英國石油 (BP) 2008 Q2 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 MacLeod, Head of Investor Relations.

Hello and welcome to BP's second quarter 2008 conference call.

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

Joining me today are Tony Harward, our Group Chief Executive, Byron Grote, our Chief Financial Officer, Andy Inglis, Head of Exploration and Production, Iain Conn, Head of Refining and Marketing, and Vivian Cox, Head of alternative Energy.

Before we start, I'd like to draw your attention to this next slide.

During our presentation today we will be making forward-looking statements.

Actual results may differ from these plans or forecasts for a number of reasons such as those noted on this slide and also in our SEC filings.

Thank you, and now over to Tony.

Thank you, Fergus.

Ladies and gentlemen, good day, and welcome to our first-half results for 2008.

In a moment, Byron Grote will take you through the second quarter in more detail.

I'd like to start by highlighting some of the major themes.

I said in February that 2008 should see operational momentum building across our businesses, feeding through into financial momentum in the second half of this year and into 2009.

That is what we're seeing.

Overall, we're heading in the right direction, and today's results are another step along that path.

Recovery is particularly evident in the upstream, where we've been able to capture the benefits of a strong environment with rising underlying production, good cost control, and a number of key startups, all of which has resulted in strong cash flow generation.

In Refining and Marketing, there's been important progress in restoring operational reliability in our US refineries, and we're also beginning to see progress on simplifying the business.

However, the margin environment, especially in North America, is challenging.

And this has limited the benefit to the bottom line.

We're all operating it seems to me in interesting times.

The world's economy is weakening, and the global geo-political situation is delicate.

The oil price continues to be high and volatile.

Against this background, BP is making steady progress.

Let me give you a summary of the numbers.

Replacement cost profit for the first half of 2008 was $13.4 billion, up 23% from the same period last year.

Earnings per share are up 26%.

Unlike 2007, when several key assets were offline or delayed in starting up, our operations in 2008 can be better described as what I call silent running.

And that's the way we intend them to stay.

In our E&P business, this is delivering underlying production momentum which is sufficient to more than offset the effects from production sharing contracts that we talked about in February.

In addition, strong cost discipline is allowing us to capture more of the upstream margin.

We're also delivering planned operational improvements in US refining, but into a weak margin environment.

Outside of the US, our refining and marketing businesses are operating well.

All of this is feeding through into very strong cash flow generation with post tax operating cash flow rising 25% to $17.6 billion in the first half, despite higher working capital requirements.

This performance is underpinning the step-up in the dividend we announced in February.

The oil and gas industry continues to be one of the best sources of income for investors, and I hope that is of some comfort in the current difficult economic environment.

Today, we're announcing a further increase in the (inaudible) dividend to $0.14 per share, 29% higher than a year ago.

The Sterling dividend is up 33% year-on-year.

In summary, the first half of 2008 has seen BP make satisfactory progress along the course I laid out in February.

We have the wind in our sails in the upstream, although in the downstream, it feels more like sailing into a gale .

Let me now hand over to Byron, who will go through the results in more

Thank you, Tony, and good day to those joining us on the call.

As usual, I'll begin my review of the quarter with the trading environment.

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

In 2Q, our liquids realization exceeded $109 per barrel, 76% higher than a year ago, and 21% higher than in the first quarter.

Our gas realization increased to $6.63 per 1,000 cubic feet, 49% higher than last year, and 13% higher than the previous quarter.

Taking both oil and gas together, 2Q and year-to-date total hydrocarbon realizations were over 60% higher than last year.

Compared with the previous quarter total hydrocarbon realizations were 21% higher.

Our refining indicator margin of $8.19 per barrel has increased compared to the previous quarter but remained less than half the level of 2Q '07.

Year to date, it's down 50% compared with 2007.

Actual refining margins have been negatively impacted by higher energy costs and product price lags, which are not reflected in our indicator margin.

Turning to the financials, our replacement cost profit of $6.9 billion was 6% higher in absolute terms than 2Q '07.

Our profit including inventory gains and losses was $9.5 billion, $2.1 billion higher than last year.

Nonoperating items and fair value accounting effects had an unfavorable impact of $1.8 billion on the results, including $160 million for restructuring charges supporting the forward agenda.

Adjusting for these items, the 2Q results represent the highest quarterly replacement cost profit ever achieved by the group.

Operating cash flow was $6.7 billion, 10% higher than a year ago.

Cash flows were adversely affected by the substantial increase in working capital associated with the sharp increase in oil and gas prices.

As Tony just indicated, the $0.14 per share dividend announced today, which will be paid in September, is 29% higher than a year ago.

I will now turn to the segments.

In E&P we reported a pretax profit of $10.8 billion for 2Q, up $3.7 billion compared with last year.

The 2Q results included an unfavorable impact from fair value accounting effects of $370 million, and a net charge of $2 billion for nonoperating items, primarily from embedded derivatives associated with a number of long-term, North Sea gas sales contracts.

This accounting charge march to market the difference between the various forward indices under which the gas was originally sold, versus forward UK national balancing point gas prices.

Excluding these items, our underlying result was $13.1 billion compared with $6.8 billion in 2Q '07.

This reflects benefits from higher realizations and strong underlying production, which was partially offset by higher costs.

Reported production of 3.8 million barrels of oil equivalent per day was broadly flat compared with a year ago.

Adjusting for the impacts of production sharing agreements, underlying production grew by 6%.

TNK-BP contributed $1.35 billion to our 2Q results, nearly $700 million higher than 2Q '07, reflecting higher prices and a greater benefit from lag tax reference prices.

The 2Q 2008 tax lag benefit is around $500 million.

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

Our Refining and Marketing pretax profit was $540 million.

This included a net charge of $260 million, mainly related to restructuring costs and unfavorable fair value accounting effects.

Excluding these items, the underlying result was about $800 million, half the $1.6 billion level of a year ago.

This reflects significantly weaker US refining margins which more than offset higher refining throughput from Whiting and Texas City, and lower turnaround activities and good operating performance in other parts of the portfolio.

Our fuel value chains, which comprise refinery, supply, logistics, and marketing activities, experienced both lower sales volumes and flat or reduced margins as a result of higher fuel input costs and lower demand.

Our international businesses, which include lubricants, chemicals, LPG, aviation and marine fuels, continue to perform well in a challenging environment and have been able to recover higher feedstock prices.

Despite the difficult environment, the segment is demonstrating considerable progress in underlying performance.

Adjusting for changes in the environment, the underlying performance of the segment for the first half of '08 was around $600 million better than a year earlier.

In other business and corporate, our second-quarter underlying charge was $190 million.

Relatively lower charges for the first half have reflected benefits of a number of one-off items and the cost of cost phasing.

For the remainder of the year we expect the underlying charge to be in line with earlier guidance.

Turning now to cash flow, this slide compares our sources and uses of cash in the first half of 2007 and 2008.

Operating cash flow increased $17.6 billion, up 25%, and disposals provided a further $300 million.

We use this cash to fund $9.4 billion of organic capital expenditure, up 23%, and $6.8 billion of shareholder distributions.

We have rebalanced our distributions in favor of dividends in response to feedback received from shareholders.

Dividends paid in the first half of the year were $5.1 billion, up 28%.

Our net debt ratio was 19.4% at the end of 2Q, which remains at the lower end of our targeted range.

In the current volatile and uncertain environment, we believe this strong balance sheet leaves us well positioned.

Looking forward to the rest of the year, in Exploration and Production, we expect strong underlying production growth.

Entitlement effects under production sharing agreements will have an opposite effect, the magnitude of which will be determined by prices.

The E&P turnaround season, which began last quarter, will continue throughout 3Q with major planned activities across many of our operations.

This will impact volumes and costs, particularly from the higher margin areas in the North Sea and North America.

In Refining and Marketing, we expect benefits from the continued increase in refining availability.

However, current quarter-to-date refinery margins are some 60% lower than the second quarter of 2008.

Higher energy costs and planned third-quarter turnarounds will also impact refinery earnings, notably in the United States.

Our marketing businesses are being impacted by the slowing of the OECD economies, and margins compressed by rising wholesale prices.

We project our second-half tax rate on replacement cost profit to be in the region of 36%, at the lower end of our February guidance, and consistent with the average over the first half of the year.

Overall, the second-quarter results reflect further progress in our journey to restore our competitive performance.

It's our determination to continue to build on the improving base, step by step, in the quarters ahead.

That conclude my remarks.

Now back to Tony.

Thank you, Byron.

I would now like to stand back from the detail and look at our strategic progress as well as a number of other topical issues including, of course, an update on our joint venture in Russia, TNK-BP .

Back in February, I told you that our goal was to close the competitive gap in our financial performance against our key competitors.

There are three key strands in doing this.

First, restoring revenues, second, reducing complexity and costs, and third securing new assets and opportunities for the long term even as we improve a near-term financial performance.

In the first half of 2008 we've made good progress in all three areas.

First, restoring revenues.

Underlying production growth is up 6% in the first half of 2008.

This has been sufficient to more than offset the impact of high oil prices on our production sharing contract volumes.

We've started up four major projects in the first half of 2008.

The Thunder Horse project in the Gulf of Mexico should be on stream by the end of the year as we promised.

In fact, commissioning is already underway with early production from the first well in Thunder Horse South.

We anticipate bringing on further wells from Thunder Horse South through the remainder of this year, with Thunder Horse North starting up in the second half of 2009.

I know Thunder Horse has had its share of delays but it is on the very frontier of what our industry has achieved in the deep water.

When it is up and running it will be a powerful symbol of what BP can deliver.

In US refining, both the Whiting and Texas City refineries have been restored to full crude processing capability, and we expect to begin to see the financial benefits of high refining throughputs in the second half of the year.

Of course, the actual contribution will depend on refining margins which are currently depressed.

In summary, our focus on safe and reliable operations is building significant operational momentum which we expect to continue through 2008.

The second strand of our plan to restore our competitive financial performance is what we call the forward agenda, to reduce complexity and costs.

Again, progress is good.

Our program is ahead of schedule, and we should soon begin to see the first financial benefits from lower overheads.

As we previously indicated, our aim is to reduce corporate overheads by between 15% and 20%.

The program of simplifying our business model, especially in Refining and Marketing, is well underway with the establishment of six integrated fuel value chains, the focusing of our marketing for print and aviation and in lubricants, and the shift of our US convenience resale operation to a franchise model.

I would expect to see the financial benefits of these changes begin to feed through into our results toward the end of this year and into 2009.

A key challenge for all international oil companies is to secure their future by renewing their portfolio.

I'm glad to report that while we've been improving our operational performance, we've not lost focus on the longer term.

We've had continuing exploration success in the first half, including the 15th discovery in block 31 of Shore Angola, the southeast natural gas discovery in Egypt's Nile delta, the North Shadwan oil discovery in Egypt's Gulf of Suez, the Kodak discovery in the Gulf of Mexico, and two discoveries in the UK North Sea.

We continue to gain new access to resources.

We've completed a deal for the integrated oil sands and refining joint venture with Husky.

We've been awarded new exploration acreage in the Beaufort Sea in the Canadian Arctic.

And have agreed to acquire new shale gas acreage in the Arkoma Basin of Oklahoma.

And we took the final investment decision and gained government approval of the Block 31 program development in Angola.

We've also joined forces with ConocoPhillips to launch the Denali pipeline which will carry natural gas from Alaska to the markets of Canada and the lower 48 states.

In refining, we've recently taken the final investment decision on the significant upgrade of the Whiting Refinery so that we'll be able to run 80% Canadian heavy crude.

And finally, we've also formed a major joint venture to enter Brazilian bio-ethanol production, giving us a significant position, in arguably the world's most efficient biofuels industry.

Taken together, these milestones are a testament to how our people are rising to the challenge of closing the competitive gap.

I'd now like to say something about our joint venture in Russia, TNK-BP, which some of you may have noticed is making the odd headline or two over the last few months.

The important thing to remember, and I want to emphasize this, is that TNK-BP has been a highly successful joint venture over the past five years.

It's been good for Russia and good for all its shareholders.

As part of the current negotiation, doubt has been cast in some quarters over that track record.

It's worth stating the facts.

Since 2003, the year in which BP got involved, TNK-BP has had the best performance in the Russian oil industry on virtually every key metric used by serious investors.

The track record under the leadership of Bob Dudley is truly impressive.

Take production.

As this graph shows, since 2003, TNK-BP has delivered the highest rate of organic rate in oil production of any major Russian oil production company.

This industry-leading production growth has not been delivered at the expense of renewing reserves for the long term.

TNK-BP leads here, too, with an organic average reserve replacement ratio of almost 140%.

Again, the highest of any major Russian oil company.

This reflects the benefits of the world-class technology and capability that BP has brought to the JV, notably in reservoir characterization and water flood management, seismic acquisition and processing, and drilling and completion technologies.

And this commitment has not come at the cost of failing to distribute cash to shareholders.

On the contrary, distributions from 2003 to 2007 have totaled $18 billion, more than any other Russian company we know of.

TNK-BP continues to create value on other metrics, too, whether you look at production growth, reserve replacement, finding and development costs, or return on average capital employed, the company has the best track record in the Russian industry.

When the JV was established, we promised the Russian federation we'd be a good corporate citizen, and TNK-BP has fulfilled that objective, too, making huge strides in health and safety, the environment, governance, and transparency.

The company has paid more than $70 billion in taxes and duties to the Russian federation.

Just a couple of weeks ago, the Russian premier, Vladimir Putin, called for more investment in the future of Russian oil and gas production in order to sustain its growth.

BP as a shareholder in TNK-BP, is committed to that important policy.

Capital expenditure by TNK-BP has risen threefold since 2003.

The proposal for 2008 is to increase capital spending by a further 20%.

However, not all of the other shareholders support this investment, which brings us to the current debate over the future of the company.

Why is BP engaged in such a public spat with fellow shareholders?

As I've indicated, it isn't about performance.

Performance continues to be excellent as today's results show.

In fact, in many respects, TNK-BP is having its best year ever.

Nor is it about greater state involvement in TNK-BP.

It is about control and about the future governance and direction of TNK-BP.

It's about whether to continue to increase investment in the long-term development of the Russian oil industry.

It's a pretty lively negotiation as you're witnessing.

The other shareholders want to tear up the agreement that they willingly signed in 2003.

We're not prepared to do that, and we'll vigorously defend our rights using all legal means at our disposal.

We will not be intimidated by strong arm tactics.

We cannot be sure how things will pan out in Russia, but I can tell you that we're committed to finding a solution that's acceptable to all parties.

Whether that is possible, we will see.

The next subject I'd like to address is how the global business environment is evolving for BP.

I indicated earlier this year that we believe the era of cheap energy is over.

At least for the medium term.

Events are playing out even faster than any of us expected.

The key factors in this are population growth and industrialization in the world's developing nations, which are driving strong demand.

And the very weak response we've seen on the supply side.

There is not a shortage of hydrocarbon resources below the ground, but there is a problem above the ground in turning resources into production capacity.

We see an increasing likelihood that oil and gas prices will be stronger for longer.

Gas prices, especially in North America, have continued to lag behind oil prices.

It will be a great benefit to BP if this gap narrows or closes, adding around $2 billion to $3 billion a year to operating profits.

In refining, high input prices and the weakening economic environment across the OECD have combined to create the opposite effect to that found in the upstream.

As this chart shows, margins have fallen markedly in the last year, especially in BP's refining heartland in the US.

Although non OEC demand is robust, as I've mentioned, high oil prices and the slowing global economy have led to falling gasoline consumption, especially in the key US market.

The majority of demand growth in 2008 is expected to be for diesel, and as a result, gasoline cracks are barely possible in the US and are negative in Europe.

Moreover, the planned Autumn startup of the Indian Jamnagar refinery will add significantly to global gasoline supplies.

As a result of all of that, as I said earlier, we're sailing into a gale in our refining business.

We cannot shape the business environment, but we can respond positively to it.

So what are we doing?

Well, we're treating it as an opportunity to grow the company.

People sometimes ask me, where will the growth come from for BP?

The answer is threefold.

Firstly, increased activity in exploration production.

At a time when access to new resources is constrained, incumbent positions are increasingly valuable.

So we're accelerating activity and looking for opportunity to deepen, especially in our key tax and royalty areas, that allow us to capture price upsides such as our recent Arkoma shale gas deal in North America.

We're also focusing on the pull-through of resources in established basins including the Gulf of Mexico and the North Sea.

Secondly, we're closing the competitive gap through greater efficiency.

Implementation of the forward agenda is on track, bringing with it reduced complexity and continued focus on costs and efficiency.

It's good for our downstream business as it faces the challenge of depressed margins, and it's good for our upstream business, allowing us to flow more of the price upside to the bottom line.

And thirdly, we're creating value in alternative energy.

These businesses are increasingly economic without subsidy, and we will continue to provide visibility on our investments and the value created.

I'd like to finish by summarizing our strategy again.

It is a simple one.

We have a very strong upstream portfolio with a growing reserve and resource base.

Our challenge is to convert that strong base into growth in production and cash flow over the next few years.

I'm confident that we'll do that.

Our downstream business has been doing badly in the past few years, while many of our peers have been doing well.

We're working to turn it around.

Our costs have become uncompetitive in some areas.

This is a major opportunity for improvement, and we're grasping it with both hands.

We have a significant and unique growth option in our alternative energy business.

Our challenge is to expose that value for the benefit of BP's shareholder.

This is the plan that I want you to judge us by.

It's early days, but so far we're on track to deliver it.

Speaking for myself, I'm excited about the next few years, and I know my team is, too.

Ladies and gentlemen, thank you for listening.

We'll now be delighted to take your

(OPERATOR INSTRUCTIONS)

Thank you, Operator.

I think the first question comes from Tipan [phonetic] at Morgan Stanley, last name Tipan.

Good afternoon.

Just a couple of technical questions.

And then a question on the alternative energy business.

Just in the upstream, I was wondering if Andy could give a little color in terms of cost inflation that we're encountering in the first half of this year, and what he sees going forward.

And sort of spitting out production taxes.

And if you could comment perhaps on where you see sort of the DD&A per barrel moving.

Secondly, I know it may be difficult to get sort of volume going for this year particularly given sort of the variability around PSF effects.

I was wondering where you thought that may be at $120 oil, and perhaps a little more color in terms of what volumes you think Thunder Horse will be producing at the end of the year.

And lastly just on alternative energy, in February we talked -- I think you -- BP talked about the possibility of crystallizing some of that value that you see in the alternative energy business.

I was wondering how that was progressing, thank you.

Thank you.

Let's go first to Andy, and then we'll go to Vivian.

Andy?

A lot of questions.

To start with, with cost inflation.

I think on the CapEx side it's certainly running at sort of ahead of 10%, probably 10% to 12%.

And we're probably managing to offset around 4% of that.

I think on the cash cost side, I think we actual had a good quarter in the second quarter of this year.

If you look at the cash costs, second quarter of '08 versus second quarter of '07, they were just up 4%.

Which which I think is significantly below inflation.

I think inflation on the cash cost side it's probably around 8%.

We're beating that by 4% .

I think that's really part of what's given a good upstream delivery in this quarter.

We've delivered not only the volume growth, but we've hung on to the margin, I think, through real discipline around costs.

And that is, I think, the first early shoots of the forward agenda actually hitting the bottom line.

All of which is good news.

And there have been some offsetting factors, as you said.

Production factor is the biggest hit we've had is in Alaska, probably running at about $500 million per quarter.

Despite those effects, we've still managed I think to really hang on to the margin.

That gives you a send of both the cost impacts and the production tax impact.

On volume guidance, sort of unchanged, I think.

I'm not going to reforecast the year.

I think it's too early to do that, which was in esense fired at $100.

All I would say is the first half has actually been pretty good.

The oil price has probably been around $110 headline number.

And production growth has sort of been about half of the same.

Oil priced slightly higher than we'd anticipated.

But we've actually delivered slightly more volume than we anticipated.

So, I think we've had a good start to the year.

Hopefully we can continue that in the second half.

But a lot of stuff needs to happen.

The turnarounds need to be done well.

We have some remaining ramp-ups.

But a good start to the year.

Finally on Thunder Horse, again, I think it's a similar sort of sentiment.

Tthe objective was to get it up and running by the end of the year.

We've had an early win with getting one well on earlier than we thought.

And that's been helpful.

It's allowed us to fully commission the top sides.

And the performance has been good.

We've had production efficiency since startup in the high 90's, which is great.

That's world-class performance for a new facility coming on.

The well is running at over 40,000 barrels a day, which, again, is great.

The reservoir is performing as we would expect.

Which is an important early signal.

So, I think we're in good shape.

So what needs to be done now is there's more wells to be brought on from the Thunder Horse South, four wells, and we'll get three or four of those going by the end of the year.

It will depend on weather patterns.

And then we have Thunder Horse North coming on in the second half of '09.

And you can work out by the well capacity here.

You need six to eight wells to fill the facility.

We'd anticipate getting there by the end of '09.

So, the ramp-up is going well.

And I think we made real progress this quarter in understanding the facility and understanding the

This is Byron.

I just wanted to add a little bit to Andy's comment about production taxes.

If you look at note five on the stock exchange announcement, we lay it out in detail there.

And if you refer to that, you'll see that production taxes are up $2.5 billion over the first half of the year.

Now, that's driven primarily in Abu Dhabi and in Alaska.

Reflects the increase in prices and the change in legislation that we saw in Alaska over the course of the last year.

Thanks.

Thanks, Byron.

In terms of energy --

Yes, thanks.

Since February when we gave some information which allowed people to get a rough equity value for the businesses, we have been looking at a range of different options to give more transparency.

And we've looked at IPO options, we've looked at partnership options, we've looked at other options.

We've decided that at this point, we will keep the businesses inside BP.

That these are businesses that are important to us.

That they have great growth opportunities and potential, and so we've decided that these are businesses for the BP portfolio.

And we have no plans to IPO at this point.

So in order to give the transparency on value, we'll continue with the approach we started in February, and give information probably next February, give information so that you can all value the businesses from standard industry multiples.

Great.

Thank you.

Our next question comes from Neil McMahon at Bernstein.

Hi.

A few questions.

Maybe the first one looking at why the strategic move toward the Woodford Shale in the States.

And maybe just walking through why now since it seems to be a sort of late response to an already-developed shale play.

And secondly, looking at the TNK-BP situation, what can you really do in the current environment?

Is it possible to withhold dividends for the group, and how far away are you from arbitration and could that actually lead anywhere, thanks.

We'll get Andy to talk about the Woodford Shale, which I have to say, I don't think is late, but we'll let Andy talk to that, Neil.

Then I'll talk to TNK.

Yeah, Neil.

On the -- let's talk about shale.

It's like opening the aperture up slightly and look at the total for the non conventional gas position.

If you wander out to 2020, I think it's a reasonable expectation that nonconventional gas will be around 50% of the US's production.

Now clearly we have a strong position in tight gas in our Rockies position, well established.

We have a strong position in coal bed methane in San Juan.

And really, we've been working over the last year or so to figure out how we build an equivalent distinctive strong position in the emerging shale plays.

We have an established position in the Hainesville through our current acreage holding.

And as you look across the tier one shale plays, the Woodford was an important addition to ensure that we had the scale and the materialality.

So that's why we did the deal with Chesapeake.

I think, it's up to two TCF in the Woodford, and I think our Hainesville play is yet to be appraised.

It's probably double that size.

So you can see we are really building materialality in there, and therefore have three strong positions in each of the unconventional plays in the US.

And it will allow, as I believe now, to have confidence that we can grow the US gas business, which is an important signal going forward.

So if you look at the real strategic tenets to the Chesapeake play, it's about ensuring the portfolio's complete.

It's about establishing that incumbency in an area where we already operate in.

We already operate in the Arkoma where the Woodford shale is, so it's a direct bulk on, and clearly it's an analagous piece of technology to our existing North American and conventional plays.

So I think a huge amount of synergy.

And I believe that it will prove to be a very good acquisition.

Andy, any plans to take this technology overseas?

It seems relatively little has been done in Europe using this technology in the European mainland on top of that in the US.

Yeah.

I'm probably not as strong for it in the European mainland.

I think there are lots of challenges in operating there.

What I would say is we're taking that technology and applied it in Oman.

That was one of the key distinguishing features of our bid in Oman.

It was tight gas, very similar to the plays we see in North America gas.

I think there is real opportunity to leverage our North American technology on nonconventionals.

And that's what we're looking to do.

Okay.

Neil.

On TNK-BP, I think all I can say really is that we clearly have rights under a shareholders agreement which we intend to defend robustly using all legal means at our disposal.

Exactly what and when, we will determine.

And I think the second thing I'd say is that we intend to do everything we can to ensure that our fellow shareholders cannot play by one set of rules in Russia and another on the international stage.

And I think it's sensible that I leave it there.

Thanks.

Thanks.

The next question comes from the United States and Robert Kessler at Simmons.

Robert?

Robert Kessler, are you there?

We seem to have lost Robert.

The next question comes from the internet.

A question about Brazil.

How does BP feel about the deep water and pre-salt potential Brazil and do we see ourselves becoming involved, which we've not been

I think this is a question for Andy.

I think clearly there's been initial success in that pre-salt play in our series of exploration discoveries.

We're clearly not involved in those on a worldwide basis.

I think it would be inappropriate for me to comment on the absolute potential there.

But clearly, an important, new play emerging.

And it's an area where we believe we have something to bring in terms of technology.

We clearly have deep skills in seismic through salt in our Gulf of Mexico.

It's been a hallmark of our exploration success there.

And clearly we have skills in the deep water development.

So we continue to talk to Petrobas.

We would like to participate in the forthcoming bid rounds should they be licensed.

And we believe we can be competitive.

So yes, it's great to success there.

You can't be in every play.

But this is certainly one I think for the future.

All right.

Back to the telephones.

And John Rigby from UBS.

Right.

There's two questions.

One on the upstream, one on the downstream.

On the downstream, I recognize it's a lot of moving parts.

So maybe you can't tell me what the profits forgone are.

But is it possible just to get some insight into what additional costs you're still incurring on the Texas City site, either because you can't optimize your crude or in terms of the contractors that are still on there that you have to pay, that ultimtaely those costs will go away?

And the second is on TNK-BP.

I guess I'm not going to be the last one to ask a question on this.

Thinking back, you were able to sell (inaudible) fairly easily because I think the structure at TNK-BP is that all the assets are in separate subsidiaries.

Is one solution ultimately, if you both have a positive view on Russia ultimately, but fairly clearly can't work together, that you just break up the join venture?

Then you can choose your own partners for each of the assets that you retain?

Okay.

Let's get into give you an update on Texas City.

And then I'll come back and deal with TNK-BP.

I think I'm playing sweeper today.

John, thanks for the question.

You're right.

There are a lot of moving parts.

I think the best way to get at this would be the following.

Byron indicated that our underlying performance improvement in the first half in '08 versus the first half in '07 was approximately $600 million.

While there are a number of moving parts in there, including much better performance from our international businesses offset by the rest of our marketing where we've had a challenging time with demand, effectively what that means is that most of that recovery is due to Texas City and Whiting's recovery, and most of that, therefore, is to do with the recovery of the US system.

And Texas City has made a significant contribution to that.

And that's how I'd like to leave it.

I think on TNK-BP, John, I would not rule anything in and anything out in terms of what a final solution might be here.

Clearly, the route that you've suggested isone that we can think about.

It would ultimately, I'm certain, require the okay from the Russian authorities.

Okay.

Okay, thank you.

Thanks.

The next question comes from Mark Iannotti at Merrill Lynch.

Good afternoon, Mark.

Afternoon, gentlemen.

A couple of questions, I'm afraid another on TNK.

Now that you've taken all of the BP special advisors out of country, do you think that this will have any impact at all on volumes in the short term, and if not the short term, on the medium term?

And then just on the business itself, can you make some comment on block 31 and the reserves you think you may be able to put on the books this year from that?

And final oh price realizations.

It just looks like your crude price realizations relative to market prices were swinging around quite a lot in the quarter.

The UK looks very strong.

US looks quite weak.

Can you make any comment on what we can expect third quarter around the current prices we have?

Usual rules apply, we go to Andy for Block 31 and usptream realizations, and then I'll deal with TNK-BP.

Hi Mark.

On Block 31, just standing back, this was an important announcement because what it does allow us to do now is to develop the 15 discoveries we have in Block 31 as a series of projects now where it's design one and build many.

The same approach as we used in Azerbaijan, in Trinidad, and now we're taking that across to Angola.

We spent the time front end loading this to enable us to do it.

It's good for the country as a Plc holder and good for us.

It's been a successful process.

The first project off the block is PVSM.

And I'm not going to give you a reserves number.

But it would certainly -- that we would be booking the -- our share of PVSM in '09 now that we've reached FID on that project.

And then as we get to FID on each of the projects that follow down in the southeast probably next, and then to the northeast, and then probably one more, we'll book relatives as we go.

But clearly, as we look to the reserves placement ratio, keeping that production line of projects moving forward is key.

So the first one will be in '09, it's 25% of share.

And I'd stay's a typical scale project.

And you can figure out what the reserves are as a result.

Thanks, Andy.

As far as the specialists were concerned, Mark, they were largely focused on major new developments for the future.

And ensuring the delivery of a pipeline of well locations for beyond 2008, in some cases beyond 2009.

So I think the impact short run will be very modest.

It's important to recall, of course, that we still have significant Ex-BP presence in TNK-BP.

So the COO is an ex BP executive, the head of the downstream is an ex-BP executive.

The head of technology and exploration is an ex-BP executive.

The treasurer is an ex-BP executive.

So there remains a lot of presence in TNK-BP of BP.

However, it's clear that the specialists were doing something which we felt was important which was creating the growth options for the future.

Not for the next year or two, but for the period beyond the next couple of years.

And if they're not present, then the growth prospects beyond the next year or two will clearly be impacted.

Mark, finally, I think you had a question about realizations.

Specifically the fact that UK realizations, I think look strong relative to markets and UK realizations looked weak relative to markets.

The technical reason is the timing of lifting some specific fields in the UK North Sea and in the US and geo pricing which is included in the liquid realizations.

I can talk you through that off line if you would like to do that later.

Thanks.

Next question comes from the web, it's a combination of several questions which are asking for an update on plans for the Whiting refinery.

Okay.

Let's go to Iain for that.

Okay.

I saw a couple of questions there.

And basically, Whiting, we announced this week we're going to the next phase of implementation and execution on the upgrade of Whiting.

As you recall, this is converting the refinery to a predominant slate of Canadian crude.

One element of the question was how committed are we to it in light of the margin environment.

The answer is we remain very committed to it for the simple reason that the main benefit from this investment is actually feedstock advantage and location led rather than changing the product slate of the refinery.

The other reason is that the quality of this investment competes very well with other investments across BP.

I think the only other things I'd say about Whiting is that the air permits and water permits have been received, and we've been through quite a lengthy process around that.

And the other part of the question on the screen says would BP entertain a long-term supply agreement to secure feedstock for the Whiting refinery now that the FID on that project has been reached.

Clearly we will look at all aspects to strengthen this investment.

We see this investment as providing considerable strategic advantage due to the scale and location advantage of the refinery.

If there were the right opportunity to tie supply to this refinery, of course we'd look at it.

Great.

Now back to the telephones.

We go to a question from Brahin Karim from Lehman Brothers.

Actually, Fergus, it's Lucy from Lehman.

Byron, at one key stage, you indicated there were about $1 billion pretax of exceptional, perhaps potentially nonrecurrence of items, some of which have recurred in the second quarter in terms of the tax lag effects for TNK.

Could you summarize what you think the exceptional pretax profits might have been for the quarter.

I mean, were there any exceptional trading profits or --

Thank, Lucy.

There really are two specific items which have contributed to higher 2Q results than are likely to be repeated in 3 Q and 4Q.

The first, as you already noted, is the $500 million benefit from lag tax reference prices in TNK-BP.

And the second is the phasing effect within other business and corporate which is about another $200 million.

So we calibrated it as a total of $700 million of items that -- let's put in the bracket, of unusual in the second quarter.

As far as trading goes, the overall trading contribution in the second quarter was within the normal bounds.

It was a bit weaker in oil and products, which impacts refining and marketing, a bit stronger in gas and power, which impacts the E&P results.

But overall, it's generally in line with expectations.

Thanks.

Could I also ask a follow-on question?

Obviously there's been a lot of focus in terms of TNK-BP.

Are we likely getting an update in terms of how the negotiations are proceeding with Kavitka [phonetic]?

The negotiations with Kavitka remain in the deep freeze, frankly, whilst we sort out the other issues and as such the legal entitlement to Kavitka remains with TNK-BP.

And TNK-BP continues to be the custodian of that asset and to carry out a relatively modest work program to take it forward.

And could I ask, why does the ongoing debate with AAR impact the negotiations with (inaudible)

Because everything is linked to everything else, I expect.

Thanks, Lucy.

Next question is from the United States and Jason Gammel.

Thank you very much.

I wanted to ask for some incremental commentary on the Arkoma shale acquisition in three specific areas.

The first of which is the ease of integration of these assets with your existing US and continent portfolio.

I believe you already have a pretty strong management team in place in the mid-continent.

The second would be the pace of investment and development in the Woodford.

And rather this would be incremental to the 10-year, $15 billion investment plan you have for the US onshore.

Third, I was hoping that Andy might be able to talk a little about the differences of technology in this shale play versus your existing, nonconventional gas position and specific horizontal drilling and multiple fracture stages.

Okay, thank you, Jason.

Let's hear from Andy.

All right.

Shale plays.

I think that your first question about integration, I think, is key.

One of the reasons that we're attracted to the Woodford is that we have an existing operation in Arkoma.

We have people on the ground.

We have the operation centers to do this relatively easily.

We're picking up three rigs initially from Chesapeake.

And then what we'll be bringing in our own drilling machines to build that up to seven over the near term, which is the current rig rate they're operating with.

So I actually believe the integration of these assets is relatively easy.

In terms of the pace of investment, this is incremental, clearly, to the current spend in North America.

I believe the subsurface is well described in terms of drilling locations.

And actually the issue really around the ramp-up of pace will be around the pace at which we bring in the additional drilling equipment.

And insure that we use the same approach as we've used elsewhere in North America, which is to generate long-term rig commitments so that we get stable rig crews, we get stable equipment, and we get efficiency from it.

And then in terms of technology, you're right.

It is all about -- it's three things.

It's being able to image well, which is about seismic.

Which we have, we believe real, in-depth knowledge of.

So your well locations are optimized.

It is then about horizontal drilling, again, which we're using very effectively in the tight arenas.

Then clearly it is about fraccing.

So we believe we have the depth of technology and maybe additional technology in the way that we integrate the subsurface beyond some of the common players, the current players.

And, you know, we're taking all of that clearly to the Hainesville, as well, which is as yet unappraised.

But we believe has probably more than double the potential of the Woodford.

So, it actually plays to our strengths.

We've got the technology, we have the operating footprint, and we clearly have the business efficiency from operating scale.

efficiency from operating at scale.

Thank you.

And now back to the web.

The next question is about TNK-BP.

Under what circumstances might you change your accounting treatment for your interest in TNK-BP.

And what could be the changes?

Sounds like one for me.

I suppose we should start by being clear that no one, not even our fellow shareholders, has questioned ownership rights to 50% of TNK-BP.

So it is just a question of how we choose to account for the 50% interest.

It's not about economic substance or value or about the flow of cash to BP.

Since 2003, I think as most of you have known, we have equity accounted for our 50% interest in TNK-BP.

What that means is we include our share of TNK-BP's earnings in our upstream results each quarter.

I suppose the alternative would be to account for our interest on the basis of dividends paid as they're paid.

I think the reality is, in practice, both accounting treatments, if I'm not mistaken, would have been broadly similar in terms of the impacts on our reported earnings over the last five years, as the dividends from TNK-BP have broadly tracked our share of earnings.

So no matter what the accounting treatment we choose, the important point is the economic substance for that 50% ownership of TNK-BP and the entitlement to 50% of the dividends would be unchanged.

And of course under any scenario, we'll continue to provide supplementary information on TNK-BP's production and reserves as we have done since we started it.

So I don't really see this as an issue.

Back to the telephones and a question from Ed Westlake at CSFB.

Good afternoon.

Two questions, both North America and E&P focused.

Just following on on the gas side, obviously you're generating more cash flow than you're using this year.

Oil prices help, your gearing's at the low end of the range.

Peers are pushing into gas, shale, arrow.

And you've done a bolt-on, as well.

E&P space is down 20%.

What are the barriers to the simple view that big oil, including youself, should be even more assertive in North American gas if they are going to convert longer term?

That's the first question.

The second is in the Gulf of Mexico you've had recent successes, which is great.

But maybe you could just point us to the next hub developments or exploration targets that you think could be material to the Gulf of Mexico production in the 2012 timeframe and beyond?

Thanks.

Thanks.

Over to Andy.

I don't disagree with your thesis here, which is clearly why we did the deal with Chesapeake and Woodford.

We will continue, I think, to look at opportunities to increase our resource capture in areas where we have stable fiscal regimes, and we have good margin.

And we have the ability to add distinctive value either through our incumbent operating positions or our technology.

So I agree with all of that.

We clearly have demonstrated that we can be very efficient and effective in North America.

We build to scale.

I'm happy with the portfolio we have in terms of our balance of conventional and nonconventional.

But I believe we probably could continue to deepen in areas where we can pull in those synergies.

So without talking about specific targets, we are going to continue to look and see if we can actually create value-adding additions So I don't disagree with your push.

In the Gulf of Mexico, as you said, we've clearly been focusing on getting the current fields under development, up and running, making progress on that.

I think, as you look at the future hubs now, I think that the Kodiak discovery was important.

It's adjacent to Tubular Bells.

And without getting into the specifics of what a development concept would look like, we clearly have materiality between those two discoveries.

And I would see a hub emerging from either the Kodiak T Bells.

We're focusing hard on that to insure we bring it forward with the right pace but obviously with the right front-end loading.

Against, a lot of that is about standardardizing the design and bringing all the lessons we've learned from Atlantis and Thunder Horse.

The other area I'd point you to is the western plank of Mad Dog, adjacent to the PUMA discovery.

We're in the early stages of the appraisal of PUMA.

But I think I can see further development in the western flank of Mad Dog potentially linked to the early development of PUMA.

And maybe some concepts of a development through appraisal.

How can we accelerate that.

Those are two big near-term things which would be production in the early part of the next decade.

Thank you.

Thanks.

Irene Himona from Exane.

I had a question firstly on the downstream.

Can you give us some guidance on the opportunity costs of the Husky deal in Q2.

In other words, what refining EBIT did you give up through that deal?

And then my second question is on CapEx.

I realize it's a little early, but you talked about CapEx inflation running at 6% to 8% for yourselves in the upstream.

Obviously, you are launching Angola, Block 31, the Whiting, FIDs.

So what order of magnitude higher CapEx should we be looking at for 2009 versus this year on the basis of these announcements?

Thank you.

Thanks, Irene.

Let me just deal with the capital one which is our guidance for 2008 remains unchanged, $21 billion to $22 billion.

We'll update you on what we think for 2009 when we get to February.

If I can ask Ian to talk about the foregone EBIT in Husky.

Thanks, Irene.

First of all, I don't want to talk about the foregone EBIT other than to say that the state of the US refining margins, it's somewhat lower than it would have been before.

tthe second thing just to point to is Toledo is a small refinery, $130,000 barrels a day.

Of course, we're going to expand it.

In the scheme of things, there's a small impact on the onstream availability in the US as a result of this.

But it's actually -- it's relatively second order.

As I say, especially given the state of the margin environment at the moment.

Okay.

Thank you.

Thanks, Irene.

And now back to the US and to a very patient Mark Gilman at Benchmark.

I had a couple of things for Andy and two for Byron, if I could quickly.

First, Andy, can you give us an idea of the development cost for the Block 31 project in Angola.

And also an idea of the benefits associated with the intended reduction in Russian minerals taxes to kick in January 1 of next year?

Whether that's deductible in terms of Russian overall income taxes?

For Byron, if I could, I'm a little bit puzzled by the UK R&M earnings number, the replacement cost number, very large given the asset base.

And then also I guess because I didn't have enough to do this morning I got to reading the note on the fair value accounting adjustments.

And it struck me that you're measuring those adjustments based upon management's estimate of what performance would be.

Which struck me a bit curious in light of the fact that one could quantify those effects just on the basis of the adjustment itself.

I was wondering why you chose that route.

Thanks a lot.

Okay, Mark.

On Russian tax, I'm afraid we can't provide you with any greater clarity at this moment.

We'll wait and see what actually transpires in Russia.

Would you like to say anything about -- not the development costs, Andy, but the development in Angola?

Yeah, Mark.

We don't disclose the individual CapEx estimates for the individual projects.

All I would say is that the opportunity I think to bring a standardized approach will allow us to be very cost competitive in terms of the development there.

It's going to be competitive with what we're doing in the Gulf of Mexico.

And competitive with what we're doing elsewhere in the world.

And I think the real issue that we've learned is if you're going to drive a capital efficiency into a project you've got to standardize the approach.

So we'll be designing this development once, and we will be producing three to four hubs around there.

And let's hear from Byron with what I will definitely say is a specialty subject, the treatment of fair value accounting under IFRS.

I think the easiest way to describe this, Mark, is the reference that you've pointed out is merely the way in which we're describing the fact that by doing fair value accounting effects, by isolating these, we're trying to ensure that we've established symmetry between the physical volumes, which are treated under IFRS under one accounting method, which is basically historical, and the derivatives which are being hedged directly associated with those, which are mark to market.

So all we're trying to do is ensure that these asymmetric effects are pulled out because management's view is that the underlying performance of the various business segments is best looked through without those timing distortions that would otherwise occur under IFRS.

I think Iain will say something more about UK R&M.

But you need to remember that our underlying presence in the UK in refining marketing is now relatively limited.

And there's a number of corporate adjustments, timing factors here, that impact a relatively modest amount of income.

So you should expect it to be highly volatile.

I'll pass it over to Iain.

This is in addition to what Byron said which is really with regard to interregional recoveries.

The business we've got left in refining and marketing in the UK is basically three things.

We have a pretty strong retail business.

We have, one of our main hubs for the acetic acid business, and that's been doing pretty well this year.

And then the third thing is we've got a big center for our global fuels business, particularly aviation.

And those have been doing quite well.

And then lastly, some of the supply optimization around those have done well.

So those would be the other factors.

Thank, guys.

Thanks, Mark.

Now we're back to an equally patient Michele Della Vigna of Goldman Sachs in London.

If I could ask two questions.

The first one is about PSC and if you could give us an idea of how much PSC affects increase by the end of the year if we remain at the current level of oil price.

Then the second one is with Henry Hub, where it stands at the moment.

Why for your Alaskan gas development you're not considering an L and G development instead of doing it by plan today into the lower 48?

Back to Andy for PSCs and Alaskan gas.

What I would do is refer you back to the view we gave you at the strategy review in February that showed the impacts of PSC effects going forward.

In particular, the basic message with that was that near term there are some big effects.

We've talked about 6%, 200,000 barrels a day.

The big impact in '08 and '09 as you go through some profit trans changes on some of the big PSCs we have in Azerbaijan and Angola.

Of course once you've gotten through those, you get to more of a steady state where the effect becomes much more moderate.

And that was the shape of the curve that we showed you in February.

And I think our experience through '08 has been very much in line with that.

In terms of the best way to develop Alaskan gas, I think there's been a huge amount of analysis of this over many, many years.

Probably too many years.

And of the schemes that have been reviewed, I think there's common agreement amongst the various parties that gas pipeline is the best way to develop it.

And that's the scheme that we're pursuing.

And we believe, now that we've announced the approach with ConocoPhillips, created the Denali gas line company, we're making real progress this year and look forward to proceeding through to collect approvals.

Now up to Scotland and Jason Kenney at ING.

Hi there.

Just three short questions.

One for Andy.

Could you give us an update on Australia L&G and the outlook there.

One for Byron, could you give us an update on the outhlook for share buybacks in the second half of 2008.

And then one for the sweeper -- have you considered or could you envision swapping your TNK-BP stake for further assets elsewhere in Russia?

Okay.

Jason.

Thank you very much.

Let's start with Andy.

Okay.

In terms of the upstream, Australia, I think your question is really about the progress on the fifth train of North West Shelf and when would that start?

It was forecast to start in the second half of '08.

And obviously it's in an operated asset for us.

But we have no reason to believe that the project isn't going to be delivered against those timelines.

So in terms of the operational side of it, it continues to run well.

Looking forward, we have our share in IO, Io Jans [phonetic].

We're continuing to look at ways in which we can continue to work with the current proposed schemes, and we look forward to securing the value from that anchorage.

So the portfolio in Australia in L&G is strong and is a good piece of business at the moment.

We don't provide any forward guidance, Jason, on share buybacks.

You can look at what we've done over the first half of the year.

It's been about a $ billion a quarter.

If you remember back in my remarks in February, I said that this is a swing element.

We've now rebalanced our distribution much more towards dividends.

And to the extent that there are opportunities to make acquisitions, as we've identified recently in the upstream, smaller, but important strategic acquisitions, we'll do that.

And to the extent that there is cash that is not necessary for those activities or ongoing ones, then we'll continue to distribute it in the form of share buybacks.

But it will be a considerably lower amount going forward than it was prior to 2008.

Thanks, Byron.

I think what I'd say, Jason, is I would rule nothing in and nothing out, as I said earlier.

The only point I would make is that we have a great position, and we are intent on defending it robustly to ensure that we preserve the value that we've created for the BP shareholder.

How it transforms itself in the future, only time will tell.

Okay.

Thanks very much.

Thanks, Jason.

Now on to Colin Smith at DKW.

Are you there?

Yes.

Good afternoon.

Question on the US downstream.

I wonder if you would be willing to just give us a bit of a view about what was actually -- what the contribution between the refining part of the business and the rest of the business in the US was.

And maybe comment about how far of a toll you thought the margin structure you're experiencing now effectively reflects the impact of Whiting in Texas City coming back as very large assets in that market.

Thank you.

Thanks, Colin.

Let's hear from Iain.

Thanks, Colin.

Maybe I ought to tie that to a question on the web, which talks a bit about turning around US downstream, while we're on it.

I think, first of all, I'm not prepared to split the refining and marketing contributions, not least because a fundamental tenet of what I'm trying to do is run the business as an integrated business.

In parts of the US, notably the west coast, it's actually impossible to make sense of that split.

So I'm not prepared to do that, Colin, I'm afraid.

As far as the margin structure's concerned, there's actually a bunch of things playing in here.

Not least the interplay between very strong distillate demand around the world which is causing people to run refineries very hard even though the gasoline that they're producing as a byproduct actually hasn't got a particularly strong demand profile right now.

I would say that's the biggest driver of the weakness in the US refining margins.

But clearly there's also the fact that miles driven are 2% down year-on-year, and it's the first time we've seen that in an awful long time.

So I think the reasons for the margin structure today are rather more fundamentally linked to what's going on in the product markets rather than the return of our two refineries.

Although clearly the return of a number of refineries does have an impact on this.

Just if I may turn to the question on the web -- firstly, I would just like to comment on turning around downstream in general.

The turnaround program that I indicated to you in February is on track.

We're clearly, though, battling low refining margins.

The principal drivers of returning performance to US downstream are, firstly, restoring revenues, and the majority of Texas City's economic capability is effectively restored.

We have one train, as we said, hydro treated backup, a very valuable unit.

Another one coming up in the next few days.

The second is clearly continuous improvement in refining performance and efficiency.

The third, which Colin provoked was obviously running the business in an integrated way.

The fourth is US convenience retail.

That's actually getting out of operated convenience.

And that's going very well.

Despite the economic downturn, we're confident in our ability to franchise that business.

And then fifthly, we've got to improve the overall back office efficiency of the business, as I indicated in February.

And last but not least, it's investing in competitively advantaged positions with the focus on manufacturing, and that's what the Whiting investment's all about.

So it's on track.

A long way to go.

But we're making quite a lot of progress.

Thanks, Colin.

We're now down to the last three patient callers.

First, of the last three is Neil Morton at (inaudible).

One question and one clarification, please.

The question is on Denali.

Could you perhaps give us an update on your progress potentially bringing in other partners to the project, whether it be the Exxon pipeline company, I think even Gazprom has been mentioned.

Could you also clarify the process.

I understand the Transcanada project has been approved by the Lower House in Alaska.

If it gets Senate approval, is that it, or are you still intending to proceed in Paddle L [phonetic]?

And the clarifications on other business and corporate.

I think Byron talked of phasing.

Are you still sticking to the full-year guidance of $1.5 billion, or are you implying that from Q3 onward, you go back to the quarterly run rate of $375 million?

Thank you.

Thank you, Neil.

Andy, Denali?

Yes.

On Denali, Neil, we believe that Denali, the joint venture company between BP and ConocoPhillips, is ultimately the best chance of ensuring the line is constructed by a couple of big reasons.

First is that companies do have the ability to undertake a large project of this scale.

It is huge, it requires significant financial strength.

It needs Arctic experience, and it needs an understanding of Canada.

And we believe we bring all of that to the project.

And the second thing is that actually our shippers, we are incentivized to control the construction costs, reduce cost overruns, which have blighted I think previous pipeline projects in Alaska.

So therefore we believe the industrial logic is strong.

You're right, the Lower House in Alaska has supported the geoprocess with Transcanada.

It has yet to go to the Upper House.

But irrespective of that, we are continuing because we believe we are the best vehicle to execute the project.

And we're making good progress.

As you know, the company's been announced.

We've announced the CEO.

We've announced some of the senior executive team underneath him.

We've got 125 people working on the project, employees of the company, and the contractors.

We have the field work going on.

75 people those are in the field.

And we have approval of the prefiling process for FERC.

Those are all very strong indications of our intent here to see this through.

In terms of other people joining us, I think you need to ask Exxon on hat question.

They've been invited.

You need to ask them.

In terms of other pipeline companies, clearly Transcanada is one of the pipeline companies.

There are others.

Would have to examine, I think, with Transcanada, their potential with drawing partner liabilities.

So we'll look at all options.

But what I would say is that the partnership between BP and COP is strong, and we're making good progress.

Thank you, Andy.

Byron?

Neil, thanks for asking for the clarification.

And you're exactly right in your conclusion.

The net charges in all other business and corporate tend to be volatile on a quarterly base.

They really are impacted by a huge number of factors.

The first-half charges have benefited from a number of these things, as well as cost phasing.

So when we look into the second half of the year, although it's impossible to know with certainty, we think that the original guidance, the pace of that which would be $750 million on a half-year basis, is the right call.

And if you look back to 2007 and you compare the charges for the second half versus the first half for the reconfigured OB&C that we have today, you'll see that the charges in the second half were more than twice those in the first half.

So I think that the guidance that we're providing, which is to go back to the original indication, but no catchup in the second half, is the right one.

Okay, that's great.

Thank you.

Our final question from the United States, Jack Moore from Harpswell Capital.

Good morning, good afternoon.

I was wondering if you could give a little bit more color on cost inflation upstream with respect to any either regions or particular segments that you see prices rising at a rate higher than what you anticipated.

And then secondly, I was wondering if you could comment on BP's appetite for more significant M&A, perhaps upstream or integrated oil.

Okay, Jack.

Let's go first to Andy on cost inflation.

Then I'll do the M&A question.

Yes, John.

I'd actually, this is a sort of self-evident point.

But I would say that clearly we're seeing the most cost inflation in areas where there is the most shortage of supply.

I think in particular in deep water, you pick out a couple of areas, subsea construction as we start to expand globally the activities there, whether it be in Angola, whether it be in the Gulf of Mexico, we're seeing certainly supply challenges there.

The industry is responding, there's new equipment coming through and being built.

So I think pacing of activity in the right way, the right design approaches to try and get rid of some of the supply bottlenecks is key.

Certainly I would say that's probably one of the harder areas.

And we continue to see strngth I think in the deep water rigs, the fifth/sixth gen rigs.

BP is particularly well-positioned.

We have some long term contracts and we have a rollover of those.

So we are mitigated to some degree, I think, from the very high rates that others are experiencing today, and taking a long-term view of that market has helped.

If I pick out a couple of areas for ourselves that are probably seeing slightly stronger inflation than the number I talked about, those would be the two.

Thanks, Andy.

Jack, I think on M&A, major M&A is not on our agenda today.

I think we've got plenty on our plate to get what we've got running properly.

And frankly, we struggle to see value in the things that we may have looked at.

What I would say, I think that small scale M&A expanding our existing footprint or creating new opportunities for the future is very much on our agenda.

And we will continue to pursue those sort of opportunities as appropriate.

Great, Good answer.

And congratulations on a good half.

Thank you.

The very last question comes from David Kline of ABN Amro.

Thank you.

I believe that Mr.

Hayward made remarks about demand destruction in the OECD at a press conference this morning.

I wonder if you could just share your thoughts on that subject with us.

It's varying by markte.

It is, of course, our experience which is very much an OECD experience.

And we're seeing between 5% and 10%, typically around 5%.

I don't know whether Iain wants to add anything by way of regional flavor.

Thanks.

Yes.

As Tony says, we've been seeing 5% to 10%.

In most of the markets, the big markets we're in, it's been around 4% to 5%.

That's true in the US, it's true in Germany.

We've seen slightly lower volumes than that in the UK.

Generally in OECD we're seeing volumes down.

By contrast, and I admit we're not significantly in the non OECD markets, but firstly, where we are, in Australasia, we're seeing quite strong demand.

But that's actually driven by the mining sector as a large sucking noise is heard from China.

And in terms of China and India themselves, my data says that gasoline and diesel demand is running at about 5% to 10%, up on last year.

Probably nearer to 10%.

So when you take 10% in non OECD and you take 5% down in OECD, and recognizing that although non OECD is only about 35 million a day of oil demand out of the 85, or whatever, it's a net increase despite these dramatic reductions in the OECD.

So the world continues to be tight product, it's mainly driven by diesel.

But we are seeing demand distruction in the OECD in the main.

Thanks, Iain.

And I think we're now going to draw it to a close, ladies and gentlemen.

I just want to make a couple of remarks.

I believe that BP's very much on track with the plan that we laid out in February.

We have strong operating momentum across all of our businesses.

And we look forward to giving you a further update in the third quarter.

In the meantime, I'd like to wish you all a very safe and happy summer break.

Thank you all very much.