英國石油 (BP) 2004 Q4 法說會逐字稿

Welcome to the BP presentation, to the financial committee conference call.

I will now hand the call over to Fergus MacLeod, Head of Investor Relations.

Please go ahead, sir.

Good afternoon to those of you listening in Europe and Asia.

And good morning to those of you in the Americas.

It's my pleasure to welcome you to BP's fourth quarter 2004 results and strategy update conference call.

My name is Fergus MacLeod, BP's Head of Investor Relations.

Speaking on the call today are John Browne, our Chief Executive, and Byron Grote, our Chief Financial Officer.

Before we start, I'd like to draw your attention to 2 items.

First, today's call refers to slides that we'll be using during the webcast.

Those of you on our e-mail list should have already received the slides.

These materials have all been available to download from the Investor Center on our website, bp.com since 7:00 U.K. time this morning.

If you haven't received this information and would like to be placed on our list for future releases, please do let us know.

We hope this earlier access to the webcast materials was useful to you.

Second, I would like to draw your attention to 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 here.

Now over to John.

Thank you for joining us for our webcast on the announcement of our final 2004 results.

We were delighted to report earlier today that our replacement cost profit for 2004 of $16.2 billion is a record, up by 26 percent over 2003.

And that we've been able to raise the dollar quarterly dividend to $0.085 a share, an increase of 26 percent over 4Q 2003.

And more about all that later.

Those achievements have been helped by the external environment, but they couldn't have been delivered without the internal improvements that have been achieved over the last decade.

That's down to strategy and to the disciplined way in which we've pursued that strategy.

And that approach will continue.

We believe we have the right strategy and we're determined to maintain the discipline we've followed so far.

I think you will see that discipline in action throughout this presentation in the way we manage capital, in the way we plan the business, and most important of all, in the way we handle the gains from a positive external environment.

Investing for the future, but also returning funds to the shareholder.

We have 2 things we want to discuss today.

Firstly, our review progress on strategy.

Our strategy and the associated targets and indicators remain exactly as outlined in March of last year.

As I said at the time of the 2 and 3Q results, we are on track.

Secondly, Byron Grote, our Chief Financial Officer will take us through a specific discussion of the 4Q and full-year results.

He will also say a little about the forthcoming shift of our financial reporting to IFRS, and the changes in our segment reporting, which will accompany the separation of our Olefins and Derivatives business.

Finally, in about an hour's time, we'll begin a question-and-answer session for around an hour.

Byron and I will have done all the talking so as to make this webcast as efficient as possible, but you'll be able to hear the segment heads answer questions about their segments.

So Ralph Alexander, Vivienne Cox, Tony Hayward, Andy Inglis and John Manzoni will be here for the Q&A session.

I know I speak for the whole team when I say how much we're looking forward to meeting many of you again over the coming months during face-to-face meetings.

So let me start by reviewing the overall context in which we're implementing our strategy.

World economic growth in '04 was strong, and oil demand was the strongest that it's been for almost 30 years.

Oil demand was met without interruption, but the level of spare capacity, that is production held back by OPEC, was reduced to lower than historical levels. 2005 is expected to show more moderate oil demand growth, as well as economic growth reverts to trend.

There should be sufficient spare capacity to accommodate the reasonable ups and downs of demand and possible disruptions to supply.

Oil price prospects will clearly depend on the future strength of underlying supply, demand growth, OPEC politics and perceptions of risk of political stability in the key producing areas.

On supply, non-OPEC production is expected to continue to grow in aggregate.

For the next 3 years, this net growth is estimated to be about 1 million barrels per day each year, broadly similar to the average increase over the last 5 years.

Growth in Russian production is expected to continue.

But probably at a somewhat slower pace than in the recent past.

OPEC's crude oil production capacity should also grow and should be supplemented by an increased extraction of NGLs.

The level of demand will determine how much spare capacity is available.

If the annual increase in demand reverts to the historic norm of 1 to 1.5 million barrels a day, increased OPEC capacity should allow for a gradual rebuilding of global spare capacity to a level more like the 3 million barrels a day average that has prevailed for the last decade.

In the third quarter, we concluded that on the basis of the supply demand balance, and OPEC's 5-year track record of maintaining production discipline, oil prices are likely to have a support level of around $30 a barrel for at least the medium term.

As far as BP is concerned, we'll continue to use a Brent oil price of $20 a barrel for the purpose of testing projects and planning our activity level in the E&P sector.

This allows us to maintain a portfolio of activities with strong returns.

For the Group, a planning assumption of $20 a barrel remains a good yardstick for testing the downside and the balance between investment and total distributions to shareholders.

Turning to gas.

Gas markets have also been strong, with natural gas remaining the fuel of choice, especially in power generation.

Natural gas prices were at record highs during '04 in the liberalized markets of the U.S. and U.K.

The U.S. market is likely to remain supply constrained for several years, given the underlying decline of North American production and the lag in bringing on new LNG import capacity.

So, gas prices are likely to continue to track oil prices quite closely.

The futures market currently shows Henry Hub gas prices trading above fuel oil parity through the end of the decade.

The U.K. gas market also appears supply constrained in the near term.

But significant new import capacity is expected to come on stream starting in 2006.

Whilst underlying demand for gas should be strong in both the U.S. and the U.K. markets, the impact of high natural gas prices on effective demand is a key uncertainty.

Finally, a word on refining margins.

In 2004, strong demand growth raised refinery throughputs and margins to record levels, caused increased production of heavy sour crudes, and resulted in low product inventories.

This drove the premium for light products over fuel oil to exceptional levels and has favored upgraded refineries, like BPs, over less complex sites.

In 2005, a similar but perhaps less pronounced situation is likely to prevail.

This should underpin refining margins in '05 subject, as always, to regional demand patents.

Turning now to our strategy.

Our strategy remains as we described it to you last March.

A key strategic judgment is striking the balance between the level of investment and the level of total distribution to shareholders.

I talked about this extensively last year.

This balance is driven by consideration of the appropriate level of growth in what is a maturing industry.

Too faster growth rate is likely to be unsustainable and too low a growth rate could hand competitive advantage to others.

But growth is not an end in itself.

The essence of our strategy is to keep providing better goods and services in the strongly competitive way.

Our challenge is to add new sources of cash flow to existing ones, with the new sources having cash returns at least as good as the existing ones.

And we've identified a strong set of opportunities to do just that over the medium and long-term.

Our analysis of our immediate investment opportunities gives us confidence that an overall investment level of around $14 billion per annum is about right for the next 2 years after taking account of the current level of the dollar and the sector-specific inflation we've recently seen.

Our analysis also gives us confidence that our existing opportunity set is broad enough for us to not need to make substantial new investments in non-conventional crude oil production and to be able to dispose of our interest in olefins and derivatives.

In summary, our strategy is for the resources business, to build production with steadily improving cash returns at $20 a barrel, by investing in the largest, lowest cost new hydrocarbon deposits and managing the decline of our existing production assets.

For the customer facing businesses, to expand gross margin capture from customers, improve quality to offset competitive forces in order to grow cash flow, while keeping underlying cash returns at least constant.

Achieving this strategy requires us to be both technologically and commercially innovative.

We continue to develop both technology and know how.

Let me give you a few examples.

Thunder Horse breaks many records as a development, as the largest floating facility in the deepest water in the harshest reservoir pressure and temperature regime.

Our drilling technology is allowing us to improve recovery of hydrocarbons at lower relative cost.

Seismic imaging, especially below salt, opens up the possibility of new discoveries.

We remain a leader in relevant technologies ranging from seismic imaging to enhanced oil and gas recovery to deep water know-how.

We continue, also, to improve the way in which we participate in our customer facing businesses, choosing the right markets, products, and offers to give us competitive advantage.

For instance, introducing new formulations of gasolines and diesels, which reduce tail pipe emissions and add more power to engines.

And we continue business development, both in the upstream and downstream, not least in countries which are resource rich, we'll have large developing customer bases.

In some cases that involves working with state or quality state enterprises, so long as we can reach the right balance of mutual advantage to make business viable.

The outcome of all this is that we have confidence in BP's ability to perform sustainably, not just for the next few years, but for the long-term.

We believe our performance will be distinctive in 4 respects.

Firstly, to renew our E&P business we only need to rely on the exploration for and the development of primarily conventional oil and gas resources.

Secondly, we can achieve growth without participation in the Olefins and Derivatives subsegment.

Thirdly, we are pursuing an approach to our customer facing businesses, which avoids selling all our products just as pure commodities.

And finally, integration of our activities, not just through conventional physical linkages, but also with those afforded by the markets.

This we do with the integrated supply and trading function.

Let me now look at the segments.

The basis for this review is the presentation we made to you in March of last year.

While the details, of course, do change in the light of events and competitor actions, the segment substrategies have not changed materially.

Turning first to E&P.

For the industry, investment levels continue to rise.

Third party estimates indicate that industry E&P spending rose to around $170 billion in '04, an increase of 12 percent over '03.

Industry average finding and development cost per barrel will be at a very approximate indicator of capital intensity, rose in '03 and are likely to rise again in '04.

The broad trend showed that the finding and development cost for the super majors remain below those of the rest of the credit industry.

But nevertheless also appear to be rising.

History would suggest that this is cyclical as new basins are opened.

It remains to be seen whether or not this is the case.

By the way, it shows that asset quality and efficiency enabled by technology are key to maintaining competitive costs.

BP's 5-year rolling average, finding and development costs to end '04 were $4.65 per barrel of oil equivalent for subsidiaries and $4.37 per barrel of oil equivalent for subsidiaries plus associates.

These are within the indicator range of $4 to $5 per barrel oil equivalent given last March.

Looking forward, it's more representative to focus on subsidiaries plus associates as TNK-BP is now a material part of our portfolio.

On this basis, we expect the forward trend of finding and development cost to be broadly in the range of $5 to $6 per barrel of oil equivalent as a result of inflation in the capital goods market and foreign exchange movements.

We talked at length about this in our 3Q presentation in October.

2004 was the 12th consecutive year in which our reserves have been replaced at over 100 percent as presented under the U.K. statement of recommended practice. 106 percent for subsidiaries, and 110 percent for subsidiaries and associates.

You should note that these estimates are based on our assumption of $20 per barrel oil for long run E&P planning purposes.

We have made major discoveries in new plays including the Western Nile Delta of Egypt, Sakhalin and the deepwater Gulf of Mexico, which are creating new opportunities for the future.

We have also made significant discoveries in Trinidad and Angola.

In total, we added over 1 billion barrels oil equivalent of resources.

Exploration capital expenditure was $530 million in '04 and is expected to be $600 million in '05, mostly focused in the deepwater Gulf of Mexico, Angola, Sakhalin and Trinidad.

Appraisal capital expenditure in '04 was $230 million and will rise on the back of new discoveries to an estimated $500 million in '05, spent mostly in the deepwater Gulf of Mexico and Angola.

In the existing profit centers, the rate of decline of production in '04, compared to '03 was between 4.5 and 5 percent after removing the affects of price on production sharing contracts, divestments and one-off operational issues, the Temsah blowout and Hurricane Ivan.

The average decline rate over the period from 2002 to 2004 was around 4 percent per annum in line with our previous estimates.

Going forward, the decline rate is unchanged from previous estimates at around 3 percent out to 2008.

In 2004, cash costs in existing profit centers were around $280 million higher than projected.

This was mostly a result of sector cost inflation, increased fuel costs and FOREX movements.

The remainder was caused by repair costs as a result of Hurricane Ivan and Temsah.

These repairs were completed within the cost budgets established for them at the time.

After correcting for these environmental and one-off impacts, unit cash costs in '04 were in line with previous guidance at around $5 per barrel of oil equivalent.

Looking forward, a weaker dollar and sector-specific inflation will increase costs, although we will continue to mitigate these impacts through a combination of technology and rigorous supply chain management.

Capital expenditure in the existing profit centers has risen to $3.5 billion in '04 compared with $3.2 billion in '03.

We expect this to rise further to around $3.6 billion in '05 as a result of specific oil field inflation and a weaker dollar.

We are planning further activity in our North American gas business, both to accelerate and to increase recovery of natural gas over the period of 2010.

The impact of these activities will take some time to be material.

Now, the new profit centers.

Projects are on track with the guidance we gave you last year.

Production in '04 was at 1 million and 4,000 barrels of oil equivalent per day, up from '03.

In 2005, the level of production from the new profit centers is expected to be significantly higher.

The precise outcome is sensitive to oil price because of the technicalities of production sharing contracts.

Earlier this year, we approved our share of the investment in the Tangguh project and we expect Kizomba C, Phase I, and Northwest Shelf train 5 to follow later in '05.

Capital expenditure is expected to be slightly lower than the $6.3 billion in '04 at a level of around $6 billion in on '05.

Turning now to Russia.

Investor confidence has been eroded by the continuing news flow on new costs.

This has not affected TNK-BP's operations.

TNK-BP continues to increase production from the existing fields, growing oil production in '04 by just under 14 percent over '03, to 1.45 million barrels of oil per day or 1.66 million barrels of oil per day including the 50 percent of Slavneft that was added at the beginning of next year.

We expect production to continue to grow by around 5 percent in '05.

Capital expenditure in TNK-BP, which continues to be self-funding, grew from around $1 billion in '03, to $1.5 billion in '04 and is forecast to increase further to approximately $1.8 billion in '05 as new prospects are developed for the future.

These include new extensions to Samitslah [ph] and the Uvat project, both 1 billion barrel developments in West Siberia.

In addition, projects to improve the refining system are nearing completion, with a significant enhancement at the Reazan [ph] refinery targeted to deliver 500,000 tons per annum of light products rather than fuel oil to feed the Moscow market.

Now, over 18 months into the joint venture with Alfa Access-Renova, significant positive changes have taken place in TNK-BP's organization, the system of internal control, the ability to plan, the approach to safety and environmental issues, and the application of new technologies.

While there are always uncertainties, our constructive relationship with Russia and our joint ventures continues to strengthen.

The result of this can be seen in the performance of the TNK-BP Company.

Since the formation of TNK-BP, the total investment made by BP has been $5.3 billion, and total dividends received by BP has been $2.2 billion.

In addition, as I previously noted, exploration success in Sakhalin has opened up significant potential for the future.

Overall for the E&P segment, production is on track with our previous estimates.

The absolute level depends on price, divestments and unusual weather affects, such as Hurricane Ivan.

Our expectation for 2005, based on our $20 per barrel planning basis, is the reported production will be between 4.1 and 4.2 million barrels of oil equivalent per day before any divestments.

The exact level will depend on oil prices, divestments and many other factors.

For instance, at $45 a barrel, production will be reduced by around 50,000 barrels of oil equivalent per day.

Capital expenditure is expected to be between $9.5 and $10 billion in '05 and '06.

The exact outcome will depend on FOREX and inflation.

Divestitures include Ormen Lange, and some other minor additional properties.

So this updates the medium term position.

But of course, and in particular in E&P, the longer term needs to be considered.

I want to update and extend the discussion on the opportunities there that underpins our confidence to grow production through the remainder of this decade and beyond.

This, again, is based on our presentation of March '04.

Simply start by talking about the balance of our proved developed and undeveloped reserves and our non-proved oil and gas resources.

At year-end '04, total reserves under SORP stood at 18.6 billion barrels of oil equivalent, of which 42 percent is gas.

Non-proved resources are estimated to be 39 billion barrels of oil equivalent, of which 32 percent is gas.

Of particular note, are the resources in the existing profit centers, comprised mainly of Alaskan gas, other North American gas, Argentina gas, Abu Dhabi and the North Sea.

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

In particular, because of the quality of the potential in the new profit centers, we estimate about 13 billion barrels in the new profit centers alone could reasonably be added from exploration.

These reserves and resources continue to grow with exploration and are converted into production.

The quality of this significant base gives us confidence that our present portfolio has the potential to continue to grow production over at least the next 10 years.

We've taken a snapshot at the end of the decade and at that point in time conventional oil contributes around 60 percent of production.

Within that, the contribution from TNK-BP remains stable at around 20 percent.

The contribution from deep water oil production grows from 10 percent to 15 percent, as a result of the existing projects in the deepwater Gulf of Mexico and Angola.

Natural gas currently makes up 40 percent of our portfolio, and this percentage remains stable to 2010, while absolute volumes increase.

LNG's contribution is expected to grow from around 10 percent to 15 percent, while pipeline gas declines from 30 percent to 25 percent.

This broadly stable patent of contribution from different sources of production indicate that the potential unit cash margins from the segment might also be broadly stable, subject, of course, to sector- specific factors, such as the oil price.

On top of all this, production volumes are expected to grow.

This growth, as projected to the end of the decade, does not rely on exploration success or new access to gas markets.

Of course, we expect to continue to discover new oil and gas from our existing portfolio to underpin growth beyond 2010.

And we're continuing, too, to develop new business.

So to summarize the E&P segment, we continue to build on our successful exploration track record with 12 years of reserve replacement above 100 percent.

Decline in our existing profit centers is in line with prior projections.

All our major projects are on track, and the trend in production growth to '08 is developing in line with our expectations.

A significant portfolio of new conventional resources gives us confidence in our ability to grow not only in the medium term, but sustainably for the long-term.

Turning now to the Refining and Marketing segment.

Our purpose is to capture more customers through upgrading the quality of our offer and expanding the gross margin on each unit we sell.

As a result, we aim to increase the cash flow from the business, while maintaining cash returns at least constant.

Let's look at 3 of these segments.

First, refining.

We continue to upgrade our refining portfolio.

I think the best way to summarize this is with the benchmarking from the Solomon survey.

The majority of our refining capacity, following the divestiture of Lavera and Grangemouth will be located in the U.S. where margins are structurally advantaged and our refineries are in the top quartile on net cash margins and return on investments.

In Europe, after the divestiture of Lavera and Grangemouth, our position should improve considerably.

We have built this strong portfolio by focusing on the quality and flexibility of our refinery configuration.

This flexibility allows us to capture incremental margin through sourcing crude oil and the optimization of the refinery operations.

Capital expenditure in '05 is expected to remain at around $1.3 billion.

The mix of expenditure is varying as we complete our clean fuels investment phase and increase our spend on commercial projects.

Capital expenditure is likely to increase towards the end of the decade, as we build on our strong position in the U.S. by adding further upgrading capability and improve our position in Europe.

In the retail business, we continue to improve our services and products, and seek to participate only where we have competitive advantage.

First, store sales continue to grow.

In the markets where we're focusing our investment, we continue to see significant growth above market.

Second, the sales of our premium fuel Ultimate continued to grow.

We are capturing more gross margin with our offers.

The quality of our offers is also improving as reflected by store sales per square meter and the increasing share of margin being generated by the store and premium fuels.

All of this demonstrates the effectiveness of pushing against commoditization.

Capital expenditure is stable at around $950 million, with capital employed broadly flat to declining over the period.

We will continue to rationalize the network with the sale or decapitalization of weaker market positions.

Our lubricants business continues to grow.

We offer better products through investments in brands and new technology to meet our customers' needs.

Consequently, volumes have consistently grown above market whilst we have expanded unit gross margin.

Overall, the Refining and Marketing segment continues to perform well.

Capital expenditure is expected to be around $3.2 billion in '05, and the same in '06.

The segment continues to grow and the quality of performance is improving significantly.

We continue to grow gross margin from our customer base, while focusing on expanding unit gross margins across all our business.

Cash returns are expected to remain at least constant over '05 and '06 for equivalent external conditions when compared to '04.

Turning now to gas.

Our global gas sales increased to 32 billion cubic feet per day in '04.

Going forward, we expect medium term growth of 2 to 3 percent a year, which is in line with global gas demand, with increasing concentration on customers who best fit our capabilities.

As we previously stated, North America remains our number 1 market.

Our gas segment continues to be the leading gas marketer in North America, anchored by strong upstream positions around the Gulf of Mexico, the Mid-Continent, the Rockies, Canada, and Trinidad.

In North America overall, our gas sales grew by 16 percent in '04 over '03, continuing the track record of growth.

Our strong position in the North Sea, imports of LNG, and our partnerships in Russia, create an opportunity for us to continue supporting Europe's move towards cleaner gas-fired heat and power.

Our gas business is built on 3 core pillars, strong upstream positions near the leading markets, world-class marketing and business development, and integrated LNG positions in both the Pacific and the Atlantic basins.

Our plans for LNG are on track.

Our Atlantic-based LNG business is underpinned by our upstream positions in Trinidad, Egypt, and in the future Angola.

We're bringing this gas to market through selected investments and downstream regasification and logistics assets.

Our American position is supported by access agreements at Cove Point and Elba Island, as well as LNG sales delivered through the Everett terminal in Boston.

In the U.K., the Isle of Grain terminal, where with center track we have 450 million cubic feet per day of capacity, is on track for startup in the second quarter of this year.

In Spain, our regasification capacity allows us to serve markets in Iberia and provides a certain anchor for our Atlantic Basin position.

In the Pacific Basin, long-term marketing of our new upstream is to both existing and new customers.

For example, BP and our partners will access new customers through 4 new regas terminals being built in the region.

Our terminal in Guangdong, China where we have a 30 percent participation.

As well as marketing agreements through the terminals now under construction in Fujian, China, Gwenyang [ph], South Korea and Baja, Mexico.

Long-term supply agreements for the first 2 trains at Tangguh were completed in the third quarter and support market commitments in Asia, as well as the West Coast of North America.

Sales volumes of natural gas liquids have continued to grow at around 5 percent a year.

We are presently reviewing our position in this business with a view to focusing it further.

Let me turn to the 2 subsegments of petrochemicals.

First, Olefins and Derivatives.

Almost all of our existing interest in these activities will form the basis for the Olefins and Derivative that we plan to divest, probably by way of an IPO, subject to market conditions and necessary approvals.

To these will be added the refineries at Grangemouth and Lavera and that will allow the new company to capture additional synergy value across the 2 sites.

The formation of the new holding entity is proceeding on plan, and we're on track for divestment in phases, commencing in the second half of '05, again subject to market conditions and necessary approvals.

We've summarized the performance of this subsegment in terms of cash returns and capital expenditure.

We're actively managing the portfolio to strengthen the returns and the business.

For instance, the fabrics and fibers business is being divested.

We have announced the permanent closure of the Linear alpha olefins operation at Pasadena, Texas and we've announced our intent to form a styrene polymers joint venture in Europe.

These changes allow the subsegment to simplify its structure and processes resulting in more cost efficient operations and improving returns.

The business is also on plan with its growth projects.

The most significant source of growth is the startup of our 50 percent owned, $2.7 billion Olefins and Derivatives complex in Shanghai, China.

This project is on track for beneficial production by the third quarter of '05 and is designed to add 2.3 million tons of new capacity to serve Chinese and broader Asian demands for petrochemicals.

In addition, we should soon complete the 300,000 ton expansion of our ethylene crackers in Chocolate Bayou, Texas.

Olefins and Derivatives CapEx is planned to decline slightly in '05.

In the high growth aromatics and acetyl subsegment, BP enjoys leading market shares in technologies.

Cash returns have been competitive and are trending upwards.

Capital expenditure in this subsegment is running at $200 million in '04, and this is likely to increase slightly as we invest to maintain our leadership positions.

Now let's summarize the overall operational base of the Group.

As I've said, we expect capital expenditure in '05 to be around $14 billion.

The exact level will depend on the level of the dollar and our continuing track record of offsetting normal underlying inflation of around 2 percent per annum.

Further out for the medium term, a level of $14 billion is a reasonable expectation.

Divestments, with the exception of Olefins and Derivatives are not presently expected to be large.

In '05, we expect an amount of around $1.3 billion comprised of the remaining proceeds from Ormen Lange and normal portfolio optimization, including continued upgrading of our retail activities.

Cash returns are on track.

Actual cash returns have risen between '02 and '04, as has the actual oil price.

Returns adjusted to $20 a barrel as best, as we can estimate, are in line with those shown in March of last year.

Let me now turn to the subjects of the dividend, the level of gearing, and the use of excess free cash flow.

Our dividend policy is to progressively grow the dividend.

In pursuing this policy and in setting the level of dividends, we're guided by several considerations including, firstly, the prevailing circumstances of the Group.

Last year we achieved all we set out to do.

Performances on track, investments are going in and producing revenue, strategy is on track.

Secondly, the future investment patents and sustainability of the Group.

We have a strong set of opportunities, which we are pursuing, giving us a clear view of our future, whether related to resources or customers and we're confident about that future.

And finally, the future trading environment.

It does seem that oil prices have a support level of $30 a barrel for at least the medium term.

This gives us some comfort in considering the timing of dividend changes.

However, we will continue to use our planning assumption of $20 a barrel as a good yardstick for testing the downside and the balance between investment and total distributions to shareholders.

We have concluded that the Group should make a significant one-time step change in the level of the quarterly dividend from $.07.1 per share, the 3Q '04 level, to $.08.5 per share for 4Q '04.

Thereafter, we would expect to grow the dividend in line with our view of future sustainable performance.

We estimate that this level of dividend still allows us to maintain prudent earnings cover, even if oil prices went down to levels of $20 a barrel.

We determine and pay our dividend in the functional currency of the Group, namely dollars.

However, we're aware that many of our investors are sterling based and that the dollar's weakness has had an impact on their sterling cash flows.

This one-time step change will be to their benefit.

This new level of dividend means that the dollar-based investors will have seen a 26 percent increase in the 4Q dividend compared with last year, for sterling investors the increase is 23 percent.

For the year as a whole, dollar-based investors will have seen an increase of 13 percent and sterling-based investors, 4 percent.

Our approach to the level of gearing is unchanged.

We are managing our gearing in the lower half of our band of 25 to 35 percent, in order to provide the appropriate cushion against potential oil price volatility and also to prevent an increase in our weighted average cost of capital, which would result from an inefficiently leveraged balance sheet.

Finally, our approach to the use of cash flows in excess of those needed for investments and dividends is unchanged.

We remain committed to returning 100 percent of excess free cash flow to our investors, so long as oil prices remain above $20 a barrel, all other things being appropriate.

We could use some of the excess free cash flow, for example, for material acquisitions if we saw opportunities which fitted the strategy, but we see no such opportunities at present.

We plan to continue our program of share buybacks subject to shareholder approval at our forthcoming AGM and to market conditions.

Between the completion of the ARCO acquisition in 2000 and last Friday, we have bought back some 1.7 billion shares for $14.3 billion, reducing the number of shares in issue by more than 5.5 percent after accounting for the issue of shares for employee stock programs and to AAR in respect to TNK.

Let's now look at the potential amounts of cash which could be distributed by way of share buybacks and dividends.

This is much the same chart as we showed you last year, updated for '04 delivery and the wider range of oil prices.

We've compared what we've distributed in '01 to '03 and in '04 with all other things being appropriate, what we could distribute in '05 and '06.

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

Under these assumptions, and if oil prices were $30 a barrel, the amount of cash flow available for distribution will be about $23 billion in total for '05 and '06.

And at the present rate of dividend distribution, around 60 percent will be paid as dividends.

Let me conclude with an update on our targets and strategic indicators.

As a reminder, we have 3 targets.

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

As we said last year, this can be tracked by looking at 5 strategic indicators, which themselves are guidelines, not targets to which we manage the Group.

One, production growth.

In 2004, we grew production by 11 percent, a strong start for the indicator for 2003 to 2008.

Having banked this growth, the forward growth rate indicator, not materially changed from our prior indications, is expected to be somewhat ahead of an average of 5 percent per annum for the remaining years.

This results from our present expectation that TNK-BP's growth rate will converge with the growth rate of the rest of our portfolio over time.

Of course, the actual outcome will depend on many things, including the oil price, our divestment program, and the weather.

I want to repeat again, that these cumulative average growth rates are an indicator, not a target, and should be treated as such.

Two, pretax cash returns, which, as I said earlier, are on track on a normalized basis.

Three, growth in capital employed.

Growth in '04 was 13 percent, around half of which was due to the higher oil price and the weaker dollar.

Four, finding and development costs.

These have risen due to sector-specific and the weaker dollar.

And finally the CapEx levels.

As I said a moment ago, in today's trading environment, we regard around $14 billion per annum to be the appropriate level of reinvestment for the group.

I want to emphasize again the difference between a strategic indicator and a target.

A strategic indicator is an estimate of an outcome, not a going-in target.

Indicators are provided so that people can assess how we're doing.

These indicators will change if we find better ways to achieve our targets.

The second target is to increase the dividend in the light of our policy given to you in March '04.

We have delivered on this with a 26 percent year-on-year increase in the dividend.

The third target is to distribute to shareholders 100 percent of all free cash flows in excess of investment and dividends needs, generally when the price of oil is above $20 a barrel, all other things being appropriate.

We have delivered on this by undertaking $7.5 billion of stock buybacks in '04.

So to summarize, our success so far is due to the combination of strategy and discipline.

Over the past few years, we've built a strong base for the Group, with material assets and markets into which we're investing.

We are achieving the targets for growth we outlined, we're improving quality, and we are maintaining our financial strength.

Importantly, in spite of the significantly better than expected trading environment, we are maintaining a disciplined approach at the execution of our strategy and consequently making sure that excess free cash flows are appropriately distributed to shareholders.

There is growing momentum in our activities and growing confidence in our future.

The operational base of the Group is strong, and it is positioned appropriately to seize opportunities in the future despite the inevitable political and economic uncertainties.

Our commitment to the combination of strategy and discipline is unchanged.

And that's why I can still say with great confidence that the best is yet to come.

Now, let me hand over to Byron.

I will start my review of fourth quarter and full-year results with a recap of price and margin conditions, building on John's earlier remarks.

Upstream realization strengthened in 2004.

Oil realizations continued the upward trend that started last year.

Averaging $41 per barrel in 4Q.

Our full-year realization of more than $36 was 29 percent higher than in 2003.

Gas realizations also rose in 4Q.

Our full year-realization approached $4 per thousand cubic feet, benefiting from record high gas prices in the U.S. and U.K.

Our overall average hydrocarbon realization was up 41 percent in 4Q and 23 percent for the year compared to 2003.

As shown on the right, we also saw solid double-digit growth in industry indicator margins for both refining and petrochemicals.

Refinery margins were at record levels, with our industry indicator margin exceeding $6 per barrel for the year.

As in the third quarter, refineries designed to handle heavy and sour crudes, such as the majority of our own, were able to achieve better than average margins.

4Q also saw continued strong supply optimization performance and a recovery in marketing margins, partly offset by a charge related to the carrying values of marketing assets.

The net affect of all these factors was a record refining of marketing result for the quarter and the full year.

Petrochemicals margins continued to improve with the global economy.

Both the aromatics and acetyls and the Olefins and Derivatives businesses benefited.

Trading conditions were up in all of our main lines of business, which helped drive Group earnings and cash flow to record levels for the year.

I'll start with the fourth quarter data.

Our 4Q pro forma result of $3.6 billion was up 26 percent year-on-year.

Our replacement cost profit of $3 billion, which includes acquisition amortization, was up 35 percent.

Our historical cost profit of $2.5 billion, which includes both acquisition amortization and inventory affects, was up 9 percent.

All of these figures include a $1.1 billion post-tax charge for non-operating an exceptional items in 4Q, which I'll describe momentarily.

These charges were largely non-cash.

Despite the normal quarterly peak in excise tax payments, our 4Q adjusted operating cash flow was $5.3 billion.

This was more than 2.5 times a last year's level, which was impacted by the large discretionary pension contribution made in 4Q 2003.

As shown at the bottom of this slide, our full-year results were also up significantly with each of these figures a record for the Company.

The results just reviewed include a number of gains and losses not directly related to ongoing operations.

These fell into 2 categories.

First U.K.

GAAP requires us to separately report as exceptional items any gain or loss from disposals or termination of operations.

You will recall that in 1Q these totaled a gain of $1.3 billion, mainly profits on the sale of successful investments in Petro China and Sinopec.

We had $143 million net post-tax charge charge from exceptional items in 4Q.

Second, in order to help you better understand our underlying results, we also disclosed material non-operating items, as well as the unrealized profit and stock on Alaskan crude supplied to our West Coast downstream system.

These items brought the total charge to $1.1 billion post tax in 4Q.

Most of the fourth quarter charge relates to the steps that we're taking to improve the performance of our petrochemicals portfolio.

Following a thorough review as the business has been separated, we have announced reductions in asset carrying values, plant closures, and business exits in both our aromatics and acetyls and Olefins and Derivatives operations.

For the year, non-operating and exceptional items totaled a net post-tax loss of $609 million in 2004.

Compared with a post-tax gain of $440 million in 2003.

Our stock exchange announcement provides further details of all these items.

This chart shows BP's pro forma return on capital employed relative to our principal competitors.

The results shown are on a headline basis and include all items that various companies refer to as exceptionals, specials, non-operating items, and the like.

These items make earnings enhance return on capital employed, more volatile.

Our 4Q return of 17.4 percent includes a 5 percent reduction due to the non-operating exceptional charges I just discussed.

We continued to find cash returns, which exclude the impact of these non-cash charges, to be a better indicator of business performance.

Our full-year average pre-tax cash return, shown by the white lines, increased from 26 percent in 2002 to 31 percent in 2003 and to 35 percent in 2004.

This represents progressively stronger cash generation on a growing capital base.

The data shown are based on actual prices and margins, which are substantially above our planning assumptions.

As best we can estimate, our underlying cash return in 2004 was in line with the projection we showed last March.

This chart shows the main elements driving the $3.3 billion improvement in the full-year result, from $12.9 billion in 2003 to $16.2 billion in 2004.

Building from the left, the shift in exceptional and non-operating items from positive in 2003 to negative in 2004, which I discussed earlier, amounted to around $1 billion.

Higher prices and margins added around $5.1 billion with improvements in all business segments.

Around 60 percent of the improvements relate to higher oil and gas prices, and the remainder relate to margin improvements in our customer facing businesses.

Turning to FOREX we estimate the full year negative impact of the weaker dollar to be around $550 million post tax.

Acquisition and divestment activity added around $250 million, with the full-year benefit of the TNK-BP acquisition more than offsetting the impact of disposals.

Depreciation charges, excluding foreign exchange affects, were up $550 million between years on a post-tax basis.

This reflects changes in portfolio composition and the startup of new projects over the past year.

The remaining improvement of around $150 million encompasses a number of factors.

It reflects the actions we've taken to mitigate the recent rise in sector-specific inflation.

It includes the profit contributions from our new E&P startups, partly offset by the decline in existing profit centers, plus the impact of the Temsah blowout in Egypt and Hurricane Ivan.

It also includes volume growth and commercial performance in our customer facing segments, partly offset by the charge related to the carrying value of marketing assets mentioned earlier.

Lastly, it reflects lower interest costs for the Group, offset by a slight increase in our effective tax rate in the higher price and margin environment that prevailed in 2004.

As John mentioned, 2004 is the 12th consecutive year in which BP has replaced more than 100 percent of its production through discoveries, extensions, revisions, and improved recovery.

Calculated on the basis of the U.K. statement of recommended practices for SORP.

This included 106 percent reserve replacement in subsidiaries, and 118 percent reserves replacement for equity accounted entities.

Just to remind you, BP's main equity accounted entities are TNK-BP, Pan American Energy in Argentina, and our Abu Dhabi operations.

Our total combined replacement ratio was 110 percent.

All these figures are determined using our internal process to control the quality of reserve bookings.

We recognize reserves in major projects on sanction.

That is, on the final investment decision.

For a short time earlier when a project has been confirmed as both technically and commercially viable at our long-term planning assumption at $20 per barrel.

This aligns our recognition of reserves with our financial commitment to development, which we believe is the most useful disclosure to shareholders.

I would like to remind you of the basis of our reserves reporting.

BP is a U.K. company reporting under U.K. accounting standards.

We report our reserves under the principals of the U.K.

Oil Industry Accounting Committee statement of recommended practice.

We interpret this SORP as similar in principal to SEC Regulation SX, which governs reporting of reserves by U.S. listed companies, although there are some differences, including the interpretive guidelines which the SEC provides.

The SEC requires reserves to be estimated based on year-end prices, around $30 in 2003 and around $40 at year-end 2004.

This introduces volatility into the reserves calculation, particularly for reserves booked under production sharing contracts.

The SEC base reserve replacement for 2004, again, looking only at discoveries, extensions, revisions and improved recovery, was 78 percent of subsidiaries, 114 percent for equity accounted entities, and 89 percent if combined.

If 2004 year-end prices have been unchanged from the 2003 level, we estimate that the SEC replacement ratio for both subsidiaries and the total combined would also have been greater than 100 percent.

John described TNK-BP's strategic progress.

So I'll focus on its 4Q results.

Our share of TNK-BP net income, after accretion of the discount on deferred shares consideration, was nearly $400 million in 4Q compared with around $500 million in 3Q.

The main driver of this decrease was a full quarter of the new export duty regime that came into effect on August 1st, as well as the lagged impact of reference price increases for the duty.

Price impacts were broadly neutral between quarters, although production was up nearly 3 percent quarter-on-quarter, sales volumes were 2 percent lower due to seasonal stock builds.

Crude and products exports totaled 62 percent of 4Q production compared with 65 percent in 3Q, as the Company optimized its sales mix in view of seasonal market conditions and the new Russian duty regime.

The 4Q results also include a $23 million post-tax credit related to the prior quarter.

We received an additional $610 million of dividends in 4Q, bringing our full-year total to more than $1.9 billion.

This includes the one-off impact of TNK-BP shift to paying dividends one quarter in arrears.

The increase in mineral extraction tax that came into effect in the start of 2005, is expected to reduce our 1Q result by around $40 million post tax.

In January, TNK-BP announced further details of their corporate restructuring program, which is intended to simplify the corporate structure and provide greater internal transparency.

We believe this marks a further significant improvement for TNK-BP building on the positive changes described earlier.

Returning to the Group results, this slide compares our sources and uses of cash for the past 2 years.

Operating cash flow was $24 billion in 2004, up $5.5 billion over 2003.

The China share sales and other disposals have added more than $5 billion after tax, bringing total sources of cash to more than $29 billion.

We have reinvested $17 billion of this, including $3 billion in acquisitions.

And we distributed nearly $14 billion to shareholders via dividends and buybacks. 80 percent more than in 2003.

We ended 2004 with gearing just below our 25 to 35 percent band, up from 22 to 23 percent earlier in the year and 1 percent lower than at year-end 2003.

The increase in 4Q includes the normal quarterly phasing of German motor fuel excise payments, which will reverse in 1Q.

It also includes the Solvay buyout.

Consistent with the policy outlined last March, we distributed nearly $14 billion to shareholders in 2004.

This included $7.5 billion of share buybacks on top of the $150 million purchased for employee share programs.

It also included more than $6 billion in dividend payments.

The $.01.4 per share dividend increase we announced today is well underpinned by the earnings and cash flow capability of the firm.

The strength in current prices and margins should also support substantial further share buybacks consistent with our financial framework and distribution policy.

In fact, this quarter we have already purchased $750 million of shares under our closed period buyback program.

Now I'd like to spend a few moments looking forward.

I'll start by updating the guidance I gave last March on the outlook for several items that impact the Group's results.

In 2005, we expect our underlying other business and corporate activities to generate a net pretax charge of $900 million plus or minus $200 million.

This is the same as I indicated last year.

In addition, beginning in 2005, we'll divide our petrochemicals results between the Refining and Marketing segment and OB&C.

Our Olefins and Derivatives operations, including the Grangemouth and Lavera refineries will therefore be reported as part of other business and corporate until sold.

We continue to use primarily floating rate debt to finance the Group, thus interest expense will fluctuate with short-term market interest rates.

There is no material change in the funding status of our pension and benefit plans compared with a year ago.

So we expect both cash funding and earnings impacts in 2005 to be similar to those in 2004.

We also see no material changes in our income tax situation.

We estimate the marginal tax rate on changes in prices and margins to be around 40 percent.

So our actual income tax rate will depend upon the strength of actual trading conditions.

At current high oil and gas prices, we estimate our 2005 tax rates to be around 36 percent on earnings and around 28 to 29 percent on a cash basis.

Last year I also provided Rules of Thumb to help you model the impact of price and margin changes on our results.

The updated 2005 indicators reflect the year on year changes in our volumes and portfolio mix, as well as higher assumed prices and the consequent impact on fiscal terms.

Other factors being equal, we expect our pre-tax result will move by around $500 million for each dollar change in oil price, $100 million for each $0.10 change in the Henry Hub first of month index and $1.1 billion for each dollar change in the refining margin.

These Rules of Thumb should be considered directional indicators, which are more useful on an annual basis than for quarter-on-quarter comparisons.

Over shorter periods changes in differentials, seasonal demand patterns and other factors can be material.

During 2005, we intend to implement several changes in the way we report our results, some of which we have already mentioned.

But I'd like to leave you with a more complete list.

Firstly, like all U.K. corporations, we'll move to international financial reporting standards in 2005, replacing U.K. GAAP.

Secondly, starting this year, we will discontinue pro forma reporting for the ARCO and Castrol acquisitions.

We initiated pro forma reporting in 2000 to show our results on a comparable basis with others in our industry who had accounted for merger activity in different ways.

IFRS does not require goodwill amortization as U.K. accounting standards do, resulting in a clearer and more comparable presentation of underlying business results.

Consequently, we've decided that pro forma reporting is no longer required.

Finally, we will transfer some operations amongst our business segments to help position the Olefins and Derivative business for sale, and to further strengthen operating synergies amongst related assets.

As with similar changes in the past, we will restate 5 years of history.

None of this has an impact on our strategy, the economic value of our business, or the cash that we will distribute to investors.

All of these remain unchanged.

And as we have indicated today, our performance in these areas is on track.

However, the 2005 reporting changes will impact the way we present our results.

As well as the level of reported earnings and capital employed.

I will describe these impacts in an on-line technical briefing on March 14th, accompanied by substantial background material on our website at that time.

We will then begin reporting on the new basis starting with our first quarter results to be announced on April 26th.

We hope the supplemental information we provide next month will be helpful to you in preparing for those changes.

Thank you.

That completes my review of results.

Now back to John.

Byron, thank you very much.

We are all here ready to answer your questions.

I'm just waiting for them to come on the screen.

And the first question I'll take from Fadel Gheit at Oppenheimer.

Fadel, good afternoon.

Good afternoon to you.

I have 2 question.

One, on the proved reserve at the end of the year, can you quantify the impact of the year-end high prices on the PSC approved quantities at the end of 2004?

I'll ask Byron to answer the question.

Fadel, let me just put all this in context, if you will just give me a minute, I want to make up a more general remark.

If you think through this as a U.K. company, we do report our reserves on a SORP basis.

Since we're U.S. listed, we need to also report it on an SEC basis.

But like many other things, there are differences between both U.K. and U.S.

GAAP, so it shouldn't surprise us that these different languages tend to lead to somewhat different results.

The biggest element, as you suggest, has to do with the use of year-end prices for calculating our reserves on an SEC basis.

We've got about 19 percent of our reserves in production sharing contracts.

And that means, of course, that as prices do go up, the reserves go down because they are tied to a revenue stream.

And therefore, there's less recovery at high prices.

As a U.K. corporate, we use $3.50 for Henry Hub prices and $20 Brent as our long-term planning assumptions.

On an SEC basis, as I indicated in my remarks, we've moved from $30 at the end of 2003 to $40 at the end of 2004, a $10 a price movement, with the consequent impact on our reserves in production sharing contracts.

Now, there's a slight offset to this, because at a higher oil and gas prices, we have the ability to recover additional volumes from our tax and royalty related reserves, because cessation of production is extended out and there are some additional areas that would provide reserves recovery.

But that is only a partial offset.

And that's really the drives the primary difference between the 110 percent on a SORP basis and the 89 percent on an SEC basis.

The difference between the 2 numbers is approximately 300 million barrels in aggregate.

But I want to be very clear, Fadel, that had there been no change in the year-end prices, that what we'd have found is that the reserve replacement, even under an SEC basis, would have been more than 100 percent for the year, both with respect to subsidiaries and on a combined basis.

And I would like to add that in order to assist analysts and investors in this area, that we plan, with our 2004 annual report in accounts, to provide you side by side the full disclosure with respect to reserved movements both on a SORP basis consistent with U.K.

GAAP, but also to help those who want to look at this on an SEC basis also in that context.

And just if you allow me --

Byron, thank you.

Fadel, you had a second question, I think.

Very quick follow-up.

Have you changed the methodology by which you estimate reserve based on the SEC new guidelines?

SEC reserves we have for SORP at -- probably not, I would say.

Okay.

Thank you.

The SORP.

Fadel, I think we are very satisfied on the basis of very rigorous process that we're fully in line with the SEC guidelines in all respects.

Thank you.

Thank you.

Could I turn to Tim Whitaker, please, of Lehman Brothers.

Tim, good afternoon.

Yes, good afternoon.

A general question and a specific question.

Firstly, the general question.

It appears that the rate of reserves bookings for you and perhaps wider industry is slowing while CapEx is rising, and that might also apply to you coming to that 1 billion barrels of resources added, which seems to be less than production.

Can you explain what you think are the drivers here and what do you think reserves bookings will pick up in due course as a result of the CapEx that has been rising over time.

And specifically, could you comment on the status of your discussions with the SEC regarding reserves bookings in 2002 and 2003?

And have you closed out those discussions or are they still ongoing?

Well, reserve bookings obviously vary year to year.

And it does depend on the amount that we're investing and the projects that we're bringing on.

And so but our reserves replacement seems pretty constant and pretty clear.

It's worth looking at it, I think, on a more average basis.

And I think that's pretty clear. 5-year basis, it's well north of 100 percent.

CapEx has risen not because activity has risen, but as we went through in the third quarter results on the basis, I think, of commodity price inflation, notably steel, but also the reduction and spare capacity in the service sector, all of which seem to take place in about April of this year.

The market prices for the aggregate sum of services and goods that we buy is going up about 10 percent, but we've mitigated that.

We always mitigate at least 2 percent a year through technology and through rigorous supply chain management, so we've absorbed some of it, but we can't absorb all of it.

The other thing for BP and this is a specific BP thing, is obviously we don't spend all the money in dollars, so we do spend it in non-dollar currency.

And with the weaker dollar, that's gone up.

All of that, of course, could go another way.

But let's just see.

So I think net-net as far as BP is concerned we're not seeing too many changes.

I think as far as the industry is concerned, S&D charges, a very primitive indicator, of course, are showing rising trends.

Our S&D cost as I said was around $4.50.

We expect it to go up because of the sector-specific inflation and weaker dollar.

But actually for the industry as a whole, it really is rising quite dramatically.

The non-super majors rising much faster than the super majors.

And that I think is something about selection of opportunity as time goes by.

With the best opportunities, the cost can keep down.

Let me ask Byron to update you on our SEC discussions.

We have responded to all of the questions that the SEC has asked us with respect to our prior-year's filings.

We have not received any further inquiries from them since the third quarter.

So that's the state of play.

Does that mean that the --

Thank you very much.

Colin Smith of CSFB.

Colin, good afternoon.

Thank you, gentlemen.

Could you just come back a little bit and discuss how the cash balances work.

Just looking at cash from operations this year of 24 and thinking about $14 billion of CapEx and $7-plus billion of dividends now in the environment that we had in 2004 and relate that back to the comments you make about distributing cash in excess of $20 Brent.

Obviously, we are distributing cash after the right level of investments, so that's $14 billion.

And we're making sure that our gearing stays within the range 25 to 35 percent, of course, at the bottom half of that range.

So as the Company grows, of course, that gives us a little bit more borrowing capacity.

But I think the most important thing is that this -- even with the increased dividend, we're still able to balance the cash and distribute broadly all other things being appropriate, the free cash flow above $20 a barrel.

It means, of course, that the underlying cash generative position, all other things being equal for the Company, is rising, as the new projects are coming onstream, as decline is being mitigated, as, indeed, the investments in the downstream businesses are generating.

I think that's the fundamental to look at is what's actually happening to the fundamental basis of the business.

Thank you.

Pleasure.

There is a very similar question to this problem from Paul McGinnis at the co-op Europe, and I hope we've answered that question.

Could I now turn to Robert Kessler of Simmons & Company in the U.S.

Good afternoon.

Question on your Olefins and Derivatives spinoff, given that you announced today the planned inclusion of the 2 European refineries in the O&D package.

Particularly in light of your comments in the press release about the relative profitability of sweet crude refiners versus complex refineries.

I was wondering if you might give us the change in your portfolio sort of before and after in terms of the percentage of sour crude you might be able to produce -- or refine, I'm sorry.

Let's give you the rational for why we put these 2 refineries with Olefins and Derivatives.

We thought about it long and hard and it's very clear that they fundamentally support the cracking capabilities which are so needed in O&D.

And to take them apart would have just increased the complexity enormously and that's not what we wanted.

These refineries are designed primarily as part of the petrochemical complexes.

They are not highly upgraded refineries like the rest of the refineries in our portfolio.

But, John, if we don't have the information on the details, we can certainly send them to Robert later.

Sure.

Let me just give you a general comment, Robert, on the capability of the refining system to deal with the crudes as they differ.

We are essentially trading in different crudes into the refineries all the time and optimizing on a cargo-by-cargo basis.

And just to give an example, if you think about something in the Midwest like Toledo in the United States, which in 1999 was really dealing with 100 percent sweet crude.

By the end of 2005 will be able to deal with 100 percent sour crude.

This is by virtue continuous incremental investments into the upgrading of those machines in order to allow that to happen.

This is a fairly dynamic process, and doesn't move, if you like, in sort of step changes.

We're doing this all the time in order to optimize the profitability of each refinery.

Appreciate that.

A quick follow-up --

Adam Sieminski at Deutsche Bank.

Good afternoon.

Good afternoon.

My question is about the U.K. downstream.

The results there were better than we had expected.

Particularly in this market, which historically I think has been a break-even type operation.

I was wondering if you could discuss the key factors responsible for the improvement and give us a thought or two on whether you think it's repeatable.

Thank you, Adam.

I'll ask John Manzoni to answer the question.

Let me help you.

I would start by saying the U.K. downstream is certainly improving, and those people in the U.K. will be able to see that we're investing in the retailing business in particular here in the U.K.

We are doing incremental investments into the refining.

So we are creating better offers for the customers, which is improving the business as we go forward.

It's not improving the business quite to the extent that the stock exchange announcement would have you believe on the basis that actually between, I think, the third quarter and the fourth quarter, we have moved cost distribution, which sit in the U.K. and used to sit in the U.K., because the U.K. is our corporate headquarters.

That has been distributed across the piece.

So actually the improvement in the U.K. slightly -- it would be nice if it were quite as good as the numbers would indicate, but it isn't.

The business continues to be improving but still very, very tough in the marketing side of the business many independent dealers are closing its -- this is still cheap gasoline across Europe when you take the tax out.

So we've got a tough environment.

And actually, what's happening in the stock exchange announcement are some other things changing.

Thank you.

Thank you.

Could I ask John Rigby of UBS.

John, good afternoon.

Good afternoon.

Sorry, just need to go back to the point about the dividend and the structure of the business.

As I understand it -- well, as I thought I understood it, the $20 per barrel level paid for your CapEx and paid a dividend and then you cleared the cash out in the form of share buybacks thereafter.

What we're seeing now is an increasing CapEx, an increase in underlying cost, yet you feel comfortable in increasing the dividends.

Does it really balance at $20 a barrel right now?

I doubt if it does on a year-to-year basis, but certainly over the cycle absolutely.

Because this is not a target.

It's just a piece of very shorthand analysis.

It's all about, I think, I come back to the underlying cash generative position of the Company, its future prospects, both in reserves, 18.5 billion, both critical resources, as well as exploration.

We don't have to scramble around to get new things.

These are things that we have and they will be developed, as well as the significant improvements we're seeing in bringing about in the customer facing businesses.

So over the cycle, I expect this certainly would.

But day-to-day, year-to-year, I doubt very much it will.

To ask that is not a significant factor.

Byron, you want to add?

Yes, I think it's important that people don't take the cash from operations in 2004 and assume that that's indicative of the cash generating capability in the environment that we see at the current time.

There was quite a run up in prices and margins over the course of the year.

Therefore, there's more than $2 billion worth of working capital affect that -- that one would add onto this in a steady state environment.

Okay.

Thank you.

Mark Iannotti of Merrill Lynch.

Mark, good afternoon.

Yes, Byron just answered the first question, which was on working capital.

If I can then just go back to petrochemicals.

It looks, John Manzoni, that you're giving us some better guidance now on Refining and Marketing in the U.K..

Can you help us with trying to value your olefins disposal by giving us some idea of both Grangemouth and Lavera cash flow so that we can add on to the cash flow we can see from the chart you've split out today on the olefins business.

The answer is not yet.

Obviously, we'll be talking about this very extensively as we bring together the final details of the holding company.

And at that time there will be quite sufficient, obviously, to value the holding entity.

Okay.

Thanks.

There will be quite a bit of information that will be available in my technical review in March, because we'll be laying out the businesses in their reconstructed fashion.

So you'll be able to gain some insights from that information.

I mean, is it fair to say that Grangemouth, for example, given that 219 adjusted number today in refining is making a decent contribution, it's not just a marketing contribution in U.K. refining.

Both Lavera and Grangemouth are making a very reasonable cash contribution.

Okay.

Thanks.

Can I go to Neil Perry of Morgan Stanley, please.

Neil, good afternoon.

Good afternoon. 2 questions.

You've mentioned several times now that you're interested in relationships in state and quasi state organizations.

Can you tell us what sort of type of opportunity you are talking about or what sort of scale?

I mean is this a bolt on discussion or is it something transformational you're thinking about.

Secondly, on your non-conventional comment.

You say you don't need to go into non-conventional upstream activity, but a lot of your competitors are going into it in heavy oil and gas to liquids.

Is there is a danger if you don't take part at this stage, they will establish the best positions and leave you being perceived as lacking the skills or the acreage or the relationship to build those businesses should you wish to do so in the future?

As to relationships with state and quasi state companies, of course our opportunity set, which we have under control today, allows us to grow the Company without any of these activities being successful.

But we are developing business based on our prior relationships in various parts of the Middle East as well as in the highly dense consumer countries such as China and India.

It would be wrong of me, I think, to give you any details of that until they actually come about.

But we have time and we have patience, and, indeed, these things take that to make sure that we don't take on business that actually may be beneficial to a country, but not to the Company.

As to non-conventionals, not everyone has to do the same thing.

We obviously are very much involved in gas to liquids.

We will continue to be.

That's a rather different matter than deep heavy oil, very, very ultra-heavy oil.

We are involved in that, but in the downstream in upgrading it.

So our choices are slightly different.

But those choices, I think, are the right choices for us, so that we keep the margins of the upstream business as high as possible.

We don't want to take on very high cost activity when we have lower cost activity to undertake ourselves.

Thank you.

Thank you, Neil.

Could I now take a question from William Farrah at W.H.

Reese & Company in the U.S.

Good afternoon, gentlemen, and thank you for your consideration.

I do think it is important just to make the comment from the institutional shareholder point of view how respectfully BP has included the cash dividend catchup in the fourth quarter.

That certainly is an important thing.

And it hasn't seemingly gotten the response, perhaps, that it should.

So certainly congratulations for that.

I am referring to the chart in this -- in the slides of shareholder distribution potential.

And there are case A, B, and C at various pricing levels suggesting different potential shareholder distributions in the future.

And the one striking change in pricing that doesn't occur seems to be in the refining forecast, either in case A, B, or C. Having made positive comments about improvement in the U.K. business, are you seeing anything that would perhaps give us reason for fundamental improvement in the longer-term refining profitability?

Thanks so much.

Thank you very much for your comments on the dividend.

They are much appreciated.

Secondly, that chart, of course, is just an example chart.

We were very reluctant to change the assumptions we put in the chart last year to keep consistency between the 2 charts.

What we actually think will happen to refining margins is we think they, perhaps, will not be quite as strong as they were in '04.

That was a pretty strong year.

But there's every reason to expect them to be supported, not least for complex upgraded refineries as long as demand for crude oil stays up, there's every indication that's the case because that brings on more heavy oil and will keep the light heavy spread open.

And this is very good for BP.

We would expect this year refining margins harden that in reality.

Thank you.

Thank you.

Could I go to Jonathan Wright, please, at Citigroup.

Jonathan, good afternoon.

Good afternoon.

Thanks.

Just had a question regarding upstream margins, especially in the U.S.

From what I can tell, it looks as though with the $13 oil price increase through the course of the year, the U.S. margins have been relatively flat.

Now clearly, there will be some higher costs from the Gulf of Mexico disruptions, as well as the new startups.

But are there any other costs that you'd highlight or tax pressures?

Or is there just a structural cost problem within the U.S.

Thank you.

I'd like Tony to answer the question.

Any other cost we would highlight is exploration write-off which was higher in the U.S. as we went through the last 2 quarters of the year, Jonathan, so I think that probably explains most of it.

Clearly, in terms of realizations, we continue to see some widening of the disk between the Rockies and Henry Hub in terms of gas.

I don't think we would point to any structural cost issues in the U.S.

Has there been -- do you incur sliding tax scales in some of your areas in the U.S., Alaska in particular, royalties I'm thinking of.

Not material.

All right.

Thank you.

Could I go to Neil McMahon at Bernstein.

Good afternoon, Neil.

Good afternoon.

John, I have a question on strategy for yourself, and then hopefully an operational question for Tony.

Just looking at your deep water percentage as you go out to 2010, as we look at the industry in '01 to, say, '03, there have been significant problems maybe not with yourselves, but with deepwater fields across the globe.

First of all, how do you feel about having so much of your portfolio within the deepwater when arguably we could say as an oil industry we don't fully understand the geology in the deepwater.

Secondly, how are the new fields coming along in the Gulf of Mexico that have just started up?

Then a question for Tony, just really an update on how the upstream up-time metrics did for 2004, both on the North Sea specifically and just around the globe in terms of your productive up-time.

Right.

Thank you very much, Neil.

I'll answer the first question, I'll ask Tony to also add to it.

We've spent a long time both looking at and developing the deepwater.

For us it's taken 3 particular technologies that I've indicated in any presentation.

First is actually to go to very deepwater, look at the scope and scale of very complex platforms in the very harsh conditions.

We really are learning a tremendous amount about that.

In less harsh conditions, the idea is to build them again and again broadly similarly.

And that is something I think we really do have is a piece of know how inside BP, it is know how of the technology as well.

Secondly, it's drilling, and we've been able to improve the drilling technology enormously, both in terms of accuracy and then the way in which wells are completed to get very high initial production rates.

Thirdly, of course, underpinning it all, these enormous advances in subsalt seismic technology, which get better and better every year.

I think we can see that from some of the complex fields that we're now developing.

So it's a suite of technologies, it's a lot of know how, because we've been doing it for a very, very long time.

This has been part of our purposeful strategy and we feel comfortable with this, again, given where we are.

But, Tony.

Well, let me just sort of answer what John said before I answer the specifics, Neil.

I think you can look at it in terms of our ability to see the reservoir, I think we made strides there particularly with subsalt seismic imaging.

We've been in the deep-water since the mid-80s.

We have a tremendous experience and knowledge of operating in the areas where we're operating.

Secondly, it's in drilling where we've seen extraordinary step changes in our ability to drill in the deepwater.

More than 50 percent reduction in the cost of penetration, for example, in Thunder Horse as we drilled up the development wells there.

Then thirdly in completions.

And it's good to report the completions that are now producing and Holstein at Mad Dog are performing very well and we have the completions in the ground in Thunder Horse, and we float oil to the surface there as well.

So I think those 3 technologies give us a lot of confidence.

I have to say personally I don't really see the geological challenges being really any greater than in any other sort of geological setting.

So I think we feel very comfortable about our ability to understand and execute in the deepwater and clearly have built a track record over what is almost 20 years now, frankly.

In terms of add projects, as you saw Holstein started up at the back end of last year.

Mad Dog started up a few weeks ago.

We continue to see reservoir reserve upside in both of those.

We drilled a well recently on the flank of Mad Dog that has come in significantly ahead of our expectations.

So lots of reserve upside there.

Thunder Horse is on track.

We would expect it to start up before the end of the year.

Atlantis is on track for the following year.

So all in all, things continue to look very good.

We continue to find new discoveries in both the deepwater, Gulf of Mexico and in Angola.

So overall we feel very confident about our ability to both find, execute, and produce in the deepwater.

Thank you, Tony.

Paschal at XM, good afternoon.

Good afternoon.

Just 3 questions, the first one is regarding the BP strategy indicator of 5 percent growth, that's '04 to 2008.

The difference from what we can infer from the slide called E&P production in CapEx, where the level of production from BP in 2008 is about 5 billion barrel per day, and when compared to the current level of production it points to a fact company growth rate of about 6 percent.

Which indicator is most -- are you the most compatible with?

The second question is regarding the previous presentation where you highlighted that you were expecting a downward trend in your CapEx.

As you weigh existing, so a period of big investment in [inaudible].

It seems to me that this CapEx now almost flat when you took at 2006 and even 2007.

Could you also elaborate for us on what is your outlook for CapEx in 2006.

And my last question is regarding previous presentation, again, where you stated the Group was now transitioning to a phase of internal generic growth in free cash flow from the high-grade opportunity set of the expanded group.

Now you are stating that you could use some excess free cash from material acquisition.

Could you elaborate us on that, please?

Let me answer these questions, Paschal, because I think there may be a slight misunderstanding.

We've used -- these are simply guidance indicators.

I don't think we want to get into decimal points and arguing about 1 percent here or there.

We simply said, look, we banked a lot of growth in production in the first year.

Obviously that means that the growth rate is different in the subsequent years.

So I've said it's going to be ahead, somewhat ahead of 5 percent.

I'm afraid that's about the best guidance we can give you.

But indeed, let's see how somewhat ahead it will be.

Secondly, CapEx, we went through this in the third quarter at great length.

And the underlying activity of the Company hasn't changed much with the single exception of when we gave a range in the past, we took it to the upper end of the range, because we have made so many discoveries that we've got to spend twice as much appraising them for the future.

So we have a rather embarrassment of riches.

We used to think that we could spend $250 million on appraisal, well, we've doubled it, plus we've added a bit more in exploration as well.

So the real trend in CapEx is the function of 2 things.

One is sector-specific inflation.

As I said a moment ago, the market for our mix of goods and services is going up at about 10 percent a year, but we're offsetting probably half of that from poppy [ph] technology, we do that 2 percent a year, roughly, year in, year out and 3 percent from the net of supply agreements that we have.

So we're seeing that come through.

The second thing is that we don't buy all our goods and services in dollars.

We buy them in mixed currencies, Euro, sterling, and things like that.

And unfortunately the dollar has weakened, which means that all those mix currencies have actually cost us more in dollars, at least for the time being.

So we say the good number to use is around $14 billion for '05 and '06, and let's see what it takes after that.

But this is the sort of pattern that we're in.

And it will vary depending on the exchange rate and the impact of this inflation.

If people build a lot of services, drilling rigs and so forth in this industry, then I would expect input prices to go down.

That comment on acquisitions was just to say that we didn't see any at the moment.

I think that was the main point I wanted to make.

Thank you.

Could we go to Gordon Gray at J.P.

Morgan, please.

Yes, Gordon Gray from J.P. Morgan.

Can you hear me?

Yes, Gordon, we can.

Gordon, please go ahead, if you're there.

Hello.

Hello.

Can you hear me?

Yes, we can.

Sorry.

It was just a small question about whether you can quantify a little bit more the affects year-on-year of the volumes of disposals and of those nonrecurring stoppages you had during 2004.

Tony.

The disposals was of the order of 20,000 barrels a day.

And the nonrecurring stoppages averaged through the year, which was a combination of Hurricane Ivan and Temsah in Egypt was around 60,000 barrels a day.

60.

Okay.

Thank you very much.

In particular in the fourth quarter, those 2 combined to impact production by around 88,000 barrels a day.

Thanks very much.

Thank you.

Can we go to Jason Kenny at ING, please.

Good afternoon, gentlemen.

I had a quick question between the production growth going forward 5 percent and LNG moving from 10 percent of the 2004 figure to 15 percent at 2010, and then trying to relate that to the supply, LNG supply 20 percent annual growth at 2008.

I'm assuming that you're going to be taking a lot of trading of other people's LNG towards the end of the decade, unless you find significant new volumes elsewhere.

Gives me a good chance to ask Vivienne to answer that question.

Vivienne.

Jason, thank you for the question.

It's certainly our intention to develop our traded LNG business on the back of our equity business.

So the situation we've had this year, we've had a gross of equity gas into plant by about 11 percent and we've been able to capture more market than that.

And this is part of our long-term strategy of developing markets ahead of supply.

That does not, of course, let Tony off the hook in terms of looking for more gas.

This year we've sanctioned Tangguh and that will be delivering end of 2008 and 2009.

Great.

Thank you, Vivienne.

Can we go to John Rigby for a second go.

John.

Yeah, hi.

This was on the downstream.

I've noticed in the past 2 quarters, refining earnings have probably outperformed your global indicator margins, as I think you've just performed.

And I guess a portion of that is to do with the light heavy spreads and the complexity of your refineries.

Are you able to give an indication of how sticky you think [inaudible] earnings improvement is or do you think it will all be given up as markets to put in quotes normalized over time?

You broke up, but John Manzoni, you have the question?

John Manzoni.

How sticky is the improvement that we've seen in the last couple of quarters I think was the question, John.

Yes, it was.

The answer to the question is that, it's reflective, of course, of the light-heavy spread and the propensity of our refining kit to be able to process that in a profitable way, and to that extent as John has already said, the extent to which demand patents of the world crawl forward increasingly heavy oil or the marginal barrel is increasingly heavy then that will continue.

But it's not only that.

It's also we -- as we've said sort of optimized the supply into those refineries through our trading arm.

That is continuing to go, frankly, from strength to strength.

And that is, I believe, those things are pretty sustainable going forward.

One should never bank on it because, of course, it depends on what the crude is available and the market conditions, but we've been seeing and have consistently seen better and better supply optimization into the refineries, which I think should be sustainable.

In addition, as I said before, given the example of Toledo, we do continuously upgrade the refineries to be able to take heavier and sour crude.

So all of those things, I believe, we should be aiming to be sustainable in the future.

Not at levels that we saw in 2004, but nonetheless a continuous improvement story there.

Is it right you're adding more conversion capacity into Europe as well?

We are.

Incrementally we are.

And into the future we see -- as we see opportunities and some are on the sort of drawing board, then we shall do that in the future as well, yes.

Yes, we have quite a lot on the drawing board, John.

We need to pick the right combination and timing of them all so that we don't overdo it.

Right.

That's what we're presently doing at the moment, both in Europe and the United States.

The United States very probable that we will be investing to take a further heavy dot in the northern tier refineries.

Thank you.

Jack Moore of Vanguard in the U.S.

Good morning.

Good morning.

Thanks for taking my question.

Most of my questions have been answered.

But kind of a big picture thing, I was wondering if you could talk about how your CapEx in the coming years will differ from that that you expect in '05 relative to allocation and magnitude.

Jack, if I could answer this question in the way of saying if all other things are equal, what would happen?

Because the exchange rate, given that we spend in mixed currencies and the vagaries of sector-specific inflation can catch you out.

But if you were to look at it and say, well, actually what are we doing in terms of growth, what the right level of input do we need for growth?

This 14 billion number is about right.

It will vary, of course, depending on all these other things that come about.

But equally, inflation is high when the price of oil is high.

The weaker dollar does in a very rough way probably also supports our higher oil prices because it's cheaper for the world to buy.

So these things are not just 1 sided, they are 2 sided.

Revenues will work.

Do you see any major shift in prioritizing allocation to different business sectors, aside from assuming the dollar is constant or taking that out of it.

Carry on with the broad allocation of things.

There are things to do as we've just talked about in terms of refinery upgrading.

Equally there's a lot of things to do to bring on both the reserves and the resources that will be converted into reserves over the medium and long-term in the E&P sector.

So that's roughly where we are.

Of course, we will not be investing in Olefins and Derivatives, as soon as we get to sell it.

And so that's a slightly different change in the mix.

That's about $500 million of capital at the moment.

Great.

Thanks very much.

Neil McMahon of Bernstein.

A second go, Neil.

Just on the previous question, just to Tony on the uptime question versus this year versus -- sorry 2004 versus 2003 or was the production uptime in the North Sea and through the rest of the world for the upstream business.

Thanks, Neil, sorry I didn't get to you previously.

We overlooked you.

In the North Sea we were ahead just over 2 percent year-on-year, which was a very strong performance given that we had a very large planned shutdown program there.

So that was pleasing.

If you look at the actual result, it was pretty well flat given primarily the impacts of Hurricane Ivan and Temsah, if you put those aside then we were ahead by about 0.5 percent year-on-year.

But certainly in terms of the existing profit centers, you will recall a year ago we said we were aiming to drive operating efficiency there up by 1 percent over a couple of years.

We delivered more than half of that in the first year.

Could you give just the absolute levels, please?

Level was 87.5, 88 percent.

Great.

Thanks.

It was up from 82 percent to above 84 percent.

Great.

Thank you very much.

Thank you, Neil.

A bit more to go there.

And I'm sure we'll get there.

There's one remaining question now on the web, which is about how we measure leverage and just in capital or cash flow.

The answer is we actually look at leverage in a whole variety of ways, but we tend to shorthand it around a broad range of capital measures for the purposes of these discussions.

But we look at this very, very carefully, both in the nature of stress testing and different types of metrics and where if you think about this thing in a multiple different ways before we actually make real decisions.

So thank you, Mr. Lafluer [ph] for that question.

Ladies and gentlemen that concludes all the questions.

Thank you very much for joining us this afternoon.

Again, I want to repeat how we welcome you being here and how we very much look forward to seeing so many of you face-to-face in the coming few months.

Thank you very much for joining us and good afternoon.