英國石油 (BP) 2007 Q3 法說會逐字稿

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

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

Please go ahead sir.

Hello and welcome to BPs third quarter 2007 results conference call.

My name is Fergus McLeod, BPs Head of Investor Relations.

Joining me is Byron Grote, our Chief Financial Officer.

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

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

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

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

Second, I'd like to draw your attention to the information on this cautionary slide.

Now, over to Byron.

Thank you, Fergus.

Good day to those joining us on this call.

I will begin my review of the quarter with the trading environment.

The table shows the percentage year on year changes in BP's average upstream realizations and refining global indicator margin for the third quarter as well as year-to-date.

In the third quarter, oil prices continue to strengthen amid concerns over hurricane activity and draws on U.S.

crude stocks.

Our average 3Q liquids realization of $71 per barrel was higher than both the previous quarter and last year.

By contrast, our third quarter gas realization of around $3.90 per thousand cubic feet was down 12% compared to a year ago as gas prices were lower in both the United States and the United Kingdom, in light of ample supplies and mild weather conditions.

Taking both oil and gas together, our total hydrocarbon realizations for the quarter and year-to-date were comparable to last year.

In refining our 3Q indicator margin fell to around $8 per barrel on the back of lower seasonal demand and the increased supply from the switch to winter grade gasoline.

This indicator margin was half that experienced in 2Q '07 and 4% lower than 3Q '06.

The actual margins realized by our own refineries were, however, significantly lower than the same period last year, mainly due to the narrowing of light, heavy crude differentials.

Turning now to the financials.

Overall our results for the quarter and year-to-date were down year on year.

This was the result of a number of factors which included the continued impact of operational issues as well as the absence of favorable once-off items realized last year.

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

Both our replacement cost profit of $3.9 billion and our profit including inventory gains and losses of $4.4 billion were down significantly compared to 3Q '06.

Operating cash flow of $6.4 billion was up 24% compared to last year.

The per share metric shown reflect the benefit of the reduction in our shares outstanding by 4% over the past year.

The [$0.10825] per share dividend announced today, which will be paid in December is 10% higher than a year ago.

The sterling dividend is roughly the same year on year reflecting the sharply weaker dollar.

Moving now to our segment, in E&P we reported a pretax profit of $6.3 billion for the third quarter which included small non-operating gains, primarily from the sale of assets.

Excluding these non-operating items, our underlying result was down by $1.1 billion compared with last year.

The benefits seen from stronger liquids realizations were more than offset by lower gas realizations, lower production, higher cost, and the absence of the disposal gains totaling $1 billion which we realized in our equity accounted entities last year, primarily from TNK BP.

Reported production was 3.65 million barrels of oil equivalent per day, a decline of 4% compared with a year earlier.

After adjusting for the affect of disposals, lower entitlements in our production sharing agreements, and the cat's pipeline shutdown in the North Sea, production for the quarter was broadly flat.

Full year production is still expected to be in the range of 3.8 million to 3.9 million barrels of oil equivalent per day as indicated back in February.

In refining and marketing we reported a third quarter result of $380 million, which included a charge of $340 million for non-operating items.

These charges were primarily related to new provisions and revisions to existing ones.

Excluding these non-operating items, our underlying result was $720 million compared to $1.9 billion a year ago.

This reflects weak refinery margins and the continued impact of operational issues, particularly at the Whiting refinery.

The quarter's result also reflected greater integrity and repair spend as well as adverse effects from fair value accounting.

Turning to gas power renewable, we reported a pretax loss of $60 million compared with a profit of $150 million a year ago.

Our 3Q underlying result decreased by nearly $300 million relative to the previous year.

This reflected a significant reduction in the contribution from the marketing and trading businesses, lower natural gas liquids volume, and higher alternative energy expenditure, partly offset by improved margins in the NGL business.

In other businesses in corporate, or OB&C our third quarter result included a net charge of around $200 million in respect of non-operating items, which was primarily comprised of new provisions and revisions to existing ones.

As you may recall, we conduct a review of our environmental and various other provisions each year in the third quarter.

The results of which we include in non-operating item.

Our expected full year underlying charge remains within the range I indicated in February.

Turning now to cash flow, this slide compares our sources and uses of cash in the first nine months of 2006 and 2007.

Operating cash flow of over $20 billion and disposals of $3.9 billion funded $12.5 billion of organic capital spending and $1.2 billion of acquisitions plus $12 billion of shareholder distributions.

Our net debt ratio remained flat and at the bottom end of our targeted band of 20 to 30%.

Our shareholder distributions for the first nine months were $12 billion.

Dividend payments have exceeded $6 billion, and we have bought back $6 billion worth of shares.

As I've said many times, we remain committed to distributing 100% of excess free cash flow to investors, other factors being appropriate.

Now let me talk about some of the progress we've made.

In E&P we are building momentum in our operations through the delivery of major projects.

Early in October, we achieved the successful start-up of greater Plutonia, BP's first operated project in Angola.

And in the deep water Gulf of Mexico, we have started commissioning the Atlantis field.

In the fourth quarter we expect production to ramp up from these and other upstream projects.

In R&M, we continue to make progress in the recommissioning of both the Texas City and Whiting refineries in line with prior guidance.

By the end of the fourth quarter of 2007, we expect available production capacity to reach 400,000 barrels per day at Texas City.

And at Whiting we plan to reach 300,000 barrels per day available production capacity with our crew processing by year end.

We expect to restore both refineries to their full crude capacity and flexibility in the first half of 2008.

We have recently announced changes, which are designed to simplify the organization and improve productivity and accountability, bringing up operating units to enable them to focus on safe, reliable, and profitable operations.

BP will in the future comprise two primary business segments, exploration and production, and refining and marketing.

A separate division, alternative energy, will handle BP's low carbon businesses and future growth options outside oil and gas.

We will continue to report along current lines until the end of the year and will restate our historic results in February of next year.

We expect to reduce overhead and complexity by reducing layers of management and redeploying staff to strengthen front line operations.

For example, in our exploration and production business, we are simplifying the organization with a strengthened focus on 13 strategic performance units as the key deliverers of performance.

These 13 strategic performance units will now report directly to Andy Inglis, the Head of E&P, and we are selectively removing layers below that level.

We are consolidating our existing centers of expertise in both Houston and Sunbury to pool key skills and resources, increasing standardization and productivity and reducing costs.

And we are strengthening incentivization for the delivery of plans for continuous improvement in our operations giving frontline staff a clear and more direct stake in our success.

These changes will support more consistent execution of our strategy.

We have great positions in many of the major hydrocarbon basins of the world as well as in the markets of key economies.

And we are preparing for the longer term by building a new, low carbon energy business.

Our problem has not been the strategy itself but our execution of it.

That's why our focus remains the same.

Safety, people, and the delivery of improved performance.

That concludes my presentation of our third quarter results.

We'll now be happy to take your questions.

(OPERATOR INSTRUCTIONS) If you're listening on the web please submit your question using the web question facility.

Thank you, operator.

I think we're ready to take the first question which comes from Neil McMahon at Sanford Bernstein.

Neil, are you there?

Yes, thanks Fergus.

Just a few questions.

The first one is really, and thanks for Byron's remarks on the organizational change.

What might be useful is if you could just go through what is the real difference today between the way information will flow from, let's say, the reservoir engineer or geologist at the cold face as it were up to Andy Inglis as Head of E&P versus what was happening in the past.

And I've got a follow-up question as well.

Thanks.

Thank you for that question, Neil.

Clearly the changes that we've announced have not been put into full affect yet.

So I can't talk about the changes that exist today, but the changes that we're in the process of implementing.

One thing that will definitely occur is that there will be less layers between that individual and Andy.

We're going to be taking out several layers in all parts of the organization, in many cases extending the span of control, and by doing that removing the need for incremental layers in the process.

Much of this is about ensuring that the right information is available.

The flow of it occurs to the right levels in the organization.

We probably today have far too many people involved in analyzing information from different perspectives.

And one of the things that we've done within the organization is announce that we're taking a move to integrate our control and planning and performance analysis activities, all of whom were working with data from different perspectives but doing it independently and treating that as one functional activity as opposed to three.

We believe that's an example of where deep efficiencies can be driven through all layers of the organization.

Okay.

Great.

Just a second question on looking at Russia, obviously you're saying, I suppose a memorandum of understanding with Gazprom.

When are we likely to get some idea of how the relationship is going to work going forward and with regard to the potential of any LNG swaps or indeed getting back into Kovykta?

Neil, we are in discussions with Gazprom.

We are looking for opportunities with them that create a balance in the relationship, something that's a win for both sides.

We remain confident that that can be achieved, but it would be inappropriate of me to speak to specifics of that at this time.

Okay, thanks.

Thank you very much.

Now we'd like to move to Mark Iannotti with Merrill Lynch.

Mark are you there?

A couple of questions.

Firstly, can you maybe borrow me just a few more granular comments on why we saw such a good result in gas and power this quarter and maybe try and help us distinguish what's one-off, and what could be a factor going forward?

And also maybe give us some guidance on how much you think this business can earn on an ongoing basis given that you will be stopping showing it from the start of this year -- of next year?

Second question, with three or four decent sized new E&P projects coming into the portfolio in the fourth quarter, can you maybe give us any early idea of either group or E&P level depreciation for 2008 against your current annualized level of about $10 billion for the group?

Thank you, Mark.

Well, let me begin in gas and power.

As I indicated in my remarks, there are a number of factors.

Probably the biggest contributor to there being a loss in the quarter was a very weak performance, actually losses from our gas trading and marketing activities.

This is, I think, to be expected.

There the contribution goes up and down.

It was impacted quite materially as were many trading activities during the July period when all markets were subjected to a deep and unanticipated volatility.

So that is one area where I think it would be appropriate to treat it as a once-off.

We did have some additional impacts with respect to lower natural gas liquids volumes.

That's a consequence of just doing the split differently there.

And a bit higher costs in alternative energy as we're continuing to build our business there, there are costs of business development costs ahead of the actual developments themselves.

So some of these things, I think, in fact, most of these things you can treat as once-off affects in the third quarter.

Now, as far as how we're breaking the business up, the bulk of this activity will now show through into the exploration production of business and will just be an additional component into Andy Inglis business.

The one element that we're going to separate out and we will be next year showing it as a contributor to other business and corporate is alternative energy itself.

Although we won't be giving a detailed financial disclosure, we certainly will continue to provide you with milestones as we develop the various businesses that make up alternative energy.

As far as exploration and production, and a guidance on depreciation in 2008, it is too early to do that.

There will be additional depreciation from the start-ups, some of which are very big capital projects.

But I'd also like to point out that as we move to SEC reserves reporting in 2007, that in its own right created an increment of DD&A because of the way in which the reserves treatment is applied to production sharing contracts.

And that element has led to increased charges of about $100 million a quarter.

And in fact, we have about another $100 million a quarter that is a consequence of reevaluating decommissioning expenditures, decommissioning estimates over the course of the past year.

So when you're comparing 3Q of '07 back to 3Q of '06 there's bout $200 million of noncash charges that radiate from those two affects.

2008, if oil prices stay where they are, we'll have another impact with respect to the way in which production sharing contracts respond on a reserves basis to very high year end prices.

But rather than speculate, I think it's best to wait until our February presentation.

Where we'll be able to give you much clearer guidance in line with the activities that have progressed in the interim and with full knowledge of the way of prices into the year.

Thanks.

Mark, just to answer that without getting into full cost of 2008, give you some sense in the rise in the NP DDA that Byron has been referring to for 2007, it's in the order of $1.5 billion within that group number that you mentioned, so give you some sense of the momentum there.

Moving to the United States we've got on the line Nicki Decker from Bear, Stearns.

Nicki, good morning.

Good afternoon, Fergus, thank you.

Byron, my question is on cost.

Would you talk a little bit about where the cost reduction will occur, the magnitude and timing.

I'm referring to whether it will all occur in -- on the corporate level or perhaps there are some opportunities on the operational level.

Thank you.

Nicki, again, thanks for a very pertinent question.

As Tony Hayward said, we've not set up any specific cost targets.

We don't know what is achievable at this stage and we prefer to lead from the perspective of addressing complexity within the organization by taking steps to remove it, and then seeing what benefits will flow from that.

We are confident that we have far too complex of an organizational structure.

And that's standing in the way of excellence on the operational side as well as adding a significant overhead burden to the Company as a whole.

That overhead doesn't just exist at the Corporate level.

It is fettered in at various levels within the business segments as well.

So this is aimed at a complete housecleaning from the top to the bottom of the organization.

We are not aiming to address front-line staff, those who are actually involved in an operational activity.

In fact, on the contrary, we've been taking significant steps to beef up personnel in that area.

So in response to your question, it's aimed at overheads but it's primarily at unraveling the complexity that the Company has inadvertently developed over the course of the last several years.

That's great.

Thank you, Byron.

Thanks, Nicki.

Back to London, Jon Rigby from UBS.

Two questions.

First is just to back up your comment on strategy.

You said that execution was the issue and not strategy.

Can you just comment as a sitting member of the Board, the last three years you've clearly been focused very internally.

Has that led you to not be able to think sort of why the strategic base is or has it constrained you from taking action strategically because of the things you've had to do.

I say that because the last three, to three and a half years, clearly the world has significantly changed and obviously your strategy hasn't.

And the second question is just on the point you made about consolidating key areas of expertise in E&P.

Could you give us examples of what areas of expertise are being consolidated together, and just get an idea of what areas you consider to important to be brought together in one place.

Thanks.

Jon, as a member of the Board and as the CFO of the group, I will tell you that although we have felt it was appropriate to focus on the fundamental activities of the group, that there was much more value to be unlocked for shareholders by making sure we got our operations right.

And we've worked very, very hard on that across all of our E&P and refining and marketing operations over the past couple of years.

Although we've been deeply focused on that, having said that, we have not felt as though that that has prevented us from pursuing strategic opportunities as they were available.

And I would say that on the E&P side we've worked hard to get access.

We've been successful in Amman and Libya this past year on the refining side.

We thought there were benefits associated with swapping refinery capacity a Corytan and in Rotterdam and we've done so.

In alternative energy we pursued a wide range of transactions to build up capability and opportunity in particular in the wind arena.

So in pursuit of our strategy, we've not been reluctant to pursue opportunities.

What we haven't done is some big mega deal if that's what you were referring to.

But we've certainly not foregone what we believe were very important strategic steps in support of our attempt to build a value for our investors over the longer term.

Fergus.

Yes, Jon, just developing this point Byron made about the Centers of Excellence in Houston and Sunbury just outside London.

Really the idea here is to co-locate people with gas skills, reduce activity in the field.

Let me give you an example, high pressure, high temperature expertise to hold that summarily in a central location, or two central locations rather than attempting to deploy it and every one of those strategic performance units as Byron also mentioned earlier.

It has the incidental affect of reducing the cost, especially expatriate costs in some locations.

But it's those technical skills, it's front end skills, engineering work on projects, it's those skills perhaps that are most valuable and in most short supply within the upstream industry at the moment.

We do think there's a significant productivity and cost and capability uplift that will come from strengthening those two centers in the United States and in Europe.

Thanks.

Moving on now up to Scotland, Jason Kenney from ING.

Jason, are you there?

Good afternoon.

Two questions if I may.

Firstly, on the downstream, the marketing really surprised in the third quarter.

Could you enlighten us on some of the moving parts there and maybe the robustability of marketing in near or median term?

Secondly in Q2 results, share buybacks were seen as slowing given the revenue outages ahead at the time.

Is it too early to see share buybacks quickening going into the new year with revenues returning?

Thank you, Jason.

As far as marketing, when we talk about marketing, there's a very wide swath of different activities that are included in that, not just retail marketing where most people naturally go and where we give ongoing indicators to investors, but also in activities such as lubricants, aviation, fuel activities, marine fuels, and petrochemicals, our acetyls and aeromatics businesses.

It's a very wide portfolio of activity, most of which had better margins in the third quarter than in the second.

And I think the difficulty of reading through all of that heterogenous activity is the explanation for a good portion of the outperformance relative to expectations in refining and marketing.

As far as share buybacks go, I think maybe it would be useful to talk about the momentum of the group, because your question is really a reference to that.

As we look into the fourth quarter, we see a number of milestones that will be met to achieve the things that I referenced in my webcast, in particular various E&P startups and the refining, recommissioning efforts at both Whiting and Texas City.

Much of this is occurring late in the quarter, and therefore will have limited impact on the financials in 4Q.

We will, however, see an improvement in our operational metrics as we move into the first quarter.

But in this phase as well, as is especially true in exploration and production projects, the -- there are start-up costs, so the operational end tends to run ahead of the financial delivery.

But we would then see this picking up as we roll through 2008 with progressive improvement in the underlying financial performance over the course of the year.

So I think it's best thought of as three phases.

Fourth quarter is about meeting milestones, and we're on track to do so.

First quarter should be reflected by a much, a notable improvement in operational metrics.

And over the course of 2008, remembering that we've got two refineries that won't meet their full capacity and flexibility until midyear.

Over the course of 2008 we'd see increasing underlying financial performance showing through.

Share buybacks are then a reflex of the cash delivery we have at hand, recognizing that we have a gearing range in which we anticipate to operate.

As the revenues return and we find that we have excess cash flow, then we will, all other things being equal, increase our share buyback program again.

Many thanks.

Thanks Jason, coming back to London, Theepan from Morgan Stanley.

Good afternoon, Theepan.

Hi, good afternoon, gentlemen.

Just a couple of questions, actually.

Firstly, two quick points on the financials.

I was just wondering whether you could confirm your guidance of $18 billion CapEx for the full year?

And second, just confirm sort of the tax rate for the full year.

Secondly, just on refining and sort of the ramp-up back in Texas City and Whiting, I was wondering whether you could provide any sort of information on the opportunity cost for Q3 from Texas and Whiting?

And then where you see sort of the ramp up for Texas in particular into Q4.

It does seem if you look at the volumes of the throughputs in the U.S.

and they seem to have ramped up quite quickly.

I was wondering whether we may see a quicker than expected return to volumes from Texas?

Thank you.

Well, let me address your financial questions first.

$18 billion does remain our guidance for organic capital spending in 2007.

We indicated that the beginning of the year.

If you look at the year-to-date numbers, they are running a little bit less than that on a pro rata basis, but fourth quarter is normally a high capital spending quarter.

So our expectation is that the number will come out in line with guidance.

Tax rate, the guidance at the end of the year -- at the beginning of the year was 35 to 37%.

It's running year-to-date at the lower end of that.

Fourth quarter is always volatile.

But I have no doubts that it will fall within that range, probably at the lower end of the band.

As far as opportunity cost goes, the losses at Whiting that I had indicated that stem from the problems that were identified there in the second quarter of about $100 million per month or around $300 million per quarter, have continued to be good guidance not only through 2Q but through 3Q.

Although Whiting made a contribution to the group, it was clearly limited as a consequence of being forced to run sweet crude as opposed to sour crude and at limited capacity as opposed to full capacity at that refinery.

Texas City has continued to operate at a loss.

It has since the beginning of 2006.

That continued in the third quarter of 2007.

But some of the underlying improvements there have shown through because the losses in the third quarter were in line with those of the second quarter in spite of a much weaker refining margin environment.

Let me just give you an outline of what's going to happen at Texas City and perhaps this will answer your question.

Over the third quarter at Texas City, we've been recommissioning the products cluster, which is designed to desulfurize product streams and upgrade them.

So it's very, very critical.

To do that prior prior to what we're doing now, which is working on bringing the second crude unit into production.

And we still aim at having that done by the end of the year.

So that would give us available production at Texas City of 400,000 barrels per day.

If you look out then into 2008, we achieve full capacity and flexibility by restreaming the heavy upgrading resid hydrotreating unit and bringing it on stream along with the second ultraperformers.

So there is a bunch of work to still be done still downstream of the crude units there.

That will take place over the course of the first half of 2008.

Though the guidance that we provided, which is -- to have it to 400,000 barrels a day by year end, and to have full capacity and flexibility by midyear, we remain on track and we're not providing any incremental guidance to that.

Thanks very much.

Now like to move on to [Stefan Succo] from SG.

Good afternoon, gentlemen.

I have two questions more operationally focused.

The first one is about Angola.

Some service companies in Angola talked about delays in some infrastructure contract awards and BP offshore assets, Blocks 31 and 32.

We're also hearing that BP Chinese partner on Block 18 may not be good to prove some costs on Block 18.

Could you perhaps comment on that and elaborate on any possible impacts on gross for BP in that part of the word, if these delays are, indeed, concerns?

My second question is on Thunderhorse.

Base on the start-up of Thunderhorse next year, when would you expect to reach plateau production on this field?

Particularly, I was wondering if we are contemplating a very quick ramp-up or was a progressive increase and therefore if we can expect plateau production in '09 or perhaps later?

Thanks.

I'll take those two.

On Angola, rumors about delays, obviously we don't comment on rumors.

We have our guidance on production.

We're not changing any of that.

So there's matters there I think about where we stand in terms of timetable in Angola.

Second on Thunderhorse, again, the guidance hasn't changed.

It's start-up by end '08 and progressively ramping up thereafter.

You can see from the Atlantis startup that we're being very careful and cautious as you'd expect us to be with these very complex and sensitive projects, and that we will do it the right way and we'll do it progressively.

So you should expect to see production from Thunderhorse build up in the months following commissioning and commissioning will take place by the end of 2008 as we previously indicated.

Moving back to the United States, Mark Gilman, Mark, you're on the line from Benchmark Company.

Yes, Fergus, thank you.

I had a couple of specific things and more general if I could, please.

On this specific front, I was wondering if you could quantify the volume impact in the third quarter of the unplanned upstream downtime as opposed to breaking it out quite the way you did.

Secondly, of a specific nature, could you comment on reports of early water encroachment and the impact on production at Chirag and AIOC and whether or not that would have any going-forward impact on volumes in that area?

Thirdly, and more generally, as part of the organizational changes that are going to be implemented, is consideration being given to eliminating the matrix aspect of the current organization?

Namely, having both regional and functional responsibilities, with particular reference to the U.S.?

Thanks, guys.

Thanks, Mark.

I'll do these in reverse order.

As far as the organizational structure, we believe that there remain benefits from having a regional organization, and therefore a matrix of functions, regions, and business segments.

That being said, we're looking to simplify the way in which these interfaces occur.

There are too many notes of where functions and regions and segments come together.

And that's part of what creates complexity.

Although we're not eliminating regions, we're structuring them in a much more fit for purpose way.

And in most parts of the world, the regional activities have been moved into the business segment, which leads in that region.

In most of Europe, that's refining and marketing.

In much of the rest of the world that's exploration and production.

We have a bigger regional organization in the United States, because of the very large footprint we have there across much business activity from all areas of BP.

And so it's important that we maintain a regional organization there.

But it needs to be developed in a fit for purpose way, and we are certainly progressing to do that.

As far as your question about Chirag, we don't comment on that, so I'm not going to provide you any specific guidance.

And I'll ask Fergus whether or not he can provide some additional perspective--?

Just a couple of points, really, Mark.

Obviously ACG Phase three is scheduled to start up next year.

The whole field complex is performing as previously expected.

Actually, the bigger issue in terms of BPs net production Azerbaijan of course is cost of country under production sharing contract, under very high prices which we provided information on, which I think you saw during the field trip to Azerbaijan just a year ago now.

If you're looking for net production from BP I'd focus on PFC in fact, field performance is really much as expected.

The big issue actually in the fourth quarter is the continued ramp-up of production from Shah Deniz as we move into the winter.

We should see higher gas deliveries out of the field, which, as you know, has been relatively slow in its ramp up earlier in 2007.

And finally, Mark, I think you asked a question about unplanned upstream downtime.

The two major things that were completely unexpected in the third quarter were the cat shut down, North Sea pipeline that was damaged by a ship dragging its anchor, that had impact of about 50,000 barrels of oil equivalent a day in the third quarter.

There was also a unplanned shutdown of the Baku-Dujai hand pipeline at the end of the quarter for just a few days there, which was about 10,000 barrels a day.

Obviously there's downtime across the rest of the business in the normal course of things, for maintenance and other factors.

But the two big ones that might affect your numbers and forecasting, were Cat and the BCC shutdown at the end of the fourth quarter.

No Alaska affect, Fergus?

Sorry?

No Alaska affect in terms of unplanned downtime.

Nothing unplanned, Mark.

It is the maintenance season in Alaska in the third quarter, as you know.

Alaskan production was relatively low in the third quarter.

Both for that reason and because of obviously lower compressor efficiency, but we would expect to see Alaska back up again in the fourth quarter, the instance that were commented in the press didn't have any material impact on production.

Thank you very much.

Europe, Ed Westlake, CFSB.

Ed, are you there?

Yes, I am.

A lot of the questions have been asked.

Maybe just on TNK BP.

Obviously realizations rose both domestically and internationally yet the profit didn't rise that much relative to the shortfall in production versus Q2, just maybe some comments on cost and the tax impacts?

And secondly, whether you'd be able to give some rough guidance at this stage in terms of CapEx and volumes for 2008 at least in terms of the arms and legs of your thoughts in terms of inflation and overall volume growth.

Thanks.

Thanks for those questions, Ed.

As far as TNK BP goes, there's nothing unusual in the third quarter.

The tax rate is the rate that we would expect on an ongoing basis.

I think, perhaps, the issue here is the very low tax rate that we booked in the second quarter.

There was a writeback of a provision in TNK BP, so it led to a lower rate than would be the expected statutory rate.

So I'd look backwards as opposed to 3Q in searching for answers on that specific question.

CapEx for 2008 will be an issue that we will discuss with investors in our February strategy presentation.

One thing, which is obvious, is the fact that we are, like everyone else, subject to double digit inflation in the capital spending arena across not only refining and marketing but also much of the heavy spending around refineries and refining and marketing.

So with double digit inflation coming through, one would expect that to be reflected even with the same sort of activity set as we saw in 2007.

Beyond that, you will need to wait for the guidance that we provide in February.

Volume remains consistent with the guidance Andy Inglis provided back in February of this year, and we have not moved at all with respect to that guidance.

Thank you.

Going back to the United States, we have Don Barcelo on the line, I hope, from Banc of America.

Good afternoon.

Thank you.

If I could, just a quick question about the old business versus the new.

On the E&P side, post The Gulf of Mexico lease sales is there any further color you can give now that you've achieved those leases in terms of what prospects you find interesting going into '08, '09?

And also maybe a quick update on the lower tertiary.

Then in terms of the new business and your plans for alternative energy, can you just touch pretty broadly about some of the core businesses you've had historically, like solar, how those are faring?

Also in terms of carbon legislation it seems that seems to be front and center on legislative front.

Are you able to comment broadly about any actions there on the U.S.

front or changes in Europe?

Thank you.

That's a wide swathe of questions.

Let me talk about the alternative energy business, and then we'll come back to the specifics of the Gulf of Mexico here.

Let me give you color on the two main areas within alternative energy, and that's wind and solar.

In the United States, because that's where the bulk of our wind activity is, we're making good progress.

We have four wind farms under construction there with a total of 420 megawatts involved in that at places Cedar Creek, Etom Wells, Silver Star, and Dolle to name the projects.

Cedar Creek, which is the biggest of those is the largest wind farm in the United States.

And at 300 megawatts is being commissioned.

We've got a very large land bank in the United States, potentially 15 gigawatts of land portfolio there.

So it's -- we've built up a very good platform for the business in the United States.

We also have first wind farm in India that's producing electricity.

So perhaps that gives you some color there.

As far as solar goes, we're expanding our modular capacity.

We've got installed capacity of 300 megawatts on track for the end of 2008.

In both areas we continue to see substantial growth prospects in the near and longer term.

With respect to your questions about the plans with regard to the blocks that we acquired in the recent Gulf of Mexico lease sales and our views of various structures in the Gulf of Mexico, that is not information that we share publicly, this is the information around which great value is created in an exploration-production company.

And we believe we have competitive advantage, but we're certainly not going to disclose it publicly.

Okay.

Thank you.

Thanks.

And coming back to London, Colin Smith from Dresdner Kleinwort.

Colin, are you there?

Yes.

Good afternoon, gentlemen.

Just coming back to the organizational changes you mentioned, Byron, I wonder if you would just provide a little bit more detail about the number of SPUs you had before and the number you think you'll end up by the time the (inaudible) airing process has been completed?

Can you also touch on how far you think the OMS has been implemented within that?

And then on a completely separate topic, I just wondered if you might be in a position to talk about where things stand on the STX4 well and the implications for Shah Deniz?

Thank you.

As far as the SPUs go, this is actually less about changing the number of strategic performance units.

It's much more about concentrating performance around the strategic performance units structure.

So we're in many ways moving things down from the segment level into the SPUs and we're moving in many cases levels below that, not exclusively eliminating business units.

But we are eliminating the smaller units in some cases that existed below the SPUs all which has led to a duplication of resource.

If you activity at the group level, at the segment level, at the strategic performance unit level, and at the business unit level, you can see how much of that can be eliminated and yet achieve the same result.

The identification of strategic performance units is the main building blocks of performance delivery of the group, is an important decision.

And what we'll do is cluster resources around them as opposed to spread it more broadly.

I believe this is going to have a very important lever into reduced overhead and improved performance for the group.

It's going to take a while to get there.

This isn't the sort of thing you do overnight.

But certainly I and my colleagues are deeply optimistic on what can be achieved here.

Colin, coming back to your question, detail question about the well in Azerbaijan.

Clearly one of the main reasons BP is in Azerbaijan and won the production sharing contract back in the early '90s is our ability to manage the complex geology of the Caspian and the very difficult drilling conditions that can result from that.

So we're working away on that.

It's not unexpected that this was going to be a technical challenge.

It's something that we're up to and up for and we're dealing with that.

We're beginning completion on that well as we speak.

And I mentioned in response to Mark's question earlier on that Shah Deniz is an asset where we would expect production to continue to ramp up as it has been doing all year, relatively slowly but it has been rising and we expect a further rise in production in Azerbaijan in the fourth quarter of 2007.

Coming back to those who have patiently waited.

Irene Himona at BMP.

Irene, are you there?

Good afternoon.

I had two questions.

First of all, could you perhaps update us on where you are in relation to the plan to upgrade the Whiting refinery given the recent environmental obstacles?

When is it realistic to expect a decision on that?

Secondly in EP, if we actually strip out last year's capital gains at your affiliates, it appears that the absolute result was a bit better than the rules (inaudible) would indicate.

Could you perhaps talk a little bit about trends you are seeing in operating cost inflation in the upstream?

Thank you.

Let me cover the Whiting question and Fergus will come back on the exploration and production inquiry you made.

Let me -- I think it might be useful to just kind of talk as I did with Texas City about where we are with respect to Whiting at the current time, then I'll use that as a lead in into the investments that we have planned there.

As far as Whiting goes, it, like Texas City, is on track with the guidance that Iain Conn provided during the July webcast.

The key issue there on the operational side is the return of the hydrogen compressors for the cap feed hydrotreating unit, which is necessary to allow us to return to sour crude processing.

At the current time, we expect to have a couple of hydrogen compressors back in service by year end, which will then allow the sour crude train, one of the sour crude trains to come up.

Then those two events together are what allow us to return to the 300,000 barrels a day and sour crude processing that I indicated in my remarks.

They are too, achieving full capacity and flexibility is achieved when we have all four of our hydrogen compressors up and running alongside, both of the sour crude units.

And again, here we expect to achieve that by the middle of next year.

So there's still a lot of activity going on in Whiting as there has been over the course of 2007.

So we've been very careful to ensure that the activity, which is around the major upgrade of the refinery is done on a separate but parallel track.

And that is, indeed, what's occurring.

And we expect to be able to progress according to the time tables that have been outlined there.

And we, as Iain Conn indicated in July even acquired some long lead time items.

With respect to environmental permitting, we are always cognizant of the environmental regulations of the United States, plan on adhering to them.

We have a permit, and we will meet the requirements of it.

Irene, on your question on cost and the trends we're seeing in cost inflation, Byron has already made reference to the rise in non-cash cost relative to the year previously and I've indicated that the upward trend in DD&A is on the order of 200 million to $300 million in total for the quarter, that's a change relative to the effects you're looking at on non-cash cost.

On the cash cost the increase is similar, it's in the order of 200 million to 300 million.

Clearly that's been exacerbated by weakness of the U.S.

dollar.

So that has a proportion of our cost fix in the North Sea which is not dollar denominated.

Behind all of that, there's probably underlying inflation rate we think in terms of our upstream cash cost running at about 6% cash on the operating cost side.

Hopefully that gives you some sense of where inflationary trends in that part of the upstream value trend is on the line.

Thanks very much.

Coming back to the U.S.

we have [Joseph Tovey] on the line from Tovey Company.

Joseph, are you there?

Indeed.

Good afternoon.

And thank you.

Couple of questions, if I might, or maybe more than a couple.

Have you set up any sort of reserves for separation costs during this past quarter with respect to the costs expected to result from the organization or the organizational changes in the Company?

That was one question.

Second question was with respect to your refinery outlook, and since you're reworking some of the refineries of necessity, do you have a view as to whether there's going to be a dieselization of the product barrel rather than at the expense of gasoline?

Thirdly, in conjunction with your reduction operations, do you have a view as to -- I'm not quite sure as to where the trading activities take place.

Are they purely considered to be downstream or are they considered upstream if you trade in crude and gas?

And why do you consider the losses that occur to be one off items?

Thank you.

I'll take your questions -- I'll do the first and third, and Fergus maybe can respond better to the second one.

As far as reserves for various charges associated with workforce implications of the restructuring that we've announced, we've taken nothing.

It's far too premature to be doing that.

It may well be that when we come to announce our fourth quarter results in February, that we'll have detailed enough plans in place in order to take a provision.

We would only do so in line with the accounting standards which require that you cross a number of criteria in order to do so.

If that is to occur, we'll provide clear line of sight to our investors on the scale of any provisions that might be taken with respect to restructuring associated with the announcements that have been made.

The trading activity, we have a long track record of delivering incremental value to the group through both our oil and products and our gas and power trading.

These contributions tend to be volatile.

They are driven by the nature of the marketplace, what sort of opportunities it offers, as well as the performance of the teams involved in it.

Ninety days is a very short period of time.

And the nature of this activity, as any investment bank can speak to, is that it tends to be volatile.

I am confident that the track record that we have over many many years is a better indicator than the short-term performance that was delivered over a 90 day period which had some very unusual characteristics associated with it.

Fergus, second question?

Just on dieselization, which is a very interesting question, but one I think where the market has to lead.

Clearly there's been a significant shift in that direction in Europe and we've made investment plans to meet that increase in diesel demand.

Most recently we've indicated that they haven't taken 100% control of the Netherlands Refining Company earlier this year after selling Carson that we would invest there with a view to increasing its diesel production capacity.

If you're talking specifically about the United States, it's always an interesting question as to whether consumer preference in the United States will shift towards diesel vehicles.

We've seen that happen dramatically in Europe and elsewhere.

There's not much sign of it at the moment in the U.S.

but clearly we would invest to follow that trend.

We wouldn't seek to lead it if it was to take place.

We're talking about long periods of time.

I hope I've understood your question correctly, Joseph, was that what you're asking about?

Perfectly understood.

And thank you very much for a comprehensive answer.

Thank you.

Now, for the last person who has been waiting most patiently, [Neil Morton].

Neil, are you there?

I am, indeed, thank you Fergus.

Just a couple of questions left on the Q3 numbers.

The the downstream and the rest of Europe segment seemed to be particularly resilient Q3 versus Q2, just wondered if there was anything over and above the mix shift of marketing effects you mentioned?

Perhaps some early benefits from the purchase of the ethical minority.

Just secondly on you U.S.

natural gas realizations.

Those remained at a fairly stubborn discount versus Henry Hub benchmark.

Just wondered if you could comment on your expectations going forward as the various phases of the Rockies Express pipeline comes on stream?

Thank you.

Let me deal with the second question.

Fergus will handle the first.

As you noted, there is material discounts to Henry Hub of our U.S.

gas production.

The biggest discount is in the Rockies area, as you pointed out, where our own delta there versus Henry Hub was more than $3.

And that compares with only a bit over $1 dollar back in 3Q of 2006.

An incremental $2 discount year on year.

The way in which these discounts disappear is when there's additional pipeline capacity to evacuate the gas.

As you have indicated in your question, once we have additional oweage from new pipelines, that should modify the situation to some extent.

neil, your question on refining and marketing and the contribution of marketing in the third quarter relative to the second.

I suppose the first point to make is overall refining business did record a loss in the third quarter of around $100 million.

That was more than obviously fully offset by a stronger performance in marketing.

So you're absolutely right.

Marketing did strengthen in the third quarter relative to the second.

I would just remind you what Byron said earlier, that marketing for us is quite broadly defined.

It includes the chemicals business, the NA business, it includes lubricants, it includes marine, it includes aviation.

And it was these businesses rather than retail marketing, gasoline station marketing that did do considerably better in the third quarter and provided that quite strong offset to the weakness in refining, which can't see another quarter where refining did report a loss at actually on the page I'm looking at.

So that was a very weak quarter in refining obviously reflecting both the margin environment and our own issues in terms of the downtime at Texas City and Whiting.

Okay.

That's great.

Thank you very much.

He's already asked a question but if he's there we'll be happy to take it, Neil McMahon from Bernstein.

Just actually two quick ones.

First of all on Azerbaijan on ACG3, it appears that the platform is undergoing sort of hookup and is on site ready to go.

Could you give us just some guidance on ACG2 how long it took between getting the top site on place and when it was actually flowing oil.

And secondly, are there any high impact exploration wells that are likely to be finished in the fourth quarter or on the start of next year?

Thanks.

Neil, on your ACG question, I think the best thing is I'll take that one offline.

I think there's a video I can send to you of the hookup process on ACG 2 which you might quite enjoy actually.

So I'll do that offline.

High impact wells, actually it's a bit like what Byron said about the lower tertiary in response to Don Barcelo's question.

It's not something that BP does, which is to talk about these things ahead of time.

If we have successes we'll tell you about them after they take place and not before.

Sorry to not be more helpful on that but I will come back to you on ACG.

Okay.

Thanks.

Well, I think that concludes all the questions.

I'd just like to thank everybody for participating this afternoon.

We're always happy in investor relations to take any of your questions at any time.

So please do contact us if you have any follow-up.

Thank you.