英國石油 (BP) 2006 Q1 法說會逐字稿

I'll now hand the call over to Fergus MacLeod, head of Investor Relations.

Please go ahead, sir.

Hello, and welcome to BP's First Quarter 2006 Conference Call.

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

Joining me today 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 will be used during the webcast.

Those of you on our distribution list should have already received these slides by email.

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

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

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

Actual results may differ from these plans or forecasts for a number of reasons, such as those noted here.

And now over to Byron.

Thank you, Fergus, and good to those joining this call.

I'll begin with a review of market conditions during the first quarter.

Oil and gas prices have remained strong, while refining margins continue to decline from the record level reached in the third quarter of last year.

Our first quarter oil realization of $58 per barrel and gas realization of around $5.50 for 1,000 cubic feet were both up by around 1/3 compared with a year earlier.

Our first quarter industry indicator refining margin of around $6 per barrel increased slightly, compared with 1Q '05.

But the margin realized by our own refineries was slightly lower year-on-year.

Overall marketing margins were similar between periods.

Our first quarter replacement cost profit of $5.3 billion was 4% lower than in the first quarter of 2005.

The per-share result was similar to a year earlier, reflecting the benefit of share buybacks.

Our profit, including inventory gains and losses, was $5.6 billion, down 15% in absolute terms, or 11% per share.

These figures include non-operating items.

The year-on-year earnings decline shown are largely the result of the absence of last year's $500 million non-operating gain.

Excluding these items, our underlying replacement cost profit was $5.3 billion, up 7% in absolute terms or 12% per share, compared with 1Q '05.

We generated $8.9 billion of operating cash flow in the quarter, a level similar to last year, in spite of the significantly higher tax payments, the absence of Innovene, and the continued shutdown of our Texas City refinery.

The $0.09375 per-share dividend announced today, which will be paid in June, is 10% higher than a year ago.

The sterling dividend is up 18% year-on-year, reflecting the stronger dollar.

Turning now to the segments, our exploration and production result of $6.8 billion pre-tax was 6% higher than a year earlier.

The impact of non-operating items was substantial, moving from last year's gain, related mainly to the Ermen-Longer disposal, to this year's charge, related mainly to embedded derivatives on long-term North Sea gas contracts.

Excluding non-operating items, the underlying E&P result was up 26% year-on-year.

This includes a significant benefit from higher oil and gas prices, partly offset by reduced volume, continued repairs for hurricanes, and Thunder Horse, and ongoing inflation in the sector.

Our 1Q production of more than four million barrels of oil equivalent per day was slightly higher than in 4Q '05, reflecting the progressive return of production, impacted by Hurricanes Katrina and Rita.

Production was down around 2% compared with the year earlier.

This was mainly due to the lingering effects of last year's Gulf of Mexico hurricanes, notably on the Mars Field.

Looking toward the end of the year, we expect a marked pick-up in production growth, as hurricane losses in the United States are fully restored and a number of major projects come on stream.

These include Thunder Horse, in the U.S.

Gulf of Mexico, the BTC pipeline and the Shah Deniz gas project in Azerbaijan, plus Dalia in Angola.

We expect production for 2006 to be consistent with our previously indicated range of 4.1 to 4.2 million barrels of oil equivalent per day, less the effects of prices above our $40 per barrel planning assumption on production-sharing contract volumes, and any 2006 disposals.

TNK BP contributed $400 million to our 1Q result, similar to a year earlier.

We also received nearly $800 million in dividends from TNK BP in the quarter.

In refining and marketing, we reported a pre-tax profit if $1.6 billion in 1Q '06, up from $1.4 billion a year earlier.

This quarter's result includes disposal gains of around $550 million.

Excluding these non-operating items, our underlying result was around $1 billion.

This is up nearly $1.3 billion, compared with the fourth quarter, a very significant turnaround despite the continued shutdown of Texas City.

Compared with the first quarter of 2005, realized refining margins were slightly lower, and overall marketing margins were similar.

The absence of our Texas City refinery impacted our first quarter result by around $650 million, compared with 1Q '05.

This reduction was partly offset by improved supply optimization and business improvements elsewhere.

The quarter was also adversely impacted by IFRS accounting effects.

Recommissioning of Texas City began at the end of March.

Throughput is currently 200,000 barrels per day and is expected to increase in a phased manner through the remainder of the year.

The full financial potential of the site is not expected to be realized until 2007.

Our reported result in gas power renewables was around $300 million, pre-tax.

Excluding non-operating items, such as embedded derivatives and the 1Q '05 gain on disposals, the underlying result was up 16% year on year.

This reflects stronger results from our gas and power marketing and trading activities, partly offset by adverse IFRS fair value accounting effects.

Now I'll mention a few of the strategic milestones we achieved in the first quarter.

In exploration and production, we started up the Cannon Ball gas field in Trinidad, and lifted the first cargo from Atlantic LNG Train Four.

We're also seeing good progress in major projects elsewhere.

We expect first listing of oil from the BTC pipeline later in the second quarter.

Work at Thunder Horse is proceeding well, in support of expected start-up in the second half of the year.

During the first quarter, we were the highest bidder on 73 blocks in the central Gulf of Mexico lease sale and were awarded three new exploration blocks in offshore Pakistan, subject to government approval.

Consistent with our divestment strategy, we announced agreement to sell our interest in the Stopyard Oil Field and the [Luva] gas discovery in the North Sea, and our remaining Gulf of Mexico shelf assets.

In refining and marketing, our European efficiency programs remain on track.

We also completed a number of asset sales, including our retail operations in the Czech Republic and our interest in Zhuhai Refining and Chemicals Company in China.

In gas power and renewables, we announced plans to build a $1 billion hydrogen-fueled power plant alongside our Carson Refiner, near Los Angeles.

The plant is expected to generate 500 megawatts of lower-carbon power, enough to serve 325,000 Southern California homes.

In other business and corporate, or OB&C, we reported a first quarter charge of just over $200 million, pre-tax, including a small non-operating gain this year, compared more significant -- Innovene's separation charges -- last year.

The underlying result in 1Q '06 is consistent with the expected range of annual charges that I indicated in February.

Our first quarter effective tax rate was 35%.

This does not include the impact of the yet-to-be enacted increase in the UK North Sea tax rate.

This change will have two elements.

First, a non-cash charge of around $600 million related to deferred tax balances from prior years.

Second, a current tax increase to reflect the 2006 impact of the proposed higher rate, which is retroactive to the start of the year.

Putting both elements together, we'd expect the group effective tax rate to spike by around 10 percentage points in the quarter this change is enacted, reflecting the retroactive elements.

As I indicated in February, at current price levels, we expect our full-year group effective tax rate to average around 39% in 2006, including the one-time deferred tax charge.

Turning from earnings to cash, this slide compares our sources and uses of cash for the first quarters of 2005 and 2006.

Cash in flows and out flows were essentially balanced in the first quarter of 2006.

Operating cash flow of $8.9 billion, net of taxes, along with nearly $700 million of disposal proceeds, funded $3.4 billion of capital expenditures and $5.4 billion of net shareholder distributions.

This is consistent with the strategies and the plans we described in February.

Our first quarter debt ratio was 16%, down slightly from year-end 2005.

Strong operating cash flow, including normal working capital phasing benefits, offset increased shareholder distributions, as I described previously.

We continue to expect the earnings to return to within our target band during 2006.

Shareholder distributions approached $6 billion in the first quarter.

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

Cash dividends increased to $1.9 billion, and we bought back $4 billion of shares.

Share buybacks are continuing in 2Q, with purchases during the closed period totaling $1 billion.

Our low gearing and strong cash generation position us for substantial further share buybacks during the year, in line with our financial framework and strategic intent.

That concludes my presentation of the results.

Fergus and I would be pleased to address any questions.

Before we star the question and answer session, I'd just like to make a brief apology.

I know we've had some technical problems with the website used to access this call earlier today.

Those of you who are on our email list should have received an alternative address to allow you to access the call.

In addition, there is a telephone playback facility, if you did miss any part of the call and would like to listen to it again.

If you do need any assistance to access any of those facilities, I hope you'll contact BP Investor Relations.

So, sorry about that, but now I'd like to ask the operator to poll for questions.

[Operator Instructions]

Thank you very much, Operator.

I'd like to start off in the UK with Neil Perry from Morgan Stanley.

Neil, are you there?

I am, thanks.

Two quick questions for you, Byron.

One is on the gearing.

It's now down at 16%, and you say you're going to get it back into the range, this year, very clearly.

Do you really think you can do that through the buyback mechanism alone, and have you got any concept of where you think the limit is on buybacks, because it would imply a substantial ratcheting up of the buyback program.

And then my second question is, can you just elaborate a little bit on what optimization is in the downstream - by that, do you mean trading?

Thank you for those two questions, Neil.

First, with respect to gearing, what we're seeing in the first quarter is a seasonal effect.

We have, at the end of each year, a big build of working capital with respect to excise taxes, in particular, in Germany, and that gets released back in the course of the first quarter.

So we have found this always to be the case, as we've looked at first quarter.

I do not believe that we have any difficulty at all in meeting the share buyback objectives of the firm.

There is deep liquidity in our shares, both in the United Kingdom and in the United States.

We are not met any limitations at all with respect to the buyback program to date and I'm noting $4 billion worth of buybacks in the first quarter as well as amounts pretty similar to that in the third quarter and fourth quarter of last year.

So I would anticipate that as we progress through the year, consistent with other years, that we find ourselves returning back to the low end of our gearing band.

The only thing that kept us from that in 2005 were the very large proceeds that we realized from the divestment of our Innovene assets to INEOS.

As far as optimization, it - it would probably be simple for you to think in terms of this as trading, but what we do is much more sophisticated than that, looking to constantly upgrade the margins that realizable from the inputs and the outputs of our refining system, which means we are constantly adjusting, using both physical and derivative markets to achieve that.

At times when there are substantial elements of volatility in both crude and products markets, there are then opportunities to deeply enhance the margins that are realized.

What we saw in the first quarter, where the opportunities to achieve substantial additional margin through those activities.

The reason I say ``not trading'' is because if we did not have the refineries in place, this is not an activity we'd be pursuing.

It's the ability to process the oil and convert it into products that allows us to access this opportunity.

Thank you.

And so--

Thank you, Neil.

I'd now like to move Mark Iannotti at Merrill Lynch.

Mark?

Hi, Byron.

Quick question on Thunder Horse - you're still indicating second half of 2006 for field commissioning.

Can you talk us through some of the- or the major timeline, and milestones that you're looking out ahead of that, given it's still fairly wide guidance on the fact that it's only ten weeks 'till the second half?

Well, we're going to keep that very wide guidance in place, Mark.

The reason for that is there are a number of issues still to address on the facility itself, but of course weather in the Gulf of Mexico, as we move into the hurricane season, remains a big question mark, and we think it's prudent at this time to remain in a relatively large window, indicating that we expect Thunder Horse to be back online in the second half of the year.

And obviously, the earlier it is in the second half, the better.

But for purposes of guidance, it remains that relatively large band.

Thank you, Mark.

Now moving to the U.S., Robert Kessler of Simmons and Co.

Firstly, to sort of state the obvious, crude prices are about $30 above your long-term planning assumption as it relates to your production guidance.

In light of that, any recalibration you could provide [to the PSC activity] would be appreciated.

And then secondly, just a minor clarification point, as to why you're still recognizing charges associated with Innovene?

Well, Bob, I'll probably take those two relatively technical questions.

In terms of PSC effect, the delta in oil prices in the first quarter of 2006 relative to the first quarter of 2005 has an impact on our production of about 30,000 barrels a day.

In terms of the recognition of the charge on Innovene, even though, as you correctly point out, the assets have now been sold to INEOS, as Byron mentioned, is essentially a post-closing working capital adjustment, and that's all it is, Robert.

So there may be a little bit more of that to come later on 2006, but the numbers are really becoming quite small, and they relate solely to the finalization of the working capital, post the disposal.

Yeah, Robert, these are showing through as non-operating items.

There will be additional ones, as we finalize all the remaining aspects of this very large and very complicated transaction that we've pursued with INEOS.

But these are very, very small adjustments that continue to flow through, relative to the overall scope of the transaction.

Neil McMahon from Bernstein.

Two questions, or sort of three, actually.

On the first one, if you could give us some guidance Atlantis, you didn't mention that in terms of the major projects.

I know it was the back end of the year.

Is there any potential that sort of slipped into '07, or are there still plans at the back end of the year?

And also, at this stage, any guidance on what exit volumes we're talking about in terms of the BTC pipeline by the end of the year, in terms of the ramp up we're going to see there?

Also, just wondering if you could give any clarity around the exploration in the Turkish Black Sea, now that well has finished?

And lastly, maybe just a comment on the gas and power stream?

Looks like you were potentially weren't able to avail of some of the very strong LNG prices in December, that sometimes get lagged into the first quarter.

Maybe you could comment on that?

Well, let me talk about Atlantis BTC and the exploration.

I'll let Fergus pick up the last one.

As far as Atlantis, it remains on track.

Our expectation continues to be that it will be in production at the end of the year.

As far as BTC, we're much more interested right now in getting it to the first export cargoes in the second quarter, and the actual rates will continue to build up, as more and more productive capacity comes on stream in Azerbaijan.

I don't have a specific number for the UN run rate on that, but perhaps we can find you something before the end of the webcast.

As far as the wells in the Black Sea, we've not provided any public disclosure on that, and I don't intend to do so in this webcast.

Yeah and Neil, as far as BTC's design capacity, as you probably know, it's around a million barrels a day, and we'd expect, you know, as we ramp up from [Derry and ACG], that we'd rise overall in terms of [inaudible] flying towards that level.

Could you just remind me of what your final point was?

Yeah, sorry, it was just on the BTC as well.

I know you accelerated phase II of it, coming online for Derry production.

That's a run rate of 600,000, isn't it, the potential of those two bolted together.

Would I be correct in saying that.

In terms of outright, with phase III coming in 2008.

Right.

And just the last question was to do with gas and power--

We can come back to you on more details on that, if we may, Neil.

I'll put you through what the profile looks like on that later on.

OK.

Staying in the UK, we now have John Rigby from UBS if you're there, John.

Two questions.

One is, with regards to the disposals process you've got going on in the upstream, recognizing the fact that you give guidance on production based upon the existing portfolio, is there upside later on in your outlook for 2010 for the effect of releasing resources?

I'm talking about [people] here, through the process of disposing [volume].

First question.

Second is, maybe this directed to Byron -- Byron, is there any process by which you're talking to your peers regarding the way you account for [gas] projects relative to derivatives, because it seems to me that you're recognizing a much larger provision than almost anyone else in the market, yet as far as I can see, it's not really reflective of the way that your gas business mostly works -- i.e., that it's not that much bigger than any of the [inaudible]

John, as far as the first question goes, you certainly are right, that what we will achieve by the disposal of assets that are immaterial, non-strategic, very mature, in many cases, is the ability to take some of our very key people who otherwise be engaged in activity is relatively modest in its value-adding characteristics and being able to redeploy them elsewhere to get involved in bigger, more important projects.

It's a strategy, human resources strategy, that we've been involved in for quite an extended period of time, and we think that it's right, especially in an industry where people are, at the end of the day, actually the most important asset because of all the oil and gas in the ground, stays in the ground, unless you have the people to explore for it, to produce it, and to transport, ultimately, to market.

What that means over the course of the next five years is the ability to, as I said, is address more important projects and that certainly underpins the delivery of that.

It [doesn't] provide some opportunity to enhance it.

As far as the embedded derivatives, I don't know what exactly the scale of these particular contracts is with respect to the full competitor set that we have in the North Sea.

What I do know is that following the guidelines of IFRS, we are forced to mark these to market in the way that we are doing it, which is across the full lifespan of the contracts.

They- the difference is really not a true economic loss for BP.

We- we engaged in these contracts at the time the fields were being developed.

There was not a liquid gas market at that time.

We sold the gas on the basis of other indices, and what we're seeing is a marked to market effect of the forward curves of the indices versus forward gas prices over a ten to 15-year timeframe, all booked as those changes occur, on a quarter by quarter basis.

So I don't think it, in any way, represents the true contribution of the firm, which is the reason we pull it out as a non-operated item.

But it is what is required to be in compliance with IFRS, and therefore we'll continue to do it, and you'll continue to see what recently has been a series of negative charges.

I suspect at some stage, when North Sea gas prices stabilize, it will probably be a series of positive contributions but again, we will continue to pull them out, treat them as non-operating items for you then to exclude from your analysis, as you see appropriate.

Going back to the United States, Nicky Decker at Bear Stearns.

Nicky, are you there?

My first question is on Texas City -- would you expect to continue to incur repair costs at Texas City in the second quarter, and what throughput level do you anticipate being at the end of the second quarter?

And my second question is regarding Wamsutter.

If you could just bring us up to date on progress at that project.

Well, I'll handle Texas City, and Fergus, who's, over the course of time, become an expert on Wamsutter, will handle that question.

Texas City, since we're just now have ramped it up to 200,000 barrels a day of throughput, clearly there are additional costs that are being incurred as we are working to bring the rest of the facility, not only the crude throughput, but derivatives facilities, back into operation.

So there will be additional charges associated with that.

Let me give you, perhaps, what would be a helpful view of Texas City in the second quarter.

The cost of Texas City on a normal basis, what I'll call the fixed costs, and that's both cash and non-cash, is about $350 million a quarter.

So that's the sort of losses that one's incurring if the facility is not able to operate at all.

We're currently at half throughput.

In spite of getting that back to that level, we're still incurring a small loss on a day by day basis, so in order to get to break-even, we either need substantially higher refining margins than we even have today, or we need to get the facility to higher throughput capabilities.

And therefore, if one looks at the contribution from Texas City in the first quarter of last year, which was about $200 million, and that's excluding all the non-operated item charges, then you can see that there will still be a substantial decrement on 2Q versus 2Q, partially from the fact it didn't' operate for the first part of April, and secondly, that even as it is operated, it's still not able to offset its full cost structure.

And Nicky, on Wamsutter, this is obviously the further development of this.

You know this is 1,700 square miles, 950 producing wells.

It's the largest contiguous block of acreage that we have in the United States.

The plan is to invest an incremental $2.2 billion in the field over the next 15 years and essentially to double production from the acreage in the first stage of the redevelopment of Wamsutter.

The project is going well, the seismic program definition progressing, we've had meetings with the Bureau of Land Management to kick off the regulatory process, we're starting a sub-surface of [in-fill] drilling, we're planning to move to 40-acre spacing there.

The first multi-well [part] facility is installed and hooked up, ready for production, and you should start to see incremental production from this field, particularly as we go into next year and especially into 2008.

So it is a long-term project but one with very significant value associated with it and with a very long plateau.

So one we're quite excited about.

Coming back to the UK, Colin Smith from DKW.

Colin, are you there?

Just given your production guidance, prices year-to-date, and where the forward curve is sitting, and given that you've disposed or had removed approximately 50,000 barrels a day, is it fair to assume that the absolute number you'd expect to report at the end of the year is going to be below the 4.1 million barrels a day guidance number?

The answer to that, and I'm not going to answer it directly, but to say that we provided initial guidance of 4.1 to 4.2 million barrels a day, so we provided guidance within a range.

What Fergus has indicated when he's talked about production sharing contracts of about 30,000 barrels a day, plus the divestments that we've announced to date, which would impact the quarter by around 40,000-- sorry, the year, around 40,000 barrels a day, means that one should slide that range down by about 70,000 barrels a day, so the range now is [skewed] below 4.1 million barrels a day, but what I don't want to do is say, ``No, we're at the lower end of that range.'' We should wait and see how production develops across the year, but indeed we are adjusting the range, according to those two factors, as we indicated we would in February.

But Colin, just to be absolutely clear, to give you a definitive answer to your question, you'd have to tell us what the average oil price is going to be for the year, so we can tell you what the PSC effect would be, relative to the $40 basis on which that guidance was provided.

And second, we're having great success with the divestment program.

You've noticed the prices that we've been achieving in excess of $20 a barrel on some of the assets that we've sold.

We believe we're getting value for those divestments and we think that program is going very well, so don't be surprised if you hear about further divestments as the year goes on, because this who business is being run, clearly, for value rather than in terms of [purely] focusing on a volume metric number.

Absolutely, and presumably you would expect it to--

--a time when it was better to be a seller of upstream assets as opposed to a buyer, then this must certainly be that time.

Thank you very much.

We could take a question on the web now from Bruce Marley, which builds on Colin's question.

The question is, ``The sale of your Gulf of Mexico properties appears to be done at a very attractive price.

Is this the primary reason why you sold these properties, or does this represent a strategic shift to your outlook for the shelf and possibly other mature U.S. assets, which are on a relatively fast treadmill?''

Bruce, thanks for the question.

It doesn't indicate a shift in strategy at all because we've consistently focused on selling assets that are either non-strategic, immaterial, or have reached the mature stage of their life, as I indicated earlier.

We think that there is clearly a lot of [prospectivity] in many places in the United States, but for BP, the set of assets that we have reached agreement with Apache to sell are assets where we've felt that we were achieving a very attractive price.

It's $22 per barrel of oil equivalent, of proven reserves, and one that by doing so, we could release resources, both financial and human, to concentrate on other, very important opportunities in the Gulf of Mexico and elsewhere.

But that's something that we've been doing for a very long time, and you're just seeing another step in that process in the first quarter of 2006.

You've also, Bruce, asked a separate question about Innovene profits -- your question is, ``It appears as though the Innovene profits were not used in your share buybacks.

If not, when can this be expected?'' Well, we don't set aside any particular cash as being cash from one corner or another.

It's all cash, and to the extent that we have a gearing rate that's below our target band, we're going to continue use that to buy back shares and as I indicated in an earlier comment, we still expect that the program that we have been progressing over the last several years, and that we're continuing to progress today provides us the capability of buying back shares in order to, over the course of time, get back to the gearing range that is our target.

Now coming back to London, Ed Westlake from CSFB.

Yes, good afternoon.

Sort of, again, sort of a theoretical question at this point in the cycle.

The- you've benefited in the past from sort of over-spending on some good, big projects which are going to come on stream over the next couple of years, so cash generation is going to be strong, but capital inflation trends are still very much on the up.

Would you sort of consider delaying projects if they weren't able to meet your hurdle rates, or when do you think that you're going to have to sort of up the level of capital spends in order to sort of reinvigorate the portfolio at the back end of the decade?

We believe that the guidance that we've provided, of $15 billion, increasing by about a half a billion dollars a year, in '07 and '08, is indeed adequate investment to underpin the growth prospects that we've provided you, which in-- in a $40 oil environment, granted, that's a long ways away from today's price, but in a $40 oil environment, would underpin an underlying growth of 4% per year to that point in time.

I would [inaudible] we're seeing the impacts of inflation on the sector, we're seeing it in our own capital goods.

What we said in February still reigns true; about 12% is what we're expecting in 2006 over 2005, impact on capital goods, that we, through various actions, through our long-term contracts we have in place, and through just general technical and efficiency measures, we ought to be able to offset 2% to 3% of that, but the rest of it will flow through, and that is built in to our $15 billion projection for 2006.

Obviously if it runs further, then the spending will need to grow in response to that, because what we're doing is underpinning an activity set over the course of the three-year period that we've indicated.

You know, in today's environment, it's kind of hard to see how capital spending is likely to- sorry, that the inflation in the sector is likely to knock any of the projects off the track.

We put these projects in place over a long period of time, they were all robust at a $20 to $25 environment.

We still look at them in that sort of environment for long-term returns.

Everything that we're looking at, in spite of recent capital inflation, is a very robust project and would continue to go forward as planned.

And it's always worth remembering, the capital spending in TNK BP which of course is not included in the $15 billion of consolidated capital spend that Byron just referred to, and as you know, that's doubled since 2004.

We expect to spend about $2.5 billion there this year.

So we're seeking to deploy the capital where the rates of return are higher.

Staying in London, Tim Whittaker from Lehman Bros.

Tim, are you there?

OK, moving to the U.S., Mark Gilman, from Benchmark -- Mark, are you there?

I have three specific questions.

First one, has there been or do you now expect an adverse change in fiscal terms in Trinidad, relating to the gas production and LNG project there?

Secondly, it looks to me as if there was a significant increase in the tax rate on TNK BP to a level above 40% in the quarter.

Is that likely to be sustainable?

Thirdly, could you clarify and quantify the adverse IFRS effects that the release and Byron alluded insofar as the refining and marketing business, which don't appear to be treated as a special item.

With respect to Trinidad, we've reached agreement with the Trinidadian government on fiscal terms there, that-- and that's reflected in the current results.

With respect to TNK BP, what you've noticed is an increase in tax provisions for TNK BP.

This is a decision that BP has taken, and that's the reason why the charge itself is up in the first quarter versus the prior periods.

It's a once-off adjustment that we've made, in line with a review that we've taken of the-- the tax exposures that we have in Russia.

And thirdly, with respect to the asymmetric IFRS accounting effects, indeed, we had those in both refining and marketing and gas power renewables in the first quarter, and in each case, they were in the range of $100 million adverse, relative to the first quarter of 2005.

So, $100 million, round number, for each one of them, or $200 million impact on the group itself.

And no, we do not treat these as non-operated items, so yes, they're built in to the underlying results of the segments and the firm itself.

We've thought about whether or not we should isolate them as non-operated items, because they're very different than the embedded derivatives that I was discussing earlier, which are very long-term and can be very large and volatile in their nature.

These are a consequence of the asymmetric treatment of our derivatives positions that we have often times at the end of the quarter, to offset physical positions.

In essence, to lock in economic margin, and where, under IFRS accounting rules, we need to treat the financial derivatives items differently than we treat the physical side.

So, you end up with a mismatch at the end of a quarter, but these tend to even out over the course of a calendar year, and on the basis of that, we've decided to keep it in place as an underlying item in the results.

But when it's appropriate to do so, signaling it, as we did in the first quarter results.

Tim Whittaker?

In the downstream, could you give a breakdown between refining and trading, and the rest of the businesses?

Could you explain why you dropped out of the [Hindustan] refinery venture?

And also, could you maybe discuss some of the dynamics of the Atlantic Basin LNG market just now;

I understand demand from the U.S. has slowed.

Maybe you could talk about target destinations and pricing trends at the moment.

Fergus, do you want to take the first one?

While Fergus is looking up something here, let me just deal with the second of your questions, which has to do with Hindustan Petroleum Corporation, Limited, or HPCL, the Indian refiner.

We had a memorandum of understanding with them, which we announced earlier in the fourth quarter results.

That was a memorandum of understanding.

We went through a detailed study, looking at the opportunity.

When we got to the end of that, we decided that although the opportunity, indeed, was an economic one, it didn't provide attractive enough investment characteristics for BP to engage in it.

So on the basis of that, we terminated the agreement with HPCL.

It does not mean that we're not continuing to be in interested in opportunities in India and China and elsewhere, the big developing markets of the world.

But we use the same investment criteria there as we do in mature markets; it needs to carry its weight.

It can't be too much a view on things that might happen many years down the road.

It needs to have good investment characteristics from the get-go.

And this one, in our mind, at least, didn't meet our criteria and we've chosen to point our attention elsewhere.

Tim, addressing your question about what was, if you like, the breakdown within the refining and marketing segment of the underlying profit, excluding the non-operating items, of just over $1 billion in the first quarter of 2006.

It was about 70% refining and about 30% marketing.

Now, all of what we call commercial optimization, which as Byron earlier described, is really reducing the cost of raw materials into the refining, what I think you referred to as ``trading,'' but I mean, that's what we do - it's about reducing the raw material that goes- the cost of the raw material that goes into the refineries and improving their margins.

You can get a sense from that 70%/30% split, which compares to around 85% refining, 15% marketing in 1Q '05, or just about break-even refining in the fourth quarter of '05.

You know, there was a significant benefit there from that lower raw material cost, which benefited the net realized margins from the refining business.

There is also some reduction in costs there, and indeed, some phasing of costs, which were unusually high in the fourth quarter of '05, plus of course the Texas City effect.

So hopefully that gives you some sense of the order of magnitude, anyway, of the benefit that we got from the unusually volatile markets in the first quarter, the light-heavy, light, sweet, sour, [inaudible] and so on.

So that was all and consumed in that 70% contribution and just over $1 billion from the overall refining and marketing business.

As far as Atlantic Basin LNG, this is a volatile market, like most markets these days.

It will swing back and forth as the gas price in the United States moves vis a vis prices here in Europe.

There was a period of time back in the latter part of 2005 when there was a strong incentive to bring cargoes into the U.S. because of the after effects of the hurricane there and the spiking of gas prices in its wake.

As gas prices in North America have come off, then there's been greater incentive to swing the discretionary cargoes towards Europe.

But we take these decisions as the cargoes themselves are being loaded in Trinidad.

I would note that the first cargo out of our [New Train IV] in Trinidad had a destination of the Isle of Grainger here in the United Kingdom, kind of consistent with our throughput requirements into that facility.

Now on to William Farrah from W.H.

Reed and Co. in the United States.

Thank you for your color on Texas City, but if I may, just a couple of more downstream clarifications.

On the fixed cost side, I believe you mentioned-- or fixed and operating cost, a number of around $350 million on a quarterly basis, and wouldn't many of the costs incurred because of the terrible accident there be capitalized rather than expensed, and I'm wondering why that number is so large?

Secondly, the balance of those costs, around 300 or so, how much might the trading or as you refer to it, the optimization costs, be a factor in that number?

And lastly, on the downstream--

Well, the $350 million is-- is the revenue expenditure, the operating cost for the facility, and yes, there are items that are capitalized, but I was looking specifically at the impact on the profit and loss accounts in the second quarter.

So one starts with about $350 million of underlying charges associated with Texas City, and then one builds on top of that as margin is created, as throughput in the facility increases over time.

And as I was saying, at 200,000 barrels a day, we don't quite have enough margin being generated at current margin structure to be in a break-even mode.

Does that answer your question, William?

Yes.

Could you comment a bit on how much of the balance of that 650, just by simple subtraction, 300, would have been impaired, say, or ongoing, because of your absence of ability to pursue commercial optimization, or trading as some people call it, commercial optimization as you call it.

Well, the $650 million we're referencing would be made for the- now I'm going back to the first quarter.

We said that the impact of Texas City was about $650 million on our first quarter results.

Part of that was the underlying cost of the facility, which was then unable to generate margin.

The rest of it was the foregone margin that was achieved in the first quarter of 2005, plus some second-order effects on other businesses that are dependent upon output from Texas City in order to optimize their own particular situation.

So you had about 300, as you suggest, on 350 impact in the first quarter of 2006.

But, we continue to meet our requirements for product supplies into our customers in the United States.

This has required much more active behavior, from our supply and trading organization, and they have managed to, through their capabilities in the marketplace, ensure that we have met all of our requirements to all of our customers on the backside of the hurricane and then through the first quarter of 2006.

To try to segment these into individual buckets, as both Fergus and I have said over the course of this discussion in the past, is something we do not do because it's all really integrated into the activities of the various sites themselves.

We've got a question on the web, really following up on a remark that Byron made earlier in the call, which was, was there still issues to be addressed on the facility itself, on Thunder Horse?

In essence, this question is from Peter Hoffman at NTB.

It's merely, Peter, that there are still some follow-up activities as a result of the incident last year.

That's part of the ongoing work and the commissioning of the [topside] on Thunder Horse, so nothing very complex, really.

Just the final part of remediation from particularly the sea water damage that occurred at that time.

Sorry, Peter, if in any way I left an impression that there were material issues still to address there.

As Fergus said, things are progressing extremely well, but there was a lot to do and it's getting done.

Great.

And I think finally we've got two follow-up questions, one in the United States, one in Britain.

First of all, John Rigby at UBS.

John, do you have a follow-up question?

Yes, to what extent are the IFRS inventory effects that you can talk about, just the quarter-end accounting manifestation of the optimization activities that you're doing, right the way through the quarter-- are those two numbers related in any way?

So just the mark to market effect of the activities you're doing?

--we have a very structured risk management criteria, locking in margins, managing our stock levels to specific levels that are deemed as appropriate for an ongoing operation, so we have a fixed criteria around which we then look to manage forward exposures of throughput into the refinery.

That means that commitments are being made at one point in time and the oil being processed and subsequently sold at another point in time.

So that's what I mean by economic risk management - we will take and lock in offsetting derivatives positions relative to the underlying physical positions to ensure the margin that is available is not subject to fluctuations in either product prices or subsequent raw material prices.

Having done that, at the end of the quarter, because of the way IFRS has deemed accounts to be managed, we treat the derivatives position one way and we need to treat the physicals position in another way, so they're each marked differently than the true economic relationship between the two.

In some periods, that will create the appearance of profit.

In other occasions, it'll create the appearance of a charge.

But over the course of time, since what it's doing is the positions are set, since they're set, the underlying economic position will work its way out, over the course of a couple month timeframe.

And in each case, there's a reversal of the position in the quarter, from the quarter end effect of the prior quarter, but at the same time, as you're suggesting, a new quarter end effect is occurring, so we reverse out the end quarter effects of the fourth quarter but found ourselves with new end quarter effects at the end of the first quarter.

The net of those two created both a $100 million charge in refining and marketing and approximately $100 million charge in gas power renewables.

I hope that illuminates what is a very, very complicated accounting issue, which we're trying to make as clear as possible but it is a challenging issue and I'm very happy to continue to respond, as are Fergus and his team, to more specific questions related to this item.

Thanks, John.

Mark Gilman at Benchmark in the U.S.

Mark, are you still there?

Yes, Fergus, thank you.

Can you quantify what the hurricane-related shut-in or deferred oil and gas volumes were in the first quarter, and whether at the end of the quarter, the only significant deferred volumes were associated with Mars?

Secondly, please clarify whether that $350 million number Byron cited on Texas City includes repair costs, because if it does not, it works out on a full operating rate to be about $10 a barrel, which just sounds enormously high.

Well Mark, as far as your first question goes, the indication that we've given in our first quarter results was that in the absence of the hurricane-related effects on production in the Gulf of Mexico, production would have been more around flat, so it's about 60,000 barrels a day of production, for BP, was still being impacted in 1Q.

About 45, or about 3/4 of that, is related to the Mars field itself, which has not yet begun production, and the specifics of that, if you've got more inquiries about Mars, you should ask the operator in two days time.

Do you have any other questions, Mark?

Right now, one final, final question from the web, from the Ontario Teachers Pension Plan, James Sikora - James's question is, ``Could you please provide an update as to where you are with your plans to increase investment in U.S. conversion capacity?

As well, what are you thoughts on entering supply partnerships at oil sands producers, to streamline future feedstock needs?''

No specific update on this, except to reiterate what [John Manzone] said at the time of the investor presentations in February, which is that we have refineries that are well-positioned to take advantage of the very heavy oil that's being produced in Canada.

And that we are evaluating investment opportunities into those northern-tier refineries in the United States, in particular, Whiting and Toledo, to evaluate the economic potential of such an investment.

I just would go back and remind you that across our portfolio as a whole, BP has the most complex upgrading capability of anyone in the international oil set, and that we are continuing to look at opportunities and plan to continue to invest behind opportunities to maintain that gap vis a vis others, to utilize the cheaper, more difficult crudes in the world, to turn them into light product and to capture the margin associated with that.

Right.

That pretty much concludes the question.

I'd like to just say one final thing, which is that Neil McManus at Bernstein asked a question earlier on about Azerbaijan and the throughput from the Baku to [Jahan] pipeline.

My answered referred to overall the gross capacity of the Baku to Jahan pipeline, but just, I don't know if Neil is still there, but just for the benefit of everybody, the expectation for BP's net equity production from Azerbaijan would be that it was around 70,000 barrels a day in 2005, and on the basis of the projections we gave in February, of $40 a barrel, we would expect that production to around double in '06, triple in '07, and quadruple by '08, so it gives you a sense of one of the drivers of the significant acceleration in production growth that we expect to see as exit 2006 and through 2007 and 2008.

I'd just like to thank everybody for their patience with the technical problems that we had earlier today.

Thank you for your very good questions.

If you do have any follow-up questions, please do contact Investor Relations, and we look forward to speaking to you in something under 90 day's time.