英國石油 (BP) 2007 Q1 法說會逐字稿

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

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

Please go ahead, sir.

Good afternoon for those of you listening in Europe and Asia and good morning for those in the Americas.

I'd like to welcome you to BP's first quarter 2007 conference call.

I'm Fergus MacLeod, BP's Head of Investor Relations.

With 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 we will be using during the webcast.

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

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 day to those joining us on this call.

This morning you would have noticed that we've made several changes to the form of our stock exchange announcement.

We've also moved from a quarterly trading update to a weekly trading conditions update to deliver more timely information on key prices and margins.

These changes were made in response to feedback received from many of you.

We hope that you'll find them helpful.

Let me now begin my review of the quarter with the trading environment.

Oil prices in the first quarter continued to decline from the record level reached in the third quarter of last year.

Our average liquids realization of $53 per barrel was similar to 4Q '06 and 4% lower than a year ago.

Gas prices have, however, remained relatively flat since the second quarter of last year.

Our 1Q realization of around $4.90 per thousand cubic feet was 12% lower than experienced a year ago.

Taking both oil and gas together, our total hydrocarbon realization was 7% lower, reflecting the weaker trading environment.

By contrast, our refining indicator margin of $9.45 per barrel was 50% higher than 1Q '06.

The margins realized by our own refineries did not increase to the same extent because of our product mix and narrower light/heavy differentials.

Turning to the financials, our replacement cost profit was $4.4 billion, 17% lower in absolute terms than 1Q '06.

Our profit including inventory gains and losses was $4.7 billion, also down 17% compared to last year.

These figures include gains of around $400 million for non-operating items.

I'll describe these items in more detail when discussing individual segment results.

Operating cash flow of $8 billion was also lower compared to a year ago, but by less than the reduction in earnings.

The lower per share impact for all our financial metrics reflects the 6% reduction in our shares outstanding over the past year.

The $0.10325 per share dividend announced today, which will be paid in June, is 10% higher than a year ago.

The sterling dividend is down slightly, year-on-year, reflecting the sharply weaker dollar.

Turning now to our segments, in E&P we reported a pretax profit of $6 billion for the first quarter, which included approximately $750 million of non-operating gains in respect of disposals and embedded derivatives.

Excluding these non-operating items, our underlying result was $5.3 billion compared with $7.2 billion last year.

This reflects lower realization, lower reported volumes, continued sector-specific inflation, greater integrity spend and higher DD&A charges.

Reported production of 3.9 million barrels of oil equivalent per day was down around 3% compared with a year earlier.

Adjusting for divestments, production was flat.

Underlying production reflected strong growth from new projects, offset by declines in our existing profit centers and lower entitlements under production-sharing contracts.

Full-year production is expected to be in the range of 3.8 to 3.9 million barrels of oil equivalent per day, consistent with the guidance given in February.

The TNK BP first quarter contribution was much lower than 1Q '06, reflecting lower prices and the adverse effect of lagged tax reference prices.

Our refining and marketing result was around $850 million in the first quarter.

This includes a charge of about $250 million for non-operating items, mainly related to impairment.

Excluding non-operating items, our underlying result was $1.1 billion, similar to a year ago.

Our results benefited from a stronger margin environment for both our refining and marketing businesses.

The benefit of higher refining throughput, primarily at Texas City, was more than offset by the impact of operational issues at a number of our other refineries.

In addition, the quarter's result reflects a significant IFRS fair value accounting charge, lower supply optimization benefits and greater integrity spend.

Late in the quarter, operational issues at the Whiting refinery have reduced the throughput to around 200,000 barrels per day, around half its capacity and limited the crude flay to primarily sweet grades.

This will continue until we complete the necessary repairs.

Our 1Q underlying result in gas, power and renewables was $200 million compared with around $350 million last year.

This reflects a lower marketing and trading contribution, which was partly offset by the absence of last year's fair value accounting charge and strong operational performance in our NGL business.

In other business and corporate, or OB&C, our first quarter underlying charge was $150 million.

Whilst we expect the charge to vary quarter on quarter, our full-year view remains unchanged.

We expect the annual charge to be around $900 million, plus or minus $200 million.

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

As we said in February, we are committed to transforming BP into a leader in process safety management.

We are currently incorporating the Baker panel recommendations into our forward plans, which already reflect significant changes to our process safety system that include substantial investments in integrity management across the Group.

In exploration and production, we secured new access in Oman that could yield resources of some 20 to 30 trillion cubic feet of natural gas.

We continued our strong exploration track record in Angola, with Miranda, our 13th successful well in block 31, and made the Giza North gas discovery in Egypt.

In refining and marketing, we continued to improve the positioning of our refining portfolio with the acquisition of our partner's 31% share of the Netherlands Refinery Company and the announced divestment of the Coryton refinery.

We continue to make significant progress in alternative energy and biofuels.

We announced plans for the construction of 5 U.S.

wind power generation projects, which are expected to deliver a combined generation capacity in excess of 500 megawatts.

We have also begun expansion of solar cell production capacity in both Spain and India and we've selected our research partners for the BP Energy Biosciences Institute.

Returning to the Group result, this slide compares our sources and uses of cash for the first quarters of 2006 and 2007.

Cash inflows and outflows were essentially balanced in 1Q '07.

Operating cash flow of $8 billion and around $900 million of disposals funded $3.7 billion of organic CapEx and $1.1 billion of acquisitions, plus $4.4 billion of shareholder distributions.

Our net debt ratio remained flat at 20% in the first quarter, at the lower end of our target band of 20% to 30%.

Cash dividends in the first quarter increased to $2 billion and we bought back $2.5 billion of shares, further reducing shares outstanding by more than 1%.

Over the past year, a considerable amount of our attention and energy has been focused on the various incidents of 2005 and 2006.

This clearly has impacted our performance.

Nonetheless, we've come a long way and the lessons we've learned are being embedded across the Group.

2007 will represent a year of consolidation.

We are stabilizing our operations and beginning to build momentum as Texas City continues its recommissioning and we focus on delivering major E&P projects like Atlantis and Thunder Horse.

Our strategy is unchanged and our current focus remains on safe and reliable operations and the delivery of improved performance.

That concludes my presentation of our 1Q results.

Fergus and I would now be pleased to address your questions.

(OPERATOR INSTRUCTIONS)

Thank you, operator.

We'll now go to the first question, which I think comes from Neil Perry at Morgan Stanley.

Neil, are you there?

I am.

Thanks very much.

Byron, I wonder if you could answer two questions on the downstream.

Firstly, on Whiting, which has-- you say it's gone down-- down to half capacity, could you quantify for us what sort of contribution Whiting makes as one thinks about the impact Texas City has had and Whiting is of a similar size, albeit not as severe.

And secondly, can you tell us what the actual mark-to-market effect is in the downstream, giving that you say it's substantial, but this number is now-- well, it's often a third of the downstream result number.

Can you actually tell us what the number is so that we can get to an underlying result?

Thank you, Neil.

Why don't-- why don't I deal with the second question first?

Because I was wondering how long into the webcast we'd go before someone asked that question and expected it would be first and, indeed, it is.

I want to-- I want to back up to go forward.

We-- we don't provide specific disclosure on the mark-to-market effects because this item is only a timing feature on the recognition of income on certain inventory positions that we have around our refineries.

It reflects the difference between the way we economically manage the risks and assess the day-to-day internal performance within the sector versus the timing in which the contribution is reflected in our accounts.

It is an underlying feature of our accounts under IFRS and that's the reason why we've not considered it an non-operating item.

I know some of you have asked me this question in the past.

That said, it-- it-- and this-- the timing impact on R&M in the first quarter, as you pointed out, Neil, was significant.

In fact, for R&M it's the largest that we've had since we began reporting under IFRS.

And, as a consequence, we've got a significant amount of deferred economic gain -- I do mean economic gain -- that'll be realized over subsequent quarters and the exact timing of that will be dependent upon the market structures that evolve at the end of the quarters in those particular reporting periods.

As I've pointed out before, over the course of the calendar year, these timing differences tend to wash out and it's not material on a sector basis-- on a segment basis, let alone on a Group basis.

Now we do review this.

We had a long discussion about it at the-- at the start of this calendar year reporting cycle and we've concluded that the current presentation of the effect is still the-- the appropriate one because, coming back to the initial thought that I conveyed, this reflects a difference between the way we run our business on a day-to-day basis and the way that our statutory reports need to be configured.

And, as such, we think of it as underlying income and we'd like you to think of it as underlying income, as well, noting, of course, that there are timing effects that-- that do tend to skew it a bit back and forth.

To help you, we've been willing to provide directional indicators and I hope you find those directional indicators helpful, but it does remain our intention not to provide specific disclosure of this item, nor to pull it out and treat it as a non-operating item.

Byron, can I just come back on that for just one second--

You have questioned, why don't you see it in the quarterly reports of other companies?

I can only suggest that you ask them that question and you my get more insights into how they recognize their underlying reporting amounts as a consequence.

As far as-- as Whiting goes, I hope you appreciate, Neil, that this is actually an extremely difficult thing to estimate, given the uncertainty of the timing, given the uncertainty on the cost of the repairs and given the volatility of the margin environment.

What I will say is that if we look back to the last year when refining margins were very strong in the second quarter -- just now I'll talk about the second quarter -- Whiting did make a very significant contribution to the Group results in that quarter.

So we'll see a significant difference, quarter-on-quarter as a result.

As a very rough indicator -- and I do mean that this is a very rough indicator -- if margins are in the area that we see today -- and they may well be higher or lower -- but if margins are in the area that they are today, the forgone loss of contribution would be of the order of $100 million per month -- that's month, not per quarter -- plus any repair costs that are associated with that.

So hopefully that'll give you some way to get a calibration of how this may impact the second quarter results.

Again, at this stage, we cannot provide you specific guidance on timing, because we're still assessing the magnitude of the repairs required and the amount of time that will be needed to put those in place.

Thank you, Byron.

Can I just come back on that disclosure point that you made?

There's just two things.

One is that-- that the downstream is the area where you've had the biggest problems and we're all looking for some evidence that Texas City is coming back and making a contribution, yet the-- these mark-to-market swings are a multiple of the impact of Texas City on a quarterly basis.

So it's making it absolutely impossible to track the progress in probably your key performance division.

And second, it seems that you're looking at the business without that swing in it, yet we're unable to.

So it would be helpful just to be able to know what that number is, even if you don't take it out your numbers so that we can take it out if we choose to.

I note your comment, Neil.

Okay, thanks.

Thanks very much.

On Whiting, we have another related question from [Bruce Varney] on the web, which was, "Can you expand more on the issues at Whiting?

What are the specific problems and is this operationally or safety related?"

Just for everybody's information, the issue was in this year, March the 22nd, there was a failure of a hydrogen compressor on the hydrotreating unit at Whiting.

There was a fire.

Most importantly, nobody was injured, but the damage that's resulted from that fire has rendered that unit inoperable until repairs can be completed.

And there was a second incident, unrelated, on April the 5th, which was a power outage at Whiting which, again fortunately, there were no injuries, but it has led to several process units being taken out of service.

I stress these incidents were operational in nature.

Prior to the failure of the hydrogen compressor, it had been regularly inspected.

No mechanical or process deficiencies had been identified when that inspection took place just weeks before the incident.

So these were operational and of a mechanical nature, but they have had the implications that Byron described.

Moving on to the next question, we have Dan Barcelo from Banc of America.

Dan, are you there?

--natural gas prices, in particular, first quarter '07 versus the year-ago period, as the realization that you've highlighted seems to be in line, despite the collapse in the U.K.

spot market over the same period.

I didn't know if you could comment a little bit about your exposure to U.K.

spot-- contract versus spot and a little bit on the pricing on the U.K.

move?

We have very little exposure, Dan, to U.K.

spot prices.

One of the elements that we oftentimes refer to in the-- in the results is the impact of embedded derivatives and those embedded derivatives exist because so much of our contracted volume is tied with various other index commodities, in some cases oil, in some cases products, in some cases electricity, in some cases coal, in some cases just a normal inflationary index.

So the-- the largest amount of our volumes in the United Kingdom tend to have longer-term contractual term prices.

They do vary, but they do not vary with respect to the U.K.

spot price and that's the thing that you're seeing as you compare first quarter of '06 versus first quarter of '07.

Perfect, thank you.

And now coming back to Ed Westlake of CSFB.

Ed, are you there?

Yes.

Good afternoon, everyone.

Obviously, TNK's profitability has fallen and we know some of the reasons in terms of domestic realizations and also higher taxes.

Can you just maybe just give us an outlook in terms of some of the arms and legs of how some of those things may change in terms of cost inflation, et cetera, going forward?

And then, just an update on Atlantis and Thunder Horse in terms of startup dates.

Thank you.

Okay.

Let me cover the Russian question and Fergus will talk a bit about Atlantis and Thunder Horse.

As far as-- as TNK BP goes, the-- the biggest thing that tends to swing around our results there is the impact of the tax reference price, which-- which is calculated on a lagged basis and especially during periods when prices are volatile, it can-- it can swing profits up substantially or, by contrast, reduce them quite substantially.

If I just talk about the first quarter of '06 versus the first quarter of '07, in 1Q '06 the Urals price in the first quarter was $4 more than the tax reference price, which is calculated more or less on the basis of prices that exist in the previous quarter.

Whereas in the first quarter of 2007, the Urals price was about $2.50 below the tax reference price.

So that was a $6.50 swing against an environment that was not that much, really, different.

And it has, because of the marginal tax considerations, quite a substantial impact on-- on underlying P&L.

As far as costs and related matters in Russia, they're not immune from the sort of inflation that we're seeing in other parts of the E&P sector, which have seen inflation increasing at about the rate of 14% per annum.

It's dependent upon the particular area of cost.

Some are higher; some are lower.

But the operations in Russia are facing the same sort of challenges but are managing it as we are in-- elsewhere in BP's operations by pursuing a number of cost-mitigating steps which take out a bit of it, but you still see the underlying inflationary pressures coming through.

You want to speak briefly about our projects, Fergus?

Yes.

Really nothing much new to say from what we said in February on either Atlantis or Thunder Horse.

Those projects are proceeding well, Atlantis for a startup by the end of this year, Thunder Horse for a startup by the end of next.

Clearly we have to get through a (inaudible) season in the Gulf of Mexico and we have to get through a hurricane season, one in the case of Atlantis and two in the case of Thunder Horse.

One thing that is going pretty well is that the delays in this projects have allowed a larger number of the production wells to be pre-drilled, which means that the ramp-up, once the projects do come on stream, may be more rapid than had been the case with the earlier schedule.

But no, they're both on schedule according to the time scale that we laid out in February.

Thanks very much.

Ed, if I could just add a more general comment to Fergus' specific reference to Atlantis and Thunder Horse.

If we look across our projects as a whole, we could say the same thing, that, obviously, not very much time has passed since-- since we talked with you at the time of the fourth quarter results, but across the portfolio as a whole, we've-- we've made certain that we've built in appropriate contingencies, recognizing that there inevitably are some startup issues and that we want to make sure that we-- we've built in factors appropriate for that.

And we do find that these pop up.

But nothing is happening and we wouldn't anticipate at this time that things would happen that would throw us off of the-- the forecasted time table for the ramp-up of production that we shared with you during the course of our February presentation.

Moving on to Neil McMahon at Bernstein.

Neil?

Hi.

I've got a few questions, really, again on Russia.

The first thing on Russia, it seems like there are lots of reports in the papers when you look at who might be the successor to Putin that the new hydrocarbon law could be extended from future strategic new reserves to existing producing strategic reserves and I was just wondering -- a) if you could give us an update on Kovykta and Rospan and b) give me your interpretation if the new hydrocarbon law will also apply to Samotlor, Uvat and various other TNK BP fields that TNK BP currently operate?

Again, there is not much to-- to share relative to what Bob Dudley described in the webcast and various meetings that took place in February.

We remain confident of our position in our various licenses across Russia.

We recognize that there's a lot of speculation, some of it on our properties and some of it across the hydrocarbon sector as a whole.

It is a place where rumor is rife and until there's fact behind the rumor, I think we should continue to treat it as such.

Just, Byron, maybe is there any time scale we should be looking at for any announcements in the next few quarters at all on Russia?

With respect to what, Neil?

With respect to, I suppose more specifically Kovykta and Rospan.

Do you think you'll know the ultimate position before the end of the year or is this something before the middle of the year?

I'm sorry, but I don't think it's helpful for me to be speculating on things which are not in the hands of BP.

Okay, thanks.

All right.

Thanks, Neil.

Now back to Jon Rigby at U.S.

Yes, hi.

It's Jon Rigby at UBS.

A couple of questions.

The first is on supply optimization.

I noticed you said something here about gas power and also the downstream that show either supply optimization negatives or trading negatives.

I just wondered whether you could comment on those in the context of -- a) reported losses in your trading or among your traders and secondly, any change of risk appetite after, obviously, high-profile litigation started last year?

The second is just to come back to you on this IFRS accounting and it's really a comment as much as anything else.

It's the replacement cost profitability that you report is a non-GAAP measure.

It is a construct to remove, basically, inventory gains and losses on your existing physical inventory, so surely stripping out something that relates to paper gains and losses on inventory positions would be exactly consistent with that and would, therefore, help us with visibility on earnings in the same way as you do already on the physical.

Okay.

That's three or four questions.

I think I've got them all written down, Jon.

If I miss any of them, please-- please remind me.

As far as supply optimization, you termed it as trading.

It is the activity that we pursue around our refining and marketing operations and there are trading dimensions associated with it, but it's properly called supply optimization because it is around the optimizing of the supply into our manufacturing facilities and the distribution of that product out of it.

In the case of both oil and gas operations in-- in 1Q of '06, there were very, very strong results.

It was a period in which there was considerable volatility in both gas and oil prices and we were able to utilize that environment to gain particularly strong contributions from that activity.

And so some of what you're seeing in the first quarter of 2007 is a reflection of a return to a more normal contribution as opposed to the abnormal contribution that we-- that we saw in 1Q of '06.

As far-- as far as reported losses, I'm not going to comment on that, except to say obviously we-- the range of the positions that we're taking in pursuing this means that in some cases there is a negative contribution, but in aggregate there is a very significant positive contribution.

Risk appetite -- we have tight controls on the way that we-- that we utilize risk across the Group as a whole.

Those-- those controls are similar to what we have had in place for a number of years.

We've spend a lot of time making certain that they are more standardized across BP as a whole, but the risk appetite that the Group is pursuing in a very controlled manner is similar to what you saw in 1Q of '06.

I'm not going to speak to the specific issues that we have with the CFTC and with respect to both propane and gasoline except to-- to note that those discussions continue.

And as far as your comment about replacement cost profit, I-- I note, as I did in response to the first question of the day, that we have taken a look at this.

We believe that our current presentation is the appropriate one.

We clearly could choose to-- to present replacement cost profit in a different way, and we will keep that under consideration.

But having-- having started 2007 down this line, we have no plans whatsoever of changing the reporting basis that we currently have in place.

Okay, thanks.

Going back to the U.S.

and to Mark Gilman of Benchmark.

Good after-- or good morning to you, Mark.

Good afternoon, guys.

I had a couple specific things, if I could, please.

First, Byron or Fergus, can you give us an update on the situation at Shah Deniz, the nature of the problems as you currently understand them and what impact it would have regarding production levels for the project?

Secondly, do you reaffirm the 37% effective tax rate guidance for the year in light of the 35% which I calculate for the first quarter?

Third and finally, Byron, I wonder if you can clarify something out of the 20-F, at least in terms of my interpretation, namely that the conversion to SEC-based reserve reporting basis is resulting in a $400 million to $500 million increase in 2007 DD&A charges?

Could you confirm my interpretation of that and exactly what's going on and the whys and wherefores on that?

Thanks a lot.

Okay, a good point on the last one, Mark.

We referred to in the-- in the webcast, as well as in the stock exchange announcement the fact that we're seeing higher DD&A charges in the exploration and production segment.

That's related to a number of factors, but one of the factors is the change from a SORP-based reserve calculation to an SEC basis and what's driving that is that it will reduce the number of reserves that we have in production-sharing contract regimes.

It tends to increase it in tax and royalty regimes, but it decreases it in production-sharing contract regimes and, in particular, places like Angola and Azerbaijan.

And by having, then, it spread over a smaller number of barrels, remembering that one looks forward with the end of year price, which in the case of year-end 2006 was in the high $50s, taking that price over the life of the contract reduces the number of barrels, increases the amount of DD&A applied.

And the impact as we look across 2007 is, indeed, of the order of magnitude indicated in the stock exchange announcement, $500 million, plus or minus, and it will be critically dependent upon the price as it evolves over the course of this calendar year, as well.

As far as your second question, and then I'll hand it over to Fergus for an update on Shah Deniz, the 37% guidance that I provided in February was based upon the assumption of a similar price and margin environment to that that we experienced in 2006.

First quarter's been a little bit lower than that.

What we do at the end of each quarter is-- is project what we're going to see across the course of the year and, based upon what we see right now, we've projected it at being about 35.5%.

And we continue to do that smoothing on a quarterly basis as we progress during the course of the year.

I think for purposes of modeling, recognizing that prices currently are higher than the average that we saw in the first quarter and recognizing there is-- there is certain quarter-end or year-end inventory effects which we call [COSNA] effects, that tend to drive this, as well, I think a band between 35% and 37% is still the appropriate guidance for-- for the year and, depending on what your assumptions are, you should use the higher or the lower one of those two numbers.

Fergus?

Yes, Mark, your question on Shah Dinez, well, as you know, production began in mid-December.

Production is steadily building up.

We've currently completed 3 wells.

We're drilling the fourth.

There have been some teething problems as there often are in new developments, particularly when you've got complex geology of the type I know you're aware of in Azerbaijan and we're looking at those and we're resolving those on a well-by-well basis.

Production is increasing.

We're on track to reach plateau production by the winter of '08-'09.

We're already delivering gas to Azerbaijan and Georgia.

And the sort of technical challenges we've had on some of the early wells are exactly the reason why BP is in Azerbaijan and why we were invited in by the government of Azerbaijan.

It's not the world's most straightforward geology, but that's exactly the sort of cutting-edge technological (inaudible) where a company like ourselves operates, so it's really business as usual and it's all, in terms of its production implications, taken care of in the more conservative guidance that Byron described just a few moments ago.

Fergus, I was under the impression the first two wells have been shut in.

There are three wells currently drilled and the fourth one is drilling.

And two of them have been shut in at different times, Mark.

I can come back with you and give you well-by-well detail, if you'd like, after the call.

Okay, thank you.

And, Mark, we're continuing to deliver gas into Azerbaijan and Georgia and this is one project across a wide range of projects that the Group is pursuing that, in aggregate, are very much on track, as I said earlier.

Thanks, Mark.

[Lucy Hopkins] at Lehman.

Lucy?

All right.

Well, while we're looking for Lucy, perhaps we could move on to Colin Smith at DKW.

Colin, are you there?

--gentlemen.

Two things.

First of all, just in Whiting, if you can, can you give us some idea of when you might be able to get the de-sulfurization capacity back online?

And the second thing was just in your magazine you highlight that you've got the Greater Plutonia FPSO on station since February.

You wouldn't normally, I think, expect sort of an 8-month hookup time to first production there.

So I wonder if perhaps if you could tell us how that's going and perhaps update on when we might expect startup there?

Well, as far as Whiting goes, I admire your persistence, Colin, but no, we really cannot at this stage assess what is a time table for returning the unit to full capacity.

And then, Colin, as we go on to Greater Plutonia, [Nicky Dakers] asked a similar question.

What I can tell you is -- I'm going to sound a bit like a broken record here -- that nothing's changed since February.

So we're expecting startup by the end of the year.

You're absolutely right, the FPSO has reached Angola.

It's just currently getting moored.

Everything's going to schedule.

We've completed the second of the two gas injection wells, but the time scale is to start it up by the end of the year and that's the guidance that we're providing.

Thank you.

So thank you very much, Colin.

Al Anton at Burnham Securities.

Al, are you there?

Yes.

A question about Miranda, the 13th discovery on Block 31 in Angola.

There seems to be a lot of discoveries and not too much talk about development.

I wonder what your development plans are?

Also, the ratio of oil to gas on the block?

I think it's mostly oil, but I don't think that's been clarified.

And also the quality of the oil found?

Is it a light crude, acidic crude or what?

Al, well, as you know, the Miranda discovery is the 13th that we've made on Block 31.

It was just announced, again, as you know this morning.

Too soon to say in terms of a development plan, although it's clearly very promising in terms of the continued run of exploration success there.

It's light crude, yes, but I think probably the best thing is I'll come back to you with some more detail after the call and take you through some of the technical details on that.

But no, we remain very excited about the continued exploration potential in Angola.

And the ultimate development capability of the block.

I take it there'll be a number of modules aggregating some of these fields?

That's probable but no decision has been made on that at this point.

Thank you.

Irene Himona from Exane.

Irene, are you there?

Yes, good afternoon.

I had some questions on the downstream.

First of all, on the Nerefco position, is there anything you can say about potential synergies or any plans for upgrading the refinery?

And also there are-- obviously, you have less than 100% in other refineries, so should we expect to see similar moves in the future?

Secondly, is it possible to split for us the refining versus marketing profit, with or without the IFRS effects?

And finally, a question on gearing.

Some of your peers look at expanded gearing, which is what the credit agencies look at, including things like unfunded pensions and operating leases.

Can you tell us what that expanded gearing is and what the sort of upper limit would be from your perspective?

Thank you.

Okay, Irene.

You cover a lot of different areas in that set of questions.

As far as Nerefco goes, by having 100% of the operation, there clearly are the synergies that we're able to-- to manage all the inputs and all the outputs of the facility and we believe that-- that that is a very important benefit associated with the acquisition of the minority share and gives us, then, the latitude to pursue a wider range of possibilities around the Nerefco site going forward.

At this stage, there's no intention of acquiring the interests of our partners in any other refining operations.

Nerefco was a unique circumstance.

Our partner was looking to exit and we took advantage of that, but we have no plans at this time of looking to extend our refining footprint in some of our joint ventures in Europe and elsewhere.

The refining/marketing split, I'm going to speak to the clean income, so that's the $1,067,000,000 -- I'm trying to get-- the break between refining and marketing is about 25% refining, 75% marketing.

You need to remember that the refining is impacted by the bulk of the IFRS-related factors.

Refining is impacted by the weaker supply optimization.

Refining is impacted by the integrity spend that we're pursuing.

And so the refining side is taking the bulk of the once-off factors that are impacting the refining and marketing results in 1Q '07 via-a-vis 1Q '06.

Turning to gearing then, we can provide you with that, Irene.

What we-- we clearly look, like our competitors do, at expanded gearing because that is the basis upon which rating agencies are going to assess our debt.

It is somewhere in the middle 30% and when we're giving a guideline of 20% to 30% on conventional gearing, we're giving that guideline with an eye towards what does our expanded gearing shape up to be in the eyes of Moody's and S&P.

If you want a specific number, Irene, if you could give the IR department a call, we will provide you that.

It's broadly on the order of 30%, Irene.

Thanks very much.

And I think we have one final question from Jason Kenney at ING if Jason's still there.

Thank you for your patience, Jason.

That's all right.

A couple of questions answered, but you mentioned earlier a 14% cost inflation.

Was that just applicable in Russia or are you raising the 12%-13% cost inflation that we've seen across the Group over the past year or so?

And secondly, is the run rate of buy-backs in Q1 '07 indicative of a kind of average to expect in Q2, Q3 and Q4?

The cost inflation number I was providing was not a specific Russian rate.

It was across the wider sector.

It was the sort of rate we saw in 2006 and the type of rates that we're seeing in 2007.

So that's a mix across all different elements that we acquire, ranging from rigs to seismic to tubular goods, again, across the whole spectrum.

And, as Tony Hayward and Andy Inglis have previous indicated, we've managed to mitigate that by several percent on an ongoing basis across the course of the last several years, so as a company we've seen 14% translate into around 11% and we'd expect to see that to continue.

So sorry if I left the impression I was talking about Russia.

This was a more generic statement.

And as far as buy-backs go, the-- some have queried as to whether or not they should anticipate a buy-back program in line with that that they saw in 2006.

I just would remind those on the webcast that the 2006 buy-backs were a consequence of not only underlying cash flow in a high oil price, gas price and refining margin environment, but also the opportunity to distribute proceeds we received from the Innovene sale late in 2005.

So the rate of buy-back in 2006 was positively impacted by that and so we are naturally, having distributed those proceeds, operating at a somewhat lower level and consistent with statements in the past, we do not provide forward guidance with respect to our plans to buy back shares on a quarter-by-quarter basis.

Okay.

Many thanks.

Thank you, Jason.

And we've got a late question from Neill Morton at Man Securities.

Neill?

Yes, good afternoon.

A couple of quick questions.

You've given details on the problems at Whiting, but there also seem to have been a fair number of glitches recently at Texas City.

Is all this to be expected with a restart from a cold shutdown or do you see the risk of further delays beyond your plan of full throughput by end-year?

And just secondly, you commented in the outlook for the P&L tax rate.

The cash tax rate in Q1 seemed particularly low.

Could you perhaps give a guidance on the cash tax rate for the full year?

Thank you.

Okay.

Well, let me just talk about Texas City first.

Currently there is an unusual amount of media attention on Texas City and, consequently, we're seeing a lot of small operational incidents which, for the most part, occur at all manufacturing plants are getting substantial press coverage.

And while we take each of these incidents very seriously and there's been a number of them reported over the-- over the course of the last several weeks and we review them for root causes and any lessons learned, the heightened coverage of Texas City, I think, does lead to the-- the incorrect impression that-- of the progress that we're making there, both culturally and in the introduction of-- of operational integrity processes and in the recommissioning of Texas City itself.

It remains on track for startup-- or for operation at full throughput by the end of the year, as we indicated in February.

And I've lost your second question, which was--

It was just the cash tax rate.

Oh, cash tax rate.

Sorry.

The cash tax rate in the first quarter was impacted by two things on a comparable basis versus 1Q of '06.

In 1Q '06 we paid additional taxes associated with-- with the gain on sale from Innovene.

So that impacted the cash taxes in 1Q '06 by about $0.5 billion and we received in the first quarter of 2007 a refund from taxes paid in the United States of about $400 million.

So the swing between 2006 and 2007, about $1 billion of that can be attributed just to those two once-off effects.

In general, in a steady state environment, you'd expect our tax cash-- cash rate to run a couple percent below our effective tax rate.

So somewhere 33% to 35% is a good projection, but these two once-off effects that I talked about would have biased last year up and this year down a bit.

Okay.

That's very clear.

Thank you.

Well, thank you, Neill, and we don't appear to have any further questions, so I'd just like to say thank you for your interest.

We look forward to speaking with you again after the second quarter results in July and, in the meantime, as ever, if you have any questions or queries, please don't hesitate to contact the investor relations team.

Thank you.

Have a good day.