英國石油 (BP) 2009 Q4 法說會逐字稿

Welcome to the BP presentation to the financial community, webcast and conference call.

I now hand over to Fergus McLeod, head of Investor Relations.

Welcome to BP's fourth-quarter 2009 results conference call. I'm Fergus MacLeod, BP's head of Investor Relations. And joining me today are Tony Hayward, our Group Chief Executive; Byron Grote, our Chief Financial Officer; Andy Inglis, Head of Exploration and Production; and Iain Conn, Head of Refining and Marketing.

Before we start, I'd like you to take a moment to read this next slide. As usual, during today's presentation, we will be making forward-looking statements. As ever, actual results may differ from these plans or forecasts for a number of reasons such as those noted on this slide and in our SEC filings.

I would also like to remind you that we are holding our annual strategy presentation on March the 2nd. More detail on some subjects such as reserves replacement and capital spending plans will be covered then. Thank you. And now over to Tony.

Thank you Fergus. Ladies and gentlemen, welcome to BP's fourth-quarter results of 2009. Before I hand over to Byron to take you through our 4Q results in more detail, I would like to spend a few moments reviewing what was a very good year for BP. Let me begin with our 2009 full-year financial results.

Headline replacement cost profit was $14 billion equivalent to $0.745 per ordinary share, down 45% from 2008 due to the much weaker environment. Post tax operating cash flow was $27.7 billion, our organic capital expenditure was $20 billion, and we divested around $2.7 billion of non-core assets.

Total 2009 dividends paid were $0.56 per share, up 2% in dollars and 24% in sterling versus 2008. This means we distributed to shareholders $10.5 billion. Despite the overall weak trading environment our financial condition remains robust with gearing ending the year at 20% at the bottom of our target range of 20% to 30%.

Before I talk about the operational and strategic process that we made during 2009 I'd like to summarize our performance against the expectations we set out a year ago. This highlights the momentum we are seeing in growing our business and making it more efficient.

In exploration and production we increased production by more than 4% in 2009 well ahead of our expected sustainable long-term growth rate of 1% to 2%. In refining and marketing, we increased refining availability by around 5%. The restoration of our refineries is now largely complete and they're approaching full operating capability.

On efficiency and costs we did better than we had expected. We exceeded our initial cash cost reduction objective by more than twofold with 2009 cash costs down by more than $4 billion year on year. With that totaled approximately 60% was a consequence of direct interventions by the Company with the remainder related to foreign exchange benefits and lower fuel costs.

We maintained capital spending in line with guidance whilst benefiting from the improving efficiency of this spend. And finally we achieved our targeted level of divestments to improve the quality of our portfolio. I'm pleased with the track record we are establishing of delivering on our promises to shareholders and at the same time I'm conscious there is a lot more for us to do.

Let me now look at the strategic delivery from each of our businesses in 2009. In exploration and production we've continued to see very strong strategic as well as operational and financial momentum. In 2009, we were successful in accessing substantial new resource opportunities including a major new entry into Iraq with the Rumaila field, one of the great oil fields of the world.

In Indonesia we obtained the rights to develop coalbed methane in the Sanga-Sanga PSC through our joint VICO joint venture and, subject to government approval, we added acreage in West Papua close to the Tangguh LNG facility. In Jordan we are joining with the state-owned National Petroleum Company to exploit the onshore Risha gas concession.

We also strengthened our exploration portfolio in several of our core areas by adding acreage in the deepwater Gulf of Mexico and in the Nile Delta of Egypt. And in Azerbaijan we signed a memorandum of understanding with SOCAR to jointly explore and develop the Shafag and Asiman structures in the Caspian sea.

Our industry-leading track record of exploration success continues including the Tiber discovery, a joint field in the Gulf of Mexico, which along with further appraisal success on Mad Dog South helps to underpin the potential for continued growth in the deepwater Gulf of Mexico.

We had further good news in deepwater Angola with the 17th, 18th, and 19th discoveries on Block 31. Conversion of past exploration success into production continues with the startup of seven major projects -- Tangguh LNG in Indonesia; Dorado, King South, and Atlantis Phase II in the Gulf of Mexico; and Savonette in Trinidad. And in TNK-BP we saw the start up of Uvat and Kamennoye.

The pipeline of future projects was increased with the final investment decision on a number of new developments including Block 15 Clochas Mavacola in Angola and the Serette new field development in Trinidad. In addition strong performance from the first well in the second phase of Atlantis has given us confidence to make a final investment decision on further development this year.

And last, but by no means least, I'm pleased to report that we achieved a resource replacement ratio of more than 250% and a reported reserve replacement ratio of 129% in 2009, continuing our industry-leading track record of better than 100% reserve replacement ratio over the last 17 years.

Turning now for the downstream business. We have made significant progress in the planned turn around of the business on all levels with improvements in safety, operational and underlying financial performance, albeit in the face of a dramatically weaker industry environment with refining margins in the fourth quarter at their lowest level for almost 15 years.

Starting with safe and reliable operations, which remains our top priority, all of our operated refineries and major petrochemical plants are now on our group wide operating management system. We've restored missing revenues through a significant improvement in our operational performance. Our Solomon availability for the year with 93.6%, the highest level since 2004.

We've established new regional business service centers in Budapest, Kuala Lumpur and Chicago which will carry out finance, customer service and procurement activities more efficiently. And we've made good progress on business simplification including completing the sale of our Greek ground fuels marketing business, reducing our geographic footprint in the international businesses, and franchising our US convenience retail.

Over the last two years we've reduced our refining and marketing head count by more than 4,500 excluding retail staff. Coupled with other cost efficiency initiatives this has reduced 2009 cash costs in refining and marketing by more than 15%.

In alternative energy we are now focused on four key areas -- biofuels, wind in the US, lower-cost solar manufacturing, and two major carbon capture and sequestration projects in Abu Dhabi and California.

Our forward agenda has been focused around corporate efficiency where we have exceeded our original objective having reduced the told BP non-retail headcount since December 2007 by around 7,500 and permanent contractors by more than 1,500. In addition, we've reduced senior executive roles from 650 to fewer than 500.

In parallel, across the business we've continued our focus on deepening expertise. Over the last two years almost 22,000 people have left BP and over 14,000 have joined accelerating the process of change within the Company. We will continue to drive greater efficiencies into the business to ensure that we really do make every dollar count.

Now over to Byron who will go through the 4Q results in more detail.

Thank you Tony and good way to those joining us on this call. I will begin my review with a summary of the trading environment. The table shows the percentage year--on-year changes in BP's average upstream realizations and the refining indicator margin for both the fourth quarter and the full year.

In the fourth quarter the group delivered strong operational performance against a mixed market environment. Our liquid realizations increased by 8% compared with the third quarter rising to $68 per barrel, over 30% higher than 4Q '08. Our 4Q gas realizations increased to $3.68 per thousand cubic feet, over 30% higher than the previous quarter but almost 30% lower than a year ago.

Taking both oil and gas together, our total average hydrocarbon realization was up 12% compared with 4Q '08. Refining margins remained very weak with global industry refining utilization in 4Q running around 80%. Our refining indicator margin of $1.49 per barrel in 4Q was over 70% lower than a year ago.

Turning to the financials. Adjusting for the charges of $940 million for non-operating items and fair value accounting affect, our fourth-quarter underlying replacement cost profit was $4.4 billion, an increase of 70% on 4Q '08. The higher result benefited from production growth, strong operational performance and reductions in cash costs.

The underlying replacement cost profit included a negative consolidation adjustment of $500 million reflecting higher volumes of equity barrels in our downstream inventories at year-end coupled with higher prices. As in the past, this volume impact is likely to reverse out in future quarters.

Non-operating items included a $1.6 billion write-down of goodwill in refining and marketing related to our US West Coast fuels value chain. Adjusting for the impact of this goodwill impairment, which is not tax deductible, the effective tax rate in the fourth quarter was 27% and for the full year it was 31%. Fourth-quarter operating cash flow was $7.3 billion, up nearly 30% compared with the same period in 2008.

The $0.14 per share dividend announced today, which will be paid in March, is the same as a year ago. We also announced today that subject to shareholder approval at the annual general meeting on the 15th of April we'll be replacing our current dividend reinvestment programs with an optional scrip dividend. We believe that for those shareholders who choose to take their dividend in shares rather than cash the issuing of scrip is a more attractive alternative. Any cash freed up by this change would provide the Company with additional financial flexibility.

In exploration and production, after adjusting for a gain of $1.4 billion for non-operating items and fair value accounting effects, we reported a pre-tax underlying replacement cost profit of $7.1 billion for 4Q, up $2.8 billion compared with last year, reflecting both higher oil prices and stronger operational performance.

Production exceeded 4 million barrels of oil equivalent per day, 3% higher than a year ago. In addition, the fourth-quarter production benefited from the makeup of a prior period underlift of around 40,000 barrels per day.

We maintained momentum in reducing costs. Full-year unit production costs was 12% lower than 2008. DD&A was higher than a year ago in line with previous guidance. BPs share of TNK BP net income was $540 million for the quarter and we received a dividend of $940 million.

In refining and marketing, after adjusting for charges of $2 billion for non-operating items and fair value accounting effects, we reported a pre-tax underlying replacement cost profit of $15 million for the fourth quarter. This was a decrease of $630 million compared with the same quarter of 2008 primarily due to the extremely weak refining environment. Rising crude prices and reduced volatility also compressed marketing margins and led to a weaker supply and trading contribution.

Our operational performance, however, continued to strengthen with Solomon availability increasing still further. Costs continued to track well below 2008 levels. Looking ahead to the first quarter, we expect refining margins to remain weak.

In other businesses and corporate, after adjusting for loss of $65 million for non-operating items, the fourth quarter's result was a charge of $330 million, a $50 million improvement on a year ago. This year-on-year improvement was primarily due to favorable foreign exchange effects and lower costs partially offset by a much weaker margin environment for shipping and solar.

Turning now to cash flow, this slide compares our sources and uses of cash in 2008 and 2009. At the start of 2009 we indicated our intention to balance our sources and uses of cash in an oil price environment of around $60 per barrel. We have essentially achieved this aim during 2009 despite much weaker than expected refining margins and North American gas prices.

Our net debt ratio was 20% at the end of 4Q, 1% lower than a year ago. This reflects the numerous steps we took to improve business performance and enhance cash delivery in the face of the weaker environment we experienced in 2009.

I will now turn to specific guidance for 2010. Production growth was very strong in 2009. It benefited by about 40,000 barrels per day on an annual basis from the combination of the absence of a significant hurricane season and the underlift makeup I mentioned earlier. As a result we expect production in 2010 to be slightly lower.

Our longer-term guidance is unchanged and indeed our confidence in the longer term has been reinforced by our successes in exploration and access in 2009. We will talk more about this in our strategy update next month.

Building on the significant reductions we achieved in 2009, cash costs are expected to fall further as the benefits of our actions continue to feed into the bottom line. In the current environment, we expect to face adverse year-on-year foreign exchange and energy cost effects which would be an offset to our underlying progress in 2010.

We expect our organic capital expenditure to be around $20 billion including an increasing growth component as the efficiency of our spend continues to improve. DD&A is expected to increase by around $500 million in 2010, a smaller increase than in 2009. Divestment proceeds are expected to be between $2 billion and $3 billion, similar to 2009.

We expect an underlying average quarterly charge of $400 million from other business and corporate costs in 2010. This is likely, as in previous years, to remain volatile on an individual quarterly basis.

The effective tax rate for the year is likely to be slightly higher in the range of 33% to 34% due to a slightly lower expected proportion of income from associates and jointly controlled entities which, as you remember, are included net of tax.

That concludes my remarks. Now back to Tony.

Thank you Byron. Before I conclude with the summary of our strategy let me say a few words on the environment as we move into 2010.

In the major economies of the US and Europe we expect recovery from the recession to be slow and gradual. The oil markets look well supported by OPEC but we expect gas markets to remain volatile. Demand for petrochemicals products is recovery only slowly and there is significant refining over capacity, particularly in the Atlantic basin. As a consequence, refining margins are likely to remain depressed for the foreseeable future.

Let me close by summarizing our strategy. It hasn't changed. In the upstream we remain focused on delivering profitable growth. As Byron has already said, after a very strong year in 2009, we expect reported production in 2010 to be slightly lower. This expected level of 2010 production is in line with the guidance we gave in our strategy update in March of last year. Growth is expected to resume in 2011 and the longer-term guidance is unchanged. Costs are expected to come down and capital efficiency to go up.

In the downstream, operational momentum has been restored and we are continuing to drive cost efficiency. In alternative energy we have focused on four key areas and have a disciplined investment framework. And we are continuing to drive efficiency at the corporate center.

In closing, 2009 has been one of the best years for BP and its shareholders since the merger with Amoco, but we're not resting on our laurels. In an environment that remains challenging and volatile, particularly in the downstream, there is a lot more to do.

Thank you for listening. The team and I would now be delighted to take your questions.

(Operator Instructions)

Let's begin with going to Mark Bloomfield at Citigroup. Mark, good afternoon.

Just a quick question on the cash cycle, please, and your priorities there. Clearly gearing stands right at the bottom of your preferred gearing range and in 4Q you generated over $1 billion of free cash flow predisposals which I guess suggests, all other things [being] from the macro environment, you could sit well beneath 20% coming in at the end of 2010.

I just wondered if it's still your intention that -- well, will excess free cash be used to delever the balance sheet some 20% or do you think we should expect to return to distribution of excess of cash flow or indeed do you think you have got the optionality in your CapEx program to significantly increase activity? Thanks.

I think the short answer to your question is that it is all too early. We remain very cautious on the overall trading environment. We want to demonstrate that the momentum we have delivered in 2009 is sustainable, and as I said we are not so sure about how the environment is going to pan out.

We have been very clear about our financial framework over the years and it remains intact. Clearly, if the world looks a lot better and we are delivering significant free cash flow, then we always have the opportunity to return it to shareholders.

Thanks.

Let's go now to Alastair Syme at Nomura. Alastair?

Good afternoon. I'll just ask about the reserve replacement figure. I know you probably won't -- it's too early to give too much granularity, but I don't recall a lot of big sanctions in 2009. So maybe you can just fill us in for where the big components are coming from?

Well, it's across the portfolio. Andy will go into much more detail in this in early March, but it is a reflection of the progress we are making of adding reserves across the portfolio. So I wouldn't actually highlight anything in particular. It's across the board.

The only thing I would say is that BP on its own was also well over 100%. So it's not like it's a TNK-BP phenomena. It's a broad base and Andy will go through the details in a months time.

If I would just add in terms of the SEC rule changes, there was no contribution from that. So it is actually around the underlying performance from our asset base, as Tony says, around the world.

Thank you, gentlemen.

Let's go now to Theepan at Morgan Stanley. Theepan?

Good afternoon. A couple of questions actually. Firstly, just on production. Perhaps, I think you have mentioned a return to growth in 2011. Can you sort of give a little bit of a flavor in terms of startups relative to 2010, what you expect in 2011 and 2012? I know we have got the March presentation coming up, but do we see a substantial ramp up beyond 2010?

Secondly, just a follow-up question on 2010. I wonder if you can give a little bit more color on assumptions on three areas, [EROC], Russia, and also US gas. Thank you.

Let me ask Andy to give you a brief synopsis. To go through it in detail would take a long time but let me get Andy to a give you a brief synopsis, both of the projects we see starting up over the next couple of years, but also I think importantly the final investment decisions that we anticipate taking over that time frame as well.

Yes. Thanks, Theepan. We will obviously cover this in more detail in March but I can give you the overall color. Clearly we had a very strong performance in 2009; it was sort of beyond what we talked about. And part of that is about confidence in the delivery of the base. As we look forward, I think we demonstrated that the base is firm. It's performing well and we have a sound basis on which to forecast future decline rates. So that is the first thing that I take away from 2009.

Going into 2010, as you are aware, it's not a year of big startups in the upstream. Just a couple of projects starting up, Great White and the Noel project in Canada.

By contrast in 2010, we have a very long list of projects starting up. There are eight major projects starting up in 2011, three of them are in the Gulf of Mexico. The Galapagos area development has a big tie back to Na Kika; the next phase of northern development of Atlantis, Ni Kika Phase III. Then we have two large startups in the North Sea, Skarv and Valhall. We have the Liberty project in Alaska and Serrette the next phase of development in Trinidad.

So very long list of projects all on track and I think we've demonstrated the delivery on our major projects over the last couple of years. I think actually more important than those is actually the projects that we are going to bring to FID in 2010. Of course that is all about growth beyond 2010 and sustaining that growth into 2012 and 2013.

It's a long list. I've taken enough time already, but if you go down the FIDs in 2010, there were 12 in total. There will be five in the Gulf of Mexico -- Mars B, Atlantis North continuing growth there, Horn Mountain Phase II, Na Kika Phase III. The next phase in the North Sea, Devenick, Kinnoull; Chirag oil project Azerbaijan; CLOV in Angola; Sunrise in Canada; and then the extensions in North Africa In Salah and In Amenas.

So a long list and that list then continues into 2011. As you can see there is a pause in the major projects in 2010 and that was part of what we told you about in March of last year. But the future looks very strong in terms of the projects that will actually start up in 2011, most important the list of FIDs that are being progressed at the moment.

Thank you very much Andy. Let's now go to Jonathan Rigby. Jonathan, UBS.

A couple of questions actually. The first is on the downstream profit. It swung around a bit compared to the sensitivities that you give. I think 3Q looked like it outperformed, 4Q looks like it underperformed.

I just wondered whether you could give us some color on what the bits outside of refining were doing. How would you characterize that performance in the fourth quarter, whether there is earnings captured to come back as maybe trading or business to business or whatever against the normalized?

The second question is just on the impairments in the US. I guess did this come from a change of view, of the outlook for refining on the West Coast of the US? If so, what is that and will it change your plans for investments into the downstream in North America as a result? Thanks.

Let's go to Iain to talk about both the profit and the impairment and our views going forward.

Thanks for that. Firstly, on the downstream result in 4Q versus 3Q, which I think was your question, the rules of thumb as you rightly point out only give about a $450 million deterioration out of what was a $1 billion deterioration. So where did the rest of it come from?

So basically half of it is margin capture and if I can split that out there are two things. One is below normal supply and trading performance. The volatility in the marketplace was quite low towards the end of the year and that was a major contributor. And the second issue was that the rising crude oil price meant that a number of products which we price on a quarterly basis lagged the price and so we ended up with margin compression. So that dealt with about half of the difference that you can't see.

The other half was costs. This was a number of dimensions. We had higher turn arounds in the fourth quarter which I think we had signaled. There was some other investment decisions that were slightly lumpy to do with sales promotion in lubricants. And then really the rest of it is phasing effects. 3Q had slightly lower costs in a phasing sense and 4Q slightly higher. So that is basically where that came from.

As far as the impairments are concerned, this does result from the current low margin situation. Obviously you have got to join where we are today to a view of the future. Clearly we came off a considerable way over the year and the front end of any forward view clearly affects the MPV and carrying value of assets.

So we had to look at that in combination with the future view of margins in the West Coast and say this is the prudent thing to do. Obviously we go through the goodwill assessment each year. Although I'm not the CFO let me just say one other thing about it, we don't amortize goodwill under IFRS. And so clearly if we had done since we bought ARCO there wouldn't be much of it left, but we don't amortize it and we have written it all off as a result of that margin assessment.

Thanks, Jon. Let's go to Robert Kessler at Simmons & Company. Robert?

A couple more questions on production if you don't mind. You reiterated that your long term guidance is unchanged. I don't know whether this would classify as long term any longer but just going back to your prior comments on what you were to achieve by 2012 and 2013, in early 2008 you threw out a target of 4.3 million barrels a day for 2012. I want to say that numbers or your growth rate from the early 2009 strategy update would have implied around 4.2 million barrels a day for 2013.

Glad to see you have a heavy queue of project start ups after this year but I'm wondering if both of those might be more of a stretch, at least over that time horizon, and what your thoughts are in achieving a 4.2 plus kind of aggregate growth or aggregate production figure might be?

I would say we are absolutely on track with the guidance we gave you at the strategy presentation a year ago, 2009. I don't recall off the top of my head what the number in 2012 was then but the 1% to 2% sustainable is absolutely unchanged. We clearly had a bit of a flying start in that direction in 2009 and as Andy has indicated, the queue of projects waiting to both start up and move forward gives us a lot of confidence in underpinning that projection.

I think if anything we have more confidence in that projection today than we did a year ago because a lot of good things have happened in the course of the last year to further underpin it.

Can I ask another quick follow up? On Gulf of Mexico obviously a strong year in 2009, particularly with the absence of hurricanes and the strong production from Thunder Horse, do you expect that by 2011 you can see a repeat year of at least the 2009 production levels for your Gulf of Mexico assets or might you be lower than that level?

I'll ask Andy to deal with the details of the Gulf of Mexico.

As I'm filling out your spreadsheet for you Robert but I think you would be fine to say that our goal is to grow production there. I think if you have an assumption of holding it flat, that is a pretty good assumption.

Okay. Thank you.

Thanks very much, Robert. Let's go now to Irene Himona, Exane.

On costs if I may, excluding FX and energy costs, it appears that last year you lowered cash costs by about $2.5 billion. So if we assume no changes to FX and energy costs going forward, how much more do you think you can do in 2010 by internal efforts?

And then secondly could you talk a little bit about the potential for external supply chain costs? Have these normalized to a $70 oil price environment? Thank you.

Thanks, Irene. We haven't quantified it and we are not going to. We'll update you as we go through the year what the -- how we are doing in 2010.

What I would say is that we clearly have done a lot within BP to deal with costs and there is still some more to do and there is still the end of the programs we are currently running. You'll notice that we took a provision in the fourth quarter of $500 million to cover further restructuring in the downstream which will clearly flow into the downstream cost base as we go forward. We will of course also see the benefits of the full year in 2010 of the actions we have taken in 2009.

I think in terms of the supply chain -- we made some good starts in the matter of the supply chain in 2009, but it's clear to us there's a lot more opportunity there both with respect to the supply chain itself and how BP approaches the supply chain, which I think is the biggest opportunity.

And Andy, in particular will talk about that in the strategy presentation in March. Iain will talk a bit more about the cost opportunity we see going forward in the downstream business in March. I would say both of them are material. So we think we've got a lot behind us but we also think there's a lot of opportunity ahead of us.

Thank you.

Okay. Let's go now to Neil McMahon at Sanford Bernstein. Neil?

Hi. Just going back to reserves again, you've given plenty of color before your strategy presentation but just a quick one on your proven developers there. Have they grown this year? They have been holding pretty flat for the last few years, just wanted to know how they were growing. It certainly looks like your proven undevelopers there have gone up with your reserve replacement numbers, but any clarity on that would be great. And I have got a few more questions too.

Why don't you finish your questions, Neil, because you're not going to get a detailed answer to that? You will have to await the strategy presentation and the publication of the annual report.

Okay. So I'll keep going. Your disposal plans going forward, it seems like there's been a sort of $3 billion run rate in terms of disposals. Any clarity on what you are looking to dispose of, anything in particular?

And just lastly on a cost question. DD&A per barrel is rising; it's risen over a dollar or so a barrel over the last year. Any projection of how that's going to keep going over the next few years as you progress projects? And what do you think the impact of a movement in natural gas prices if we continue to see the levels of $5, $6 per MCF this year relative to $3 or $4 MCF for last year is going to do on your cost base? Thanks.

Let me take the disposal one. I think we will continue to sift the portfolio and dispose of non-core assets. That means things that are peripheral to the business. We've got a long list of things, nothing of any particular note individually, but all together add up to somewhere between $2 billion and $3 billion and as we do it we'll tell you about it. In terms of DD&A, Andy would you like to?

Yes. I'd actually say that if you look at the delta of '09 to '08, primarily the increase in DD&A in the upstream was all volume driven, which sort of says that the unit rate was relatively flat. And I think as you look forward, I think we are starting to see the impact of the actions we are taking on capital efficiency.

Today's F&D is obviously tomorrow's DD&A and the F&D costs have come down significantly in '09 versus our long-term trend. They are actually around $12 a barrel versus a five-year rolling average of around $16. So you have seen the steps changes we are making I think both in capital efficiency and in the pull through of reserves on that.

So I actually look to that as being an important part of us expanding the margin going forward. We've obviously talked a lot about cash costs today, but it's equally important to ensure that we are working hard on the capital side which is ultimately the DD&A part of the margin. So I feel good actually about the progress we've made on that and we are starting to see a turn up in F&D and clearly that will start to turn up in DD&A.

And as Byron has signaled the increase for 2010 versus 2009 is around $500 million. Most of that is actually just to do with the difference in price, the SEC effect and the difference in price. $60 for '09 and the year-end price for '08 was around sub $40, that's a primary driver there. So I actually feel good about the long-term trend on DD&A but clearly just gets back to the agenda that Tony has talked about which is this constant drive now to bring efficiency into all of the cost lines.

Thanks Andy. I think on gas price you have to look at the capacity that is being created in the supply chain over the last two or three years I suppose. And the key thing is that of course the rig count is probably about half what it was two years ago. I don't think a gas price moving to $5 or $6 an MCF is going to change materially at all the level of activity that the industry is conducting because put simply we are all demonstrating, I think we have done this particularly well, that we are getting more out for the wells we are drilling which is about the application of technology and the advent of shale gas in the US where we've established, I think, a very strong position. So I don't think a modest increase in the gas price is going to do very much at all to tighten up the supply chain in the North American gas market.

Okay. Let's keep going. [Joe Tovey] at Tovey and Co. Joe?

Good morning. Can you hear me?

Yes, we can. Good morning.

A couple of quick questions if I might. In the talks you had referred to the changes or the problems that occurred because of the relatively -- excess capacity in the Atlantic basin in terms of refining capacity. I think there had been reported shutdowns on the part of Valero, Sunoco, and Shell in the Atlantic and in Montreal, about 300,000 barrels a day or more. Does that impact upon your outlook for 2010 and thereafter?

I think the short answer is no, Joe, because more needs to be shut in before the market is going to be coming back into balance. So if you look at the supply/demand balance today, the surplus capacity is probably closer to 3 million barrels a day than 300,000. So more needs to be shut in.

Let me see if Iain wants to add anything.

Just to add a couple of comments, Joe. Firstly the total volume either shut down or mothballed in the Atlantic basin somewhere -- by our estimates somewhere between 1.2 million and 1.4 million barrels of day. But as Tony says, even that will not make a material impact.

The issue is one of oversupply, particularly of distillate. And I think just by way of comments on the outlook, if you look at 1992 to 2003, the global indicator margin levels were about $2.50 to $4.50 a barrel nominal. If you convert that into money of the day today, the range is probably $3 to $5.50 or something like that. So I think our challenge is going to be to make the business profitable in a 2009 environment and that's what we intend to do.

Thanks, Iain. Let's move on to Colin Smith at ICAP. Colin?

Hi, gentlemen. It's really a question for Iain I think or two questions. One, can you just confirm that the slightly lower throughput rates in Q4 were just all to do with turn around activity, you had no economic shut ins?

And secondly, just coming back to your comments about the $600 million that we can't quite see so easily, is it fair to characterize that as saying that at the Q4 margin structure with a more normal trading activity, more normal cost structure you would have been more like $600 million for the quarter in refining and marketing and chemicals? Thank you.

Firstly, on your first comment, the lower throughput rates were predominantly about the Rotterdam turnaround that we had just like we had indicated a slightly higher turnaround. So the only economic run cut that we experienced was a very small one in Whiting, Indiana, because of lower volumes than expected in Canadian heavy.

As far as the fourth quarter is concerned, I'm not going to give you a breakdown as to what it would have been if the margins had been, or if some of these other factors had been stripped back. But the comment I would make about it because I didn't fully answer Jonathan's question earlier, which is that clearly that some elements of this to do with margin compression one would expect to come back but I'm not prepared to give you a number for the fourth quarter because there are a lot of moving parts in that.

Okay. Thank you very much. Let's move on. I am going to take one from the web now, Paul Spedding, HSBC. Could you give us some indication of production scenarios from Rumaila field project, timing of volume? Sounds like a question for my colleague, Mr. Inglis. Andy?

I think volume may be a little too precise but let's give you some sense of the good progress we are making. As you well know we signed a contract and it was effective from the 17th of December and we agreed the initial production target at that point.

I think the most important thing then is actually the relationship that we are building in country, in particular with the Southern Oil Company and our partner CMPC. We had our first joint management committee at the end of last month on 20th of January, approved the budget. So there's real activity occurring now and that's important.

As we sort of look at the first half of 2010, it is going to be about fine-tuning the existing activity set. As you remember, we had worked with SOC for about three years I think prior to the contract, really advising them technically on the opportunity set in Rumaila. So all of that work is now coming to bear and it's actually about ensuring that we've got the best activity currently being done and a huge opportunity there.

And then the back half of 2010 as we start to contract and bring in new supply, new activity, an increase of activity will occur. So we are off to a good start and I feel very positive about the progress we are making both in a technical sense but actually in the relationships that we are building for the long term which is what this endeavor is all about.

Thank you Andy. We have got one for Iain now. This is another one from the web, [Alex Richardson] at [PHG]. Tony Hayward said recently -- I can confirm that he did -- none of us will sell more gasoline than in 2007. Question, doesn't the Company need to consider closing the refinery or reducing capacity in the US or Europe? Iain?

Thanks, Tony. Thanks very much, Alex. Firstly, you have got to stand back and look at the spread of different refineries in the Atlantic basin. The reality is yes there's over capacity but there is a huge range of different qualities of refining kit. And as you know, for many years now we have been focusing on quality to do with scale, the complexity and upgrading of our refinery, its integration both with supply and trading envelopes and logistics, and making sure that the cost efficiency of the kit is good.

Now on most of those that I mentioned, BP's refining capacity is extremely advantaged. We have larger refineries than others, they are more highly upgraded, they are in integrated positions and they therefore are advantaged. So the bottom line to your question is, no, we don't think we need to consider closing a refinery.

We do absolutely have to drive the profitability of our refining portfolio up, i.e. reduce the break-even margin. And we made a lot of progress of that in '09 versus '08 and the market came down a little bit further than our progress, but we are fully intent on being able to make refining profitable in a 2009 environment.

Thanks, Iain. Let's come back to the phone and go to Jason in sunny Edinburgh. How are you, Jason?

Four inches of snow on the ground at Edinburgh today. Wish you could be here. We've got -- we've got TNK BP slightly behind what I was expecting at least. I just wondered if you can give me a bit of the moving parts there because quarter on quarter with the price increase and the volume increase I was not expecting profit to be down.

And I did have a second question on the Tangguh ramp-up and the expected production levels in 2010 and maybe 2012 from Tangguh.

If you look at TNK BP operationally, it's running very well. Production is obviously still growing. I suspect that on a quarter on quarter sense that we had a small gain from the Weatherford transaction in the prior quarter, which may have led you to misproject what the fourth quarter should have been Jason. There may well have been some tax effects as well.

But operationally the Company is running very well and it's realizing a good price for the oil and gas it's selling. Andy?

All I would add, Jason, is also I think markets within Russia weren't quite as -- didn't move quite as high as markets internationally so there was a mix effect there between the actual realized price within country versus the stuff that is exported. So I think that was also an effect in the quarter.

Okay. Can I just have a quick follow up on that? Actually it's on your group CapEx budget, $20 billion for 2010. Are you doing more for less this year?

We certainly are and Andy will go into some detail about how we are doing more for less in 2010 a month from now. But it's pretty clear that that's the outcome.

Great. Thanks.

Let's stick with the phone and go now to Mark, Mark Gilman. Good afternoon.

Good afternoon. I had three quick ones. First, on Rumaila can you give us an idea how you are going to report Rumaila both financially and operationally and did it contribute to the 2009 reserve bookings? Secondly, could you just clarify what price assumption you are making in terms of the 2010 production guidance?

Thirdly, the TNK dividend very aggressive in the fourth quarter, looks like about an 85% payout ratio for the year. I thought the releveraging of TNK had pretty much been completed. Could you give me some thoughts on the aggressive nature of that dividend?

Thanks, Mark. Rumaila we are still deciding how we'll report it and as we decide we'll tell you. Probably wait until this time next year when we'll be disclosing for the first time how we would expect to report it.

In terms of the guidance for production for 2010, as I said it is entirely in line with our guidance from this time last year which was done at $60 a barrel.

In terms of TNK BP dividend, we have an agreement that says we'll dividend 40% of net income but we continue to look at the opportunities available in the Company and the capability we have built and make the right balance accordingly. So I think we will continue to see some probably lumpiness in the TNK BP dividend. It's the benefit of having what is an essentially a private joint venture. We can sort of move the thing around as makes sense for the moment.

Okay.

Sorry, Mark, you asked me if there were any Rumaila reserves in 2009. The answer is definitely not.

Okay. Let's go to Lucy Haskins at [Bar Cap]. Lucy?

Good afternoon. I think last year you spoke about perhaps being a good time to put more capital on the balance sheet and I wondered where in the world you might be thinking about pursuing non-organic growth opportunities. I think there was some talk coming out of [Darvoth] that Brazil was an area of interest, but I also wondered how you might be pursuing an agenda in Africa as well.

Well, as you know we don't disclose what we are intending to doing ahead of doing it in this matter so I am certainly not going to. But I have said publicly in the past that if I look at our portfolio in E&P there are a couple of places where we would like to deepen it. One of which is West Africa, one of which is Brazil, and the other of which was Asia Pacific.

We've made some moves in at least one of those areas this year, not necessarily through a big acquisition. So I think watch and wait.

And is there any cap in terms of the size of the transaction you might fulfill with -- effectively affordable at the corporate level?

I think the answer is if we see great opportunities where we think we can add real value to secure resources, then we will do so. But of course we don't need to. We are continuing to add resources to the portfolio in a very effective way through the exploration drill bit and through direct negotiated access. So there has to be something pretty special to want us to go and buy it.

Lucy, we've talked about where we are in our gearing range; we are right at the bottom end of that. So we have plenty of financial wherewithal to acquire assets if we can find opportunities that are attractive.

Thank you.

Let's go to Sergio Molisani at Unicredit.

Good afternoon to everybody. Most of my questions have been already answered so just one quick question if I may up, a follow up on 2010 production guidance. Can you give us some more color on this spec contribution from the ramp-up of the 2009 startups for the entire upstream portfolio? And then in more details if it's possible letting some more flavor on the Tangguh development in 2010 and 2011. Thank you.

The right answer to this question is we'll deal with this in the March strategy update when Andy will go into production, not only in 2010 but looking over the next four or five years, in a lot more detail, Sergio. If you can just wait filling in the spreadsheet until the March 2, you'll get a better answer. Okay?

Thank you very much.

Let's go to Pavel Molchanov at Raymond James.

Thanks for taking my question. Could you give us a quick update on Kaskida what we might expect from any results there in 2010?

Andy, Kaskida?

Yes. In 2010, we're going to drill the next appraisal well and that appraisal well is then targeted to be a full-field test, a flow test from the well which will occur in the back end of 2010 through 2011. So as you look at the [Palogene], the key uncertainties around well rate and obviously that flow test is an important piece of information.

So the well will be going down this year and the flow test will occur in 2011 and we are very hopeful around what that result will bring. So important progress on it. Obviously it's a significant resource and we are making good progress on bringing it forward to a development decision.

Thanks, Andy. I think this is now the last question which is Neill Morton at MFG. Neill?

Just a couple of quick ones, please. Just from a qualitative perspective can you just repeat your comments from the strategy presentation last year where you talked about long-term growth of 1% to 2% through end of this decade from the existing resource base? So if the resource base grows, can we assume that 1% to 2% is a minimum target threshold?

And just secondly, how much will BP be spending in Iraq in 2010? Thank you.

I think 1% to 2% remains 1% to 2%. It's what we think is sustainable both in the medium and long term. Clearly as we add resources we continue to high grade to make certain we develop only the highest quality resources. So this is about quality through choice, not pursuing every option that we have. That's the first point I would make.

In terms of Iraq, let me ask Andy to repeat what he said earlier about Iraq in terms of what we're doing.

I don't want to be too precise about the exact dollar number. I think what we have is a very clear plan in place. That plan is initially about getting the most out of the current activity set and to give you an exact number we need to get a better handle on how we can optimize that. It won't really be till the back end of the year that you would see any real ramp-up in spending as we start to increase the activity set.

So I think we'll keep you updated but I think it would be an imprecise forecast. The most important part about it is the progress we are making on actually executing the activity set which is actually absolutely in line with the plans that we had when we made the original proposal as part of the bid. And that is as a result of looking at the field for over three years. So activity has been executed well.

Thanks very much, Andy. I think that brings us to the end. Let me just say a few words by way of wrapping this up.

I think we've achieved a lot over the last few years and BP is beginning to run well. The exploration success and resource access that we achieved in over the last few years has given us a lot of confidence in being able to continue to grow production. The project startups in 2010 and 2011, which we'll review in detail in March, give us confidence about the midterm and the FID decisions in front of us, which we'll also review in detail in March, are giving us confidence about the medium term.

We also believe that there is significant further potential to be realized from our existing assets, both in terms of costs and capital efficiency, and we are planning to review all of that with you on March 2. So we very much look forward to seeing as many of you as we can in early March.

Thank you very much again for listening to us. We hope that we've answered all your questions. Ladies and gentlemen, good afternoon.