英國石油 (BP) 2006 Q2 法說會逐字稿

Welcome to the BP presentation to the financial community conference call.

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

Please go ahead, sir.

Welcome to BP's second-quarter 2006 conference call.

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

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

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

Those of you on our e-mail distribution list should already have received them.

If you would like to be placed on the list for future releases, please do let us know.

Second, I would like to draw your attention to this slide.

We may make forward-looking statements which were 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 Browne, our Group Chief Executive.

Good afternoon to all of you in Europe and good morning to all of those in the U.S.

With me today are Byron Grote, Vivienne Cox, Tony Hayward, John Manzoni, David Allen, Iain Conn and Andy Inglis.

As usual, Byron and I will do the formal presentations but the team is here to answer your questions once we have finished.

This morning, we were delighted to report our 2Q and first-half results.

Many of the financial results are records for BP.

These have clearly been boosted by the strong trading environment.

For the first-half of '06, replacement cost profit is $11.4 billion, up 9% over '05.

This is equivalent to $0.56 a share, up 14% over '05, showing the additional benefit of buybacks.

A quarterly dividend to be paid in September of $0.09825 per share, up 10% over the same quarter last year.

Post-tax operating cash flow of $18.1 billion, up 12% over the first half of '05.

Divestment proceeds of $2.6 billion, in line with our strategy of continuously high grading our portfolio.

Share buybacks of $8.5 billion in the first half, reducing average shares outstanding by 5% year on year.

And a strong financial condition with gearing at 15% below our target range of 20 to 30%.

We have also achieved a number of major milestones in the first half.

These include first oil from the Baku-Tbilisi-Ceyhan pipeline some 12 years after BP signed the agreement to develop Caspian oil and gas resources.

First gas from In Amenas in Algeria.

Continued exploration success with a new discovery in Angola Block 31.

Recommissioning of the Texas City refinery at the end of March.

Sale of Shenzi and some shallow-water properties in the Gulf of Mexico.

Announcement of our intention to sell the Coryton Refinery in the UK.

Startup of operations in the Guangdong LNG terminal in China, in which BP has a 30% interest.

Announcement to set up the biofuels business and the BP Energy Biosciences Institute.

Announcements of alliances with Clipper Windpower and with GE.

And participation in the Rosneft IPO.

First and foremost, we are committed to safety, integrity and the environment.

We're redoubling our efforts in this sphere, notably in North America and I will come back to that later.

We remain fully committed to the disciplined pursuit of our strategy, in the way we manage capital and divest noncore assets, in the way we plan the business and most important of all, in the way we handle additional cash flow, resulting from higher prices, returning it to shareholders after investing for the future.

Our strategy has always incorporated active management of our portfolio.

We're selling assets in the current high price environment and the proceeds are available for equity repurchase.

This is the counterpart to buying assets with equity, notably Amoco and Arco, which we undertook near the low point of the oil price cycle.

Byron will now take us through the key aspects of the results.

So Byron, over to you.

Thank you, John, and good day to those joining this call.

John will cover longer-term price and margin trends in more detail so I will focus on the second quarter.

Sustained growth in oil prices increased our average realization to $66 per barrel, 38% higher than in 2Q '05.

By contrast, our second-quarter gas realization of $4.44 per thousand cubic feet was nearly flat compared to a year ago.

Taking oil and gas together, our overall hydrocarbon realization was up 23%.

Our second-quarter industry indicator refining margin of around $12.60 per barrel, was 50% higher than a year earlier and slightly above the hurricane influence peak reached in the third quarter of 2005.

These market conditions contributed to the record quarterly and half-year financial results we reported this morning.

Our second-quarter replacement cost profit of $6.1 billion was 23% higher than in the second quarter of 2005.

The per share result was up 29%, reflecting the benefit of share buybacks.

Our profit including inventory gains and losses was $7.3 billion, up 30% in absolute terms or 37% per share.

These figures include nonoperating items.

Our underlying result, excluding these items, is also a record for the Company.

We generated around $9 billion of operating cash flow in the quarter, up 36% in absolute terms or 43% per share.

The $0.09825 per share dividend announced today is 10% higher than a year ago.

The Sterling dividend is up around 4% year on year, reflecting the weaker dollar.

The first-half results shown at the bottom of page, which John reviewed, are also up year on year as we captured the benefit of the stronger environment.

Turning now to the segments, the Exploration and Production result increased 33% to $7.8 billion.

The 2Q '06 result included around $480 million of gains in respect of divestments and the IFRS marked to market accounting of embedded derivatives.

Excluding these non operating items, the E&P result was 12% higher than in 2Q '05, reflecting higher oil prices partially offset by higher costs.

Production in the quarter was broadly flat with 2Q '05 after adjusting for the impact of divestments and the change in contractual arrangements in Venezuela.

We expect full-year production to be consistent with prior guidance, adjusting for portfolio effects and price-related impacts..

For 2006 as a whole, we expect these impacts to be around 65,000 barrels of oil equivalent per day for divestments announced to-date plus around 45,000 barrels per day for the impact of the higher pricing environment on our production sharing contracts.

TNK-BP contributed nearly $650 million to our 2Q '06 result, about the same as last year.

In refining and marketing, we reported a pretax profit of $1.9 billion in the second quarter, up from $1.3 billion a year earlier.

The results in both periods included significant nonoperating items, mainly charges related to Texas City.

Excluding nonoperating items, our underlying result was a record $2.3 billion.

Compared with the second quarter of 2005, our results benefited from stronger refining margins and supply optimization performance.

This was partially offset by reduced operations at Texas City and weaker overall marketing margins.

Our gas power and renewables result more than doubled from around $200 million in the second quarter of last year to around $450 million in 2Q '06.

This reflects higher contributions from marketing and trading and from NGLs, mainly in North America, partly offset by greater IFRS fair value accounting charges.

Nonoperated items were similar in both quarters and mainly relate to gains on embedded derivatives.

In Other Business and Corporate, or OB&C we reported a second-quarter charge of around $200 million pretax.

This remains consistent with the expected range of annual charges that I indicated in February.

Our second-quarter effective tax rate was 36%.

This does not include the impact of the increase in the UK North Sea tax rate, which was enacted last week.

As I indicated in February, this change will have two elements.

First, a non-cash charge related to deferred tax balances from prior years; and second, a current tax increase to reflect the 2006 impact of the higher tax rate, which is retroactive to the start of the year.

Putting both elements together, we would expect the group effective tax rate to spike to around 45% in the third quarter, reflecting the retroactive aspects of the change.

We continue to expect our full-year group effective tax rate to average around 39% in 2006, including the onetime deferred tax charge.

Turning now from earnings to cash, during the first half of 2006, sources of cash have exceeded $20 billion, $18 billion from operations and over $2 billion from disposals.

We used this cash inflow to fund around $7 billion of cash expenditures and nearly $4 billion of dividends, both up from the first half of last year.

In addition, we more than doubled our share buyback program.

Our second-quarter net debt ratio declined 15%, reflecting the quarter's strong cash flow.

Consistent with our previous guidance, it remains our intention to return gearing to within the target band over time.

Share distributions in the first half exceeded $12 billion.

This continues a pattern of progressive increases over the past several years.

Share buybacks are continuing in 3Q, with purchases during the closed period totaling $1.5 billion.

Similar to the last two years, we will suspend buybacks during the thirty-day period prior to September 20, when we issued the final tranche of shares to Alpha/Access-Renova with respect to the TNK-BP transaction.

With our low gearing and strong cash generation, we're well-positioned for substantial further share buybacks, in line with our financial framework and strategic intent.

That concludes my presentation of results.

Now, back to John.

Thanks, Byron.

Let me start with the trading environment.

The average oil price in the first half of the year strengthened to over $65 a barrel, up 20% from the '05 average of over $54.

The 2Q price averaged around $70 a barrel, up 13% from the 1Q average.

While the oil price remains strong, it's worth keeping in mind that this is relatively recent phenomenon.

The oil price has been over $40 for just over two years, over $50 for just over a year and above $60 for only the last six months.

The oil price increase has been underpinned by continued demand growth, albeit at a lower level than witnessed in '04.

OPEC's spare capacity continues to be relatively tight, inventories are robust up and there's nervousness about the ensuing U.S. hurricane season.

Anxieties stemming from the situation in the Middle East, parts of Latin America and Nigeria continue to add a premium to the oil price, the shift to a Contango market structure, where forward oil prices are above spot prices, has encouraged market participants to increase the level of precautionary inventories.

As I have said before, we see prices in the medium term remaining above $40 a barrel.

In the longer term, market fundamentals could reassert themselves and prices could move lower.

Turning to gas prices, in the U.S., the average Henry Hub gas price in the first half of the year was around $7 MMBtu, down 40% from 4Q '05 and 18% below the '05 average.

The 2Q '06 price was 15% lower than 1Q '06.

Since January this year, the U.S. gas markets have shifted from a period of concerns about supply to one of excess supply and high levels of gas storage.

Prices have fallen from above distillate parities to below resid parity in a matter months.

High prices, both before the hurricanes and after, have reduced demand and last year's mild winter furthered weakened prices.

U.S. gas consumption continues to fall by about 1% per year on average.

In the UK, gas prices surged to over $27 MMBtu in '05, and in March to almost $33 because of a cold weather snap and because the rough storage facility was down.

Prices have since declined but futures prices for the winter are above Henry Hub, reflecting concerns over winter availability.

The refining margin for the first half of the year was around $9.50 a barrel, higher than last year's average of $8.50 despite a relatively weak first quarter.

Margins have been particularly strong in the U.S., buoyed by the driving season and the switch from MTBE to ethanol for reformulated gasoline.

The switch to ultra-low sulfur diesel is also underway in the U.S. and this transition is likely to support refining margins beyond the usual seasonal gasoline lead peak.

Like heavy crude differentials remain wide by historic standards.

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

Demand growth is likely to be greater than capacity additions for awhile and we expect the global indicator margins to remain somewhat above $5 a barrel.

We continue to experience significant cost inflation across the sector.

In the upstream particularly, we see cost inflation in both capital goods and operating costs on the back of increased activity induced by rising oil prices.

This pattern is consistent with that seen in the previous upward parts of oil price cycle.

If you look back over the past 30 years, sector cost inflation seems to have been linked to changes in oil prices.

Peak cost inflation has lagged the peak year on year increase in oil price by about a year to 18 months.

Capital costs are increasing at a higher rate than operating costs, as they contain a higher weighting of costs specific to the oil and gas sector.

The highest inflation is in the cost of drilling rigs.

For example, the maximum dayrate for ultradeep water drilling rigs has increased from around $200,000 a day towards the middle of '04 to around $500,000 a day currently.

We are continuing to offset some of the cost inflation by supply chain management and technology.

Our North American gas business is a good example of this.

In '05, we contracted for 27 rig years of activity at around 20% below today's market rate.

Overall, sector specific inflation is likely to increase capital costs for the group this year by at least $0.5 billion over the estimates we made at the start of the year.

We continue to accelerate our investment in safety and operational integrity, notably in the U.S.

For example, in Alaska, we have responded to the lessons learned from the recent spill by accelerating picking operations and by renewing any infield transit lines as necessary.

Turning now to operations and beginning with E&P, progress in '06 is good.

In Azerbaijan, West Azeri achieved first export ahead of schedule in January and BTC is now fully operational.

Our Cannon Ball gas platform in Trinidad was brought on stream in March and is currently producing around 800 million feet a day from three wells.

And in Egypt, the Temsah Northwest redevelopment commenced production in early May.

We completed the first lifting of crude from the Ceyhan marine terminal in June.

Also in June, in Algeria, we achieved first export gas from In Amenas.

Wamsutter continues to grow production as part of the development program sanctioned in '05.

Turning to Thunder Horse, offshore repair work is proceeding and we anticipate having approval to introduce hydrocarbons to the facilities this quarter.

Recent work has focused on testing the subsea equipment in readiness for startup.

However, during a routine hydrotest, we experienced two leaks in the subsea manifold.

We're taking a precautionary approach and are fully investigating the events before starting up the platform.

Subject to a satisfactory outcome of these investigations, our current plan anticipates replacing just the damaged subsea equipment.

This would enable, subject to weather conditions of course, a startup of production in early '07.

All other projects scheduled for completion this year are on track.

Despite the delay in Thunder Horse, our guidance for '06 production remains unchanged after making allowance for the impact of divestments and the reduction in entitlements under production sharing contracts due to high oil prices.

Looking ahead to the next three years where we have another 15 major projects under development, eight of which are on track to startup next year.

Beyond '09, we currently see a further 26 major projects, which expect to develop about 8 billion barrels of oil equivalent, underpinning our view of continued renewal in the next decade.

So to summarize the upstream progress, major projects remain on track to underpin production growth through 2010.

Between now and the end of 2010, we expect to move from nonproven resources to proved reserves a further 11 billion barrels of oil equivalent, which will underpin continued renewal beyond this decade.

In addition, we continue to see significant potential in our exploration portfolio and we're confident that our continued track record of exploration success will deliver on a risked basis more than $10 billion of oil equivalent from our exploration portfolio.

We also continue to add material new exploration positions to the portfolio with major success in the first half of '06 in the Indus Cone of Pakistan and the Central Deepwater Gulf of Mexico.

Finally, we will continue our strategy of active portfolio management, divesting opportunities that don't compete in our portfolio.

In '06 to date, excluding disposals by TNK-BP we've realized $3.8 million of gross proceeds.

In the downstream, the Texas City refinery commenced operations at the end of 1Q and has achieved the initial target of 200,000 barrels a day of crude throughput.

The site started off smoothly and safely and is producing gasoline, diesel and chemical products for the U.S. market.

The operation to date has been very satisfactory, a great testament to the rigor shown by our people during the extensive inspection programs and startup effort.

Texas City incurred a loss of about $0.6 billion in the first half of this year.

At current trading conditions, it's near cash break even.

Our focus is to continue recommissioning the site safely and to bring it back on stream in a phased manner.

And our view remains that the full financial potential of the site is not expected to be realized until '07.

We are assuring that all the lessons learned from Texas City are applied across all manufacturing sites by implementing a six-point safety plan which embodies those lessons.

In addition, we are upgrading our process safety management system.

In spite of already being above average on maintenance spend per unit of capacity, we are increasing the amount of money spent annually on U.S. refinery integrity by around 15%.

In February, we outlined the five-point plan to help you track our progress over the next few years and I'd like to give you an early indication of how we're doing.

Our goal remains to grow sustainable free cash flow and return it to our shareholders after investing for the future.

Apart from spending on safety, integrity and the environment, everything else is in service of this overarching goal.

The first component of the five-point plan is to grow production at an average rate of 4% per annum from '05 to '10 on the assumption of $40 oil prices and with the portfolio of assets that we had at the end of '05.

We remain on track to deliver this production growth after adjusting for price and portfolio effects.

As oil prices have continued to rise, the adjustments for price effects are growing.

On the basis of divestments made to date, and assuming that oil prices remain at around $70 a barrel, in '06, these adjustments are expected to be around 110,000 barrels of oil equivalent a day.

Rising oil prices are also creating further inflationary pressures in our industry, on both capital and operating costs, as I have previously discussed.

We're seeing upward pressure on our capital costs for '06.

As a result of this higher-sector specific inflation, we now expect our '06 organic capital spending to be between 15.5 and $16 billion.

However, we will continue to maintain our capital discipline and the increase in capital cost is expected to be more than offset by higher proceeds from divestments.

We see significant value in divesting noncore upstream assets in this high price environment, for which we are receiving some strong prices.

The net effect is to increase free cash flow and reduce our equity base.

It should also high-grade the asset base, thereby supporting our objective to increase returns relative to the peer group.

If we continue the current pace of divestments and even excluding our share of divestments from TNK-BP, we expect to achieve more than double our targeted $3 billion divestment program by the end of '06.

Finally, high prices have meant higher taxes.

In the first half of '06, our taxes and royalties totaled nearly $10 billion, including over $1.5 billion in the UK and nearly $4 billion in the U.S.

These figures don't include the substantial amounts paid by equity affiliates such as TNK-BP or profit oil paid to governments under production sharing contracts.

We showed you this chart in February, here updated to include distributions made in 1H '06.

So far this year, we've distributed $12.3 billion, including buybacks and dividends.

This is up by some 59% on the first half of '05, a good start.

We have increased the dividend by 10% per share, in line with our policy.

Our ability to increase per share dividends is enhanced as the number of shares outstanding shrinks as a result of share buybacks.

Other per share measures of value are also enhanced, an important income outcome of our strategy to grow and distribute sustainable free cash flow and our primary emphasis on shareholder value growth.

To summarize, first and foremost, we're committed to safety, integrity and the environment.

We are redoubling our efforts in this sphere, notably in North America.

In supply and trading, we're engaging an independent party to review the compliance systems in our North American operations and we will share our findings with the regulators.

In Alaska and in refining, I have already mentioned the specific actions we're taking.

In addition, we are further reinforcing our internal systems of control.

In recognition of the importance of the U.S. to the group, we are appointing a new advisory board with external members for BP America, our 100% owned holding company in the U.S.

We're doing all of this while achieving the targets for growth we outlined.

We are improving quality and we're maintaining our financial strength while divesting noncore assets in the current high oil price environment.

We have strong per share growth in earnings as well as dividends.

We are distributing excess free cash flows to shareholders in this strong price environment.

We continue to search for and acquire new business opportunities, not only in the upstream but also in new areas as evidenced by our investments in alternative energies and biofuels, both of which have an exciting future ahead.

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

Now, ladies and gentlemen, we would be happy to take your questions.

(OPERATOR INSTRUCTIONS).

Again, good afternoon, ladies and gentlemen.

I just thought before we would start the Q&A, I wanted to say something about me, if I may.

I have been reading and listening to the speculation about my future and I was both astonished and shocked by it.

In particular, I was especially concerned that there made be an inference drawn that BP hadn't got a clear grip on its process for succession to the position of CEO.

So I want to be crystal clear about the situation, if I may.

As I have said several times publicly in recent months, I will be retiring in 2008.

Our Chairman, Peter Sutherland and I, have discussed this and agreed it between ourselves and with the board and that agreement is that I will leave BP at the end of 2008.

This is a long time ahead, two and a half years, and this is my decision.

Let me add that even if I were asked to stay beyond 2008, I am going to decline.

I also wanted to make it clear based on the speculations I've read that there is absolutely no rift between Peter Sutherland and me.

We have a very long-standing relationship based on a deep mutual respect.

As I have also made clear, the process of selecting a successor, which was set out by the Board of Directors last year, is something I wholly support.

I think it's a very good process.

The board is seeking my input and I'm giving it to them, and that will I believe, culminate in a very good conclusion at the appropriate time.

So I want to repeat that I will be retiring for BP, though I may say not from work, because I don't approve of retirement;

I will certainly be working, think of it as a job change in the end of 2008.

So, ladies and gentlemen, I hope that clarifies the situation and I'd like to ask for the first question from Neil McMahon.

Neil, good afternoon.

Good afternoon.

No questions here about your retiring.

Two things, one is on Texas City.

Could you go through what you expect the utilization of the refinery to be in the third quarter and the fourth quarter, given the relatively tight nature of U.S. refining?

And secondly maybe a question for Andy, as he is on the call, related to how you are displaying the development projects going forward.

There are a few that have moved into 2007 and really I suppose helping us plan how we project your production profile into the year forward.

Is there any way or any suggestions you could give us in terms of the timing of the volumes coming through in terms of '07 and which projects potentially could through [weller] or whatever circumstances move into '08 or basically when in the year you would expect them to come through just to help with forward production estimates?

Thank you.

Thank you, Neil.

Let me ask it would need to be John Manzoni to answer the question on Texas City and when John is finished, Andy will take on the question of the development project timetable.

John?

Neil, if I may then, thanks for the question on Texas City.

The first thing that I'm going to say on Texas City is that the most important thing that we can do in that plant is to bring it back safely, to bring it back to full capacity in a safe manner.

And up to now, we're currently at just over 200,000 barrels a day and it has been, with the exception of the incident over this weekend, this has been brought back safely and very well and the team there is doing a tremendous job doing that.

That means that it is sitting today roughly, roughly at between 50 and 60% utilization as counted in the industry.

I think it's also true to say that the first half of this year has been in a financial sense, will be the period which Texas City has been down the most.

So we're now building back from what I think has been the low point in the financial contribution of Texas City going forward.

It's very difficult to predict exactly what the utilization rates will be in the third and the fourth quarter for a number of reasons.

First because it's not -- as we progressively bring back units, we can't dictate what the timing of those units coming back on stream is exactly going to be, simply because we are doing very, very rigorous inspections of them each time we bring on a unit.

What I can say is that we will be progressively bringing this machine back from here.

From 200, it will gradually build back, although I do not expect us to see the full financial contribution of it until sometime in the year 2007.

So I think that gives you a frame, Neil, for how to think about this.

We are through the worst, we progressively build back from here and I would anticipate that the full contribution of Texas City will not be seen until 2007.

Yes, thanks, Neil.

I think on the project side, clearly in John's update, he has provided some more color to the projects, and in particular I think the length of the portfolio in terms of 2010 and beyond and I think that is an important piece of new news as we talked about the strength of the portfolio.

In terms of the specific question around 2007, I think the key issues on your mind are the startup of the large projects.

Clearly on everyone's mind is Thunder Horse and when is that going to startup.

As John indicated, the progress on the PDQ has been good.

We have it ready and is awaiting the introduction of hydrocarbons and that could well start with back gas this quarter.

Recent activities folks on testing the subsea equipment to ensure it has integrity before we open the wells.

And the two leaks we discovered on the manifold we're taking quite seriously and are taking a precautionary approach to ensure that we've fully investigated the leaks before we startup.

That work is ongoing at the moment.

We have in fact retrieved the manifold just in the last week.

And clearly depending on the results of that investigation, we would just anticipate replacing the damaged manifold.

But clearly we need to await the full results of the investigation.

The second big startup in '07 is Atlantis.

That again, the platform itself is in great shape.

It's ready to sale away for installation.

On the manifolds, we're taking the same precautionary approach as on Thunder Horse and as it's not as far along in terms of the installation, we can make some modifications.

The likely effect of that is to move the startup from around year end into the first quarter.

Although of course, as you are well aware in the Gulf of Mexico, you have to take account of the weather patterns and there are leap currents currently sitting in the Atlantis location and the whole process then of moving the platform will be dependent on that.

The other big startup in '07 will be Greater Plutonio.

That's moving ahead well and that is anticipated startup in the first half.

And the second project is nonoperated in Angola, which will be Rosa, and that will be to the back end.

So hopefully that has given you a little bit of color I think around the big projects that are going to impact '07 and clearly there are other projects there which are smaller.

The King subsea pump, which again will be end '07 and the ongoing program in North America around the growth in Wamsutter but also the growth on the San Juan coalbed methane, which will have a progressive impact through the year.

Neil, if I may just add, I think none of us are happy about the delay in Thunder Horse but I think it's reminded us that there is much to learn about these ultradeep water developments.

The situation on our hands here, which Andy has described very well and I went through, is something which probably except for these extraordinary conditions on the frontier that we're working in, would not have occurred.

So we're learning a lot and I think this learning, the good side of this delay, is the learning is important.

And I believe it will be very important for the future.

And I think if I ask Tony just how important for the future?

I think as everyone knows, we have made a number of discoveries over the course of the last three or four years in the deepwater.

We have three projects currently under appraisal in the deepwater, Bonsai, [Kublabelz] and Puma, all in the Miocene.

We also believe that there is significant potential in the Paleogene reservoir horizon.

So everything that we're learning here is creating new optionality for BP because we are learning how to engineer, as John says at a pressure and temperature beyond that which anyone in the industry has achieved to date, which will have direct applicability to the slate of projects that are now coming down the pipe.

Great thank you, Tony.

Could I go to Nicki Decker of Bear Stearns in the U.S. Nicki.

Thank you, Lord Browne.

Good afternoon, everybody.

My question is regarding Texas City again.

I am surprised on your comment that Texas City is operating at near cash break even now.

Is that a function of the extra cost that you have incurred or is the product yield below normal?

Maybe you could talk about what your product yield is?

And secondly on spending and safety in operations, how so we look at that?

Is that to be expensed or is that part of your new CapEx guidance?

Thank you.

Let me just answer the second part.

It's basically mostly expensed, Nicki, and I think it is something which is very, very important for us to do.

I think and if you might say the large-scale of the numbers before you after tax, these are not huge amounts of change.

They are critical, however, parts of primarily an expense budget, excluding some of the capital additions that we're making in Texas City and actually will continue to make as we retool the refineries to make them fit for the future over a run of years.

Byron?

Nicki, before John elaborates, just as a rough rule of thumb, about 75% of the expenditures that we are targeting would be expensed and about 25% of them would be capitalized.

Just rough rule of thumb to utilize.

So, John over to you -- why near cash break even?

A bit more on the Texas City situation, Nicki.

Essentially you should think about it is we have a relatively complex 200,000 barrel a day refinery up and running today.

That is what we have.

The issue is that Texas City has a capacity of about 400 to 430,000 barrels a day.

So we have essentially it running a sweet crude at about half capacity.

And the overhead structure in that plant is such that at that configuration, it is running today at about cash break even.

So what happens next is that we progressively bring on units which either create further upgraded products and that's going to happen I hope in the relatively near-term.

But the big step from 200 to 250 up to 400-ish would come when we bring on the second train for crude input, which will also allow us to put heavy and sour crude in, which will then take the refinery to full financial potential and that is essentially what is happening.

So we have it a sweet crude relatively complex refinery and it's carrying overheads for a much bigger refinery and we will be progressively bringing on units which will improve the situation, I think, I hope from here for the rest of this year.

But as I have said, I would anticipate not the full financial potential of the refinery until sometime into 2007.

Great, thank you, Nicki.

Thank you, John.

The third question is on the Web.

It's from Irene Himona of Exane BNP Paribas in London.

A two-part question.

You now expect $70 oil prices this year, which exceeds your [KC] for the Shell distribution potential?

Do you still expect a reversion to $40 a barrel should we expect you to restate KC for a higher price, and strategically what changes if your view of oil prices is more positive?

And secondly you included in your nonoperating items the gains on losses from gas contract derivatives.

While the numbers are positive this quarter, they were materially negative last year.

Are these contracts not an integral part of running the gas business and why would you treat them as nonoperating?

I would like to ask Byron to answer these questions and I will come back and talk about oil prices.

Irene, with respect to the first question, the KC is actually a pretty good representation for what we have seen the first half of the year, remembering that KC was developed with a $60 oil price and a $9.50 Henry Hub gas price.

Oil price has been a bit higher than that over the first six months but gas prices have been lower.

So net net, it's a good representation of the environment.

And if you look at our distribution, we are on track to distribute through share buybacks according to the chart that was outlined.

With respect to the second question, why do we treat these gas contracts in the North Sea as embedded derivatives as a nonoperating item, ultimately the designation of nonoperating is to help you as analysts and investors to better understand the current operations of the Company.

These are extremely volatile items because what they do is remark the forward curves over eight North Sea gas contracts out to towards the end of the next decade.

So these are hundreds of millions of dollars of revaluation occurring each quarter.

We don't think that they are particularly helpful in understanding the current running of the business and, therefore, we have segmented them out for your assistance.

Can I just add something on oil prices.

As I've said, again, just a moment ago, we do think medium-term oil prices will stay average about $40 a barrel.

And really defining the medium term is beyond precise definition.

Put it like this, it's going to be several years we expect.

That doesn't mean to say they will be limited to $40 but I think if you take the grand look, if you will, of the cycles of oil prices, it's not unlikely that after a period of time with all these people doing all this work of expanding production and the possibility of substitution for oil products through other means, that something will happen with the dynamics of oil prices.

We don't think it will come down as low as it did in the '90s because the embedded cost of the marginal production in OPEC, which has to do with the cost of production and also the taxes needed to support the large populations in those countries, is likely to keep people, keep the price above the lows we saw in the past.

We may well restate the KC for a higher price but at the moment I think we're very satisfied with this illustration and they are by the way by and large numbers and illustrative at $60 a barrel.

It is of course interesting to note that as the price goes up, we are not getting dollar for dollar dropping down to the bottom line because taxes are nonlinear.

We get higher taxes with higher prices.

And of course higher prices also bring on additional inflation in the supply chain and so the additional rent which is being earned is being heavily shared with governments and with supplies.

Can we take the next question, please, which is from Neil Perry at Morgan Stanley in the UK?

Neil, good afternoon.

I have two questions.

One is actually related to the buyback as well.

I mean if you just look shorter term, you've got 15% gearing now at $75 oil price and you've got an accelerating disposal program.

It's going to put an awful lot of pressure on you to get back to 20% gearing.

Are you prepared to use different methods of cash return under current conditions because you were emphatic that you wanted to maintain that financial framework at 20 to 30%?

And then a second question which I suspect is for Tony.

Perhaps, could you just elaborate a little bit more on what unit operating costs have done this year, where they are and numerically where that trend is going.

I appreciate it's upwards, but could you just put some numbers around it, where you expect operating costs to be during the course of that [same] year.

Great, thank you, Neil.

Why don't I ask Tony to answer his part of the question first and I'll come back on buybacks.

Yes, as you said and John alluded to, Neil, we are seeing significant inflationary pressure in the industry.

I would differentiate between capital costs, which certainly for our mix of capital investment, we're seeing rise probably 12 to 13%.

We are offsetting probably 2 to 3%, so the net is around 10.

In operating costs, the inflation that we're seeing is probably on the order of 5 to 6%.

So that's sort of ongoing and it's been ongoing now for a couple of years.

Over and above that, a couple of things I would point to in terms of looking at the first half of '06 against the first half of '05.

Clearly, we had a lot of rollover of the repair activity that was taking place in the Gulf of Mexico consequent on the hurricanes lost.

Most of the facilities are up and running.

We still have a very significant repair program ongoing on the shallow water assets that we retained.

Not the things that we sold to Apache but those things that needed to be fully remediated so we have a lot of repair work there.

We clearly have repair work on Thunder Horse and relative to the first half of '05, we have increased integrity investment in E&P by around $50 million.

So there are three things really driving the increase in operating costs that you can see in the numbers.

Neil, we're not changing the gearing ban nor is our current intention to change the way we distribute the free cash flow to shareholders.

As I think the chart showed, we almost achieved our target of 3Q '05 and we've got a bit of time to run and we will be very mindful about making sure we productively use our gearing so that we can increase the spread to the return on capital employed.

We are distributing with a progressive dividend policy, which is unchanged.

We are still buying back stock; we're obviously limited in the amount of stock buyback we can make in 3Q because we're out of the market during the issuance of stock to Alpha/Access Renova.

Could I ask now for the question from Jon Rigby of UBS?

Hi, thanks a lot.

A couple of questions.

First, I appreciate you've given us a time line of Thunder Horse startup.

I'm sorry, John.

You're breaking up.

You have to start again, please.

Yes, is that better?

That's better.

Just to go back to Thunder Horse firstly, if in the worst-case, there is a problem with the manifold or there is a design problem with the manifold and so your case of the startup in first quarter is not possible, I'm not an engineer, could you just talk through timeliness to do sort of significant replacement work so we get to know what the worst case is as well as the best case, given your best estimate of course?

Second is I saw you talking in the U.S. or reports of you talking in the U.S. about the potential for additions of complexity, certainly on the front end of some of your Midwest refineries that take heavy crude from Canada.

Is that now a formal project, is that being given FID within BP?

And could you give some more details of those projects?

Thank you, Jon.

Let me ask Andy to take you through a case where there is actually a worst-case.

I'm going to repeat that we're trying to give you our current best judgment, which will keep changing based on the investigations we're presently making.

But I think let's go through a worst-case and Andy if you could do that.

And then let me just say that the conversion of the Whiting refinery to take a steady dart of Canadian heavy, would be mostly Canadian heavy, is a project which we have launched.

We've already been spending money on front end engineering design and John can briefly talk to you about this project.

So Andy first, please?

Jon, yet again what I would emphasize is this is very early days in the investigation.

We literally have only just got the manifold out of the water.

So I think the whole conversation is clearly going to be colored by what we find when we have a chance to examine it in detail.

Starting up in the -- at the beginning of '07, we have a plan that would involve providing alternative equipment to replace the manifold installing that through the remaining part of this year.

Clearly, as I've said, the platform is ready to go, the risers are all in place and that would enable us to start up.

If you were to get to a point where it wasn't simply a case of just replacing the equipment associated with that one manifold, but we looked at a worst-case and again I think as John has emphasized, this is purely speculative at the moment where you had to replace all of the equipment associated with the subsea, that would certainly push the time line and extend it and you're probably talking around something that is around the end of '07.

So if you wanted to bound it, I think that would be a credible way of looking at it.

Thank you.

And John, on Whiting?

Just briefly then, John, as John said, it's a project which is intended now to convert the Whiting refinery to take Canadian, mainly, Canadian heavy from Alberta sands.

The intent of course is to capture the light heavy spreads as a result of heavier crude coming into the United States.

It won't necessarily increase substantially although it would increase somewhat the product make out of Whiting refinery.

That will be determined as we finalize the final configuration of the project.

We have begun spending -- the detailed phasing of the project is still actually moving around as we optimize how we're going to do that.

But you can expect that this is a project which will somewhere in the region of $3 billion over the course of the next probably five years expend at four to five years expenditure in that refinery and then we'll be ready to take the Canadian crude, which will more or less then be the total diet of that particular refinery.

Thank you, John.

Next, Daniel Barcelo of Banc of America.

Daniel, good afternoon.

A question on Russia.

If you could please comment on suggestions that TNK may have some issues with licenses perhaps on some older fields.

And then just more broadly on Russia, following the Rosneft investment you have made, I wanted to know if you are considering perhaps more synergies with TNK and Rosneft or do you consider this much more of a temporary financial investment?

And then lastly, any kind of update again within Russia perhaps on Kovytka or other potential areas for further exploration?

Thank you, Daniel.

Let me start the answer and I'm going to ask Tony to join in during this answer.

And I want to incorporate if I can the question Michael Young has been asking on the Web, which is something to do with why we went into the Rosneft IPO.

To the best of our knowledge, there's no issue with the licenses in TNK-BP.

And so I think news flow as always is a little shaky from Russia.

But to the best of my knowledge and belief, there is no issue with the licenses.

In Rosneft, of course we have done this before.

We have bought a stake in various companies, Petro China and Sinopec to assist in the launching of the IPO of these companies, these stake companies, and to express our intent to have a partnership with those companies.

This all applies to Rosneft.

We are a partner with Rosneft in some very important activities, notably Sakhalin in two licenses in Sakhalin, the Schmidt and Vankor licenses and we are also partners in a oilfield, a rather large oilfield and related areas in East Siberia.

It has the acronym VC, which is a very complicated Russian name.

We are also looking for more opportunities jointly with Rosneft in the arctic area, generally, of Russia.

So this is a very important relationship for us and I believe it right as we have done with other companies in the situation to assist in the IPO.

We limit ourselves to no more than 10% of the issue.

It's a very important point.

We did that in Petro China.

We did less than that in Sinopec because many other people were there to help and we did it in Rosneft.

We have no current intention of selling the shares.

The shares remain as marketable securities on our balance sheet and maybe one day there will come a time when we liquidate the investment but right now we have no intention of doing that.

Kovytka, Tony?

On Kovytka, I think a couple of important things really.

The first was there is now clear intent at the political level that the involvement of China in Russia's upstream oil and gas business is acceptable, as evidenced by Sinopec's participation and success in our disposal of the Udmurtneft assets from TNK-BP.

And secondly the visit of President Putin to China in the spring of this year formalized an agreement whereby gas and oil would move from Russia to China.

So that provides a political umbrella under which commercial activity can now take place.

And commercial activity is taking place.

We, as we have always said, need to reach the right agreements with Gazprom to allow Kovytka to be developed, where in that dialogue with Gazprom.

And as I would also say, as we have said many times, I would not expect to see export gas from Kovytka to China anytime before 2014 or 2015.

In the meantime, we are proceeding with an original development, which will see first gas produced and used from Kovytka towards the end of this year or the early part of next year.

Thanks, Tony.

Jon Wright of Citigroup in the UK.

Jon, good afternoon.

Good afternoon, thank you.

Two questions if I may.

The first is on CapEx.

You have given us an update on 2006 CapEx but I wonder if you could talk a little bit more about 2008?

I think your specific guidance previously was 0.5 billion increase per year so suggesting around $16 billion.

The second question is a follow-on to the Whiting question earlier, with the Midwest refinery upgrade.

Does that provide you with an opportunity to negotiate an agreement back into an Alberta heavy oil project?

Is that something you would be interested in looking at?

Thank you, Jon.

Maybe I'll ask John Manzoni to talk about the supply of heavy to Whiting?

Sure.

Jon, as you probably know, the value chain for the heavy oil results in much of the value being available in the conversion of heavy oil as opposed to the production of the heavy oil, which is why the opportunity in Whiting is so attractive as an investment.

That, however, obviously has to be linked to a supply of oil and therefore there is clearly benefit in discussions which are long-term, which secure long-term supplies into the refinery in order to facilitate the project and at the same time facilitate the development of the oil itself.

So I would say that both things have to proceed in tandem.

They do not necessarily mean that we have to participating all along the value chain nor do we necessarily intend to.

So I think the key is -- and we have many discussions going on today in order to secure the supply over the very long term for the project we are talking about.

It doesn't imply that we need or necessarily want to back up into the resource and of that particular value chain.

Jon, we have been I think surprised and I have been quite surprised, I must say, about the strength and length of the inflationary cycle that we are going through.

In particular, for E&P CapEx, it's obviously driven by complex drilling rigs and there's a balance to be struck on when to buy, when to go with the flow and get spot as well as all sorts of other factors.

And of course as you know,, the CapEx budget upstream is so dominated by drilling and it's dominated by drilling in rather complex heavy deepwater areas.

So I want to be helpful and give some numbers but I think it's too early to give what I call formal guidance for '07 and '08 because we have to see how this pattern of inflation comes through.

What we do observe of course is there are plenty of drilling rigs being built at the moment but they're not actually available.

So with all those cautions in mind, let's try and be helpful and say, first, we want to make sure that we don't simply dent the capital budget by having to spend money to eat inflation.

You actually want to keep the capital budget at least constant in real terms, if you will, if you take away this inflation amount.

Very important, you have seen the number of projects we have, which are part of the vital renewal of the future and indeed the exploration we're doing and you've heard John Manzoni talk about a really important investment in Whiting for processing heavy oil.

So on that balance, my own view at the moment is that we will see at least $1 billion more CapEx in '07 than '06 and then at least another $1 billion of CapEx in '08 rather than '07.

So put bluntly in numbers, think of 16, 17, 18 but I think we will update you on that and I think you know maybe it will be a touch more, who knows, at the moment when we have gone through our planning cycle at the moment.

I think it's really quite difficult at the moment to price inputs for all the things that we need because we are seeing as I say inflation in the E&P sector but actually we are also seeing it in the refining sector as well.

So I hope that is helpful.

Okay, thank you very much indeed.

Could I go to Bob Kessler of Simmons & Co. in the U.S.

Good morning.

Good morning, John, a couple of questions.

One, a point of clarification or additional commentary you might provide on the Rosneft transaction and then secondly on reserves.

On Rosneft, there's also the concern in the media that a fair percentage of Rosneft's assets, having been contested by Yukos for lack of another word, effectively stolen, to put it bluntly, and so implicit in your actions is a political statement on your part, confirming the Russian government's right to redistribute these assets from Yukos to Rosneft.

Can you comment about your comfort with the history of the assets involved in the transaction?

And then on the reserves, specifically the resources to reserves, the 11 billion barrels of oil equivalent, both between now and 2010, can you give us a sense for the timing of that?

Is it fair to say we should expect a ratable contribution for each of the next five reserve reports, say 2.2 billion barrels of oil equivalent per year or is there a significant skew in the timing?

Great, Paul, thank you very much.

I'll ask Tony to answer the reserves question in a moment.

Let me just talk about Yukos if I can, and Rosneft.

When we participated in the IPO, we did it with our eyes fully open.

We recognize that there would be a certain amount of PR activity and indeed there would be a certain degree of litigation in regard to Rosneft and the owners and their right to float the company.

This was of course immediately tested in the Court of First Instance and the Court of Appeal in London and the company prevailed.

We examined the prospectus very carefully and discussed the matter with the underwriters and we felt confident that as a 1.3% share owner of the shares, that this was neither a political statement nor anything else other than a statement in regard to our relationship with Rosneft.

And I would like to leave it like that.

On a wider political front, of course, helping these oil companies out from full state ownership to private ownership is a good thing for all of us because it adds transparency, it adds pressure to boards to govern well, it adds the ability of the managements of these companies to go out and about and see and talk to people and understand the pressures that would be applied to any private company, any public and credit company.

And actually I can say that based on my own experience in the change of BP who was basically owned by the UK government to what is a fully publicly owned company.

I think I would balance therefore that point against any other point and I want to repeat again we're not making a political statement; we're actually making a business judgment here.

And I think as a 1.3% shareowner of the Company, that is the right position to take.

Tony, can I ask you about reserves, please?

The 11 billion barrels of oil equivalent implies a reserve replacement ratio over the next five years of around 130%, which is consistent with what we have achieved across the last five years.

So, I would expect it to be sort of averaged over the five years.

It clearly will be a little lumpy as particular projects with particular barrels attached to them come through, but it will be -- it's an average over the next five years rather than expecting any great deluge of reserves in any particular year.

Any particular expectations on '06 being (multiple speakers)

Not at this stage.

It would be inappropriate I think to speculate at this stage.

We will report '06 when we get to it but I would expect it to be consistent with achieving 130% over five years.

Great, thank you, Tony.

Could I turn to Ed Westlake of CSFB?

Ed?

Yes, good afternoon.

Just two questions actually.

The first one is just really around Angola.

Obviously, you're getting a bit more confidence with the drilling results now in Block 31.

You've got Block 31 north, south, central, WEST and Angola LNG.

Can you give us sort of an update of when you might be able to get those projects into FID?

And then the second question is more on the financial side, particularly in the second quarter, the cash tax paid obviously came down as a percentage of the pretax income.

Just in terms of just maybe talking through what you expect in terms of cash taxes in the second half of the year and going forward.

Thanks very much.

Thanks, Ed.

The first part, I would like Andy to talk about Angola, please, and then when he's finished, second part, the CFO, Byron.

Yes in terms of Angola and Block 31, I think as you say, we've had a series of discoveries and the real push on Angola is to ensure that we drive capital efficiency into the program by pursuing a program approach.

So the notion here is to design one and build three or four.

So we're starting that process now.

The design process is underway.

And we would be looking to drive the first project towards FID I think in the sort of second half of '07 maybe beginning of '08.

The important thing here is not the timing of the first project but it's to ensure that we do the front-end loading so that we can then efficiently execute a program and then there afterwards, you would see that sort of second and third [hubf], probably following at about 18-month intervals, so you know if it's around the sort of beginning of '08, you would see the follow-on into '09 and thereafter.

So I think the good news on Angola is that on Block 31, we have found sufficient resource to be able to drive a standard approach, which we believe will lead to a very capital efficient approach, and therefore will be good for the [D] cost per barrel.

Thank you, Andy.

Byron.

The actual payments of tax tend to be volatile on a quarter-by-quarter basis because they're driven by installment payments.

What you saw in the second quarter was a change in the UK installment regime, which is associated with the 2005 budget.

And under that regime, what we did was pay both the third and fourth installments of 2005 in 1Q and there was no installment paid in the second quarter.

So it's really nothing unusual here except the volatility that occurs in the actual cash payments.

The cash rate for the year, what we would still target it to be, consistent with the guidance that I provided back in February, somewhere around 37% and that's driven partially in 2006 by the fact that we have a payment associated with the gains on the sale of our Innovene assets in the fourth quarter of 2005.

Great, thank you.

I'd like to take a question from the Web.

It's from Paul [Spedding] of HSBC.

It's two parts.

It's very unusual for U.S. gas prices to stay under resid parity for any length of time.

What levers do you see that could bring it back into the resid distillate range?

And I'm going to ask Vivienne Cox to answer that question.

And the second part is how do you judge the market's ability to absorb your buybacks, i.e., do you feel you have come close recently to the market's tolerance levels?

And Byron could answer that.

Vivienne.

Well, Paul, as I'm sure you are well aware, the reason that the U.S. gas prices are so low at the moment is because of the extraordinary amount of inventory that we have got.

And the inventory level is being driven in large measure by the demand destruction that has occurred in the U.S. with gas consumption being replaced by coal.

And I think one of the big questions is going forward, if oil prices stay high and gas prices relatively high, are we going to see gas competing increasingly with coal as opposed to the bottom of the resid distillate band.

I think though that low gas prices will cause an increase in consumption.

However, I suspect that we are seeing gas prices at the lower end of the resid distillate range going forward.

Thank you.

Byron, quick answer.

There is deep liquidity in BP's shares, both in London and New York.

We bought back $4.5 billion worth of shares in the second quarter and at that level met no constraints whatsoever.

So I feel very confident about the ability for our share buyback program to meet the financial framework of the group.

Great, thank you.

Could I ask Gordon Gray, JPMorgan London.

Gordon, good afternoon.

Good afternoon.

My main question has been asked, but as a follow-on to that, from the February presentation, your volume guidance was for a very strong surge up to '08 and then basically sort of flat-lining ex-Russia after that.

Given the strong emphasis you have on non-Russian prospects in the longer term and particularly the fact that there's only probably Kovytka I think in the post '10 outlook, do you think something like flat-lining outside Russia is probably conservative?

Thank you for that question.

Let me ask Tony to take that question on.

I may have some additional comments.

I think what we have projected to date is a balanced judgment as to how we saw the portfolio when we presented it to you six or eight months ago.

And as all things in life, it continues to evolve and develop.

We continue to have exploration success.

We continue to find new opportunities.

In particular, we are unearthing very interesting opportunities in what you might have once thought of as old tired assets in the big legacy positions we have, in particular in United States.

So I think when we come to talk to you again about the future, probably in six months or so time, we may have a slightly different view of the world.

But today, I would say it is a good judgment and we continue to find tremendous opportunity in the legacy positions we have outside of Russia.

I think the only thing I would add -- I completely agree with that -- I think we are just -- we're doing a lot.

We are doing a lot.

We are doing it in a disciplined way.

Because we are doing a lot, I think things keep changing.

In the broad envelope, you know, it's going to be very difficult for us to detect another 1% growth or 2% growth as time goes out into the future.

I think all of us know that.

We give you our best estimate from time to time but what I do observe is we are discovering oil and gas.

Outside Russia and indeed inside Russia, we have had some really extraordinary and good discoveries based on first class geophysics underneath existing producing horizons in West Siberia.

I think the geology was excellently understood.

We have other developments going on in Russia and as Tony says, we have got all sorts of things, new things and old things, coming up in our legacy position.

So things keep moving.

We certainly haven't run out of opportunities.

Can I ask Colin Smith of Dresdner for a question?

Colin, good afternoon.

Good afternoon to you.

Just a little bit more on the disposal announcement.

First of all, if I add up all the disposables you've announced, including Udmurtneft and Coryton, it would probably come to something like $8 billion.

So I'm just wondering what is in the 6 and what is not in the 6.

Perhaps more importantly just on the principle of all of this, I think, John, you linked earlier asset sales to share purchases.

And I was wondering if beyond the general housekeeping level of disposals, should we see the big step-up in disposals and sort of taking advantage of price arbitrage between the acquisition market as it stands currently and the value you think these assets may be currently reflected in your share price?

Colin, thanks for the question;

I might just answer this.

First on disposals, you have to separate out those disposals made by TNK-BP -- and I'm very careful to separate those out and I don't include them in the numbers because of course it is, don't forget, an affiliate company and we only get the proceeds far the dividend so it's whatever the cash flow is according to the dividend policy of the Company.

But you are actually right, I mean, it was a very large disposal made by TNK-BP, $3.6 billion.

This was a pretty good and hefty price I think for the sort of assets which were being sold.

Secondly, I think we need to be very careful about discretion of asset sales and disposal.

We won't go wrong in my view, at least I hope you would agree with this, if we stick to the strategy.

What we should not be doing is trying to do some very clever thing just to get onetime benefit of high price.

So, this is about strategy.

It's about looking at the assets and market positions and saying, do they really fit in a pattern of activity and what are going to do about these things.

So we commonly call these tail assets but they are sometimes not actually that.

It's just a shorthand of how do they fit?

Do we really want to participate in this area?

Can we compete?

Is the overhead right?

Does it have legs for the future?

All of these questions, I think you'd expect someone to be able to answer on a strategic basis.

That's exactly why for example we're selling Coryton.

It doesn't fit with our overall pattern of good refinery.

It started off primarily actually more about lubes than anything else under the ownership of Mobile and it's been slowly modified to do something different.

But actually in the end, you look at it and compare it to the rest of out portfolio and you should say better owned by somebody else.

We need to go and do something else with that money and that may not always be buying back stock.

We may find another way of participating and a refinery to replace it.

Let's see what we can do.

Mark Gilman of Benchmark in the U.S.

Good morning, Mark.

(technical difficulty) questions unrelated.

The first one, given the operating issues that have existed I guess over the last couple of years, any thought been given to the creation of a chief operating officer position within the Corporation?

Second one relates to following up on your comments a moment ago regarding divestments and two parts of it if I could.

I'm curious as to why Coryton and not a broader cut at the European refining network and in particular Rotterdam, which strikes me as a less competitive unit than Coryton.

And then shifting to Shenzi for just a second, this is a pattern that I have not seen from BP before in terms of divesting a predevelopment asset in a core area.

Is there something in particular about Shenzi or might we see more of this going forward?

Thank you, Mark.

Personally I can talk about the organizational issues.

BP has for many years actually looked at itself and said, actually, there are three COO's and they are the heads of the principal operating businesses of BP -- Tony Hayward, it John Manzoni and Vivienne Cox and that's what it is.

Because the roles of these jobs are very heavily operational globally and they have teams that do it.

We look at it and say actually that's not something we need to duplicate.

Rather, what we needed to do was to add further capability and strength to the American operation.

And the announcement we made today, which is to actually change our business there from business as usual to business if I would put it this way, businesses unusual, that is exactly what we have done there.

We have increased significantly the operating capability there.

I'm going to ask John Manzoni to answer the question about why only Coryton, why not a broader cut.

And then I would like to ask Tony to answer the question about Shenzi.

Mark, let me deal with the Coryton thing.

Coryton, as you know, is predominantly a gasoline machine in what is predominantly a diesel market and the growth in diesel in Europe is a trend which looks sustained, has sustained for some time, looks sustainable into the future.

And we have some options therefore with that particular asset to either invest heavily in it and turn it into something which is more suited to the future long term of its market, or indeed, as John has said, to take a different view of Coryton and it can be better owned by somebody else and then for us to do something else with those funds.

And potentially that might include further investments into our European portfolio.

As you know, our U.S. portfolio is absolutely right at the top of the competitive suite.

Our European portfolio is not bad but not at the top.

This represents a strategic step in order to enable us to strengthen the power of our European portfolio in that sense.

You mentioned Rotterdam in particular.

Rotterdam of course has unique characteristics.

Actually for BP, we operate a lot as you know of supply optimization in and out of our refineries.

And NEREFCO and Rotterdam refinery sits well in that suite and indeed is well-suited to its European marketplace.

So I think strategically, that is the background to the decision that we took around Coryton rather than anything broader.

Thank you, John.

Tony.

I don't think this is sort of a new departure, Mark, in terms of our decision to divest Shenzi.

It is part of the continuous review we do at all levels, both at the sort of segment level but also at a -- on a regional basis.

And as we looked at the Gulf of Mexico and the raft of activity we have on our plate there, we determined that our efforts and resources were better focused on some of the things where we were operating rather than being distracted by a 28% nonoperating interest.

And I would just remind you of [Omenlanger] in the North Sea last year where we took a very similar decision.

Very high-quality assets, as evidenced by the price we got for both of them, but places where we didn't actually have much leverage to our operating capability and we prefer to focus our resources on things where we do.

Thank you, Tony.

Tim Whittaker of Lehman Brothers in London.

Tim, good afternoon.

Hello, let's come back to Texas City.

Could you tell me what the total is of cash flow that you have forgone there, repair expenditure, legal settlements and also liability provisioning?

The answer is I'm sure we can, and I'm just looking around all these faces to start.

We will come back to you, Tim, if you could just hold on because that's a detailed question which we just need to add up some numbers.

Can we do that?

Could I go on to Jason Kenney of ING?

Jason, good afternoon.

Given the notable amount of projects for the 2010 and beyond period in the upstream and the slate of potential project ramp-ups, the improving optionality you mentioned and the reserves and resource progression and the continued exploration success, could you ever envisage extending the 4% CAGR for 2005 and 2010 to say even 2012 at this stage?

Secondly, a bit of a detail if possible.

Slightly surprised on West of Shetlands production numbers in the 2005 fact book.

And I'm just wondering what the outlook is for production in that region in the UK?