英國石油 (BP) 2002 Q3 法說會逐字稿

Welcome to the BP Third quarter Results Conference Call.

I will now hand the call over to Vice President of Investor Relations, Mr. Fergus McLeod.

Please go ahead, sir.

Ladies and Gentlemen, Good afternoon in Europe and good morning to all listeners in the United States.

My name is Fergus McLeod from BP Investor Relations and I would like to welcome you to our Third quarter 2002 Conference Call and Webcast.

I am joined today by John Browne, our Group Chief Executive, John Buchanan, our Chief Financial Officer, Byron Grote, CFO Designate and currently Chief Executive of our Chemicals Business, Andy Ingles, Group Vice President and Commercial Director of our Upstream Business, and Mike Starkey, our Chief Accounting Officer.

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

First, today’s call refers to slides that we will be using during the Webcast.

If you are listening on the telephone, the slides are available to download from the Investor Centre on our website: bp.com.

Second, I must draw your attention to this disclaimer.

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

Actual results may differ materially, depending on a number of factors as indicated on this slide.

I should also point out that our and your words will be recorded so that the information can be made available on our website.

Before we go on to talk about Third quarter results, I would like to hand over to John Browne, Group Chief Executive who will make some introductory remarks.

We will then hand over to John Buchanan who will talk about the highlights of the Third quarter and the current position of our financial framework.

We will then open the call to your questions.

Thank you Fergus.

Good afternoon, Ladies and gentlemen.

Although, I would not normally join you to discuss Third quarter results, I have joined the Call today for three reasons.

First, to recognize John Buchanan whose retirement was announced today.

Second, to talk about the issue of performance shortfalls and our Upstream business and the steps that we are taking to remedy them.

And third, to briefly touch on where this leaves the overall performance potential of the company.

I begin by paying tribute to John Buchanan whose forthcoming retirement as CFO was announced today.

John has served BP for six years as CFO and has played a vital role in shaping, perhaps the most exciting transformation in BP’s history.

It is difficult to believe that John is now in his sixtieth year, and I am sure that you will join me in thanking him for the enormous contribution that he has made to our success and in wishing him every happiness for the future.

The financial framework which BP uses today and which ensures that the cash flows, spending, gearing and dividend payments remain in a sustainable balance is largely John’s creation, and is a source of strength to our shareholders in turbulent times.

This financial framework will be an enduring legacy of John Buchanan’s tenor as CFO and should stand BP in good stead for many years to come.

John will be succeeded by Byron Grote in November.

Byron is a former Group Treasurer, and in him you will gain a CFO with deep experience in all main business areas supported again by the unchanged and excellent finance team in BP.

The second reason that I have joined the Call today is to talk about our Upstream business.

The past nine months have not been happy ones for this part of our operations.

We had hoped to grow our production by 5.5% this year, but we have failed to do so.

Let me explain ...

Let me begin by explaining why this has occurred.

As we indicated in our Trading Update of October 2, production growth in 3Q 2002 compared to 3Q 2001 was close to 4%, less than planned earlier, primarily due to performance problems in the North Sea, Alaska and North America, and unusually severe storm patterns in the Gulf of Mexico.

The primary North Sea events included the problem with the Schiehallion Floating Production System, the unexpected shutdown of the gas inter connector into Europe, as well as slower than expected turnarounds at the Bruce, Forties and Andrew Fields in Alaska, which chose to shut in 150 wells to assure operational safety following the explosion of one well at Prudhoe Bay in August.

In North America Gas, we continue to see transportation bottlenecks out of the Rockies and San Juan areas which hit both volumes and pricing.

As well as these performance shortfalls, we saw a reduction of around 20,000 barrels a day for 2002, compared to a normal year, due to storm-related impacts.

The cumulative effect of this year’s storm pattern in the Gulf of Mexico has been significantly greater by a factor of more than five times than we have experienced in recent years and exceeded the normal five-day allowance that we make in our plans for weather-related disruptions to production in the Gulf.

These disruptions continued into the fourth quarter, both impacting current production, as operations took some time to return to normal, following tropical storms Isadora and Lilly, and delaying the start up of some of our new projects.

The five of these performing shortfalls and the magnitude of the storm-related effects were greater than we had first expected.

I do not wish to make excuses for our performance.

It is our job to make judgments, and on this matter we would have wished to do better.

Let me now take a moment to look at how our goals for production volumes in 2002 as a whole have been affected by this series of events.

This slide shows how expectations for average 2002 productions have developed since our presentation in July.

On the left-hand side of the chart, the green bar represents 2001 production.

The first two bars represent our plans as they stood at the start of 2002.

Organic growth from new project start-ups was expected to contribute around 235,000 barrels a day.

As I will explain, we are 25,000 barrels a day below this plan due to project delays, a managed decline in our existing production base of around 50,000 barrels a day, with some improvement in operational efficiency offsetting underlying fields decline rate.

This is, as expected.

The five bars to the right represent the changed plans and disappointments of 2002 in roughly the order in which they occurred. 30,000 barrels a day due to lower than expected gas liftings due to mild weather in the first quarter and OPEC cutbacks.

An extra contribution of around 40,000 barrels from inorganic growth, mainly the increase in our interest in Sedanco in Russia. 50,000 barrels a day due to the shortfalls in the North Sea, Alaska and elsewhere in the second half of 2002. 20,000 barrels a day due to greater disruptions by storms in the Gulf of Mexico that had been allowed for in our forecast, both in 3Q and continuing into 4Q. 25,000 barrels a day due to project delay.

The net impact is that we now expect production growth of around 3% in 2002.

This is disappointing.

What I am sure you are really interested in, is what we are going to do about all this.

Can we make up for the income shortfall from lower production?

What degree of headroom due we have and do we need in our forecast? and what is the right rate of volume growth to target to achieve the highest returns for our shareholders?

It is clear from the experience of 2002 that we lacked a degree of headroom in our plan that would allow us to absorb problems of the type and on the scale that we have encountered this year.

We believe that this loss of headroom has happened for three important reasons.

The first, if and since we originally set our 5.5% to 7% average compound growth rate of 2000 to 2005 production, we have progressively reallocated capital than sustaining our base production, the longer-term growth project where we see better returns.

We have reallocated around $1bln a year of capital from the base to growth projects that should contribute to the organic growth that we expect in 2005 and beyond.

By putting that capital in the base we could have held output from the base flat.

We have chosen not to do so and to allow base production to decline by around 50,000 to 70,000 barrels per day each year.

We are convinced that this has been the right economic decision, that $1bln should produce more volume and higher returns in the future.

It has, however, deprived us of the flexibility in meeting short time production goals when unexpected events occur, which has turned out to be a problem in 2002.

We took that decision in the belief that we had sufficient headroom to meet our goals, despite the reallocation of capital.

This has turned out not to be the case.

The second reason for the loss of headroom is project delays.

As you know, there have been delays for some of our projects, for example, in Angola, due to government timing preferences.

The third reason for the loss of headroom has been that high oil prices over the past two years have made it much less attractive to upgrade the portfolio with minor acquisition and property purchases.

In fact, we have chosen to be net sellers of barrels in a high oil price environment, as seen by the decision not to retain favors 170,000 barrels a day of production and to dispose of our interest in [Altura] and so on.

We will not retain or acquire barrels just to meet a production goal when there is more value to a third party.

What does this loss of near-term headroom mean for our longer-term forecasts?

We start with a strategy that is in good shape.

The reserves that we need to deliver our growth are in place and are being booked.

This slide shows that our average organic reserve replacement ratio of 156% over the past three years comfortably exceeds that of our major competitors.

We expect to record reserves replacement in 2002 at a similar level.

The barrels are there.

As a result, if we chose to do so, we have the resources to increase our production by 20% in today’s 3.5 million barrels a day to 4.2 million barrels a day by the end of 2005 or during 2006 at the latest, but it would require more capital spending on the base than we have chosen to put in this year by around $1bln a year, but it could be done.

If we were to commit this additional spending, we could retain roughly our existing production targets.

The key question we now asking ourselves is: should we?

What is the optimum way to monetize the resource base that we built up to our exploration success and acquisitions of the last decade?

What should we do in order to optimize the economic returns from these barrels?

What is the optimum pace of development?

We are very clear what our goal is: to extract the maximum value from our portfolio on behalf of our shareholders.

The question is: how, while maintaining the right balance of returns and growth.

To answer the question, we are taking a number of steps and we will rely on our business model to guide our actions.

We are examining the organic investment in our Upstream portfolio from the bottom up.

We are questioning how much we want to invest in each area based on the detailed assessment of risk, growth prospects, declined rates, cost, returns and margins.

We are asking ourselves about high grading the portfolio.

We assets will be monetized by sale rather than continued operation or development?

We are examining future investment and its distribution to get the most efficient deployment of capital, including the optimum pace, and this is in line with our strategy that every part of our Upstream business must be fit for a $16.00 oil price world.

And we are looking at efficiency, in particular, at the costs which we carry above the field.

Field level costs are under effective control, but the question is the overheads that we carry above them.

We want more headroom in our forecasts so that our future targets are robust against the realities of managing performance.

We have too much complexity.

We will address this.

After three years of high oil prices, it is perhaps inevitable the cost in many areas have crept up and are higher than they need to be.

We need to deal with them.

These are tough steps, but it is important that the owners of our business know that we are taking action.

This review is part of our annual planning process.

It is too soon to tell you what the conclusions will be.

I expect that we will be able to tell you more about this and our plans for the rest of the group at the time of our full-year results in February.

The third and final issue which I want to talk to you about is where the 2002 Upstream performance and our review of plans for the future leads the performance potential for the group as a whole?

As far as volumes are concerned, I have already explained that we have the potential to reach 4.2 million barrels a day by late 2005 or during 2006, but that we are reassessing the optimum growth rate from a value perspective, balancing returns, investments and the potential for divestment.

As regard specific 2003 production guidance, we will stick to our practice of not giving a specific goal for the forthcoming year until we announce the 2002 results in February.

It is too soon to give that specific guidance today due to uncertainty over how quickly we can recover from our 2002 poor performance because of lack of clarity on the timing of partner-operated project and because we have yet to finalize either the pattern of 2003 investments or the level of headroom that we require in future forecasts.

As far as our financial performance is concerned, however, the picture is absolutely clear.

In July 2000, we set a three-year goal of increasing sustainable mid-cycle earnings per share at around a double-digit rate, on average, over the period 2001 to 2003, and of paying a dividend based on around 60 % of those earnings.

We stand by that goal.

The mix of means of delivering it has evolved and will continue to evolve as external circumstances change and we upgrade and learn more about our portfolio.

The shortfall in Upstream performance this year will require us to take tough steps to offset its impact, notably by closer attention to our costs.

Our aim is to do what is necessary to protect the interest of our shareholders.

In concluding, let me summarize.

One, the near-term for headroom, or margin for error above our existing production targets, has been progressively eroded.

Two, reserves, both in our base and in our growth projects, are there as planned.

The issue is how best to monetize them.

Three, the long term value-driven bias in our pattern of Uupstream investment is lengthening our growth profile beyond 2005.

Four, our short-term production profile, from now to 2005, now looks as if it might require more capital than we had previously thought to meet our existing production goal.

Five, we are currently testing what is the right mix of organic growth and investment, divestment and portfolio high grading, capital and cost to maximize value for shareholders from our Upstream business.

Six, as far as the groups existing financial goals are concerned, we have other levers to pull and other actions we can take, particularly on costs, that can compensate for any short-term shortfall in upstream performance delivery whilst these issues are being address.

Now, thank you for your attention.

I will of course be happy to answer any of your questions, but first, I would like to hand back to John Buchanan who will talk about the third quarter results in detail.

John.

Thank you John, and thank you for your kind remarks.

As usual, I would like to begin by talking about the trading environment.

This has remained broadly similar to the second quarter.

I realized liquid prices in the third quarter of this year rose by around 7%, or about $1.60 a barrel.

However, the benefit of high oil prices was partially offset by an 8%, or about $0.20 per million cubic feet reduction in global gas realizations caused by weaker spot prices and widening regional differentials in North America.

In our Downstream businesses, we saw a retreat from the improvements experienced in 2Q.

Refining indicated margins were squeezed for much of the quarter by rising crude prices with actual realized margins suffering more than the decline in indicated margins would have suggested.

There were also signs of weakening demand growth and intensified competition, but especially towards the end of the quarter.

Chemicals margins have risen slightly from the second quarter that remain weak.

Volumes and Chemicals also gave some indication of an economic slowdown towards the end of the quarter.

Overall then, compared to the second quarter, weaker downstream and natural gas markets offset improved oil prices to leave us broadly at mid-cycle, on aggregate only slightly better than the second quarter.

The next chart shows our key bottom line measures, earnings and cash, for the third quarter and the first nine months of the year.

For the third quarter our pro forma result of $2.3bln was down 13% from the same quarter of last year.

The reported result of $0.8bln, including one-time items and purchase accounting impacts of Arco and Castrol, were down 61%.

Cash flow from operations of $4.4bln remains robust, down 13% from the third quarter of last year.

At $0.06 a share, our third quarter dividend is up 9% on the third quarter of last year, reflecting the trend of underlying performance improvement.

Our dividend payout ratio was around 60%, in line with the target payout ratio from our mid-cycle earnings and reflecting that environmental conditions were close to mid-cycle.

For the first nine months, both pro forma and reported results were down compared to the results achieved under the particularly favorable Downstream conditions experienced in 2001.

Once more, cash flow from operations looks strong at $13.1bln, down 22% against the first nine months of last year.

Our return of average capital employed calculated on a pro forma basis was 13% for the first nine months, compared to a 22% in the same period last year.

This decline reflects the below mid-cycle conditions experienced earlier in the year compared with the well above mid-cycle conditions last year.

This contrast is especially prominent in the Downstream businesses.

However, the robust pro forma results and cash flow, despite the decline in Downstream, indicates that underlining performance improvements are coming through.

Overall, these results demonstrate continuing robust financial performance in the face of challenging marketing conditions.

I would now like to look at our performance in 3Q, stream by stream, and compare it to the second quarter, starting the upstream.

This slide shows that we generated pro forma replacement cost operating results adjusted for special items of $3.05bln, with increase of $161mln on 2Q.

The blue bars on the slide represent factors which had a positive impact on our results, while the orange represent negative variances.

The environment, contributing around $100mln was the biggest contributor to the increase.

Liquids realizations higher by $1.60 benefiting the operating result by some $240mln.

This was somewhat offset by weaker gas realizations, especially in the US, where these realizations were $0.42 per million cubic feet lower than 2Q, contributing to a negative impact on our result of some $140mln.

As John has explained, operational difficulties and a number of our producing fields impacted us, and together with normal seasonal factors and a series of unusually severe storms in the Gulf of Mexico, resulted in volume being down around 100 million barrels all equivalent per day, versus the second quarter, impacting operating profit negatively by $85mln dollars.

Exploration expense on the other hand was down some $100mln in 3Q, reflecting a return to normal expense levels compared with 2Q, which included the write-off of the Neptune prospect.

I would now like to focus on the Downstream and Chemicals parts of our business.

Our Downstream business continued to experienced a very difficult Refining and marketing margin environment.

I have already mentioned that our site-specific Refining margins declined by more than commonly used industry indicator margins might have suggested.

As this slide shows, the Downstream pro forma replacement cost operating result declined from $685mln in 2Q to $522mln.

Refining margins remained under pressure in 3Q, particularly in the US and on the West Coast.

An overhang of product stocks, continued pressure from higher crude prices and general weakness in the global economy were the primary reasons for the decline.

While marketing margins were essentially comparable to 2Q, they weakened at the end of the quarter, especially in the US.

The fourth quarter has begun with a recovery in Refining margins, but a difficult environment for marketing continues as competitive pressures remain intense.

One-off factors also had a significant impact on our Downstream result.

[break in audio]

... program during the second half of the year.

Lastly, and on a positive note, Chemicals.

The stream delivered a pro forma operating result of $272mln up $26mln versus the second quarter, despite a tough environment.

The environment impacted the stream positively overall, with strength in the early part of the quarter giving way to pressure later, due to high feedstock and energy costs in September limiting up-sided in margins.

The most significant contribution to the chemical result, however, came from costs, largely due to the benefits of restructuring starting to flow through and lower scheduled maintenance activities.

I will now move on to discuss the year so far.

This chart provides further perspective of the change in our after-tax pro forma results for the first nine months of the year.

As you can see, deteriorating trading conditions have impacted performance significantly year-on-year. 60 % of the total $4.5bln decline coming from lower oil and gas prices, and the remainder from weaker margins in our Downstream business.

Despite this, we have improved our underlying performance by around $800mln in the first nine months of the year, or around $600mln after tax.

That takes us around three quarters of the way to delivering our goal of double-digit underlying earnings per share growth.

Now, I would like to look at our underlying improvements for the year and why we are confident that we can deliver underlying improvement growth required to underpin double-digit earning growth ...

I’m sorry ... double-digit growth and earnings.

We have had some adverse developments which have made it more difficult to achieve our total underlying performance goal.

Notably, the impact of lower Upstream volumes and weaker demand growth in the Downstream.

Despite these difficulties, we have increased our underlying mid-cycle pre-tax profits by the approximately $800mln already mentioned.

These improvements have come from all streams, but especially from Chemicals and increasing from costs and synergies from labor in the downstream.

Performance potential.

This slide shows our latest view of the likely scale and sources of underlying performance improvement in 2002.

As usual, the likely outcome for the year is showing a different pattern from our view when the year began.

This was true in 2000 and 2001 as well.

The $800mln on underlying performance improvement delivered by the end of 3Q gives us confidence in achieving the $1.2bln required to underpin our core goal of sustainable double- digit earnings growth on a mid cycle basis.

Although the external environment is increasingly challenging, our higher goal of underlying performance improvement of around $1.4bln for the year remains our target, and we are taking new steps, particularly on costs, to offset the shortfall in Upstream volumes.

Special and exceptional items.

We measure year-on year-improvement based on sustainable performance by removing the distortions caused by non-recurring items, such as restructuring costs and gains or losses from selling assets.

We disclose these non recurring items as exceptional items as require by UK GAAP or as special items.

This chart shows our track record of these special and exceptional items on a pre-tax basis from the three years before and after the BP Amoco merger, as well as an indication of our full-year 2002 expectation.

In July, we indicated that the sale of [Rogas] in 3Q would more than offset the total first half charges.

This is indeed the case, as the [Rogas] sale is now complete, and the gain from that transaction was $1.6bln.

As part of our normal practices, we have reviewed our portfolio and have tested our assets against our associated developed and potential economic reserves.

As a result, we have taken special impairment charges against several poorly-performing assets, mainly in the Upstream, totaling $0.7bln for the third quarter.

In addition, we have accelerated the acquisition amortization on some former Arco assets totaling $0.4bln.

Now to cash flow.

We plan and run our business to balance cash sources and uses in accordance with our well-established and disciplined financial framework.

This slide compares sources and uses of cash in the first nine months of 2001 and 2002.

Cash flow remains strong despite the weaker external environment, as discussed earlier, with a reduction of around 22 % compared to 2001.

Disposals have increased versus the same period last year, reflecting the sale of mostly [Vabors] Upstream assets following that acquisition, and the more recent sale of our interest in [Rogas].

On balance, sources of cash have slightly increased versus the same period last year.

We have seen an increased level of investment versus the same period last year, due to an increased acquisition spend, primarily labor.

Our organic CAPEX outlook for the year remains towards the top end of the $12bln to $13bln bank.

The next slide sums up our position on investment and capital expenditure.

Organic CAPEX for the nine months of 2002 was around $9.3bln.

The outlook for organic CAPEX is the upper end of the target range.

Increased disposals in 3Q including the [Rogas] transaction have balanced inorganic investment for the year so far. [Weightings] of disposals means that net investment for the year is likely to be around $12bln, above the $8bln to $10bln range previously indicated, but with a balance of the disposal program made up in 2003.

The financial framework.

The increased investment levels in 2002 have been made within the boundaries of our financial framework, with our gearing level ending the third quarter at a touch under 29%, below the centre of our target bank.

This has been achieved during a nine-month period when we have been on balance below mid-cycle, demonstrating the strength of our cash generation capacity.

Our third quarter dividend of $0.06 per UK share, or $0.36 per US ADR, is up 9% on the third quarter of 2001.

The growth rate for the first nine months of the year is also 9%.

This dividend increase is based on our policy of paying out around 60% of our mid-cycle earnings and reflects continued underlying performance improvement.

In addition, we brought back around $750mln worth of shares during a quarter.

In closing, I would like to just remind you of the [call] target we laid before you in July 2000.

Our goal is to live a growth in underlying earnings per share around a double-digit rate over 2001 to 2003, with a dividend growing in line.

That is what we continue to do.

In closing, let me briefly offer a few personal remarks.

This event, marks my twenty-fifth quarter of helping prepare and communicate BP results as CFO.

In my six years as CFO, it has been both a pleasure and a privilege to work as part of the BP team under John Browne’s leadership and to engage in discussion and debate with so many of you in the investment community, in calls such as this and particularly in the one on one meetings.

I offer you and the BP team my very best wishes for the future.

I may well have contact with some of you in my future non-Executive roles.

Thank you for your attention.

We will now be happy to take any questions you may have.

If you would like to ask a question you may do so by pressing *1.

To cancel your question press *2.

Ladies and gentlemen, it’s the question and answer period.

What I would like to do is ask John Buchanan to chair this so that I am better able to listen to your questions and answer any you have for me.

So John over to you.

Thank you John.

Richard Franklin, Richard.

I want to ask two questions actually, the first is on your [Rcorp] improvement time for this year.

Particularly the elements from Refining and marketing and Chemicals which amount to $1bln.

To what extent is that target in anyway external environment related as regards volumes and therefore potentially at risk in Q4.

So, to what extent can we access any risk of your missing that billion dollar delivery at the end of the year, that’s my first question.

The second one is just to try and get some color on the [underling]declining rate assumptions you are taking for 2002 and beyond and whether or not you’ve made any changes compared to what perhaps you had this time last year?

Let me take the first and I’ll invite John to comment on the second.

In terms of underlying performance improvement for the balance of the year, we looked at this very carefully.

Looking at the performance record of the downstream businesses so far, in particularly Chemicals success with their restructuring, we have a good confidence level of achievement across the rest of the year.

John

Richard, underlying decline rate.

First it’s not an assumption of course it’s a part of a detailed build up from the bottom of the company.

The decline rate of our historic assets which we call the base is really a function of two things -- three things I would say -- first the quality of the resorvious and their has been no change to that.

Secondly, the level of investment we put into the reserves that are behind pipe right now.

Thirdly and very importantly as part of the base, it is the amount we put in to [ ] very close end exploration buying the lease next door and doing all that sort of stuff.

Now as I said in my remarks in order to keep the base flat, we would need to put in about $1bln more per year than we’re doing at the moment otherwise the decline rate of the base is between 50-70 thousand barrels a day.

A [rights] level of decline, the [right] level of decline is something that we are looking at the moment and it is dependent upon the length of investment we wish to make in the growth portfolio -- how much we spend in that -- for production which is clearly going to occur way beyond 2005.

The second, is what assets do we actually work on that is to say, are we going to the divest some and we’re still looking at that.

Thirdly then is what is the right [suite] spot to get in the historic legacy assets.

I want to make one point clear because all that sounds as if it really is work in progress and a lot of studies and indeed there are a lot of studies and because this has to be done bottom up, it can’t be done by [ ] top down, it takes time.

We’re going to leave a very clear message for you today and it’s this, I want to repeat again what I’ve said because I’m sure this will be a question from many of you.

We clearly retain the option to increase reported production to 4.2 million barrels per day by late 2005 early 2006 with a clear shape to the production profile.

It’s an equivalent to an above 5% annual average growth rate 2000-2005 or slightly to 2006.

So, we grew by 5.5% in 2001, we grow by 3% this year, we’ll grow between 3-4% next year, between 4-5% next year, over 7% for the following years.

But this, in order to achieve that, it is our estimation that we will have to put $1bln in more than we are doing at the moment per year.

This would nonetheless grow cash margins and barrels through the period but the profit margins will be flat in the short-term, growing only at the end of the period.

Now, if we choose to do it we could do that but at the moment what we are saying is so, that’s the back stop but actually is it the right way to develop the optimal value from these assets and that’s something we’re looking at.

Because, if I can just add two other points to this to make the length of the answer quite long.

One, it seems to us that while our production target is important it cannot be exclusive.

To single-mindedly drive a production unit on the basis of production target would be to actually do things which potentially are strategically inaccurate and inappropriate to deny value.

It’s all very well having a production target when you’ve got plenty of headroom because then there is plenty of degrees of freedom.

As I pointed out to you the head room is gone because of this progressive decision to drive for value so, we want to look at that.

Secondly, these production targets are based on what I call reasonability that is to say that they are basically what the assets we have can do may be with some little [ ] for acquisitions, little divestments.

What they are not however, is things that should be dressed up or achieved by buying lots of barrels, that is out of the question.

That’s a very different game and buying barrels is all about value for the barrels you’ve bought not to achieve a production target.

I hope I’ve given a comprehensive answer and I’m quite prepared to do it again.

That is very comprehensive, thank you very much indeed.

A couple of questions, looking back to the time when you set these volume targets back in 2000.

You talked a bit about head room but are there any other lessons that perhaps you have learnt from the experiences that you’ve had this year with respect to those 2000 targets.

Secondly, I think the second target was set in July 2000 was double-digit earnings growth out of the end of 2003.

What assumptions were made in that, again is there enough head room in that target so that you will still be able to hit it in 2003 with the volume short falls that you’re now indicating for next year.

JJ let me answer the question.

It’s always great to look back and ask yourself what lessons we’ve learnt from target setting.

I would make this point, that we’ve made these targets and that is as it were if I could say we’ve made our bed and we have to sleep in it.

That cannot just be expunged by saying wouldn’t it be nice if we did something different.

I don’t believe this is what the style of this company is nor should it ever be.

I think two things, one is it’s wrong to let one target be more important than any other target.

The production targets become a tortum.

It becomes something which I think people are focused on but of course like all targets there are conditions attached to it.

We’ve never drive the company just to get the production and that’s resulted in the loss of headroom.

We’re there to generate value, to do sensible things to check that we are value accretive, what we do, that it adds NPV and that it’s the right thing for the long-term as well as the short-term.

I suppose the big lesson learnt here is to make sure that no one target gets out of proportion with the suite of targets which says actually you have to balance all these things, you have to balance and that is very important and if I may compliment you and may be one or two others, that’s exactly the point that you make in your notes.

That it is more than one thing that you have to focus on.

So, that’s the big lesson learnt.

Second point for double-digit earning growth on average and I do stress that when we set this target it was the average of 01, 02, 03 not each year in particular.

Of course we would have to take some action to make sure that if the short-fall in production continue in 2003 that we are secure in delivery of this on average double-digit earning growth.

We are pretty clear that we can do that and we are very clear that we have a series of actions that we can take to do this.

Some will be tough actions but this is what we intend to do, the actions we take let me say will not be at the expense of the long-term either.

Neither in the quality of operation of our assets, their safety, their operational integrity nor robbing the future to pay for today, we wouldn’t do that.

That’s an interesting answer, can I just add on to it.

I think one of the reasons why volumes have taken on such an enormous significance for every body in the market is that frankly it’s a very easy way for us to track your performance and if we’re now in a mode of emphasizing other things over and above volumes then it does bring us back to this question of how do we externally track the financial performance of the company.

I wonder if you’ve got any plans to perhaps put forward other trackers for us and think about what those might be.

Can I just first say, [fully understand us] and I also believe that there are many proposals in the market some of which are very sensible about what we should put out as indicators, guidance if you will about how to attract [ ].

At the moment we don’t find any individual one of these satisfactory.

My sense is and this is simply in the way of trying to entertain a debate and I believe we should have this debate.

Is I think we have to separate out operational things from financial things very clearly.

There are some operational indicators after all the bulk of the operation of the company deal with things like cost above their operation.

They deal with cost to the site or field.

They deal with maximizing margin in the market facing businesses and maximizing volume subject to value in the production businesses.

We need I think to look at that and say what can we do which is very clear to people that doesn’t require them to go into very complicated analyses in order to get the answer.

We do complicated analyses because we like to try and genuinely find out what’s happening to the underlying performance of the company and we believe we do that on a pretty consistent basis internally.

As for volume, it is of course again something which you and others have pointed out is not every barrel is equal and so even volume is not necessarily a good indicator.

Barrels do depend on their cost, their tax and their location and I think it’s only a good comparative indicator if everyone had just about the same portfolio but they clearly don’t.

So, I would say that this is work in progress.

I fully appreciate as I believe my whole team does that one has to be transparent but not comprehensive, clear about the limits to accuracy of indicators and be clear that indicators don’t inadvertently drive strategy in the wrong direction but give indications of how the strategy is actually developing.

Thanks John, let’s move across to the US, Paul [T ]

First of all John Buchanan I just want to wish you warmest wishes in your future endeavors.

Two questions please, first of all on the [ ] I’m looking at a particular slide, slide 5 which talks about the difference between [ ] tool production guidance and the current production guidance including factors such as project delays, storm related incidents and OPEC cuts.

I’m wondering for your future production guidance, are you going to be more inclusive of those kind of contingencies as difficult as it may be and could production projection be inherently optimistic.

That’s the first question, second one is more of a number oriented.

Performance improvement, if you’re still going to have a target of 1.4 that will imply a fairly significant performance improvement in the fourth quarter.

Can you explain to us whether there is going to be some new activities, new programs that you’re planning to put in place?

Thank you Paul, I’ll answer both of them.

On a volume issue I want to go back to my discussion of headroom.

When we set the targets in 2000 we had an awful lot of head room above, even the upper envelope of the target we set, the 7% growth rate.

I think that you should expect and we should set targets for a company like this so that we know very well that not everything works right every year, it just doesn’t.

It’s close to impossible to get everything right every year.

We should not be construed at this time of making excuses about why we haven’t produced the volumes, these are not excuses, the simple thing is we haven’t.

There are reasons so to illustrate to you what actually went on we should be having enough headroom to make sure that a company of our scale takes care of performance management issues without breeching the target.

I think actually if I may say so, it’s a small amount.

The storms in the Gulf of Mexico have genuinely at least for our assets been very significantly more severe than the last 10 years.

We’ve used the meterological data of the last 10 years to set our allowance for this sort of storm.

That would be slightly unusual but again it’s a small number and in the whole we should be taking care of it.

So, we will be looking at that as I indicated as one of the five things we’re looking at in terms of saying what should we do next.

As to the 1.4bln dollar performance improvement we’ve given a range of 1.2-1.4.

I think what actions we’re taking will not have a great impact in 2002, it simply takes time to see the consequence of what we are going to do and I would expect them to come through in 2003.

There are some things that will improve performance notably this if I could just tell everyone, of the total compensation of the top, actually quite a large number of executives in BP [getting to] 1000 of them, is performance related.

Total comp is performance related, we clearly haven’t performed so therefore compensation is down and therefore this will add to shareholder retained earnings, it will not be distributed to executives.

Thanks for the insight I appreciate that

John Browne Thank you Paul and thank you for your remarks.

Lesley LaFaye from the buy side

John I would like to clarify, there is a comment that you made suggesting that the short-term production profile to 2005 now looks to need about $1bln more capital than you had originally anticipated.

Are we to understand then that if the production growth targets to ’05 come down to day 3-3.5% there will be no commensurate change in the E&P [CAP] expense?

Lesley it’s too early to tell, if I can say.

You’re asking a question now which requires a lot of work to get to the optimization point.

I repeat it again that we do have the option to maintain the 7.5% growth profile that I’ve just read out but we have to look I think at the mix of capital, retained assets, disposed assets and the focus on [pacing] in order to come up with the capital allocation in the company.

Broadly I would say this without giving any answer at all that is this -- in the oil and gas business in BP in particular, we come back to this question of balancing investment and cash generation at $16 per barrel and other [suites] of assumptions.

This is very important because no one can tell where the price of oil will go and therefore it is very unwise to extent yourself too far.

A couple of questions of I could please.

Are there any oil and gas implications of the impairments which are indicated in this period?

I’ll ask Andy Ingles to answer that question.

Yes, in [ ] it’s around 180 million barrels.

Reduction I assume?

Can I assume that’s a reduction or downward revision in reserves?

It is 180 million barrels and this is a downward revision of reserves.

So the comments you made previously regarding the fact that production outlook is influenced by reserve levels, reservoir quality and things of that sort, this 180 million barrel reduction certainly adds a bearing on it does it not.

Not really Mark because actually if you look at the detail of these things, first Algeria REB basically wasn’t producting, secondly Venezuela, the [Borrocan] wasn’t producing and thirdly [Badamie] was only producing a tiny amount so this is actually not changing the reserves I would say that are accessible to production.

Put another, if you look at the data this is 1% of the reserves.

I don’t think that this a material change to the accessible reserves in the legacy assets.

With respect to the BP [ ] portion of that, I know the release listed a number of [Arco] assets are there any BP assets that were subjected to this impairment?

There are.

Can you identify the significant ones?

Thank you Mark let’s move on.

Rod McClean, CSFB.

Let’s try again, back in the UK.

[Break in audio]

to the underlying double-digit earnings growth in 2003, I know you aren’t really willing to talk about E&P, can you say where you see potential and the opportunity either downstream or in chemical to deliver either volume or incremental cost performance next year for most [ ].

A second, this is specific to the baseline E&P production, can you where specifically you see problems justifying incremental and best [ ] baseline.

Is it across the board or are there specific areas like Alaska in the North Sea that can justify that incremental investment there?

Let’s mix this one around a bit, underpinning performance as we go forward.

Let’s start with Ken’s, Byron.

Thank you for the question.

In Chemicals we’ve made a big step jump improvement this year.

It was as a result of the basics of taking the operational capacity and using it more effectively, that’s about volume and with a focus towards driving out cost on all of the fronts at the operations level and as John Browne was referring to it in his remarks at the level above the plant and we’ve made a big headway in that across this year but there is just much more work to be done and on top of this we are looking to reduce the overall focus of our chemical streams activities.

We will see on the back of that as fitting out of some parts of our portfolio small bits here and there but focusing the attention to a few which will open up yet greater opportunities to reduce cost and improve efficiency.

On the downstream business again similar to Chemicals, looking at all elements of portfolio volume and cost with flat CAPEX the attention will go on productivity and performance drive.

A bit like Kens again, this one looks at the performance of retail this year, the question is asked, how do you lower the breakeven point of such a tough business.

So this will be our main focus as we go forward.

In addition of course in the down stream we’ve got all the benefits to come from further synergies through the integration of [Vaber].

Andy what about the upstream.

The upstream as John has said, we are looking very hard at the whole deployment of capital into the base.

I think there are opportunities in Alaska, the North Sea and North America gas.

I think it’s important that we drive that investment such that brings the best economic return and that’s the basis of the exercise that we’re doing so we have opportunities, the important thing to do is ensure that we optimize injection of the capital.

Mark I would like to add a couple of things.

Obviously with the increased taxation in the North Sea and we are still awaiting whether or not in reality royalty will be removed.

We haven’t heard anything about that yet.

We have to look very, very carefully at the cost function in the North Sea and indeed what is the right distribution of assets there.

In addition right across the legacy base we have to make I think some very clear distinctions about just producing what’s behind [pipe] and making sure that we don’t let opportunities go from detailed [close-in]exploration and potential leasing of next door blocks and things like that.

This has now where we’re looking at to make sure that we neither over invest nor actually under invest.

To finish of on this, outside the direct business control we are putting under the microscope all the other overheads.

Have we got it right, have we got clarity of accountability, have we got overlap as a result of these mergers and acquisitions, by region, by function etc.

By regional offices, all of those things will be on the agenda for 2003.

Right let’s turn to Jeremy Eldom.

I just have two questions, firstly on your strategic decision to shift $1bln a year of CAPEX from the base to the longer-term projects.

I’m sure that when you originally sketched out your capital plans, you had done an analysis of where best to spend the capital, can you give us an overview of what has changed to make it more attractive now to spend on the longer-term projects rather than the near term.

Secondly on a point of understanding, you mentioned that you still had the capacity if you so choose to deliver 4.2 million barrels per day by the end of 05 or maybe into 06.

I had thought that the 4.2 million was an average for 05, was I wrong in that?

Thank you let me answer the questions first.

The 4.2 was an average rate which comes out of the 5.5 annual average growth rate.

I think in the light of all we’ve seen Jeremy, that it’s possible that we can do it not I think on average over 05 but at the end of 05 we may have to go into 06 if we choose to do this.

Our reason is very simple, it’s more on timing changes on projects, we have a significant number of projects coming on stream in 05 so they may flip from one part of the year to the other part of the year.

Secondly, the decision to go longer in investment, I think was primarily driven by the performance of these new seals $16 per barrel.

They all seem to have better economics and seem to drive the investment in the short to the long term.

We have to consider that very carefully.

I would expect they had the better economics but I wonder was there something that changed about your view of the economics as you seem them now compared with as your saw them two years ago.

I sense Jeremy it was a bounce back.

If I could just remind you of 2001, in 2001 we said that we felt that we’d over invested in the base by some amount partly because we were drive by the very high oil and gas prices at the time and we took action, the upstream took action to counter balance that and perhaps it went just a bit to far.

That’s great thank you very much.

Thank you Jeremy, let’s try Doug Carrison.

Good afternoon.

Best wishes to you John in your future endeavors to start of with.

My question is to John Browne and performance objectives.

John within the context of maximization of value which I suspect is of utmost importance to everyone.

There seems to be great emphasis on portfolio management activities maybe forthcoming which has been a pretty important area of value for BP in the past.

So, my question is while it may be too early to answer this questions, and this ties in with Richard’s question early, are there specific geographical regions or particular places that you feel stand out as areas in need of remedial action.

Second, why you did exchange your cost production in E&P in 2001, could you highlight some of the areas that may cause unit cost to come in lower than the 6% target earlier in the year.

Again John Buchanan pointed out this may not happen but can you provide some thoughts and guidance in that area as well?

I’m very reluctant, of course, to speculate on where our portfolio activity will take.

But I would say this: the bulk of the [break in audio] ...

As for the costs this year, they’re not going to come in at 6% because these are lifting costs, and they’re units.

And if the production’s down, then the unit lifting costs will not come down as fast as they were expected to.

They’ll come down [a small bit].

Okay.

Can you provide some geographical color, or can we assume, you know, the broad-based comment is [applicable] here as well?

For which part of the question?

The cost structure.

Cost structure, I think, is right across the board.

I mean, I think in a case like Alaska is pretty well track.

Most of the North Sea is actually on track.

North Sea has done pretty well in the bulk of it, pretty well on forecast.

So, the rest is by deference.

Okay.

Thanks a lot, guys.

Thanks, Doug, and thanks for your remarks.

Let’s go to the web.

There’s a question from Paul Spelling that is on outlook.

Doesn’t shifting the investment program the base to growth increase the degree of oil price risk?

Isn’t a near-term barrel in the hand worth two longer-term barrels in the bush??.

John, it sounds like your sort of question.

Well, Paul, I think this is a question that has been discussed by many people for a very long time.

Of course, it is the trade-off between net present value and current running return, and it very much depends on what basis are we looking at it.

Are we looking at it at our so-called mid-cycle, which we use for financing our measurement?

Or do we look at it at the spot?

Spot, of course, changes.

So, it seems to me that there’s always a balance here, as a reasonable business basis, a reasonable balance when you have to take all these things into account.

Right.

Back to the UK.

Neil Perry.

Are you there, Neil?

Thank you.

I just want to go back to an earlier question, first of all, and say, if we?re putting volume growth on the back burner, as way of judging [explorated] oil companies, which I welcome, can you tell us what you look at when you?re screening all your products and you?re looking at the appropriate rate of growth?

How are you screening it?

How are you deciding what the appropriate rate of growth is?

What indicator are you using?

And on a similar subject, the returns on capital were 14.3% in the quarter.

Your mid-cycle target is 15%.

And given the higher-than-expected net investment and that slightly slower underlying earnings growth, slower volume growth into next year, what direction can we expect those returns to go in?

Are you prepared to restate your 15% target?

Well, Neil, first, we don’t actually know what the mix is next year, so I think it’d be wrong to assume that we’re going to have higher net investments and so forth.

So, we need, I think, to give you guidance on that when we’ve done our planning.

We normally do that anyway at the fourth quarter results.

Secondly, I would say ...

I’ve suddenly forgotten your first question, which I think is the number of criteria we look at screening.

I think we look at the quality of projects, their sustainability, their returns based on standardized measures, their risks and the overall decline, and critically the level of capital intensity, because this says something about how fast we have to work to get the money back.

So, we tend to look at it internally as something that is built up from the bottom, and then we try and optimize the pattern of investment to get the best value for money, if can put it like that: returns versus growth, capital in versus cash out.

Those are the criteria we look at.

Okay.

Could I ask you just to go back to that returns question and give us an indication of where you think returns will be heading, given the updates you’ve given us today?

Well, we’ve said that our target, we’ve never actually said what the return is to be.

It is to grow them, or at least keep them flat.

And that’s what we’re going to be targeting.

Thank you.

Thank you, Neil.

Rod McLane, are you still there, Rod?

Yes, I am.

Can you hear me?

I have just two fairly basic questions.

At the time of the second quarter results, there was a ... you showed a couple of slides which suggested improving returns in the Upstream over the sort of 2002-2006 period.

And I suppose my question is, if you decide to retain your growth targets and invest toward the 4.2 million barrels a day target, which you’re suggesting is going to cost you $1bln more, can you still improve returns through that period, or are we looking now at a sort of situation where Upstream returns might be flat, at best, or possibly even declining if you decide to stick with the growth targets?

Second question is somewhat different.

This year’s been a rather strange year.

If you look at your realizations for the nine months, they’re significantly, certainly for oil prices, ahead of your mid-cycle assumptions.

And yet, you’ve had two quarters, the first two quarters, where your earnings were below mid-cycle.

Third quarter, your earnings were in line with mid-cycle.

Does that give you, sort of, cause for concern?

Does it lead you to reconsider the sort of asset allocation across the various Upstream and Downstream and Chemicals businesses?

Or you do you just put 2002 down as a rather unusual year?

Let me have [look] a the second question first.

It’s certainly true that oil and gas prices have been above mid-cycle but, of course, as you think you infer from what you say, there’s more to it than that, which is that the Refining margin and the Chemicals margin.

Recall that Refining margins were much higher last year.

I think it’s very clear that they are quite volatile.

And so, it says, but through the cycle, they look exactly where we put them at the moment, which is neither aggressive nor pessimistic.

As to Chemicals, we have taken significant strategic action to make sure that the Chemicals portfolio is fit to be highly competitive, is reduced in costs, reduced in capital inputs.

And, of course, at this present time, it’s producing very low returns.

But, again, we would expect, at some stage, the cycle to turn.

I think if we found the cycle never turning ... we are very low at the moment ... then we’d have to rethink.

But, at the moment, the Chemicals industry is adding no capacity additions at all, and yet growth is actually taking place.

So, I think this is something which, over a period, and I won’t call which year, may well get to mid-cycle and above.

And mid-cycle isn’t actually very much higher than where we are at the moment.

It’s about $20 a tonne ... $20 to $25 a tonne, which seems like a lot when you’re running a Chemicals business ... are looking [not too great] at the moment.

That’s the second question.

I’m sorry.

I’ve forgotten what the first part of your question was.

Yeah, John, the first part was just back to the improving returns statement that you made at the time of the second quarter results from 2002 to 2006.

I was just wondering, you know, can you still deliver that sort of performance if you decide, indeed, to retain ...

The answer is ?yes?.

We can, but it would only grow towards the end of the period.

It wouldn’t be a smooth progression.

Okay.

Thank you.

Thank you, Rod.

Back to the US.

Steve Pheipher.

Are you there, Steve?

Yes.

Good afternoon, gentlemen.

Two questions: just drilling into one of the issues of base production levels.

Could you talk a little bit about US gas, in terms of what you may be changing, in terms of your view of that?

Is it a change in the reserve potential?

Is it a change in the cost?

Is it a change in just the pipeline constraints?

What perhaps has changed in your view of the base, as it relates to North America gas?

And my second question is related to the asset reductions that you recognize in the quarter.

Was this part of a comprehensive review that you conducted?

If at this point you have reviewed all of your projects, what specifically was it that triggered the asset reduction?

Okay.

Thank you.

On the base production, on particular in gas.

I mean, not much has changed, Steve.

The reserves are clearly there.

We have a pretty good position.

Costs we look at continuously.

It may be that we’ll conclude that the cost profile of some assets is not for us, but might be for other people.

We have to see.

So, that’s where we are on that.

There have been some pipeline constraints, which have caused us to reduce volumes; they’re principally in the [San Juan] and the [Wampees], and things are being done about that right now.

So, we should get rid of that pipeline constraint.

Clearly, as you all know, in the industry, there is every indication that the reserve base in the lower-48 (states) is having a tough time keeping up with demands on it.

I think our reserve base is pretty.

We’ll have another go at it, looking at every piece very carefully, as we normally do.

John, shall I answer the second question?

Asking about impairment and triggers to impairment, there are a number.

We do this on a regular basis.

We are particularly looking for any under-performing assets, not in one quarter, but over a period of time.

And also, as reserve estimates proceed to improve, that too can trigger impairment.

The Upstream part of the business had been examining the portfolio for a period, post all the merger and acquisition activity, just to put everything under review.

And this is where they’ve got; it was a comprehensive review.

Similarly, in other parts of the business, take Chemicals as an example, they too have been casting the net over all of their new asset base, and out of that process came Picky Penny.

Picky Penny has been under the microscope for some time, but while there was the prospect of doing a wider rationalization in Indonesia, before those commercial negotiations were completed it would have been premature.

Those commercial negotiations came to an end, so that’s what triggered that particular impairment.

Right.

Let’s move on.

Let’s go back to the web.

Irene Hermona has asked on performance: ?Is there much headroom left in terms of further material cost improvements?

That is, to what extent can the company resort to further cost economies as a means of continuing to improve [receipts] in the face of a potential decision to live with somewhat lower volume growth??.

Irene, this is something that we’re presently looking at, but I’ll just give you some indications of the areas.

First, of course, the costs of the company are a direct relation to the scale of the company.

So, whenever you sell anything, you don’t just sell the asset, you sell the costs with it as well, or you get out the costs.

Secondly, overheads always need to be looked at very, very carefully.

Thirdly, the back office, it seems to me that our end-to-end processes are not designed in the shape they should be for the future.

This will take time, but it is something which has great potential.

So, I just mention a few points like this, that we’re looking at at the moment.

Right.

Bert, are you there?

I hope you can hear me because I don’t hear you answer, but I suppose so.

In view of the fact that you say that the œ1bln extra investment is now under review for the next few, say, four years, let’s assume that that makes the difference between a 5% and a 3% production growth.

It still seems a rather low figure in view of the, say, 75 million extra barrels you get.

Do you, sort of, implicitly suggest with decision that you see considerably lower oil prices in the years ahead?

That’s my first question.

My second question is regarding the impairments.

Should we expect any of these impairments to return in the next quarters?

How do you expect that to go forward, especially with regard to the Arco assets?

Let me just answer the first part.

I’ll ask John to answer the second part.

Our review is not oil price-related.

We look at the strategy of the Upstream and, therefore, the planning of the Upstream, based on our so-called $16 case.

That, I think, is very important because it gives us, as it were, an agnostic view as to trying to pull the oil price in what is actually a very long time.

That is to say, more than a quarter in what is a very volatile market.

So, we have to do it that way.

We obviously look at the details around each quarter, each half year, based on the oil price.

I wouldn’t assume anything as a result of our review.

I come back to saying what I said in answer to the first question, and I want to repeat it one more time.

First, we do retain the option to increase reported production to 4.2bln a day by late 2005, early 2006, with clear shape to the production profile, and I gave you that.

And that’s at around a capital cost of increase of about $1bln a year.

This would actually deliver growing cash margins per barrel through period, flat profit margins in the short term, growing to 2005-2006.

So, I believe that’s our [thank] stock case.

The real question is: Can we improve that as we go forward?

And this debate, this discussion is all about saying: And that is exactly what we’re trying to do.

Bert, on the second part of your question on impairments, barring some new event or series of events, unless there are specific impairment triggers ... that could be a review of reserves estimate, or some such event ... no, you will not see a succession of impairment reviews, quarter by quarter.

This was a thorough review carried out, not just in the Upstream, as I?ve touched on, but elsewhere in the corporation as well.

Thank you very much.

Right.

Peter Nicholl, ABN Amro.

A couple of questions, if I may.

You mentioned, I think if I heard you correctly John, talking about that your reserve replacement for the ... you know, as you indicate organic growth is right about 156% over the past few years.

At the time of the 2Q, you were indicating that you were likely to be about 170% this year, whereas I think your comment this time was sort of similar levels.

That doesn’t appear to equate to the 180 million barrels of reserve impairments, or am I reading too much into particular numbers?

And the second one was, just changing the subject a little bit, you in recent weeks and months have been linked either with JNK directly or through mergers of Sodenco and JNK, and you’ve obviously in the past expressed your interest in expanding in Russia.

I was just wondering if you could make any comment at all?

Peter, I think you’ve read just a touch too much into what I said about reserve and replacement.

I mean, quite technically, of course, we will be producing less than we had imagined this year.

So, that’s one issue.

And secondly, yes indeed, we’ve written down 180 million barrels, which is very tiny indeed in the full scheme of things.

It’s about 15% of production.

So, I take it I think in the spirit that it’s given, but it’s a similar level.

I don’t want to be precise until we know actually what it is we’re going to do.

Secondly, we’ve made no secret that, based on what we’ve learned about Sodenco, and the way in which we understand how they manage in Russia, that we would like to expand our position in Russia.

And to expand our position in Russia, we’ll need for us to go through West Siberia in order to get to the future.

So, that means we do have to take on West Siberian production to get to the future.

We’ve, I think, learnt a lot about what to do in dealing with companies, in particular, the bad experiences we’ve had with Sodenco, as well as the good ones.

But that’s all I’m prepared to say.

We never comment on whether we’re in discussions with any company, on matters of acquisitions and divestitures, and I won’t break that rule just now.

Thanks, John.

What I’d like to do is bring this to a close in about five minutes.

So, we’ve got time for just a couple more questions.

Jack Heiden, are you there in the US?

Yes, I’m here.

I have two questions related to the ... sequentially.

In the UK, your production is down sequentially about 67,000 barrels a day.

In the US, 57,000 barrels a day.

Could you elaborate a little bit.

What percentage of that is decline, and what percentage of that is, you know, some unusual events?

And the second question is: I’m a little bit puzzled that you had 150 wells in Alaska shut down.

How could you miss something like that with all your people over there, and having a problem like that, you know, come up?

Jack, thank you for your questions.

First, on Alaska, there 150-well shut in was a precautionary action.

I do stress ... a precautionary action, deliberate, in order to make sure we hadn’t missed anything.

I don’t believe we have missed anything, and I believe that they’re all coming back on pretty quickly.

Andy ...

Yeah, I think, as John has said, it’s hugely important that we deal with this matter in the right way.

And I think there are actually still about 80 wells that are being reviewed, John.

So, some of them have come back, where it’s right to do, but we’re still taking a very cautious approach.

Now, Jack, on the others, I see nothing unusual in the data.

Setting aside these events, the UK is actually pretty well on track on its plan, and actually has been pretty well on track on its plan for quite a long time.

In the US, most of this has to do with the Gulf of Mexico storms, the problem in Prudo Bay, and that’s pretty well it.

So, nothing unusual I think in these numbers.

Thanks, John.

Fred Leipher.

Fred, are you there?

Hello, John, can you hear me.

First, John Buchanan, I want to wish you the best of luck in retirement.

I have some three questions.

The first is a numerical question.

What were the Sodenco buy-ins from the third quarter?

What were they in a year ago?

And how much of the change was due to the change in your interest?

Secondly, it’s not clear, John Brow, from your comments, what’s changed to cause you to re-evaluate your level of spending on the base production?

And thirdly, John, in your remarks, you said that costs have crept up in this high oil price environment over the last three years.

What costs are you referring to?

Right.

Three parts.

Sodenco volume, Andy, have you got that?

Thank you.

The Sodenco volume in the third quarter was around 30,000 barrels a day, from the deepening.

And the deal we’ve done in the second quarter averages out to around 35,000 barrels a day for the year.

What was the change due to your change in the interest?

It was due to our change in ownership, yeah?

Is all of that due to the change in ownership, or is there some organic growth in there?

Um, there’s a little bit of organic growth, but I think you should see that as primarily due to the change in ownership. [inaudible] ...

Yeah, it’s growing at about 3% to 5%.

Okay.

Second part, what’s changed to cause re-evaluation of the level of base?

I think, Fred, it’s to do with what other things that we can do.

The level of investment that we have going into the new growth projects.

Clearly, they’re pretty big and robust, and so it’s a question then of: what is the right combination of things that we want to do?

That’s the question.

And so that is what we are re-evaluating.

Secondly, what costs we’re referring to: these are primarily costs above the level of the business.

That is to say, not the cost of operating a refinery, gas station or oil fields, but is the cost above the business.

And I believe that those, net-net, have got too big.

Can you give us an example of what type of cost.

I’m sorry.

Yeah, John, can you give us some examples of what costs you’re referring to, costs above the ...

I did previously, first, they are the general overheads of the firm, the amount we spend in such things ?government and public affairs?, the cost of maintaining more than one office in the US, the cost of our treatment of medial benefit, of add-ons to salaries, the costs of the number of offices we have in London, the nature the organization in Europe, why we have to have national offices, why we have so many servers, why we have to have different business process for different parts of the firm ...

I could carry on.

Was that enough.

Got it, thanks.

I’m sure you’ve got it, Fred.

I got it.

Thank you very much.

One final question.

Katie Thompson of Gartmore has been very patient.

Katie, are you still on the line?

Yeah, it’s a question actually on your cash.

I was looking at that slide 19, with some ... and cash.

And you did mention that you did do share buy-backs in the third quarter.

I know that your policy is to buy back shares above mid-cycle.

Can you maybe give an indication about, obviously it’s quite early in the quarter, but whether your policy has changed, just looking at the cash?

Whether you have, how much flexibility you have to maintain buy-backs at the kind of third quarter rate, going forward?

Right.

Let me start.

We will look positively at share back-back if the market stays above mid-cycle.

It started well in the third quarter, having ended the second quarter strongly.

We started the third quarter above mid-cycle ... clearly above mid-cycle, but it deteriorated, disappointingly.

We’ll look at the fourth quarter and see what eventuates.

At the moment, it’s a tricky call.

But assuming we’re still in an open period, we’d look positively at some form of share buy-back.

Okay, thanks.

Right.

Thank you, everybody.

Thank you for your patience.

Sorry, apologies to the small number of folk we didn’t get to.

But thank you for your patience.

All the very best.