-GAAP measures can be found on our website, BP.com.

I'd now like to hand over to John Browne, our Group Chief Executive.

Fergus, thank you very much.

Good afternoon, ladies and gentlemen.

We're delighted to be meeting with you face to face and, as ever, there's much of interest to discuss; but the format of the day, however, is pretty conventional.

Firstly, Byron is going to take us through the fourth-quarter and full-year results dispersed earlier today.

And then we would like to talk about our strategy, our view of the external environment, and the leadership team will then speak on sub strategies and operations of each of their businesses.

Specifically Tony Hayward and Andy Inglis will discuss E&P, Vivienne Cox will cover gas, and John Manzoni refining and marketing.

The purpose of this presentation is to demonstrate to you that we have the assets, markets and capabilities to deliver our strategy.

I'll then put it all together in terms of progress to date and guidance for the forthcoming year and beyond, especially as it relates to our ability to continue to generate free cash flow and distribute it to shareholders.

I know many of you listened to the technology webcast hosted by Iain Conn in December, so we won't repeat that; but we'll be happy to take questions on it when we come to the third part of the event where the entire team will be ready to answer your questions.

So first, to the results.

In 2005 we delivered a record level of underlying net income of $21.1 billion, up 32% versus 2004 on a per-share basis.

We delivered a record level of free cash flow of $25 billion.

We strengthened our balance sheet by reducing the gearing level to below 17%.

We completed the sale of Innovene yielding cash proceeds of $8.3 billion.

We replaced 100% of our production with new proved reserves and had another strong year of expiration success.

This is the 13th year in a row we've replaced 100% or more of our production.

We started up seven new upstream projects -- Rhum, Clair, Central Azeri, West Azeri, Mad Dog and Atlantic LNG Train 4.

We launched the BP alternative energy business.

We distributed about $19 billion of cash to our shareholders.

And finally, we announced a dividend to be paid this quarter of 9.375 cents per share, an increase of 10% year-on-year in dollar terms, some 17% year-on-year in sterling terms.

This is the first year in which we're presenting our results under IFRS.

As expected, this method of accounting creates significant volatility in profit measures, although not, of course, in cash flow.

This volatility results from the requirement to mark to market embedded and financial derivatives and the effective inability to account for economically matched transactions as hedges.

This last affect resulting in asymmetric treatment of different parts of the same economic event.

Some would argue that IFRS neither produces a record of the accountability of management nor a measure of the changes in the economic value of assets and liabilities.

I would agree with them.

What IFRS actually does is to make our results very much more difficult to understand.

I hope that Byron, in his review of '05, will be able to help you better understand the underlying performance of the Group.

But this administrative issue should not distract us from either the true quality of these results or for the strength of the outlook for the Company.

2005 was a very good year, not just because of the year's performance, but also because we were able to confirm the foundation for even better years to come.

Our reserves replacement is the product of the strategy we put in place more than a decade and a half ago.

The resources we now have provide the base from which we expect to grow production by 4% a year through 2010 and strongly thereafter.

We expect to maintain a steady and disciplined pattern of investment and protect the efficiency of that investment by controlling cost increases to below the level of inflation.

We continue to high grade the portfolio and we expect divestments to be at an ongoing rate of around $3 billion a year.

And as a result of all that, we expect to continue to distribute substantial amounts of cash to shareholders through buybacks and dividends.

If the average oil price is the same as it has been over the last three years, that is with Brent at around $41 a barrel, the planned distributions over the next three years should total around $50 billion.

At current prices that is with Brent around $60 a barrel the distributions would be around $65 billion.

So a good year, but not the end of the story.

As I may have said before, the best is yet to come.

Now let me hand over to Byron who will take you through the details of 2005.

Good afternoon.

As John indicated, I will focus on our fourth-quarter and full-year results.

This will set the stage for my colleagues to elaborate on our longer-term strategy and operating plans.

Looking first at market conditions, prices and margins in both the fourth quarter and full year were up significantly compared with 2004.

Oil prices and refining margins peaked in 3Q, and gas prices grew strongly in 4Q.

Our average oil realization approached $54 per barrel in the fourth quarter and exceeded $50 per barrel for the year.

This reflects tight global production capacity, as well as the hurricane-related interruptions during the second half.

Our average gas realization increased to over $6 per thousand cubic feet in the fourth quarter, as prices in all markets rose substantially.

Our 4Q refining indicator margin remained high by historic standards, although it was lower than the record level reached in the third quarter.

Overall marketing margins in 4Q recovered from low 3Q levels, partially offsetting the decline in refining margins.

Turning to the financials, our fourth-quarter result was adversely impacted by a number of factors related to international financial reporting standards, as John mentioned.

We have treated some of these as non-operating items in line with earlier quarters, but have retained others within the normal operating results of the segments, and I want to focus on the latter.

Accounting under IFRS has made our reported earnings more volatile as we saw in 4Q.

It is not possible to accurately estimate all of the impacts in advance of the quarter close.

Although they are unlikely to be material in the context of the group over the year, they can dramatically impact the results of an individual segment in a given quarter.

I want to stress that they represent asymmetric accounting treatment of the two sides of risk management positions for which there is no economic exposure, and that they would be expected to net out over time.

I will come back to this point again when I discuss the impacted segments.

Now moving to the slide, our fourth-quarter replacement cost profit of $4.4 billion was 26% higher than the fourth quarter of 2004.

On a per-share basis, the increase was 31%.

This reflects the benefit of share buybacks over the past year.

Our profit including inventory gains and losses was $3.7 billion, up 22% in absolute terms or 28% per share.

These figures include non-operating items, which I will describe in a moment.

Excluding those, our underlying replacement cost profit was $5 billion, up 5% in absolute terms or 9% per share compared with 4Q '04.

Operating cash flow in the fourth quarter declined compared with a year ago to $4.2 billion.

The year-on-year difference mainly reflects seasonal inventory builds at prices that were significantly higher than in 2004, as well as tax phasing impacts.

The 9.375 cents 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 up 17% year on year, reflecting the strengthening of the dollar.

Our full-year results at the bottom of the slide are records for the Company.

These include replacement cost profit of $19 billion, up 25%, profit including inventory gains and losses of $22 billion, up 31%, and operating cash flow of $27 billion, up 14%.

Our fourth-quarter earnings included a post-tax charge of over $550 million for non-operating items.

The pretax charge was $1.2 billion.

The main element was a $1.4 billion net IFRS mark-to-market charge on embedded derivatives.

This was mainly related to long-term UK gas agreements where the contractual pricing terms did not keep pace with the increase in the gas forward price.

This chart shows the main elements driving the 25% improvement in our full-year replacement cost profit from $15.4 billion in 2004 to 2005's record $19.3 billion.

Charges for non-operating items were around $700 million greater than in 2005.

Higher oil and gas prices added around $7 billion year-on-year.

Acquisition and divestment activity was neutral overall.

The 4Q gain on disposals in TNK BP offset the impact of prior sales of non-strategic assets.

Higher depreciation, depletion and amortization charges impacted our result by around $100 million year-on-year.

Operating incidents at our Texas City refinery and extreme whether events impacted our results by around $3 billion pretax or $2 billion post tax, as shown here, compared with 2004.

This includes foregone production of prevailing prices and margins as well as directly related response and repair costs.

It does not include the charge taken in the second quarter for Texas City third party liability claims or Gulf of Mexico shelf impairment charges related to hurricane damage which we reported as non-operating items.

We also took incremental charges in our refining and marketing segment, concentrated in the fourth quarter, for planned restructuring actions intended to improve our efficiency and competitive position.

Other factors netted out.

Underlying operating improvements and strong supply optimization performance during the year offset the impact of cost pressures and a higher tax rate both resulting from the strong price and margin environment.

I'll now summarize the 4Q results for each segment starting with exploration and production.

As shown in the chart, our E&P result increased 38% to a record $6.6 billion driven by higher oil and gas realizations.

The increase, excluding non-operating items, primarily an $800 million charge related to embedded derivatives, was 52%.

Our fourth-quarter results also included around $130 million of repair costs related to storm damage in the Gulf of Mexico and Thunder Horse on top of the $100 million reported in 3Q.

TNK BP contributed over $700 million to our 4Q result, 73% more than a year ago.

This reflects higher prices and higher volumes.

Our 4Q result also included the $300 million adverse impact of the lag calculation of reference prices for export duties as Eurol's prices peaked in 3Q and then declined.

This was largely offset by a $270 million gain on disposals.

All these figures are post tax consistent with IFRS reporting for equity accounted entities such as TNK BP.

We also received dividends of more than $500 million from TNK BP in 4Q which brought the full-year dividends to nearly $2 billion.

Although our full-year production growth was constrained by the impact of extreme whether events, we achieved total production of over 4 million barrels per day.

This reflected higher production in our new profit centers and TNK BP.

On a UK reporting basis this is the 13th consecutive year that we've replaced 100% or more of our production.

This chart summarizes our total reserves replacement for subsidiaries and our proportionate share of equity accounted entities in the past two years under both UK and U.S. reporting bases.

The results shown include reserves added through discoveries, extensions, revisions and improved recovery excluding A&D activity.

Based on the UK's statement of recommended practice, or SORP, our total combined reserves replacement was 100% in 2005.

This is based on our long-term planning price assumption.

The 2005 result reflects a change in this assumption from $20 a barrel to $25.

Absent the change we estimate that our 2005 UK SORP reserves replacement would have been similar to 2004 which was 110%.

U.S. reporting practices require the use of year-end prices to calculate reserves.

So the result is influenced by the impact of price changes on our share of volumes held under production sharing contracts.

On this basis our reserves replacement was 95% in 2005.

Turning to refining and marketing, we reported a pretax loss of $160 million for the fourth quarter of 2005 compared with a $1.3 billion profit a year earlier.

Refining and marketing margins strengthened between these periods, but this was more than offset by three major items that impacted our fourth-quarter result.

Firstly, our Texas City refinery was shut down in the third quarter as hurricane Rita approached and is yet to restart as we complete its refurbishment.

The absence of this refinery, along with storm-related impacts in other businesses, reduced our fourth-quarter result by $1 billion.

This includes profits foregone in the prevailing margin environment as well as direct response and repair costs.

Secondly, we recognized restructuring charges a nearly $500 million in the fourth quarter primarily related to planned actions to improve our operating efficiency in Europe.

And thirdly, our 4Q results include around $500 million of adverse impacts largely related to asymmetric accounting treatment of portions of our normal operational activities under IFRS fair value accounting.

Much of the volatility we saw in our 4Q result was driven by the forward trajectory of market prices at year-end combined with the fact that we entered the quarter with very low levels of refined product inventory following the hurricanes and exited the year with relatively high levels as we built stocks in line with normal seasonal patterns.

Our 4Q result in Gas, Power and Renewables was around $100 million.

This includes more than $300 million of charges for non-operating items mainly related to IFRS accounting for embedded derivatives.

Excluding these non-operating items the result was around $400 million, around the same level as in 4Q '04.

This reflects lower gas trading and marketing margin relative to the very strong contribution in 4Q '04.

The IFRS accounting effects, which reduced the R&M result I just described, by contrast increased our GP&R result by nearly $300 million in the fourth quarter.

In other business and corporate, or OB&C, we reported a charge of around $400 million.

This was $150 million greater than last year.

Excluding non-operating items the year-on-year difference was $100 million.

Fourth-quarter results in the past two years reflect phasing of costs for corporate activities over the course of the year.

The phasing impact was slightly greater in 2005 than in 2004.

Following the announced agreement to sell Innovene we now report our Olefins and derivatives results in two places.

Innovene, which is now sold, is reported as a discontinued operation.

We completed the sale of Innovene to INEOS on the 16th of December realizing cash proceeds of $8.3 billion in 4Q.

Operations that were not sold as part of Innovene, mainly our joint ventures in China and Malaysia, are reported in other business and corporate for 2005.

For 2006 reporting we intend to report these operations as part of our refining and marketing segment.

We'll restate historical results accordingly and provide further information in this regard to prior to issuing our first-quarter results.

I'd like to close my discussion of segment results with updated guidance on various group items for 2006.

Following transfer of the retained Olefins and derivatives businesses we expect this year's result for other business and corporate to be within the previously indicated range.

A net charge of $900 million plus or minus $200 million.

This does not include the impact of our annual review of environmental and other provisions which occurs in the third quarter and which resulted in charges averaging around $450 million the past two years.

We use primarily floating-rate debt to finance the Group.

So finance interest will continue to vary in proportion with our debt levels and prevailing interest rates.

We expect other financing costs to improve from a net charge of around $100 million in 2005 to a net credit of around $100 million in 2006.

This is largely due to growth in our pension assets during 2005.

Excluding these financing impacts we expect both our charges and cash funding levels for pension and benefit plans in 2006 to be comparable with those in 2005.

Turning now to income tax, our actual tax rate depends on prices and margins during the year.

This guidance is based on the assumption of similar market conditions to 2005.

Holding market conditions constant we'd expect to report an effective tax rate on earnings of about 39% in 2006 compared with a reported rate of 32% in 2005.

There are two main factors driving this increase.

First, the 2005 rate included a onetime net benefit of around 3 points from provision releases.

Secondly, the announced tax increases for the UK North Sea are expected to increase our underlying effective tax rate by around 2 points and also require a onetime deferred tax adjustment resulting in a further 2 point increase in our reported rate for 2006.

Looking beyond 2006 the new underlying rate of about 37% would imply other factors being equal.

The UK tax changes also increase our marginal tax rate to around 42% compared with the 40% rate I previously indicated.

The cash tax rate in 2005 was 31%.

Tax payments tend to lag earnings so some of the taxes on last year's record results will be paid in 2006.

The UK tax changes and prevailing prices and margins will also impact the cash tax rate.

Putting this altogether and assuming similar market conditions as in 2005, we expect the cash tax rate to peak at around 40% in 2006 and then fall back towards 35% in subsequent years.

Just as changes in our portfolio and the level of prices impact the tax rate, they also impact the rules of thumb that some of you use to model our results.

These are shown here.

As in the past, they 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've seen in the past few years.

Returning to overall Group results and turning from earnings to cash, this slide compares our sources and uses of cash for 2004 and 2005.

Cash inflows in 2005 approached $38 billion.

Operating cash increased to $27 billion and disposals added more than $11 billion.

Uses of cash remained consistent with our strategic intent; organic capital expenditures were around the same level as in 2004; and distribution back to shareholders increased by 40%.

Our net debt ratio ended the year at 17%.

The reduction in 4Q reflects the stronger cash flows both from underlying operations and the sale of Innovene net of normal year-end working capital and tax phasing outflows, most of which will reverse this quarter.

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

Our aim is to return gearing to the lower half of the band.

During 2005 we returned around $19 billion to investors via a 26% increase in our per-share dividend and a higher level of share buybacks.

Share buybacks totaling $11.6 billion for the year reduced shares in issue by 4% and we accelerated the pace of buy backs during the second half.

We remain committed to distributing 100% of all excess free cash flow to investors, other factors being appropriate.

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

With our year-end gearing and strong cash generation we are well-positioned for further substantial share buybacks during 2006.

That concludes my presentation of the results.

Now back to John.

Thanks, Byron.

As Byron said, the results we delivered in 2005 were magnified into a record by the strong external environment.

But these results could not have been delivered without the position established in the past era of low oil prices, the subsequent level of investments and the ongoing performance improvements.

These have allowed us to capture the margins available.

In '05 the world economy grew by about 3%, somewhat slower than in '04.

This supported oil demand growth of over 1% despite the strength in oil prices.

For '06 we expect similar economic and oil demand growth, the U.S. economy continues to expand and there is robust growth in the emerging economies.

In '05 the year-on-year growth in non-OPEC volumes was lower than average, but this reflects the substantial impact of the Gulf of Mexico storms.

Overall we think there was relatively modest growth of around half 0.5 million barrels a day with new production mainly from Angola, Brazil, China and Russia offset by declines in the North Sea and onshore North America.

And with the modest capacity additions that were made in OPEC, global production was running close to capacity as it was in '04.

This resulted in very strong prices, the Brent oil price averaged over $54 a barrel, up 42% from '04 levels.

The global market worked and supplies were forthcoming.

Fundamentals have already eased as the production loss from the hurricanes, which peaked at 1.5 million barrels a day, has now largely come back on stream and new production is starting up inside and outside OPEC.

The world demand growth remains robust and OPEC's spare capacity is likely only to rebuild towards its 3 million barrels a day historic level over the next few years.

OPEC's market share is expected to remain largely intact as will its ability to deliver its price objectives.

The vulnerability to a significant supply disruption is also expected to remain high.

This backdrop is why we believe there is a good medium-term support for prices to average above the $40 a barrel level, as we indicated a year ago.

This of course presumes no sustained measured downturn in demand which could result from a deep and long global slowdown.

Over the longer-term, the range of possible price outcomes is much wider.

Quite how and indeed when the transition takes place between the medium-term and the long-term is in my view quite incapable of prediction.

Higher oil prices lead to conservation and substitution and also tend to alter the mix of energy sources used in the world.

There is likely to be increased supply of conventional crude oil and nonconventional liquids.

Some biologically derived and some from conversion of other hydrocarbons as well as from Bitumen.

Concerns about security of supply could promote the development of localized energy sources and concerns about climate change could promote low carbon energy sources.

Both require technology advances, but over time these responses could lead to a reduction in expected oil demand and prices well below $40 a barrel.

BP has a strategy that is designed to be robust to a very broad range of outcomes and that's why we test our projects down to $25 a barrel.

At the same time there are potential drivers that work to sustain high oil prices; these include stronger growth in demand, particularly in emerging economies, slower than expected advances in the development of alternative energy sources and the risk of non-OPEC growth falling below present expectations.

Turning now to gas prices.

Gas markets have been particularly strong, building on the trends seen over the last few years.

Prices reached record highs during '05 in the two largest liberalized markets of the U.S. and the UK.

The annual average gas price in the U.S. increased by 52%.

This is because prices are set by competition at the margin with oil.

But the price was also bolstered by the severe hurricane-related disruption to domestic supply; about 17% of U.S. domestic gas production was lost at peak.

Since 2000 U.S. gas consumption has continued to fall by about 1% per year on average.

And despite the additions of new import capacity, the U.S. market is likely to remain supply constrained for several years given the continuing decline in domestic production as well as the current limited availability of international LNG supplies.

U.S. gas prices are likely to remain strong for the medium-term, frequently well above fuel oil parity levels in the spot market.

The UK became a net importer of gas for the first time in '04.

There is significant new import infrastructure planned over the next few years; the Isle of Grain LNG terminal is scheduled to be joined in a few years time by two more terminals in Milford Haven and two new pipelines providing access to offshore supplies.

These are expected to change pricing.

UK spot prices should become more closely linked to the largely oil price driven European and Henry Hub influenced Atlantic LNG gas markets.

Whilst underlying gas demand should be strong in both the U.S. and Europe driven largely by power generation requirements, the impact of high gas prices on future demand growth is a key uncertainty.

So while gas prices may be at or above distillate parity during cold snaps this winter, further out we should expect them to move within the fuel oil to distillate range.

Next a word on global refining margins.

BP's Global Indicator Refining Margin averaged about $8.60 in '05, up by 36% from '04.

Over the past two years the surge in global demand for oil products has reduced the level of spare refining capacity which had existed for so long.

Hurricanes Katrina and Rita had a major impact in the second half of the year, playing as they did into an already tight market.

Refining margins peaked at nearly $30 a barrel in this period and yet by December were back to $5 a barrel as markets rebalanced supported by the IEA led release of strategic stocks.

In addition, the marginal crude oil barrel became increasingly heavy and sour.

This has resulted in a widening differential between light sweet and heavy sour crude oil streams.

Complex upgrading refineries such as ours in the U.S. and Germany are well positioned to take advantage of these differentials.

More stringent product specifications have put additional demand on refining hardware and infrastructure effectively reducing supply capacity.

Looking out across the next few years the environment continues to look robust, particularly for upgraded refineries.

Demand growth is likely to be greater than capacity additions.

This is why for the next few years we expect Global Indicator Margins to remain above $5 a barrel.

Further out there are more uncertainties.

Confirmed and unconfirmed refinery projects would increase refining capacity by nearly double market growth by '08.

Many of these projects will not come to fruition, but clearly some will especially in the light of strong margins.

This means that we should continue to expect cycles in margins.

A long-term successful strategy relies on having quality assets in the right locations.

In the end the environment cannot be forecast with precision.

We believe that clear strategies implemented with strategic discipline and operational responsiveness are the key to competitive performance and are factors within our control.

So I'd now like to turn to our business segments and their operational implementation and we'll start with E&P where our strategy is unchanged and it is to grow production with steadily improving returns by focusing on finding the largest fields, concentrating our involvement in a limited number of the world's most prolific hydrocarbon basins, building leadership positions in these areas and managing the decline of existing producing assets and divesting assets when they can no longer compete within our portfolio.

We carry forward significant momentum including the planned start up of more than 20 new projects over the next three years underpinning our production growth of over 4% at an oil price of $40 a barrel through 2010.

Over the next few years this new production is expected to result in overall higher unit cash margins.

We have a large and high-quality set of opportunities.

We have 18 billion barrels of proven reserves and some 41 billion barrels of additional non proven resources.

We expect to move around 11 billion barrels of these resources into reserves by 2010.

On top of that, based on our proven expiration track record, we should add over time a further 10 billion barrels of resources from our existing exploration portfolio.

Successful access to new positions will allow us to continue to build further on this position.

It's the quality and the magnitude of this resource position that underpins our expectation of continued strong production growth beyond 2010.

Put another way, we don't need to acquire anything to continue our strong growth.

The success of our Russian investment is reflected in its production, growing faster than that of competitors, reserve replacement well ahead of production, and very attractive dividend flows.

We expect this to continue.

We expect to continue a disciplined approach to capital expenditure of around $11 billion in '06 and maintain an intense focus on cost control.

We expect to maintain the strength of the overall portfolio, sustained by the nature of the additions and an ongoing program of tail divestments.

Now let me hand over to Andy and to Tony, Tony first, to take you through the E&P segment.

Thanks, John.

Good afternoon, everyone.

Andy and I are going to do a double act today on E&P.

I'll start with a brief review of the E&P strategy and progress with our exploration program.

Andy will then review progress on the major projects, the development of our new profit centers and how things are progressing in our existing profit centers.

I'll then pick up with Russia and how the segment overall is shaping up through to 2010 and conclude with a view of how our resource position is developing for the longer term.

Let me begin with strategy which, as John has already stated, has remained unchanged since 1989.

The consistent application of these fundamentals has guided everything we have done despite the oil price ranging between $10 and $65 a barrel over that time period.

We focus on a limited number of the world's most prolific hydrocarbon basins where the opportunities can be material to BP.

Our focus is on finding the largest fields because big fields matter for two reasons -- one, the larger the field being developed the greater the number of barrels over which to spread a fixed cost base thereby lowering the unit costs; and two, big fields attract continuing investment to increase the recovery factor.

In fact, I think it's true to say that in the history of the industry no field greater than 1 billion barrels has ever been abandoned.

We've been a first mover in many of the most promising new areas of opportunity, from the deep waters of the Gulf of Mexico and Angola enabled by new technology to Azerbaijan and Russia enabled by political change, and have been successful in creating the number one or two position in each of these areas.

We manage the decline of our existing producing assets and exit when the opportunities for future investment are no longer competitive within our portfolio.

Throughout we exercise rigorous quality through choice -- not choosing to drill every exploration prospects, not choosing to develop every discovery and not choosing to invest into every mature asset.

Over the last three years we've divested an average of $2.5 billion per annum.

We expect to be able to divest around $2 billion per annum going forward.

All of this is designed to build production with steadily improving returns.

Our strategy begins with a focused exploration program.

As this external analysis by Wood McKenzie demonstrates, we have been the industry-leading explorer over the last decade, finding more oil and gas at lower cost and creating more value than any of our principal competitors.

This success has created an enormous value which allows us to high-grade our investment opportunities supporting both higher returns in the projects we choose to develop and a high level of disposal proceeds for those that do not meet our investment criteria.

Over the last decade we have on average discovered in excess of 1 billion barrels of oil equivalent a year at an average finding cost of less than $2 a barrel.

In 2005 we continued our strong track record despite delays to the program because of the storms in the Gulf of Mexico.

We made a total of 12 discoveries from a focused exploration program of 19 wells.

Major successes included a number of new discoveries in the deep water Gulf of Mexico, a group of new discoveries in the southeast of Block 31 in Angola where we now have nine discoveries from 11 wells, and a second important discovering and Sakhalin, which is beginning to emerge as a potential new profit center for BP.

Our core exploration program is now focused around -- firstly, the deepwater Gulf of Mexico where we continue to see significant potential within our existing portfolio.

Secondly, Angola where over the next few years our focus will shift from the Eastern area of Block 31 to the Western subsalt area.

Thirdly, Trinidad where we will begin this year to test deeper plays in a prolific gas province.

Fourthly, the deepwater of the Nile Delta where our Raven discovery at the Miocene level in 2004 opened up a new play system.

On the basis of the prospect inventory we hold today we expect the Nile Delta in Egypt to emerge as an important new profit center for BP in the early part of the next decade.

Fifthly, Algeria where we were successfully accessing three very large tracts of exploration acreage in a license [round] last year, two of which are adjacent to our In Amenas project area.

And finally, Sakhalin, which as I've already mentioned, whilst it's still early in the exploration of the province, we see significant future potential.

In 2006 we expect to increase investment in core exploration to around $700 million from around $500 million in 2005.

This is a reflection of the depths of our opportunity set.

In total on a risk basis we have an exploration prospect inventory of more than 10 billion barrels of oil equivalent.

Let me now turn to reserve replacement and finding and development costs.

As Byron has already highlighted, on a UK reporting basis this is the 13th consecutive year that we have replaced 100% or more of our production.

Our reserve replacement ratio for subsidiaries and associates, using our long-term planning assumption of $25 a barrel, was more than 100%.

At $20 a barrel it would have been around 110%.

Over the last five years we've replaced 134% of our reserves.

On an SEC basis using year-end 2005 prices reserve replacement in 2005 was 95%.

Turning now to finding and development costs.

Industry finding and development costs have risen significantly over the last few years driven by a rising capital expenditure as new provinces such as Azerbaijan, Angola, Kazakhstan, the deepwater Gulf of Mexico and Sakhalin have been opened up and by sector specific cost escalation which I'll discuss later.

BP's five-year rolling average finding and development cost at the end of 2005 for subsidiaries and associates was around $5.10 a barrel of oil equivalent, a very competitive performance versus the industry.

Let me now pass to Andy.

Thanks, Tony, and good afternoon.

I'd like to start with an update on the progress of our major projects.

As this chart shows, over the last three years we've brought on stream 20 major projects which have together developed 2 billion barrels of reserves which we expect to add 500,000 barrels a day of production in 2006.

With the exceptions of Thunder Horse and BTC, all have essentially started up on schedule.

Specifically in 2005 in the Gulf of Mexico we started up Mad Dog and completed three out of five of the pipelines -- the Mardi Gras transportation system.

In Azerbaijan Central Azeri came onstream in February and West Azeri started up as the year closed, some four months ahead of schedule.

We inaugurated the BTC pipeline in May while it is now in Turkey and we expect to have first crew to Ceyhan in the second quarter of 2006.

In Angola Kizomba B started up in July some four months ahead of schedule.

In the North Sea we started up Clair and Rhum, and in Trinidad we commenced liquid faction in LNG Train 4 during December and lifted the first cargo in early January with ramp up following Cannonball's start up this quarter.

Over the next three years we expect to start up a further 24 major projects which are planned to develop around 3.7 billion barrels and at 850,000 barrels a day to production in 2009.

As you can see, the majority of these are already in development.

In 2006 in the Gulf of Mexico we're planning to start up Thunder Horse in the second half of the year followed by Atlantis around the end of the year.

We will also start up Shah Deniz in Azerbaijan, the Temsah redevelopment project in Egypt;

In Amenas, which is our setting gas project in Algeria; and Dalia, the second hub in Block 17 in Angola.

Looking to 2009 and beyond, we already have a deep slate of major projects under appraisal.

The level of technical challenge in these projects is increasing as we head into deeper water and operate in harsher environments.

Our response to this has been the development and application of leading technology and project management skills.

As a result we are supporting the right level of targeted technology spend and focusing that spend on areas of technical leadership including advanced geophysical imaging, reservoir access and reservoir management.

We discussed these in detail in our recent technology webcast.

And we are also investing in project management capability through our Projects Academy, an innovative partnership with MIT now in its third year of operation.

Higher prices have increased the challenge of getting sufficient high-quality inputs to develop our business.

The most important input is people both within BPE and within the contractors who provide us with many critical services.

Our ability to mitigate these risks is based on, first, focusing on the material projects so that scarce resources are not diverted to lower value activity -- combined with appropriate pacing of projects to manage the demand and application of supply chain management skills.

With the strength of this projects portfolio, the new profit centers are expected to grow strongly through the remainder of this decade and bring increasing volumes of higher margin barrels into the overall segment mix.

This should have a material impact on the segment's overall cash generating capacity over the next few years as many of these new projects have higher margin barrels than those of the segment as a whole.

Let me give you a few examples at $40 a barrel.

In the Gulf of Mexico our new projects are characterized by low lifting and transportation costs and, as a result, EBITDA margins are expected to be around $30 per barrel.

Over the next two years we expect to add over 200,000 barrels a day to our Gulf of Mexico production.

Azerbaijan and Angola show similar characteristics where over the next three years we expect to add 200,000 barrels a day and 140,000 barrels a day of new production respectively.

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

In 2005 year-on-year decline was higher than we had forecast mainly due to the impact of abnormal events -- the hurricanes in the Gulf of Mexico, storms west of Shetland, equipment failures, the largest turnaround season for several years in the North Sea.

Despite these events underlying operating efficiencies remain stable in all of our existing profit centers with the exception of the North Sea where we're taking action to address the operational issues that arose.

The 2005 reported production number was also impacted by higher prices.

Looking forward we've not changed our view on the decline rate in our existing profit centers which we expect to be around 3%.

Some areas like the North Sea will decline more quickly while others like Egypt and Latin America are expected to grow over the period.

Our projection of existing profit center production for 2006 is essentially unchanged relative to July of last year.

This view is underplanned by four things.

First, the scale and quality of the underlying resource base, over 23 billion barrels of oil equivalent of proved and non proved resource in the existing profit centers, and the technology levers we have to unlock this prize.

More on this later from Tony.

Second, best practice in reservoir management.

The large developed reservoirs in the North Sea, Alaska and North America gas continue to perform in line with expectations.

Third, operating efficiency which, as I said, remains broadly stable or improving.

And finally, new project startups.

In 2005 we started up Clair, Rhum, Farragon in the North Sea and we announced the expansion of our Wamsutter gas field in Wyoming.

Tony, back to you.

Thanks, Andy.

Let me pick up the story with a brief update on TNK BP.

TNK BP continues to perform very well.

Organic liquid production growth remains strong and ahead of our Russian competitors.

Liquid production in 2005 averaged 1.82 million barrels of oil a day, up just under 10% over 2004.

Total production, including gas, exceeded 2 million barrels of oil equivalent a day for the first time in the third quarter of 2005.

Since BP's involvement in 2003 the total production growth including Slavneft has averaged 12.5% annually compared with our projection at the time of around 6%.

Going forward we expect total TNK BP production growth to moderate to between 2 and 3% over the period 2006 to 2010 as optimization opportunities decline and we invest to make the transition from brownfield leg growth to new greenfield projects.

The longer-term potential continues to be demonstrated by the reserve replacement and the success of our exploration program focused in the Uvat area of West Siberia.

Over the last two years the organic reserve replacement ratio on a UK SORP basis for BP's share of TNK BP reserves has exceeded 100%.

TNK BP continues to be self-funding.

Capital expenditure grew from around $1 billion in 2003 to $1.3 billion in 2004 to $1.8 billion in 2005.

This year TNK BP intends to invest around $2.5 billion.

Upstream investments are planned to include further extension drilling in the Uvat area the Samotlor field and in the [Keminiya] field as well as the greenfield Demiansk project in the Uvat area.

Going forward over the medium-term we expect capital investment to lie between $2.5 and $3 billion a year.

In the downstream 2005 saw further substantial improvements in net backs via channel optimization, increased refining throughputs and the startup of the vacuum gas oil unit in the Ryazan refinery.

We now feel we have a thorough understanding of the asset base and have begun the process of portfolio high grading.

At the end of last year the first step in this process was completed with the disposal of non-core producing assets in the struck off Saratov region along with the Orsk refinery.

We anticipate further disposals in the course of this year.

TNK BP's internal capability continues to grow.

The program of investment into HSE and integrity management is delivering improved safety and integrity performance.

Control and management information systems continue to improve.

TNK BP is investing into new technology including new and upgraded drilling rigs and in the training and the development of staff.

In December the first phase of the corporate restructuring project was completed.

This project, one of the most complex to date in Russia, provides minority shareholders the opportunity to share on an equitable basis in the profits of TNK BP.

Dividend payout from TNK BP continued to strengthen in 2005.

Total dividends received by BP, including those related to the sale of non-core assets, amounted to around $2 billion.

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

This chart shows our level of capital investment over the last three years and a forward projection through 2008. 2005 capital investment was $10.1 billion.

As we discussed in the middle of last year, we've seen large increases in prices for our mix of goods and services.

For example, we've seen the cost of equipment rise significantly with rates for some of the more sophisticated drilling rigs rising threefold in two years to over $400,000 a day.

For exploration and production overall we've seen price increases of 9% in 2004 and a further 12% in 2005, a trend we expect to continue into 2006.

In 2005 we were able to offset 4% of the increase through demand management, technology and supply chain management.

The overall impact on our 2005 capital spend level was about $800 million.

We expect 2006 capital expenditure to be around $11 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.

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

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

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

On this basis total E&P investment in 2005 was $11.4 billion.

For the medium-term a level of $11 to $11.5 billion, excluding associates, is a reasonable expectation.

In the face of tightness in the service sector with the challenges of cost pressure and service quality we are determined to continue to take a disciplined approach to our capital investment program.

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

We will continue to test each major investment opportunity at $25 a barrel to ensure that it provides appropriate returns in lower-price environments.

Let me now turn to costs.

Portfolio is the biggest driver of costs.

As we have consistently emphasized, our objectives are to invest in large fields where the economies of scale result in low unit costs and to actively manage our portfolio as fields mature.

Over the last three years we've divested more than 240,000 barrels a day -- of oil equivalent a day of production with average lifting costs of around $5 a barrel.

By contrast, over the next three years, as Andy has highlighted, we plan to bring onto production 24 new projects with an anticipated plateau production rate of around 850,000 barrels of oil equivalent a day and lifting costs of around $2 a barrel.

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 2005 we believe we experienced annual cost escalation of 7% of which we were able to mitigate around 1.5% through technology, demand and supply chain management.

We expect that we will see continued sector specific cost escalation of at least this level over the medium-term.

A focus on supply chain management is a key element of our program to mitigate market cost escalation.

Let me give you some examples.

In 2006 the market rate for offshore rigs is expected to rise on average by around 50%.

Because nearly half of our fleet is on long-term contracts we expect to mitigate this rise to an average of around 30%.

Similarly, we have secured 70% of our U.S. onshore rigs on long-term contracts with a limited number of suppliers.

Across the business we are generating significant savings by aggregating demand and making longer-term commitments to suppliers.

In the face of rising costs our approach is to continue to focus our activity set on the most material opportunities and exercise rigorous discipline in the choices we make.

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

The UK is a prime example; but over the last 18 months tax take has also increased in Russia, Trinidad, Venezuela, Argentina and Alaska.

Most of our future production growth is in areas in which production sharing agreements are in place.

These have mechanisms that automatically adjust the level of government take to energy price.

For example, this applies to our operations in Angola and Azerbaijan.

This chart shows our projection of production through the end of the decade based on $40 a barrel assuming our 1st of January, 2006 portfolio.

Cumulative production growth 2005 to 2010 is projected to be around 4% compound annual growth rate of $40 a barrel, consistent with our prior guidance of around 5% compound annual growth rate at $20 a barrel.

Relative to our last projection in July of last year, the shape of the profile has been impacted by four things.

Firstly, the hurricanes in the deepwater Gulf of Mexico and the follow-on impacts of the Thunder Horse incident has shifted the major ramp up of production growth in the deepwater Gulf of Mexico from 2006 to 2007.

Secondly, moving the oil price from $20 a barrel to $40 a barrel impacts 2006 by around 20,000 barrels of oil equivalent a day and 2010 by around 250,000 barrels of oil equivalent a day.

Thirdly, divestments of around 45,000 barrels of oil equivalent a day, around 25 in Trinidad and around 20 in Russia.

We would expect this level of portfolio high grading to continue over the medium-term.

And fourthly, as I said earlier, an updated view of TNK BP's anticipated production growth rate of 2 to 3% over the next five years.

In 2006 we expect production for the segment to be between 4.1 and 4.2 million barrels of oil equivalent a day at $40 a barrel.

Let me now turn to the long-term sustainability of the resource business.

I believe this is the most important chart that I'll show you today.

It explains why we have such great confidence about the longer-term and I intend to take a few minutes to take you through it slowly.

In 2001 our resource base on the bottom left of the chart was 41 billion barrels of oil equivalent, a resource to production ratio of 33.

At year-end 2005 our resource base on the bottom right of the chart has grown to 59 billion barrels of oil equivalent, a resource to production ratio of 40, an increase of 18 billion barrels of oil equivalent or 44% over five years.

The chart describes the movements in our resource base over the five-year period.

Over that time we produced 6.7 billion barrels of oil equivalent -- the number at the bottom of the chart -- and moved 9.1 billion barrels of oil equivalent into proved reserves, primarily driven by the sanction of major projects.

We added around 8 billion barrels of oil equivalent -- the top left of the chart -- through our exploration program and 7.8 billion barrels of oil equivalent -- the top right of the chart -- through appraisal and reservoir evaluation activity, a direct consequence of a focused technology program designed to unlock our resource base.

And finally, our active portfolio management resulted in a net purchase of 0.8 billion barrels of oil equivalent to proved reserves and 8 billion barrels of oil equivalent non proven resource.

So to summarize, over the last five years, excluding acquisitions, we have added 15.8 billion barrels of oil equivalent to our non proved resource base and 9.1 billion barrels of oil equivalent to proven reserves, a track record we believe is unequalled in the industry.

That is why we are so confidence about the longer-term.

This chart shows how we expect to progress our resource base into reserves and production going forward.

Today's proved reserves, which are either on production or under development, amount to 18 billion barrels of oil equivalent of which 43% is gas.

Between now and the end of 2010 we expect to move into development a further 11 billion barrels of oil equivalent reserves.

Beyond this we estimate that we have around 30 billion barrels of oil equivalent of additional resource.

Around two-thirds of this can be developed with existing technology.

The remainder will require new technology development.

As we highlighted in our technology presentation at the end of last year, we're working on a focused set of recovery technologies that has the potential to unlock many of these resources.

These include viscous oil in Alaska, tight gas in North America and low salinity water flooding which is being piloted in Alaska and has widespread applicability across much of our portfolio.

To these estimates should be added a further contribution from our continued track record of exploration success.

As I mentioned earlier, on a risk basis we estimate more than 10 billion barrels of oil equivalent will be added from our existing exploration portfolio.

It is the scale and quality of our resource base, a consequence of the very strong incumbent positions that we hold in many of the world's great hydrocarbon provinces coupled with our focused investment in capability building and technology that means we expect to continue our track record of strong production growth beyond 2010.

Let me now summarize the E&P segment.

We continue to build on our exploration track record with 13 years of reserve replacement of 100% or more.

Cumulative production growth from 2005 to 2010 is expected to be around 4% underpinned by -- one, a broad slate of major projects which remain on track; two, detailed plans to hold decline in our existing profit centers to 3%; and three, continued strong operating performance from TNK BP.

We have a strong and growing resource base in our major incumbent positions.

And finally, in the face of a challenging environment for the sector, we will continue to take a disciplined and focused approach to investment, ensuring rigorous quality through choice, progressing only the most material opportunities and ensuring we do not pursue options where there is not the ability to execute efficiently.

Thank you very much.

Let me now hand back to John.

Tony and Andy, thank you very much indeed.

Turning not to gas and to Vivienne Cox.

BP is currently the second-largest gas producer amongst the international oil companies.

Our business has a strong and growing market presence in North America, the world's largest gas market, whilst building a base in the markets of the future, particularly in Asia.

We operate a fully integrated business from the upstream resource to the customer, capturing value along the entire gas chain and reflecting the upstream value in the E&P segment.

We have ownership or access to the key infrastructure that allows us to sell our equity gas into high-value gas markets and generate margins from the provision of a broad set of gas-related services to customers.

And finally, LNG.

LNG is rapidly growing in significance in our portfolio and it's an area in which we are now the second-largest IOC player.

Vivienne?

Thank you, John.

Today I want to describe to you how we think about our gas business and then I want just briefly to mention BP Alternative Energy which we launched in November of last year.

But let's start with gas.

As you're all very well aware, gas is growing its market share and is now a quarter of the world's energy markets.

But perhaps more importantly, gas is the bridge to a low carbon future.

We are already one of the world's largest nonstate gas companies and this part of the business is a material and highly profitable part of BP.

We operate our gas business as an integrated portfolio from upstream production through the midstream assets and down into the markets.

And we have great opportunities all along the value chain.

Our strategy is to build on the growth of the last five years by continuing to increase gas production, grow our midstream LNG and pipeline business and at the same time grow our downstream marketing presence.

We aim to maximize the value of equity production as well as capturing additional value from the transportation and marketing of that third-party gas.

So looking first at the upstream part of our gas business.

Today we are the second-largest gas producer amongst the international oil companies with daily output of 8.4 billion cubic feet in 2005.

Now just to put that into some sort of context, that's about the same level of output as Algeria or Norway.

And we are the largest supplier of gas to North America, and that gas comes from our domestic gas production in the U.S. from Canada, and as LNG from Trinidad and Tobago.

Our upstream gas production is projected to grow by an average of 4% per annum through to 2010 and that will give us over 10 billion cubic feet a day as a resource base for our midstream and downstream activities providing a really firm foundation for future growth.

Gas now represents 36% of our hydrocarbon production and 43% of our proved hydrocarbon reserves.

Today's production is backed by 46 Tcf of proved gas reserves, the second-largest reserve position amongst the nonstate producers.

Now this gives us a reserves to production ratio of almost 15 years.

But we also have very significant nonapproved resources and, of course, over time these resources will be pulled into proven reserves so that we can underpin future production growth.

I'll move now to our midstream activities.

Here we have transformed our portfolio over the past five years and we've invested all through the chain in LNG, liquefaction plants, ships, regas facilities and we've also invested in regional pipeline gas.

For example, we recently made a long-term pipeline commitment to connect equity production in the Rockies to the premium Eastern U.S. gas markets.

We are also investing in the South Caucasus pipeline to transport our production from Shah Deniz in Azerbaijan into the domestic market and also on into Georgian and Turkey.

By integrating our assets and our access to markets we're maximizing the value of our upstream equity production. 80% of our current gas production is domestic and regional pipeline gas, that's around 7 Bcf a day, and the remainder, about 1.7 Bcf a day, is LNG.

LNG's share of our overall portfolio has doubled since 2001 and projected to grow further to 30% of gas production by 2010.

If we used the measure of equity gas into plant we are currently the second-largest nonstate company in LNG and we expect to retain that position through to the end of the decade as we continue to grow our business.

For the future we are constructing the Tangguh project in Indonesia which is expected to start production in late 2008.

This will provide gas to customers in North Asia and, for the first time, will export LNG from Asia to the West Coast of the U.S.

We're also a partner in the construction of the Northwest Shelf project in Australia and that is also expected to start operating in 2008 and the gas is planned to go into North Asia.

These projects provide a strong foundation for our growing gas business in the Asia Pacific region.

With operational control of liquefaction capacity we can build further opportunities to capture income in the midstream of the gas chain and to do that we have secured three LNG carriers under operating leases and are currently building a further fourth.

As well as the monetization of our own equity, we are steadily growing our merchant LNG business by acquiring third-party LNG under short-term and long-term contracts.

A very good example of this is the memorandum of understanding that we have just signed with [Brass] Rivers project in Nigeria.

That gas will go into the U.S. and into Europe.

Another key part of this midstream gas business is our access to over 1 billion cubic feet a day of LNG regas capacity.

Around two-thirds of this capacity is in the U.S. and the UK providing access to those premium markets.

And much of that gas will come from our equity in Trinidad and Tobago.

We've made other terminal investments in Bilbao, in Spain and in China.

The import terminal in Guangdong, which is scheduled to start up in the middle of this year 2006, will be China's first LNG import facility.

We are seeking approval for a 1.2 Bcf a day LNG terminal at Crown Landing in New Jersey.

So we are making choices about the gas we produce and where and which we move it to markets.

We're also creating new markets for our gas by developing technologies to convert gas to liquids and we continue to monetize gas through growing our power generation business.

With the power industry consuming approximately 35% of the world's gas we see this sector becoming increasingly important to BP.

Turning now to the downstream.

We make most of our sales in North America where we've established a leading market position.

Our success has been based on holding a portfolio of transportation and storage assets and this allows us to optimize gas flows from supply basins and means we can deliver a comprehensive and flexible level of service to our customers.

We've been very successful in growing our customer portfolio and see further opportunity for growth.

Thanks, John.

So that's our integrated gas business.

I want to remind you now about BP's alternative energy, that's the business that we launched in November of last year.

We're moving forward with our plans, investing approximately 350 million in 2006 in our four focus areas -- solar, wind, gas fired power and hydrogen.

We anticipate that this investment will grow to approximately $8 billion over the next ten years.

In solar we are doubling our production capacity by 2007 and tripling our sales volume in three years.

In wind we plan to add over 400 mw of additional production to become a top tier wind producer by 2015.

As for hydrogen power, our plans are moving ahead for converting the Peterhead power station to hydrogen.

And we're well advanced in progressing other opportunities.

But producing low carbon power is only part of the story.

We can use our power trading and marketing expertise to supply low carbon power to wholesale customers and it's the combination of both the operating assets and our marketing and trading skills which will be important.

And so in summary, we are one of the world's largest gas companies, the second-largest gas producer amongst the international oil companies with a strong portfolio of reserves to underpin our growth over the next few years.

With our strong midstream and downstream positions we've got really exciting opportunities to add value throughout the entire gas chain.

And we're also moving forward with new opportunities in low carbon power where gas fired power development will form an important element of the new business -- alternative energy.

Thank you.

Vivienne, thank you very much.

Now let's turn to the refining and marketing segment and to John Manzoni.

We're refurbishing the Texas City refinery and we plan to restart production from 1Q onwards.

We're increasing our investment in our advantage refining base and plan to invest around $1.5 billion a year over the next three years to enhance flexibility, margins and reliability and this compares to an investment rate of around half that level in the past three years.

We're securing low-cost feedstocks from supply envelopes around these refineries by having the right access to the right infrastructure and the application of our supply and trading skills which report to Vivienne Cox.

We are improving margins in marketing through superior focused customer offers and implementing cost efficiency programs reducing unit cash cost by 10% by 2008.

And finally, we're continuing to apply our advantage technology building new acetic acid and PTA capacity in Asia and thereby aiming to maintain a global competitive position.

So, John?

Thank you, John.

You're nearly there and it's always best to save the best till last I think.

I want to begin by reminding you about the shape of the R&M segment and its core businesses which changed somewhat during the course of 2005 as we absorbed aromatics and acetyls.

This slide shows the distribution of operating capital employed and you can see that the aromatics and acetyls now comprises 12%, around $5 billion, with about a third of this being in the rapidly growing Asian markets.

So refining and marketing now consists of around 60% manufacturing businesses including aromatics and acetyls and 40% customer facing businesses.

Our goal is to have leadership positions in all of our businesses and we focus on the relevant performance metrics in each business separately allowing us to be clear on the optimal investment patterns and positioning.

But we also consider the integrated nature of the businesses along the hydrocarbon value chain.

Increasingly we're leveraging the supply and optimization skills in our supply and trading organization to derive additional value along that supply chain.

Today I'm going to focus on three of the businesses and talk about our future plans.

I'll cover refining, aromatics and acetyls and the retail business.

So to begin with refining.

Our strategy starts with having the right assets configured in the right way located in the right places.

Then we focus on the operations of those refineries and we also optimize the commercial outcome by having a flexible feedstock and product slate.

Fundamental to this is to have all parts of the portfolio operating safely and to carry out a comprehensive action plan to underpin our confidence in the integrity of all of our operations.

Byron has described the impact on the segment 4Q results of the explosion of Texas City on the 23rd of March last year and the subsequent shutdown brought about by the hurricane Rita.

The incident in March and the work involved in bringing the plant back online has been and continues to be a huge focus for our organization across many dimensions.

Before we had completed the repairs from the March explosion the refinery was shut down completely as a result of hurricane Rita on the 21st of September.

Since then the plant has remained down.

We're taking the opportunity to refurbish the refinery and bring about a substantially improved standard of operation when it returns to service.

Bringing it back online safely is our top priority and we're being uncompromising in the standards of rigor as we prepare the plant for startup.

We've undertaken rigorous inspection programs to ensure that every critical piece of equipment is subject to a full engineering review prior to startup.

Repairs and modifications have been completed in order to minimize the risks and improve the safety of the operations as we go forward.

Our supervisory and operating staff are being retained in general operations and in unit startup procedures prior to bringing each unit online.

And we've clarified the management accountabilities and processes throughout the plant.

We are now about ready to begin restarting the plant.

Based on our current estimates we're anticipating that it will begin operations shortly and gradually ramp up to around 200,000 barrels a day.

Our current projections have the refinery running at almost 400,000 barrels a day by around midyear.

This rigor, of course, comes at a cost.

Byron described earlier the impact on the segment's 4Q results from having Texas City down and we estimate that the impact in the first quarter will be between $600 and $800 million depending, of course, upon the actual startup date and the prevailing margins during the quarter.

We're ensuring that the lessons from the Texas City accident are applied much more broadly.

Our capital expenditure program includes around $500 million of incremental spend to further improve plant integrity everywhere.

As we implement these programs which we have underway today, I'm absolutely confident that our refinery operations will be safer, better maintained and even more efficient than they were before.

And we have a system which we believe is well positioned for the future.

Let's start with geography.

John has described our overall global outlook for refining margins which look to be reasonably robust over the medium-term.

But despite this being a globally interconnected business, the dynamics of the three major regions are really quite different.

We continue to believe that the U.S. margin structure will remain advantaged; it will be difficult to add significant new capacity in this market and so the margins will continue to be based ultimately on import parity.

More than 50% of our overall capacity is located in the United States.

This chart shows two other ways in which our portfolio is advantages.

First, we have the advantage of scale.

The average capacity of our refineries is more than 200,000 barrels a day which is significantly greater than any of our integrated competitors.

And second, we've invested into the upgrading and conversion capacity of our refineries.

This slide uses the latest oil and gas journal survey data for 2005 and represents the conversion capacity using the Nelson complexity index.

You can see that we have a greater complexity index than any of our peers.

This should allow us to take advantage of the changing crude slate going forward which is likely to include increased volumes of extra heavy sour grades.

So we have complex refineries benefiting from the advantage of scale located in the geographies likely to deliver the highest margins.

Our intention is to build on this advantage by a targeted increased in our investment program.

We can see specific opportunities both in the United States and in Europe for additional upgrading capacity in our existing refining base.

This slide gives a perspective of those additional opportunities in the existing base.

Over the next three years we have opportunities to almost double the investment to around $1.5 billion per annum with the incremental investment going mainly into additional upgrading capacity and integrity investments.

Over this period upgrading investment is expected to represent around 40% of the total, up from around 20% in the '03 to '05 period.

A significant option is to upgrade our northern tier refineries in the United States with the potential for a substantial increase in coking capacities in these refineries.

These investments would allow us to take much heavier crudes into those refineries and benefit from the wider spreads which are likely to be available.

We also plan to invest in a substantial energy efficiency project at Cherry Point.

In Europe we plan to begin upgrading projects in [Casteon], [Norefco] and [Bion] Oil.

In addition, we can see opportunities to the tune of around $300 million per year for very rapid payback projects.

All these investments are robust at lower margins and we believe therefore are good for all seasons.

Over the next five years, while our refining crude capacity will remain largely unchanged from these investments, we plan to increase heavy sour crude runs from 55% to around 70% and at the same time we expect to increase our light product yield by about 3%.

Of course, it's not only the location and investment patterns which determine the quality of the refining portfolio, it's also how we run them.

This slide shows two indicators of how we operate our refineries.

The bars represent the benefit we gain from applying our supply optimization capabilities.

In 2005 the margin earned through commercial optimization -- this is based on internal estimates -- was three times higher than that in 2003.

We've consistently improved the commercial optimization in our refineries since that time, both by supplying them with more economic crudes and also by adjusting the plant to produce the most valuable product slate.

The outcome in any year is partially dependent upon the volatility of the crude in product markets, but subject to that volatility we're confident that we can build further on this track record.

The yellow line on the chart shows the energy intensity index which is a measure of the energy efficiency within the refineries.

Since energy represents about 20% of the total running cost of our refineries, this is an important metric to manage down.

Our track record is clear and some of the investments that I've described will further reduce that index.

So to recap on refining, our first goal is to bring Texas City back into operation safely and ensure that the lessons are widely and rigorously applied.

Overall we have a high-quality refining base located in the right places to take advantage of the market conditions which exist today and which we believe will continue in the medium-term.

We have plans to increase investment to upgrade further our existing refining portfolio and to continue to improve their operations.

Now let me turn to the aromatics and acetyls business.

This is a world scale business which makes paraxylene, PTA and acetic acid.

PTA is used in plastic bottles and in polyester fiber.

At every stage in this chain we have world beating technology and leading market positions.

And our strategy has two main thrusts -- it's to maintain and invest to maintain our competitive position in the marketplace and, in particular, to invest in China where the main growth in PTA demand is taking place.

And secondly, it's to continuously renew our technology leadership position which yields both operating cost and build cost advantages.

Over the last five years we've grown the production capacity by 35%, three-quarters of which has been in Asia.

In 2005 we commissioned new acetic acid plants in Taiwan and in China and we announced further investments in China.

We expanded our paraxylene businesses in Europe and in the United States and, finally, we also sanctioned a second PTA plant at Zhuhai in China which is designed to be not only the world's biggest single train unit at 900,000 tons per annum, but to employ the world's best technology, deliver the lowest build costs and attain the lowest operating costs.

Zhuhai is planned to come on stream in late 2007.

Our technology leadership has resulted in improving cost efficiency as you can see from this chart.

And we fully expect this trend to continue as we introduce the next generation of technology into both the PX business and the PTA business.

So this is a very exciting business, one which is growing extremely fast, particularly in Asia, and in which we have and plan to retain a leadership position.

Now I'll turn to our retail strategy which has three main components.

Firstly, to differentiate our offers to continue to attract more customers and grow gross margin.

Second, it's to focus our investment in capital employed only onto those areas where we can be either number one or number two in the marketplace.

And third, it's to control the costs so that we remain competitive and deliver attractive cash returns.

Looking first at the differentiated offers.

This chart shows two components of differentiation in the retail business.

Our ultimate gasoline and diesel brand continues to move from strength to strength.

In 2005 we launched Ultimate in five new markets.

The left and chart shows the continued growth in margin year-on-year including 60% growth in 2000 by.

The yellow line shows the share of Ultimate in our total fuels mix in markets where it's been launched.

And you can see that it has doubled over the course of the last two years.

Gross margin from our convenience stores also continues to improve and, you can see from the right hand chart, in 2005 it was around 20% greater than it was in 2003.

But it's not only the absolute gross margin from our sales, the yellow line on the chart shows that we're getting more efficient.

Sales per square meter continue to improve as we increase the sales in our stores.

Last year in our retail business around half of our gross margin was generated from activities other than standard grade fuel, up from around one-third two years ago.

Not shown on these charts but across our network as we focus our footprint into fewer larger higher quality sites, the average throughput per site has grown from 3.6 million liters per annum to 4.1 million liters per annum in 2005.

The second element of our strategy in retail is to focus our portfolio on those areas which we can achieve leadership positions.

This slide shows the pattern of investments and fixed assets.

We've reduced capital expenditure to around $800 million in 2005 and plan to continue at this level over the course of the next few years.

At the same time in 2005 we started to accelerate divestments and we plan to continue to divest at about the same level each year for the next few years as we focus the asset base for capital and cost efficiency.

Over the course of the next two years we expect our net investment into this business to be approximately zero.

By the end of 2007 we plan to have reduced our company-owned sites by more than a third while retaining the number one or number two position in 85% of the markets in which we operate and increasing the quality and efficiency of our assets.

The third dimension of our strategy is around efficiency.

We have to deliver our offers to the customer more and more efficiently.

This applies across all of our marketing businesses.

During the course of 2005 we've defined significant efficiency programs across almost all of our businesses.

You saw the first impact of that in the nearly $0.5 billion restructuring provision in the segment's 4Q results.

These programs are designed to address both operating and overhead costs in the delivery of our customer offers.

The first phase of these programs should be complete by the end of 2007 and we expect them to deliver annual cost benefits of around $0.5 billion in 2008.

This program is targeted to deliver a 10% reduction in unit costs across our marketing businesses.

And we're currently defining the next stages which are aimed at streamlining our transactional systems, further improving productivity and costs as well as improving customer service.

I've described several aspects of strategy for three of our businesses.

And before concluding I want to describe the investment patterns for the segment as a whole.

This slide shows both history and our plans for all the businesses in the segment.

Disposals have averaged around $1 billion per annum for the last three years and I expect them to remain broadly at this level going forward.

High grading our retail portfolio represents a significant part of this.

Capital expenditure is expected to increase over the next few years as we increase investment into plant integrity and implement a number of refining upgrading projects and we'll also build new capacity in aromatics and acetyls.

Relative to the recent past, we plan to spend a higher proportion of the total investment in the manufacturing businesses.

And so to conclude, I've talked about four things which underpin the focus of our activity and give us confidence in growing cash flow delivery over the course of the next few years.

In refining it's firstly to bring on Texas City back into operation in a safe and more efficient way and to ensure that the lessons are embedded in all of our operations across the Group.

We plan to increase investment into our manufacturing assets, to improve our upgrading capability in refining and increase aromatics and acetyls capacity, particularly in China.

We will implement efficiency programs across our marketing businesses to deliver improvements in productivity and returns.

The first phase is underway and more will follow.

The fourth quarter of 2005 provides additional momentum to these programs.

And finally, in marketing we intend to continue to improve the quality of our customer offers to build loyalty and capture more gross margin.

Overall the investment patterns and strategy for the segment have been set so that at standardized conditions our operating capital employed should remain essentially flat, the gross margin should increase by virtue of our offers and our investments into the portfolio and costs should be held broadly flat through the efficiency programs I've described.

The objective is to increase cash flow and improve returns out to 2008.

John?

John, thank you very much.

I now want to turn to the prospects for the Group as a whole and look at these in the context of how we've been performing competitively.

Since 2000 we've grown oil and gas production at more than double the rate of world production growth.

We intend to continue growing.

We're directly involved in oil fields which are expected to contribute almost half the growth in non-OPEC production over the medium term.

BP has consistently been the fastest-growing super major with production growth averaging 4.4% per annum against a range of 3.6 to -1.7% for our peers.

We replace more of our production with reserves than any of the other super majors.

Part of that industry-leading track record was based on the performance of the successful TNK BP transaction which more than offset our continuing disposal of mature and less efficient production.

Our growth has contributed to improving returns.

As you know, we've communicated with you over the past couple of years in terms of cash-based measures of returns which we think are more appropriate.

However, we recognize that these measures have not been widely adopted as they do not lend themselves to competitive comparison.

So let me focus today on another useful measure, return on average capital employed, or ROACE.

We've been very successful in significantly improving our returns based on this measure.

You've heard me say many times that the affective measurement of ROACE, particularly on a like-for-like basis against peers in other accounting jurisdictions especially in the light of IFRS, is neither sinful nor standardized.

That said, whether we measure underlying ROACE against reported capital employed or adjust for purchase price accounting by excluding goodwill for BP and our peers, BP has improved ROACE consistently and at a significantly faster pace than our peers since 2001.

Our underlying replacement cost ROACE excluding goodwill has improved from 13% in '01 to 24% in '05, a rate of improvement averaging some twice the average rate of our peers.

Whilst the environment has clearly contributed significantly, our differential improvement has been driven by underlying operational and capital efficiency improvements.

We expect the underlying trend to continue as we grow production and bring more capital into service, achieve higher gross margin capture in R&M, benefit from the disposal of the Innovene business, and continue to reduce costs.

We have continued to grow the absolute level of CapEx over the last five years, so as to deliver our strategy.

We have been investing proportionately at a higher level than our peer group.

From '03 to '05, our reinvestment rate was 65% of operating cash flow compared to 55% on average for our peer group.

As my colleagues have demonstrated, we have a deep portfolio of high-quality projects available, and we plan to manage the pace and timing of our investment to maintain our track record of growth, improving capital efficiency and returns, while ensuring that the organizational capacity and capability of the group are matched to our capital investment plans.

Over the period '03 to '05, our total capital expenditure, organic and for acquisitions, averaged around $15 billion per annum.

We expect to maintain this level in '06, substituting acquisitions by organic activity.

In addition, we expect our share of the CapEx for our associated companies to be about $2 billion in '06.

If you add these numbers together to get a feel for the investments made by the group as a whole, you'll get a level of around $17 billion in '06.

Beyond '06, we expect our capital expenditure to increase by about $0.5 billion a year through '08.

Over the last five years, our divestment level has averaged more than $6 billion per annum.

Opportunities will continue to exist to high-grade our portfolio, and we expect disposals to contribute around $3 billion a year on an ongoing basis.

The exact level of capital expenditure will, of course, depend on a number of things, including sector-specific cost escalation above the 12% per annum we have seen so far.

This could stem from very tight capacity in the supply sector, time critical and material one-off investment opportunities which further our strategy, and any inorganic opportunities that may arise.

At present, we don't expect any of these things to affect our capital expenditure.

Our core objective is to grow sustainable free cash flow and to distribute it so as to grow shareholder returns.

Free cash flow in '05 was $25 billion as a result of the strong environment and proceeds from the sale of Innovene.

This has been reflected in the increased level of share buybacks, while growing dividends and strengthening the balance sheet.

Over the period '03 to '05, the average oil price was $41 a barrel, and our actual free cash flow averaged about $15 billion a year.

That period was characterized by a particularly high and probably unsustainable level of divestments.

In addition, oil prices rose, which meant that the value of our inventories increased by more than their volume.

This created a buildup of working capital.

The net effect of adjusting the free cash flow to a sustainable divestment level of $3 billion with no acquisitions and correcting for the price effect of the working capital build would have meant that our free cash flow on average from '03 to '05 would be around $13 billion per annum, [playing] the actual 15.

Looking forward to '08, our aim is to grow this level of sustainable free cash flow through the comprehensive set of activities which we have already described.

In order to underpin delivery, we have a 5-point business plan.

Firstly, we expect to grow production by about 4% a year to 2010 in a $40 price environment.

We've already discussed the projects, programs, and their improving margins that underpin this growth.

Given the quality and magnitude of the resource base that Tony has shown you, we expect to continue our track record of strong production growth beyond 2010.

We will keep a sharp eye on cost control, aiming for cash costs growing at less than general inflation.

Some cost efficiency programs are already underway, such as the one started in 4Q by refining and marketing in Europe.

These programs are expected to reduce costs on a sustainable basis by $0.5 billion in '08.

Our overall approach is to limit the increases and cash costs from '05 to '08 to well below the level of general inflation of around 3% a year excluding changes in fuel costs and the exchange rate.

We are planning more programs, many to do with overhead costs.

Building on our track record, we expect to deliver further improvements in the return on average capital employed relative to our peer group.

We plan to maintain the total capital spend to around $15 billion in '06 and grow it at about half $1 billion a year to '08.

And finally, we expect to continue to high-grade our portfolio and expect divestments to be at an ongoing rate of around $3 billion, half our historic level.

We don't expect these divestments to have a material impact on ongoing free cash flow.

Let me now turn to the financial framework.

As you know, it's got three components -- the dividend, the level of gearing and the use of free cash flow.

Our dividend policy remains unchanged.

It is to grow the dividend per share progressively.

In pursuing this policy and in setting the level of dividends the Board is guided by several considerations including the prevailing circumstances of the Group, future investment patterns and the sustainability of the Group and the trading environment.

We talked earlier about our view that oil prices might have a support level of at least $40 a barrel in the medium-term.

However, we continue to use our planning assumption of $25 a barrel as a good yardstick for testing the downside in the balance between investment and total distributions to shareholders.

Dividends per share growth depends on both the level chosen for total cash flows used to grow the dividend and the number of shares outstanding.

That in turn depends on the level of share buybacks which depend on the environment that prevails at any point in time.

During the period '00 to '05 dividends per share grew rapidly as share buybacks began to make a difference.

We've paid out a total of $29.1 billion of dividends over the last five years.

During this period the dividends per share in dollar terms have grown about 13% per annum, about 2% ahead of the growth of total cash flows distributed as dividends.

For the last 20 years on average our rate of growth of dividends per share has been 3 to 4% above the rate of inflation.

Our approach to the level of gearing is unchanged.

We believe that a gearing band of 20 to 30% is the right level to maintain an efficiently leveraged balance sheet while ensuring protection against lower energy prices.

In practice we entered '06 below this level and as a result of the Innovene proceeds.

As a reminder, we have three targets.

These remain unchanged.

The first is to underpin growth by a focus on performance, particularly on returns, investing at a rate appropriate for long-term growth.

This is covered in our 5 point business plan.

The second is to increase the dividend per share in the light of our policy.

And the third is to return to shareholders all free cash flows in excess of investment and dividend needs, all other things being appropriate.

So this chart shows the potential amounts of cash which could be distributed by way of share buybacks and dividends.

These numbers are of course somewhat by and large in nature.

It's much the same chart as we showed last year now updated for '05 delivery and a wider range of oil prices and refining margins.

We've compared what we've distributed in '03 to '05 with, all other things being appropriate, what could be distributed over the '06 to '08 period.

And these estimates are, of course, based on assumptions on oil prices, refining margins and so on.

Under the same set of conditions as we actually experienced between '03 and '05 with the Brent price at around $41 a barrel, the amount of expected future cash distribution will be around $50 billion in total.

At $60 we estimate this could rise to around $65 billion.

Now specifically for '06, we expect production to be in the range of 4.1 to 4.2 million barrels a day at $40 a barrel, CapEx of around $15 billion and divestments of around $3 billion.

To summarize.

The near-term operating environment for the Group looks very favorable.

We have considerable momentum going forward and our strong incumbent and asset-base underpins our distinctive growth prospects.

Our focus is on translating this strong environment and growth into cash delivery which we intend to return to shareholders.

We remain focused on executing our established strategy, maintaining capital and cost discipline, strengthening operational excellence and continuing to high-grade our portfolio.

Now ladies and gentlemen, thank you very much for listening for two hours.

We're going to be happy to answer your questions.

We're joined during the presentation by the Chairman of the Board, Peter Sutherland, who I'm sure would also be happy to answer questions on matters reserved for the Board.

So ladies and gentlemen, let me just sit down and we'll start.

If you could identify yourself and your affiliation I'd be grateful.

It's Edward Westlake, Credit Suisse.

Just in terms of the growth rate, obviously beyond 2008 the growth rate slows particularly excluding TNK.

What flexibility do you have to accelerate the growth rate beyond '08?

And the second question is you've given us CapEx guidance to 2008 of $16 billion, but with the suite of projects that you have coming onstream beyond 2009, do you see a sharp pickup in CapEx beyond '08 in order to deliver that longer-term growth?

Thank you.

I'd like to answer this jointly with Tony.

Tony, first you'd like to talk about '08 plus growth.

Yes, I think clearly what we're going when we do this sort of projection is we're taking a risk view as to what's going to happen four or five years out.

So what we're seeing, as you've all understood, is very strong growth right in the next two or three years as a whole series of projects come on, and then a slowing off of growth.

But what I would emphasize -- we've said this time and time again -- all of this is now locked in.

It seems that we are in the process now of executing.

There is always the opportunity to add additional elements to the portfolio.

By that I mean organic elements.

I think this is a reasonably balanced, well judged projection out five years which has the opportunity to -- we have the opportunity to do better than that on the basis of this extraordinary resource base that we have.

I think that's the key point.

While there will always be undulations in the year-to-year growth -- and, of course, as we project out there has to be relatively uncertain -- there is no reason to say that we can't continue to grow at the same rate for a very long period of time -- for a very long period of time.

As to CapEx, again, it depends and it will vary depending on the bunching of projects and so forth.

But I think if you take an overage over a run of years, it's going to be progressively going up and as it were in real terms.

I think, again, there will be little bumps depending on the timing and nature of projects.

But the efficiency seems to be there and we're doing everything to make sure we maintain efficiency.

Just to add to that, clearly the thing that we're very conscious of today is the capacity in the industry and it's not just the -- this isn't a BP capacity, it is the capacity in the supply chain.

So as I was at pains to point out all the way through the presentation we are only going to proceed to execute things that we believe we have the capacity and the supply chain has the capacity to execute efficiently.

And we won't be driven to chase things to try and get an incremental piece of production and destroy returns by doing things at a pace that is inappropriate given the state of the industry today which, as everyone here knows, is absolutely operating at capacity.

Thank you.

There was a second hand up here.

I think it was in the front.

I'm going to take five questions from the floor and then turn to the Web and telephone.

Colin Smith, Dresdner.

I wonder if you could talk a little bit more about the decision behind the dividend.

Because as I recall when you last put the dividend up sharply in 4Q last year, it was essentially designed to be affordable at 20, and you're now talking 25 as a long-term view.

In that context the amount you've announced for this year does look perhaps a little on the light side, especially if you're looking at the total level of cash that one might realistically expect you're going to be generating going forward.

And secondly, could you just say a little bit about whether you think there are any practical limits to the amount you can buy back in the market without affecting the price against yourself?

Thank you.

I think I wouldn't read too much into the difference between $20 and $25 as a test because it is a test and in the end it's judgmental based on what do we think the progressive dividend should be and how robust it should be at a variety of conditions that none of us actually know what they're going to be because we have no idea what would happen if the price went down to $20 or $25.

So it's a bit more conceptual than that.

We are progressing it, we're progressing it at this steady rate.

We are actually not cutting the amount of cash flow we're putting behind the dividend, but we are reducing the number of shares and I think that's quite important and we'll continue to do that.

And besides, we're also distributing through, as you say, stock buybacks.

It's interesting, we used to have a rule that $2 billion a quarter was about the maximum we could do, then we tried 3 billion and that seemed to work, and recently we've tried 4 billion and that seemed to work.

That's the experimental math so far.

Let me take one from this side if I can.

Thank you.

May I just ask two very brief questions.

The first one is on the cash tax rate.

Byron, you talked about it falling back from 40 to 35.

Is that on the assumption the oil price goes back down from the 54 last year and if it stays up will the cash tax stay up?

And then secondly, on gas and power.

I notice there was a particular emphasis on the interest in power generation in that part of the presentation.

Are you interested in entering or reentering the power generation business?

And if so in what sort of regions and under what sort of conditions would you do that?

I'd like Byron to answer the first question on the cash tax rate and Vivienne to answer the second one on power generation.

Neil, as I indicated in my remarks, what we're seeing in 2006 is the flowthrough of tax obligations that were incurred in 2005.

Some of them are based on normal installment payments, some of them are driven by factors like capital gains taxes as a consequence of the Innovene disposal.

We see them peaking around 40%.

Coming back to 35%, in an environment very similar to that that we see today.

So no, we haven't shifted environments on you, just a peaking and then back to about a 35% range as best we can calibrate it given the uncertainty of circumstances looking a couple years out.

I think the first point to make is that we're actually in power already; it's not a question of going back into power, we are already in power.

Primarily through co-gen assets associated with the refining system or in power plants which were designed to monetize gas flows.

So I look to gas flows for example in Korea, Vietnam.

So we are in power, but I think with the launch of alternative energy we do see low carbon power, particularly CCGT, as a component part of that business and are looking for opportunities to grow there.

So far what we found is that the best opportunities do seem to be either associated with our own facilities or in the traded power market in the U.S.

But we are scouring the Eastern markets as well for good options.

Can we take one, Tim Whittaker?

Tim Whittaker, Lehman Brothers.

You talked a lot about free cash flow and you said your ambition is to grow it.

Could you give us some indication of how much you plan to grow it and the underlying assumptions in a flat kind of environment?

And secondly, you said early in your presentation you expected OpEx's spare capacity to rebuild.

Now I'm not aware that Tony plans to build any spare capacity.

I wonder why you believe that OPEC might want to build spare capacity.

First, on free cash flow, to an extent I think we've given you quite a lot of information which I think you can draw your own conclusions from.

Basically I think we have a steady-state -- broadly steady state capital program.

We have a steady-state divestment program -- I think we've given you the starting point to calculate from and we've given you a production profile -- which even at the margins that we've indicated let alone any improvement of those margins would rapidly and dramatically increase free cash flow.

In addition, we have a big focus on costs; we've given you the first part of a program.

We'll be updating you the whole time on the cost program as we have new programs coming out because they'll doubtless have some accounting impact somewhere.

So we'll have to explain that to you.

So we'll carry on doing that.

So these components are quite important, very big positives to cash flow.

So you'd expect it to grow from what would have been the steady-state of $13 billion per annum to quite a large number.

And may I leave you to calculate that rather than to give you our own view of the answer, which is significantly higher.

Of course, we've taken account of negatives.

There are taxes, everybody is at it and so there are taxes which have taken out a good chunk of cash flow.

And of course there are other things where the market will simply compete away some of the free cash flow and I think that should be allowed for too.

OPEC spare capacity, you're absolutely right.

It's really a very interesting question.

Why should OPEC build spare capacity?

I suppose I put it a bit like this -- of course they don't have to, but on the other hand, if you want to control the price, which they do, then there is always a cost to controlling the price.

And you've got to invest to control the price which means that actually you have to invest in order to have the capacity to move production up and down so that you're not in a position where someone else is controlling your price.

It's like everything, there's a cost to doing anything and they have to have that cost if they want to be effective controllers, as I believe they do.

The second point is when you have such a big market share, as the collection of countries that represent OPEC, in some ways you shouldn't let your customers down because then they will surely go elsewhere.

So you need to be there with a few rainy day supplies, it seems to me, otherwise the tone will be maybe one should go elsewhere.

And maybe people can over the longer-term.

And so I think present thinking is that people would love to have, as I indicated in my opening remarks, capacity which is both local and very secure and green.

And I would expect that with the right application of the real brainpower of the world to this problem and the exciting energy business, something will happen to change the energy mix of the world let's say in a decade or so.

I'll take one more question here.

You, sir, in the front and then I would like to go to the Web.

Neil McMahon, Sanford Bernstein.

I have two questions.

The first one is really looking at the mark to market derivatives on the hedges.

Where do we currently stand today in the first quarter in terms of what we've seen from rapid declines in natural gas prices in the U.S. and what's happened to the oil price?

If you could just give us a sense of if these are still open hedges, what does it look like today?

Secondly, maybe just a comment on if there's any more aggressive trading activity that took place in the fourth quarter of last year versus normal.

Then a question for Tony.

I think every year we make comments on your operating rate in the North Sea.

As I remember, last year it was 87%, maybe the year before that it was 85%, if I remember correctly.

What was it last year in the North Sea?

What was it for the Group?

And given the fact that most of your existing business in TNK BP production is coming from mature fields going forward, what confidence do you have that you can increase that operating up time and have that level of production coming through those fields in the future?

And first I could turn to Byron and Vivienne for the first part, and then when that's done, Tony will take care of the second.

Well, as I indicated, these are IFRS related aspects that swing around quarter to quarter.

So you are correct in pointing out to the end 4Q result as being a primary determiner of this.

As also indicated, they tend to wash out over a period of time.

I don't think it's particularly useful to take a look at where we are in the early part of February and try to project that as to what might be happening at the end of the quarter, because the end of the quarter will be what the end of the quarter will be.

But what did happen at the end of the fourth quarter is since we are building seasonal inventories, we were longer than our normal position.

Since we were long on the physical, we were short on derivative products.

In a rising market, that created losses on the one side of what is a hedged position.

To the extent that these factors are reversed out in the first quarter, that would mean that the counterbalance to the loss that we have seen in refining and marketing would show through as a positive factor in the first quarter of 2006.

But I say that it will depend upon where we end up in about 50 days' time.

And likewise, there are in the Gas, Power and Renewables side similar things which are running the other way.

So I truly believe that trying to forecast this into your model is a futile game, and it is best to wait until the results are calculated and provided to you.

We will try to do a little bit more guiding when we're putting out the trading statement, but since it is fraught with a lot of risk in doing that, I wait to see where we are in early April before we decide that we are going to do this.

Can I just add, these are truly noneconomic accounting effects.

It is what it is.

They do not capture what actually we are doing.

I was asked this morning by a collection of people, including the press, whether these impacts would force us to change our business model, and I said absolutely not.

We are not going to run this business -- we never have -- in order to get good accounting results.

What we are actually in the business to do is to run it for shareholder value and for cash flow, and these are unfortunate consequences, far too much red tape, far too much technicality, that I'm afraid very few people understand.

It takes a very long time during the due diligence process to go through this.

And I have to say my opinion is I share everyone else's opinion on this; that it neither expresses the true value of assets and liabilities nor the accountability of management.

Other than that, that is the system.

Can I just add to what John was saying.

We manage this in a very controlled fashion.

So there is no deviation from the way in which we are hedging anything that is outside of our normal patterns.

And to the extent that there are inevitably disruptions in the course of a very, very long and complicated logistics chain, then we will hedge away those risks.

But that is what is creating a significant amount of the volatility that we are seeing this quarter.

Can we go on to operation?

Tony, operating rights.

If you look at the segment as a whole, it is just over 90% operating efficiency.

Looking at the North Sea, historically it has run around 85% as you said, which is a reflection of the challenge of the North Sea operating environment, which I think many people don't fully understand most of the time.

Last year we didn't have a very good year.

We had a bunch of operating issues, particularly in the west of Shetland and in some nonoperated facilities.

So it was just over 80% -- 81% in the North Sea last year.

We have taken interventions to get it back on track and we have a plan to get it back to 86% in the course of 2006.

So that is the North Sea in the segment.

Turning to TNK-BP.

TNK-BP is not, I don't think, an issue about operating efficiency.

It is understanding where we are in the evolution of the asset base.

So over the last three years, we have seen this extraordinary production growth which has been about essentially mechanical interventions.

It has been about well workovers, infill wells, recompletes, that sort of thing.

We are now at a point where the underlying decline is between 20 and 25%.

And what we need to do is get water back into the reservoir, so we are now into a period of optimizing the waterflood patterns.

And that is why we will see a slowdown of the production growth in the mature fields.

And we are also in a period where we are beginning to switch the investment into new greenfields.

We have been very successful through appraisal and new exploration of identifying very significant multibillion barrel new reservoirs to begin to develop, particularly in the Uvat area.

So as we switch the investment into those, and it takes a little while for them to come onstream.

So in TNK-BP, it's really about switching the investment from the mechanical interventions to waterflood optimization in the existing fields and the new field development.

That is why the growth rate is slow.

Thank you, Tony.

I am now going to turn to the 307 people on the Web who have two questions and then to the telephone where there are 40 people.

So I have to read these out.

The first question is from Bruce Lanni of AG Edwards.

How are government policy changes, i.e. PSC, UK, North Sea tax, impacting your returns and business decisions?

Are you finding access to new areas more competitive or difficult?

I would like Tony to answer the second part of the question first.

I suppose the first thing to say, of course, given the extent and quality of the resource base that we have got, which I was at [pains] to explain, we don't feel that we need to take rash decisions in the matter of new access.

So if we see new access opportunities that are competitive in our portfolio and the option arises for us to secure it in a way that it would remain competitive in our portfolio once we have secured it, then we will pursue it.

But we will not be doing things that do not compete with our existing portfolio, given the extent, scale and quality of the existing portfolio.

I think on the question of government policy changes, taxes, obviously they impact our returns.

We have fully incorporated that into both our forecasts and our present results.

Quite a lot of changes have taken place.

As Tony Hayward pointed out, the production sharing contracts in effect have self-adjusting mechanisms in, and that is increasingly about our new production.

None of them have affected our business decisions to date, I would say, because while tax take has gone up, so too has gross revenue.

It all depends.

If tax take remains very high, if the price of oil were to come down, then I think it would impact decisions.

And it's why we said when the UK taxes in the North Sea went up, well, fine, that's the case it is.

But surely if the price of oil went down to $30 to $35 a barrel when the taxes were lower, you should bring the taxes down to that level.

Generally, of course, changes in taxes just increase uncertainty, and there are so many variables in this business that it sort of affects general confidence in the way in which investments are made.

The second question is from Fadel Gheit of Oppenheimer in New York.

Do you regret selling refining assets especially in the U.S. at the bottom of the market?

I think I will just answer this very quickly.

Fadel, decisions are context dependent, and goodness, if we went around worrying about decisions we had made in the past, I think we would freeze for the future.

But I would say this, I don't regret BP buying a lot of refining assets as part of ARCO and Amoco at the bottom of the cycle as well.

So we bought a lot of assets at the bottom of the cycle, bottom of the market, and we sold some assets at the bottom of the market.

And I think, as John Manzoni demonstrated in his presentation, this made a pretty strong portfolio.

So those are the two questions.

I would now like to turn to the telephone if I could.

And the first question is from Jason Kenney of ING.

Jason, are you there?

Can you confirm if 100% of the proceeds of Innovene will be refunded directly to shareholders by share buybacks in 2006?

Secondly, could you give us an approximate uplift for the group underlying ROACE following the disposal of Innovene, which presumably is quite a boost to the start of that ROACE improvement?

First, I could confirm that the proceeds of Innovene will be sent back to shareholders.

In some ways, of course, that is only part of the definition because we would expect I think based on our projections on our chart to have a little bit more cash than that, and for both dividends and stock buybacks.

The money, of course, is not differently colored.

But in the end, it goes into the big pot of things which is our overall free cash flow.

And I repeat again, as Byron said and I repeated, that our full intention is to send back the free cash flow to shareholders by way of dividends and stock buybacks.

Now, the uplift of Innovene on future returns, Byron?

I don't have the number right off the top of my head.

We can get back to you on that number, Jason, and we will do that through IR.

(indiscernible) to say it would be positive for returns.

Yes.

Well, it clearly will be, and I think it is $8 billion of capital employed, which broadly over a run of years was making about 5%, and the rest of the portfolio is about $100 billion, making rather more than that.

So I think that it clearly indicates that it's a 10% reduction in capital employed with no material change in return.

Great, thanks.

There is another question.

Robert Kessler of Simmons & Co.

A couple of quick unrelated questions.

Firstly, on the 2005 reserve replacement, wanting to see if you could break the 100% replacement into components in terms of how much came from revisions, how much came from major new project bookings and maybe the TNK BP contribution there?

Secondly and unrelated, in your refining supply/demand outlook, you mentioned in the short-term that growth in petroleum product demand should be in excess of capacity additions but that that would flip in the longer-term.

Wondering what the year of transition was there?

Thank you.

Thank you very much, Robert.

Tony, details on reserves replacements.

We'll obviously be disclosing the details in the annual report and accounts in the 20-F in the course of March.

All I would say at the moment is that it was broad spread across the entire portfolio with large increments in North America in our gas business in the deepwater Gulf of Mexico, Angola, Indonesia and indeed TNK BP in Russia.

Widespread across the portfolio and further details to be unveiled in the annual report and accounts in about a month time.

And John Manzoni, do you want to help Robert Kessler on the moment at which we go into surplus refining?

Not particularly, Robert.

I think the point is that for now we've got a tight supply/demand situation.

Many, many projects, as John described, are being announced.

They won't all be built, of course, because they won't all sustain economics going forward.

And at some stage, as increasing capacity comes on, the margin structures will weaken and that's really why John was talking about a cycle as he was discussing it.

The exact moment of when that happens we'll all be equally interested in going forward.

Now I'll come back to the floor and a question at the back there.

Mark Iannotti, Merrill Lynch.

Two questions.

First of all, BP TNK, you're indicating 2 to 3% volume growth out to 2010.

How disappointed are you in the pace of greenfield development and would you consider reducing below 50%, taking on a Russian partner if it meant that you could accelerate some greenfield opportunities?

And if I can, a question for Vivienne.

Indicating today a quite major investment, 8 billion over the next ten years in alternative energy.

On an average basis that actually compares very similarly to what you're going to spend on exploration.

When you look at profitability potential in alternative energy, how do you think that -- your profitability for that investment compares with the profitability of investing in the upstream through the investment cycle?

Thank you.

First I'd like Tony to start on TNK BP.

I may have something further to add.

And then Vivienne on alternative energy.

I think the brief answer is not at all disappointed, Mark.

I think you need to step back and just reflect on what's happened here.

We've grown production volumes 14% in the first year, 13% in the second year, 10% this year.

We've unearthed an extraordinary resource base.

We've made a whole bunch of new -- completely new discoveries through exploration and are proceeding now to begin their development.

And we're doing it in a disciplined and appropriate way to ensure that we get high returning projects from their own production.

And I'm more than satisfied with our progress.

I think the progress of TNK BP and the team there has been extraordinary -- absolutely extraordinary.

We've clearly far exceeded any projections that we had at the time when we went into Russia with that transaction in 2003.

And all we see is tremendous opportunity for the future.

Just to make sure that -- because news on this, I'm sure, will be misunderstood -- I want to make it very clear.

We're very, very happy with this investment.

It's grown twice as fast -- over twice as fast as we expected.

We are discovering and developing reserves for the future.

The production rate will, of course, flatten a bit and then probably rise after that.

We have absolutely no intention of selling down from 50% and we're very happy with our partners.

Vivienne?

I suppose the first point to make, just to be clear, is that it's $8 billion total over the ten years, so that's the plan that we announced when we launched Alternative Energy in November of last year.

And the basis for that is that we could see a number of very profitable opportunities in the four segments -- solar, wind, hydrogen and CCGT.

But the whole point about this is that we're going to run it as a business.

In other words, these projects have to compete with our portfolio of other opportunities.

Which means that we would expect them -- the projects which are approved to make a 15% levered post tax return and therefore we'll be competitive with the rest of the portfolio.

So we will run it as a business with very tight boundaries and financial constraints and we can see the opportunity set easily will spend the $8 billion we've identified.

Great, thank you.

Over to this side now, yes sir, and then we'll come back again.

It's Jon Rigby from UBS.

Two questions.

The first is just to check my math.

It looks to me that even after the PSA effects the production target you're giving for 2010 looks like a couple hundred thousand barrels a day short to the one you were describing last year.

Is that just risking, is it the effects of the market you were describing with tightness in supply and your choices around that?

Is it TNK or is it just my math is a little bit faulty?

Second, and probably associated with that -- and I was rather hoping the Chairman was in the room, although he seems to have disappeared.

I don't know if there's any other non-execs.

I was wondering whether we could have an update on the progress to identifying the individual who might be presenting the 2010 results against these targets in four years time.

Let me take the second one.

The Chairman of the Board is gone.

And I think it's important that these questions, Jon, be referred directly to him.

The Company secretary is here and I'm sure if you wanted to make an appointment he'd be more than welcome.

I think that's the most appropriate way.

What I would say about myself is this, that I'm very much enjoying the job.

I always look to the very long-term;

I've always done that, I'll continue to do that and I have an extraordinary high-quality set of people in my direct team, many of whom, perhaps all of whom -- who knows? -- could qualify to be my successor.

So I think that's a very good position to be in.

Now, let's just talk about PSA effects and 2010.