英國石油 (BP) 2007 Q4 法說會逐字稿

Welcome to the BP fourth quarter 2007 conference call.

I will hand the call over to Fergus McLeod.

Please go ahead, sir.

Welcome to BP's fourth quarter 2007 conference call.

Joining me today are Tony Hayward, Chief Executive and Byron Grote, our Chief Financial Officer.

Before we start, I'd just 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 received them by e-mail.

They are also available on our web site.

Second, I'd like to draw your attention to this cautionary statement.

Now over to Tony.

Thank you, Fergus.

Ladies and gentlemen, welcome to our fourth quarter and full year results presentation.

Before I ask Byron to take you through the details, of our results I want reflect from where BP stands at the start of 2008, 2007 was a year of change for BP.

Our performance for the year was disappointing in some areas notably U.S.

refining compared to our peers; however, in the second half of the year, they were the first early signs of the improvement.

We began to stabilize our operational performance to resolve many of the issues we faced in the U.S.

and create strategic clarity on the future.

In 2008, we expect to begin to build on this operational momentum and begin to convert it into financial momentum particularly in the second half of the year and into 2009.

Let me begin with safety, 2007 saw further improvement in our overall safety performance.

We've made good progress in addressing the recommendations of the Baker panel and begun to implement a new operating management system across all of BP's operations.

Turning now to operations.

In the fourth quarter in particular, we made important progress.

We began to build operating momentum in our core businesses.

In expiration in production, we started off six projects including the delayed Atlantis platform in the deepwater gulf of Mexico .

Atlantis is currently producing approximately 125,000 barrels a day.

These start-ups helped us grow fourth quarter production by over 250,000 barrels a day versus the third quarter.

At our U.S.

refineries, we restored Whiting to available distillation capacity of 300,000 barrels a day and expect to restore the refinery to it's full crude capacity and flexibility of 360,000 barrels a day in the first half of 2008.

At Texas City we have successfully recommissioned the three units necessary to allow restart of the remaining crude distillation capacity.

The final style crude unit is mechanically complete and is expected to be fully operational during the first quarter.

By the middle of 2008, we expect most of the economic capability of the Texas City refinery to have been restored.

In expiration and production, we expect the Thunder Horse project to start production before the end of the year.

Finally in the U.S., we reached settlements with a number of regulatory authorities and civil claimants which is a significant step towards resolving many of the legal and regulatory issues we face there.

Just as importantly, we've made progress on the forward agenda for BP, designed to restore BP's competitive financial performance.

There are two pillars to this agenda, a significant reduction in the complexity in cost of our overhead and transformation and refocusing of our downstream business.

On the complexity agenda, we've announced a number of changes to create a fundamental shift in how BP works.

These are designed to simplify the organization, improve productivity, enable consistent execution, and focus on business performance.

BP now comprises just two business segments, Exploration and Production and Refining and Marketing.

This will simplify both our corporate governance and decision making.

Our objective is to reduce the corporate overhead by between 15 and 20%.

Were starting from the top with fewer layers of management and a smaller corporate infrastructure.

All our corporate functions will have a simplified and smaller structure and will be managed centrally to drive standardization, increase capability and prioritize spending.

In aggregate, we expect these actions actions to lead to a reduction of around 5,000 positions across the group by mid-2009.

This is in addition to the 9,500 relating to the sale of our U.S.

operated convenience retail business.

The overall resulting restructuring costs are around $350 million in the fourth quarter 2007, and we expect around a further $1 billion in 2008.

We expect to see benefits from these measures in 2009 and beyond.

While all these changes are underway, we continue to make good progress in exploration production where we maintain strong strategic momentum.

Our track record of expiration success continued with major discoveries in Azerbaijan, Egypt in Angola.

We successfully started out nine new projects.

We secured major new access in In Amenas, Libya and Canadian heavy oil.

The entry into Canadian oil sands which is subject to final agreements in obtaining the necessary approves and permits was made on attractive terms to BP.

We are establishing two independent 50, 50 joint ventures with Husky Energy to form an integrated North America Oil Sands business.

BP is acquiring a half sharing the Sunrise field in Alberta while Husky will acquire a half share in BP's Toledo Oil Refinery.

Our 2007 reserve replacement ratio excluding the effects of acquisitions and divestments was more than 100%.

Correcting for the effects of year end prices, the ratio would have been more than 120%.

This is the 14th consecutive year that our reported reserve replacement ratio has been over 100%.

In refining and marketing, our overall financial performance versus our peers is unacceptable despite the fact we have a strong set of assets.

The principal reason for this performance Gap is poor reliability in some of our U.S.

refineries but there's more to do than restoring U.S.

reliability.

We aim to transform and refocus our refining and marketing business.

It will not happen overnight, but we believe that the performance Gap can be progressively narrowed in the next few years and closed over the medium term.

We are focused on four interventions.

One, delivering safe, reliability operations, especially in our U.S.

refineries where our focus is to get the U.S.

refineries to the same level of availability, 95% as our refineries in the rest of the world.

Two, a focus on more closely integrated fuel value chains.

Three, selling our company-owned and company-operated convenience sites in the U.S.

and significantly focusing the footprint of our lubricants and aviation businesses.

And four, reducing the overhead the business carries by having few you are organizational units reducing the number of organizational layers and reducing business service costs and overheads.

This amounts to a major intervention but one that is absolutely necessary.

Iain Conn will talk to you in more detail about how we intend to do this and the metrics and indicators you can use to track our progress at our [strashy] presentation later this month.

Let me now hand over to Byron who will take you through the 2007 numbers and our plans to evolve our financial framework.

Thank you, Tony.

I'll now elaborate on our fourth quarter and full-year results starting with the summary of the trading environment.

The table shows the percentage year-on-year increased in our key indicators for both the fourth quarter and full year.

Oil prices continue to strengthen and reached record highs during the quarter primarily due to rising demand and concerns about geo political instability.

Our average liquids realization approached $83 per barrel in the fourth quarter and exceeded $67 per barrel for the year.

Our 4Q average gas realization recovered from the extremely low levels in the third quarter to $4.83 per thousand cubic feet up 10% compared with last year.

However, on a full-year basis, our gas realization was 4% lower than 2006.

Taking both oil and gas together, our average total Hydrocarbon realization was only 8% higher than last year.

A much smaller increase than the oil price reflecting our considerable exposure to U.S.

gas.

Our average refining indicator margin of $5.68 per barrel fell 30% compared to the third quarter and 10% versus last year.

For 2007, refining margins were 18% higher than 2006 in part due to record levels experienced in the second quarter.

However, the margins realized by our own refineries did not increase to the same extent because of our product mix, narrower light heavy differentials and lower refining availability in the United States.

Looking now at the first quarter 2008, although oil prices have fallen over the last few weeks on concerns of weaker economic growth, they remain higher than 4Q '07.

Meanwhile, Henry Hub prices have risen slightly on expectations of colder weather.

By contrast, refining indicator margins have continued to fall and have averaged less than $3 per barrel to date.

This is approximately half the 4Q '07 average and sharply lower than the average of over $9 per barrel seen in the first quarter last year.

This is mainly due to declines in the U.S.

margins.

You can, of course, continue to track the indicators that I've mentioned in our online weekly trading conditions update.

Turning to the financials.

Our fourth quarter replacement cost profit was $3 billion, 24% lower than a year ago.

A major factor in this swing was an unusually high tax rate in 4Q '07, recollection the tax on inventory gains.

This compares to an usually low rate for the same period last year during which there was significant inventory losses.

The tax rate for 4Q excluding the effective of inventory gains was 38%.

The full-year tax rate was 37% in line with guidance provided.

Our profit including inventory gains and losses was $4.4 billion, up 53% compared to last year.

These figures include charges for nonoperating items which reduced our results by over $1 billion.

Half of the charges relate to our forward agenda actions aimed at reducing complexity and costs which Tony has already mentioned.

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

Fourth quarter operating cash flow of $4.3 billion was 14% lower than a year earlier reflecting working capital effects driven by higher oil prices.

All of the per share metrics shown reflect the benefit of the reduction and our shares outstanding by 3% over the past year.

The $13.525 per share dividend announced today, which will be paid in March is 31% higher than a year ago.

The Sterling dividend is up by nearly 30% year-on-year.

I'll describe the evolution of our financial framework which underpins this dividend increase shortly.

In E&P, we reported pretax profit of $7.6 billion for the fourth quarter which included a charge of around $600 million for nonoperating items.

Primarily related to embedded derivatives and restructuring costs.

Excluding these nonoperating items, our underlying result of $8.3 billion was a record for the segment and 58% higher than last year.

This reflects benefits from stronger realizations and higher production volumes, which more than offset continued sector-specific inflation, greater start-up costs and higher DD&A.

Reported production was over 3.9 million barrels of oil equivalent per day, up 2% versus last year.

After adjusting for the effect of acquisitions and disposals and lower entitlements in our production sharing agreements due to higher prices, underlying production for the quarter was 3% higher.

Full-year production of over 3.8 million barrels of oil equivalent per day was within the guidance range we provided in February 2007.

In spite of the impact of divestments and higher prices than we assume at the time of the guidance, the TNK-BP fourth quarter contribution of around $750 million was significantly higher than last year reflecting a stronger trading environment and the benefit from lag tax reference prices.

As you may recall, price lags built into the calculation of Russian export duties have a favorable impact in a rising market.

This tax lag has resulted in a net benefit of around $250 million in 4Q '07 compared with an adverse impact of $200 million in the fourth quarter of 2006.

The overall effect in 2007 was a net benefit of around $600 million.

In refining and marketing, we reported a pretax loss of $1.3 billion compared with the profit of $300 million a year ago.

Our fourth quarter result included a charge of $1.1 billion for nonoperating items reflecting impairment charges related to U.S.

convenience retail, restructuring costs and certain other provisions.

Excluding these nonoperating items are underlying result was significantly lower than last year.

This reflects weaker U.S.

refining margins, lower contribution from supply optimization and higher repair, recommissioning and operating costs at our Texas City and Whiting refineries.

In addition, the quarter's result reflected the impact of a major scheduled turn around at our Toledo refinery.

These ongoing outages and repair costs in our refineries plus lower margins contributed to an underlying loss of more than $800 million in the United States.

Fair Value Accounting effects were smaller relative to the prior year, although still negative for the quarter.

Looking forward, the first quarter is typically a heavy turn around period and 2008 is no exception.

For example, we have a major scheduled turn around at our Carson refinery in progress.

Turning to gas power renewables, we reported a pretax profit of $220 million for the fourth quarter which included a small charge for nonoperating items mainly due to impairments.

Excluding these nonoperating items are underlying result of $280 million was slightly higher than last year.

This reflected benefits from stronger NGL operating performance, which more than offset a lower contribution from the marketing and trading businesses and a less favorable Fair Value Accounting effect compared to 4Q '06.

This is the last time this segment will be reported separately as I'll explain in a moment.

In other businesses and corporate for OB&C., the fourth quarter underlying charge was $310 million.

This brought the full-year charge to around $900 million in line with the guidance I provided last February.

Turning now to cash flow.

This slide compares our sources and uses of cash in 2006 and 2007.

Operating cash flow decreased to around $25 billion.

Primarily as a result of weaker refining and marketing results and working capital movements due to higher oil prices.

Disposals provided a further $4 billion.

In total, sources of cash were $29 billion.

We use this cash in funding around $18 billion of organic capital spending.

More than $1 billion of acquisitions and nearly $16 billion of shareholder distributions.

Our next debt ratio ended the year at 23%.

Towards the bottom end of our targeted bend of 20 to 30%.

The 4Q increase reflects normal year end working capital and tax phasing.

Let me talk a little more about the re-segmentation which took effect at the beginning of the year.

As Tony has described, BP now comprises just two business segments.

Our gas power renewable segment has been eliminated and its gas-related businesses, natural gas liquids, liquefied natural gas and marketing and trading have been transferred to the exploration and production segment.

Its other arm, the alternative energy business, has been established as a separate unit and held within other businesses in corporate.

As a consequence, other businesses in corporate has been redefined.

It now consists of alternative energy, corporate activities and other business areas such as aluminum and shipping.

We will provide 2008 guidance on OB&C in the context of this new structure during our strategy review on the 27th of February.

Restated historical data for the last five years are expected to be available before that.

Looking to 2008, we expect an effective tax rate in the range of 36 to 38% in line with 2007.

Our actual effective tax rate will be determined by a number of factors including prevailing market conditions.

For example, you would expect income from higher prices to attract higher marginal tax rates and move us towards the higher end of this range.

The slide also provides an update on the rules of thumb that some of you use to model our results.

As in the past, these should be considered simply as broad directional indicators which are more useful on an annual basis than for quarter-on-quarter comparisons.

And for price moves within a much narrower range that we've seen in the recent past.

These indicators are less reliable as our portfolio diversifies a way from being predominantly driven by Brent and Henry Hub prices and simple refining indicators.

You will note that we remain highly leveraged to movement in U.S.

gas prices, which are currently disconnected from oil prices.

Turning to production, we expect growth in 2008 compared to 2007 with actual net volumes dependent on how the crude price effects entitlements from production sharing agreements.

Our guidance for 2009 and '12 remains unchanged.

On the assumption of $60 oil price we would expect 2009 production to be above 4 million barrels of oil equivalent and around 4.3 million barrels of oil equivalent per day in 2012.

As in 2008, actual reported production will depend on price.

Let me remind you that last year, the production guidance we gave was also on the basis of a $60 outlook and actual production was within that guidance despite prices averaging in excess of $72 per barrel.

Given current market conditions, it's likely that 2008 prices will continue to be above $60 per barrel as well.

Andy Inglis will talk more about the PSA effects in our strategy review later this month.

We are increasing our capital spending to reflect both industry inflation and greater growth investment.

We expect 2008 organic CapEx of 21 to $22 billion.

This guidance does not include the accounting treatment of our entry into the Canadian oil sands via two joint ventures with Husky Energy.

At the group level, we are in essence swapping 50% of our interest in the Toledo refinery for 50% in Husky's Sunrise field.

However, [FRS] requires that we account for these joint ventures as investments and a disposal.

In E&P., our interest in the Sunrise joint venture will be shown as an equity investment.

In R&M, the Toledo transaction will consist of two parts, first, the disposal of BPs 100% interest in the refinery and subsequent 50% investment in the new joint venture.

We're at the end of a multiyear program of disposals aimed at focusing and high-grading our asset base.

Consequently, we expect lower divestment proceeds than in the recent past.

We expect to see an increase in DD&A of around $ 1.5 billion with the higher charges driven by a number of factors including production growth, the start-up of new projects and PSA effects.

Costs are likely continue to grow including in TNK-BP The underlying growth rate in cost should slow however, reflecting the early impact of our cost reduction agenda.

The benefits of that agenda should increase in 2009 and beyond.

Our shareholder distributions for 2007 were $15.6 billion, lower than 2006 due mainly to reduced disposal proceeds.

Dividend payments exceeded $8 billion and we bought back $7.5 billion worth of shares.

Our consistent and long-established financial framework has been to distribute to shareholders 100% of all free cash flow in excess of that required for investment.

We have had a progressive dividend policy which means that we increased dividends in line with the underlying growth of the firm.

The broad principles of that framework remain, but changes in the business context have given us greater confidence in our future cash flows and have led to us rebalance the uses of this cash.

So what are these changes?

Firstly, we hold a more positive view of the pricing environment, especially for oil.

Oil and gas prices have continued strengthen over th last five years.Demand growth driven by non-OECD demand is likely to continue to impact price as well geo-political factors such as security of supply concerns, constrained access to new resources and a mismatch between sources of supply and centers of demand.

It is impossible to predict precisely the oil price.

Indeed, we've been reminded in the last two months of just how volatile it can be.

But considering all of these factors it is our view that there is support for oil prices above $60 per barrel for the next few years and most likely in the range of 60 to $90 per barrel, although we will continue to test projects at lower prices.

The second factor is the growing momentum in our operations which Tony has already highlighted.

We are confident that our financial performance will be boosted by growing revenues for an increased production and an improved refining availability.

We also see significant potential for cost efficiencies and improved performance across all of our businesses.

The third reason is that our reduced equity base has made per share dividend increases more affordable.

Over the last eight years, we have generated significant surplus cash above the underlying requirements of the firm.

Much of this cash came from divestments, and we returned this to shareholders in the form of share buybacks.

Over the past eight years, buybacks have reduced shares outstanding by 16%, a higher per share dividend is therefore more affordable.

So how have we adapted the framework to this new context?

First, given our confidence and sustained higher price environment and improved operations, we believe it's right to increase organic CapEx to support the future growth of the company.

Second, we've decided that our approach to the level of gearing should remain unchanged.

We continue to believe that a gearing band of 20 to 30% provides an efficient capital structure and appropriate level of financial flexibility through the cycle.

Third, we will rebalance our distribution between dividends and share buybacks.

Taken together, all these factors lead to us judge that it is right to step up the dividend this quarter.

Given higher organic CapEx, lower divestments and a higher dividend, the level of free cash flow available to be allocated to share buybacks is likely to be lower.

None the less, we will continue to use share buybacks as a mechanism to return excess cash to shareholders when appropriate.

We believe that this updated financial framework gets the balance right.

With our confidence in greater cash flows from our strong asset base, allowing us to both increase investment in the future growth of the company and increase the dividend component of our distribution to share holders.

That concludes my presentation of our results.

Thanks for your attention we will now be delighted to take your questions.

(OPERATOR INSTRUCTIONS) .

If you are using the web, please submit your questions using the web question

Thank you, operator.

I think the first question comes from [Evan] at Morgan Stanley.

Are you there?

Good afternoon, gentlemen.

Just two questions, actually.

Firstly, on CapEx, I was wondering whether you could give us a breakdown of the increase in CapEx between gross and cost inflation and what you expect to spend on exploration this year.

The second question was actually just on fuel restructuring or reducing complexity.

I was wondering if you could give us a bit more color on what you could outside the U.S.

retail?

And secondly, if you've got any preliminary thoughts on what tangible benefits or bottom line benefits you expect.

Thank you.

Evan, okay.

Let me take those two.

Firstly on CapEx, the breakdown that which is attributed to increase investment to grown the firm which is a consequence of the inflation we're seeing is the sector is about 50, 50.

So we continue to see about 10% inflation.

We did better last year, offset it by 8%.

But overall the increase capital breaks down around 50, 50, 50% to inflation, 50% to further expand the asset base.

In terms of exploration in both capital and revenue investment it will been $1.5 million in 2008.

In terms of the restructuring, as I said back in October, the principal focus is to make BP a less complex, simpler more efficient company so we're very focused on the overhead piece of the firm.

We've identified 5,000 positions which we believe we can remove over the course of the next 18 months.

That is roughly, roughly split 60% in what we define as corporate, major corporate functions, 30% in refining and marketing and 10% in E&P In terms of plans to focus the footprints of the marketing businesses, I'm going to save that for the 27th of February when Iain Conn will take you through in a lot more detail our plans to transform and refocus the downstream business.

Great.

Thanks very much.

The next question comes from John Rigby at UBS.

Couple questions.

First is, just quantitatively, and I don't want you -- you don't have to be too precise but what is the kind of performance GAAP number that you think is obtainable over the next couple of years in your thinking when you've increased your dividend in the way that you have.

I think if you want to talk about differentials or earnings lost or whatever.

The second is just clarification again on the CapEx number.

Take your point that is doesn't include the curious accounting requirements that you have to go through in terms of selling then reacquiring your own assets.

The CapEx guidance you have include then the organic CapEx that goes in either Toldeo or to the oil fan or your contributions to both once that deal completes.

Yes.

I start with the second one.

Yes, it does.

Includes the organic investment going forward.

Doesn't include the accounting effects.

I just want to come back to dividend.

Before I talk about the GAAP let me talk about the rush behind the dividend It is based on confidence.

It's confidence in upstream volumes beginning to come through.

We started up six significant projects in the fourth quarter.

We start up ACG., Thunder Horse and Tango this year.

So we have strong upstream volumes coming through.

We have the beginnings of the recovery of the U.S.

refining business and have our intentions to really get off the cost base which probably won't result in an absolute reduction frankly, given the inflation pressures in the environment we will mitigate believe significantly the cost rises we've seen over the last several years.

That's sort of the confidence in the operations.

As Byron said in his remarks, confidence in a stronger price environment.

That's what the dividend's about.

In terms of the Gap, I think there are a variety of ways you can think about it.

One way of thinking about it is to say that in our downstream business it is roughly, roughly two-thirds to do with refining revenues and one-third do with costing the business.

The way of thinking giving some granularity of that, again I don't want to still all the (inaudible - highly accented) One way is to say that the lost opportunity in last year's trading environment from our Texas City, Whiting and the turn around at Toledo was about $2.5 billion .

That gives you some basis for triangulating the Gap.

And as I said Iain will take you through more detail the Gap and what we intend to do to close it on the 27th of

Thank you very much.

Now over to Mark Iannotti, Merrill Lynch.

Mark, are you there?

Few questions on E&Ps.

Firstly, E&Ps, firstly, can you tell White House your assumed decline rate on your base production for the next few years?

Maybe also try and quantify for us the impact of PSCs on volumes, I know you are basing your guidance on volumes on a $60 oil price.

Could you maybe give us some idea how to think of that on the higher oil price scenario.

Finally, albeit your growth is modest over the next couple of years and E&P that is a significant change in the mix.

Can you maybe talk a little bit about your views on margins, margin capture in new barrels versus those barrels that will be coming out of the decline?

Thanks.

Okay, Mark.

I think an average decline number is not a very useful number because in the portfolio as I said a number of times I guess there's lots of things going on so the North Sea is declining at somewhere between 5 and 10%, North American gas is flat.

The Gulf of Mexico is growing at 10% ESO.

Doesn't really tell you very much frankly, so I don't really think it's a very useful number and it's not something that we look at.

What we look at is what is happening, what's the activity set and what is happening in our core upstream businesses around the world?

Business by business.

In interprets of PSCs, I don't want to be unhelpful but I do want to remind people that this is a tricky area because the relationships are not linear.

So six months at $100 a barrel and six months at 60 is not the same as a year at 80.

So you have to be very careful when you are making projections of the future.

Obviously, descriptions of the past are easier because it's the facts.

So in the past year, the PSC impact of the realized price which was above $70, versus our projection at 60 was about 25,000 barrels a day.

If we look to 2008, with all of the caveats that I described, at $70 a barrel, we believe the impact will be around 50,000 barrels a day relative to our $60 guidance and at 100 a barrel, it will be around 100,000 barrels a day relative relative to our $60 guidance.

Thank you.

I hope that's helpful (inaudible - background noise) around which can you triangulate.

What I would say is that with 2007 behind us going forward at 60, we're still on track to hit 4 million barrels a day, above 4 million barrels a day in 2009 and above 4.3 in 2012.

I think with all of that, you should have the basis of which you can pin the tail on the donkey the way Mr.

Mcleod says.

Now over to the U.S.

and Nikki Decker, Bear Stearns.

Good afternoon.

Thank you.

My question is on finding and development costs if I'm doing the math right.

I'm coming with something around the $10 mark which is a little higher than BP's historical average.

Maybe you can talk about how inflationary pressures are affecting costs and to what extent maybe the nature of your operations has influenced costs.

We go into more detail on this on the 27th.

I don't want to steal all of Andy Inglis' thunder on the 27th.

What I would say is that inflation continues in business.

We reckon across the sectors it's running on average about 10%.

It's variable by sector and in 2007, the efforts of our supply chain management activity mitigated it to an actual number for BP of around 8%.

There is clearly inflation.

I think some of the opportunities that we're pursuing are by definition higher costs.

Some of the deeper water opportunities are deeper than things we've done in the past so they're by definition high costs.

The primary driver on S&D over the last three, four years for BP has not been the quality of the resource base that we're exploiting but the inflationary costs in the industry.

We don't see big shifts in our portfolio, but we are seeing significant inflation in the industry.

I think that's the big message.

And Andy'll talk have more about this in a few weeks' time.

Thank you.

Appreciate it.

The next question is from Ed Westlake, at Credit Suisse.

Good afternoon.

You talked or alluded to gas and obviously your global gas realization of 450 or so is low versus peers.

Can you talk about the gas assumptions behind the dividend hike?

The second question is around cash taxes obviously.

Could you talk a little about the amount on a cash basis as opposed to P&L you expect in 2008 and '09, thanks..

I'll deal with the gas assumption and I'll let Byron deal with cash tax.

I think simple answer is no different from today, Ed.

Clearly, there are two things in BP's portfolio.

Very significant exposure to the U.S.

gas price which as we all know as become materially disconnected from the oil price.

How long that can pertain remains to be seen.

My personal view in the world's deepest and most liquid energy market a long-term disconnect seems unlikely but not something you ever want to plan on.

So we're planning on the same basis as we've experienced over the last few years-- sort of what we've seen.

Again in the international portfolio, a lot of it is driven by our domestic production in places like Trinidad and Egypt.

And we've made no assumptions for anything different going on there in the foreign cash taxes.

Ed, it's always difficult to calibrate these different precisely.

Just reminding people of the difference between the effective tax rate and the cash tax rate is driven by timing differences.

It's driven by the installment payment effects and those aspects that are noncash in nature which for example, the writeback of provisions on previous tax-related items.

That said, what a good rule of thumb probably for 2008 would be to expect a cash tax rate would run a few percentage points below the effective tax rate.

Considering all those things in aggregate.

Thank you.

Next question comes from Neil McMahon of Sanford Bernstein.

Two questions.

First is really looking at your restructuring charges.

To be honest, at they seem quite high.

Maybe you could go into what they're exactly for.

I think you've gone in and obviously there are redundancies associated with that.

I presume there will be pension true ups of that as well.

Also, are you closing?

How many offices are you closing which would equal that large charge you're taking over these next few years, and then I've got a follow-up question on gas in Russia.

Byron, if you will, sir.

As far as the provisions that we've taken for restructuring and the guidance that Tony has given, this is just an estimated at the current time the major factor in this is going to be redundancies, and the mix of the personnel affected because this is about overhead and it tends to be about relatively higher paid office personnel that will be higher than it would be for an aggregate slice across the group as a hole.

As an estimate right now there's's no planned closures of offices associated with what we described, although, the overall impact of that may have a range of other charges associated with that.

More as we get to it.

We'll be taking charges probably on a quarterly basis as we go through 2008.

Once we have explicit line of sight with respect to the steps being taken.

Okay, thanks.

Russia some.

Thanks for that clarity.

On Russia, it's quite interesting everybody keeps talking about oil yet you've got the gas.

(inaudible - background noise) It appears that Russia's getting ever contained in the amount of gas it can pump toward its domestic consumers plus export to Europe.

It looks like eventually going to have the ability to supply gas into Russia and maybe Europe.

Maybe you could give us an overview of that and potentially might it be part of a joint venture with gas that will help you get back in Rospan.

Neil, in the matter of Russia all things are possible, you can certainly form part of a joint venture.

What I would say is that just to deal with that issue up front, we continue in a very constructive dialogue with Gazprom around how we can structure something that is bigger and better for both of us going forward.

And it's complicate.

It's always complicated when you're trying to combine different assets in a transaction of this sort and it's particularly complicated when there are three parties involved.

BP, TNK-BP and Gazprom .

We continue to be optimistic and obviously believe it'll take at least through the middle of the year to have everything concluded.

In the matter of Rospan, I would say you're quite right.

It is a very large gas resource which is quite rich, so it's very attractive commercially.

The issue today is that the infrastructure in the area is insufficient to allow it to get to market.

Gas (inaudible - highly accented) in the process of doing something about that.

So I would expect to see it progressively developed going forward.

I don't expect that to happen in the next year or two.

I think it's the sort of end of the decade and into the early part of the next

Great, thank you.

This is a related web question from Burt [ VanHugenhosier] in the Netherlands which is what is the production outlook for TNK-BP?

Thank you, Burt.

We said sometime ago that we expected to see flat production from TNK-BP 2007.

0.8 and through the first half into the and the second half of 2009 as we made the transition from investment in Brown fields to investment in new Greenfield development.

That's exactly what we're seeing.

Again, Bob Dudly will be along on the 27th of February to take you through that in more detail.

The Greenfield development is preceding well.

We'll invest close to $2 billion in 2008 in Greenfield development and we'll see the benefits of that coming through in the second half of 2009 and into 2010 when we would expect to see the TNK-BP production profile begin to pick up and start growing again.

Next question comes from the United States from Mark Gilman.

How are you, mark?

Good, Tony and Byron.

A couple things if I could, please.

With respect to the reserve replacement and reserve ads.

Number is impressive in light of the apparent lack of significant new project sanctions in '08 as well as very early performance oriented data with new start-ups.

Could you give us a little bit of an idea of where it's coming from?

Well, I'm sure you can guess what I'm going to say Mark.

We'll reveal all in our annual reports from accounts in early March.

The fact is it is from across the portfolio.

It's from Alaska, North America gas, our Argentina business, it's from Russia, Australia, across the portfolio.

I think Andy will talk more about this on the 27th.

It speaks very much to the strength of the technology pull through we're getting with respect to converting resources to reserves.

It's a very powerful story.

Okay.

Let me try another one if I could.

In the past, I believe you talked about a target payout ratio in the neighborhood of 40%.

Can we assume that it is a similar type of payout target in a $60 world that underlies the dividend action?

Certainly since I've been on the board of BP, which has gone back to 2003 now we haven't talked about a payout ratio as a percentage of all.

I don't believe we've ever talked about that.

We may have done in the past.

That would not be a good assumption.

I'm sure my CFO would just like to fill in here because he's been around here as long as I have.

Mark, we're not working under any explicit payout guideline, and it's probably inappropriate in an industry that has the volatility that the oil and gas sector does.

We do as a board look at a range of indicators, the prevailing circumstances of the firm, the trading environment, future investment patterns and putting those considerations and others together.

We set a dividend as a board in line with the ability to sustain it and grow it in line with the growth of the firm.

So it is not a precise mathematical equation.

Okay.

Just one more if I could , please.

You've used the words transform the downstream business, which I guess in my mind, I'm not trying to split hairs, would imply actions that would seem to be a little bit more agressive particularly in terms of the asset base and the portfolio.

Am I going in the wrong direction in term of my interpetation of your use of the word

Well, what I'm going to say, come listening on the 27th as Iain Conn describes exactly what we are planning to and then you'll be able to judge whether transform is a good objective to use or not.

I believe based on what he's planning to do, it is.

Okay, guys.

Thanks very much.

Next question is from Jason Kenny in Edinburgh.

Mark's earlier question on your cash return's policy really.

You mentioned the level of share buybacks are lower in 2008.

Can you just clarify is that low other than the 2007 number, 7.5 billion or lower than the 2006 number which was 15.2 billion.

Trying to get a feel for share buyback commitments.

What I meant by that is that it would be lower than it would have been in the absence of decision to redirect more of our funds towards capital spending and then rebalance the distribution between dividends and share buybacks with the greater emphasis on dividends.

Share buybacks for BP is a swing item, and the level of it is going to be critically dependent upon the trading environment in which we find ourselves in, 2008.

If the trading environment is very robust, there will be a lot of share buybacks.

If it weakens substantially from where we see it today, there'll be less.

I can't answer the question without a full consideration of the environment that we find ourselves in during the course of the year.

That's great.

I just wanted clarity.

Small follow-up what is the expected effective date for the Huskey JV tail?

I think we're looking at the first of April, Jason.

Okay.

Thanks very much.

The next question comes from Lucy [Hatching] from Lehman Brothers.

Just a couple questions, please.

CAn I just ask what the contribution was to the upstream business from [ACT] in the fourth quarter?

The answer is no, Lisa, we don't disclose that level of detail.

And I think you had felt some indication of not linear progression in terms of [PSE]?

(inaudible - background noise) See a more stronger price environment, when would you expect to move to the profitability for that project this year?

We're not going to give you that, either.

And perhaps finally on the sensitivity you've given it would seem to be slightly less sensitivity now in terms of the upstream metric and a bit more in -- an unchanged downstream.

Could you give me any guidance on how that was made.

We've trained -- we're trying to learn from the the actual experience in 2007 and 2006 where we seem to have not been able to adequately capture the full impact of the various things, which tend to mitigate the leverage and the oil price.

We've got higher physical take in 2008 and 2007.

Best example of that is the recent change in the production tax regime in Alaska.

We're trying to do some calibrations on how this actually works through in production sharing contract arrangements.

As best we can tell it, it was appropriate to reduce the leverage which should be symmetrical, of course and should mean things come down less as well as go up if prices were to move lower as opposed to move higher.

Thank you.

Our next question comes from Robert Kessler at Simmons & Co.

Robert?

Tony, I appreciated your attempt to simplify the complicated PSE calculation and provide that $100,000 barrel a day sensitivity for '08, can I get you to go one step further and look at 2009 and give us some indication as to what your 4.0 million barrels a day guidance would move to if oil prices averaged a$100 a barrel between now and then?

I think you have to wait until the 27th when Andy Inglis is going t to spend a lot of time trying to help all of us understand how this may move over the next couple of years.

If you can bare with us, Robert, we'll try and reveal more on the 27th with some charts that he's got that provide a bit of clarity.

Fair enough.

Thank you, Tony.

Next question's Gordon Gray at JPMorgan.

Hi, gentlemen.

I was wondering if you can help me with a couple more moving parts around the USR&M business.

Finding margins and then the refinery yields, what would you consider is abnormal costs in the quarter?

Be it at Whiting at Texas City or even with the Toledo refinery maintenance.

Secondly, can you just give a us a feel for what you think the ongoing EBIT contribution of Toledo is given it's now going into the JV with Huskey?

We can't give you the second one.

I think in terms of the normal costs incurred at Whiting and Texas City in the quarter, $300 million is a good number to work on.

Is that okay?

Thanks, Gordon.

We'll move on to the next question.

Fergus, I think maybe it could be useful to remind everybody that as we're looking back at 2007 and looking at both the foregone margin from the outages that we had at Texas City and Whiting and we look at the incremental repair costs that we experienced over the course of the year, that over the course of 2008, we will be moving towards most of the economic capability of Texas City in the middle of the year.

All of it as we exit the year, though we're looking at a refining margin environment that is much worse than what we saw in 2007.

In my webcast remarks earlier, I said it's running less than $3 according to our indicator margins through the first month of this quarter versus $9 during the course of the first quarter of last year.

So we've got great operational momentum in our refineries, but the real answer to the contribution in 2008 is going to be critically dependent upon the environment we experience as well.

Thanks, Gordon.

Our next question's from Irene Himona at Paradigm.

Good afternoon.

I think you indicated that the refining and marketing financial recovery is likely in the second half of 2008.

You also spoke of your belief that the early prices sustainable in the range of 60 to 90.

Given the material step up in CapEx and dividends, should we be thinking of your cash break even oil price this year as being closer to the 90 level than the 60.

And if that is the case, going back to the issue of volume growth.

What should we be thinking about in terms of volumes in 2008 if we were to average close to $90.

Thank you.

I think I've given you all of the guidance I can with respect to the second question.

With respect to the first, it's cash break-even will be mid-60s this year and it will fall with time and it will fall through the year as momentum returns.

Thank you.

Our next question is from Colin Smith at Dresdner.

Colin?

Afternoon, gentlemen.

Just coming back to U.S.

gas and the points you made about sensitivity there.

I wonder if you could give us any color of what you think the effect of the start up of the Rocket Express pipeline might be on your business there?

And if you could give us a little color on what the change in Alaska taxation means on an ongoing basis?

Thank you.

I think Rocket Expresses clearly helped significantly.

It's probably closed between anywhere $50 and $1 the number I have in my mind.

I've got my name print nodding his head.

We can give you more details offline but it's clearly had an beneficial effect.

It came on stream toward the end of the year.

It will help going forward.

It's something I would say we're continuing to look at.

How do we ensure that the infrastructure is put on the ground ahead in the western area of the U.S.

ahead of when the production arrives.

That is an important thing for BP and a number of other companies indeed.

The second question I've answered your second question to start with, all right.

Missed that.

Colin, was that it?

That's it.

The final question comes from Paul [Bedding] HSBC.

Thank you for being so patient, Paul.

Hi, Fergus.

Thanks for that.

Just a quick on whether the problems people have had with supply and gas in Turkey have given you any advantage and whether there is actually spare capacity both in terms of transport capacity or even productive capacity that you could take advantage of in the short-term before the next phase starts to come through.

We're putting all of everything we can produce.

I can't remember exactly what it is but we're doing more than the nameplate capacity, and it's going into a very hungry market so the real opportunity is the next phase of development, which we are looking at with a view to start up 2012, 2013 I think is the current view on that.

But there's not much opportunity beyond what we're doing today because we're putting all of the gas we have away.

Thanks very much.

I think we have reached the end of the Q&As, ladies and gentlemen.

Let me just say a few things to bring this to an end.

Thank you very much for your questions and your interest.

What I would say is I think BP starts 2008 in a much better place than it was a year ago.

We're steadily recovering operational momentum and although our financial performance isn't where we want it to be, we are taking actions to cut back on corporate bureaucracy and complexity Operational momentum is building in the business and is beginning to feed through to the bottom line and continue to do so as we go through the year.

We have again replaced more than 100% of our reserves and we'll take you through the details of that on the 27th of February.

As I said, I think it's a very strong story that talks about the technology translated resources into reserves.

Well, I conclude by saying we believe BP has an excellent set of assets.

We're showing our confidence in the future by increasing the dividends.

And our task this year and next and the years beyond this is to get on and deliver.

Thank you very much for your questions and your time.

Thank you for calling the digital replay service.