英國石油 (BP) 2012 Q2 法說會逐字稿

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

I now hand over to Jessica Mitchell, Head of Investor Relations.

Hello and welcome to BP's second-quarter 2012 results webcast and conference call.

I'm Jessica Mitchell, BP's Head of Investor Relations.

And joining me today are Bob Dudley, our Group Chief Executive, and Brian Gilvary, our Chief Financial Officer.

Before we start, I'd like to draw your attention to our cautionary statement.

During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations.

Actual results and outcomes could differ materially due to factors that we note on this slide and in our UK and SEC filings.

Please refer to our annual report, stock exchange announcement, and SEC filings for more details.

These documents are available on our website.

Thank you.

And now over to Bob.

Thank you, Jess.

Our call today proves that not everything in London stops for the Olympics.

We are operating our everyday business as usual around the world.

As well as embracing our role as the official oil and gas partner of the games.

Our results at first glance are weak for the period.

There are specific reasons for this.

Trading conditions have been particularly volatile, resulting in lower oil prices and lower contribution from US gas.

The sharp decline in oil prices has also led to some unusually large duty lag and ForEx effects in TNK-BP.

And adverse pricing of feedstock into our US refineries.

Added to this is the impact of the large planned maintenance program we have undertaken during the quarter in the Gulf of Mexico, which is part of enhancing safety and reliability for the future.

Brian will provide details in a moment.

While I am not satisfied with the 2Q results, we are in the midst of a major transformation, which will take some time.

As we deliver this transformation, we are committed to generating sustainable efficiencies in our operations.

Looking beyond the quarter we continue to transform the Company.

And I want to give you a sense of that progress today.

We are working to resolve a number of significant uncertainties, of which you will be keenly aware of.

And we continue to implement the important longer-term strategic priorities that do not show up in today's quarterly results.

We are advancing our 2012 milestones and remain confident that these milestones will deliver underlying financial performance momentum towards the mid-term goals we have set out in our 10-point plan of what you can expect and what you can measure for 2014.

Our agenda will start with Brian taking you through the second-quarter results.

I will then give you an update on the legal proceedings in the US.

Take a few moments to share some thoughts about our recently-announced intentions for TNK-BP.

And also bring you up to date on developments in India.

We will then look at specifics around how we are doing with our 10-point plan.

After that, there will be time for Q&A.

But first, over to Brian.

Thanks, Bob.

As Bob noted, our earnings for this quarter have been impacted by falling oil prices, the pricing of crude into our US refineries, in addition to upstream turnaround in the Gulf of Mexico.

All of which I will provide more detail on.

I'd like to start with a broader environmental context that underpins some of the larger movements in the quarter.

Data Brent declined sharply throughout the quarter on the back of a variety of factors.

On average, Data Brent was around $9 per barrel lower than the first quarter.

But it is a rapid decline from a peak of around $126 a barrel at the start of the quarter, to a low point of below $90 per barrel at the end of the quarter that has had a marked effect on our results.

Reducing realizations in the upstream but also creating particularly large duty lag effects in TNK-BP.

This effect has also had an adverse impact on crude pricing into our US refinery system.

In the United States, Henry Hub prices reached 10-year lows below $2 per Mcf during the second quarter, as warm winter weather, continued production growth and the high inventories forced gas to compete aggressively with coal for power sector demand.

This has continued to weigh on contributions from our North American gas business.

Outside the United States, gas prices have been held up by the continuing strong demand for LNG in Asia.

Refining margins, on the other hand, have continued to improve during 2012 as refinery run cuts and closures offset weakening demand growth.

Turning to an overview of the second quarter financials, BP's second-quarter underlying replacement cost profit, after interest and tax, was $3.7 billion, down 35% on the same period a year ago, and 23% lower than the first quarter of 2012.

Group underlying replacement cost profit for the quarter benefited by $460 million, from the consolidation adjustment for unrealized profit in inventory, reversing the loss reported in the first quarter.

Our second-quarter headline replacement cost profit includes a pretax nonoperating charge of $5 billion.

Which includes impairments of $4.8 billion, of which $2.7 billion were in the downstream, relating to the global refining portfolio predominantly in the United States.

And $2.1 billion in the upstream relating to US shale gas assets and the decision to suspend the Liberty project in Alaska.

The underlying effective tax rate for the second quarter was 34%, the same as for the second quarter of 2011.

Guidance for the full-year effective tax rate remains in the range of 34% to 36%.

Second-quarter operating cash flow was $4.4 billion, including $1.7 billion of post-tax Gulf of Mexico oil spill expenses, of which $1.25 billion represents the payments into the trust fund.

In upstream, the underlying second-quarter replacement cost profit before interest and tax was $4.4 billion, compared with $6.3 billion a year ago and $6.3 billion in the first quarter.

The result versus a year ago largely reflects a weaker price environment, with Brent training on average around $9 per barrel lower than a year ago.

And Henry Hub trading on an average $2 your lower than a year ago.

The softness in Henry Hub has reached the point where our North American gas business is operating at a loss.

Production was 7.4% lower than a year ago, primarily due to divestments and off-line production in the Gulf of Mexico.

Underlying volumes excluding TNK-BP, and after adjusting for divestments and entitlement effects in our production sharing agreements, reduced by around 2.7% year on year.

Costs also increased year on year, including higher DD&A as we indicated earlier in the year, and the ongoing impact of sector inflation.

Compared to the first quarter, our second-quarter result is $1.9 billion lower.

Just over half of this related to the reduction in volumes concentrated in high-margin areas.

With the balance relating mostly to weaker price environments.

Costs also increased slightly, primarily related to maintenance.

As we signaled at the time of our first-quarter results, the second quarter brings the onset of seasonal maintenance and turnarounds, which are typically concentrated in the Gulf of Mexico.

During the second quarter, we lost an average of 86,000 barrels of oil equivalent per day of production in this region.

There were a number of programs carried out on BP-operated facilities, as well as on facilities operated by others.

The most significant event was the complete replacement of the facilities on the seabed at Atlantis, which resulted in a shutdown of facility for the entire quarter.

Tropical storm Debby at the end of the quarter also contributed to the drop in production.

During the third quarter, we will bring both Mad Dog, after 15-month shutdown, and Atlantis back online.

Looking ahead, we expect third-quarter reported production to be slightly lower in 2Q.

Although we are seeing the restart of the facilities in the Gulf of Mexico, we are now beginning the turnaround season for the North Sea, also a high-margin region.

In addition, there are other planned activities in 3Q that will impact production to a lesser extent.

In aggregate, our top four high-margin areas will be slightly down in 3Q relative to Q2 production.

Finally, 3Q production will be impacted by the continued effects of the divestment program as we reshape the portfolio.

We expect production to rise in the fourth quarter, as we come out of the summer maintenance season and see the benefits of the continued ramp up of our major project startups.

Turning to TNK-BP.

BP's share of TNK-BP underlying net income was $450 million in the second quarter.

58% lower than a year ago and 61% lower than the previous quarter.

The result reflects a reduction in net income for the quarter, driven primarily by the drop in Urals crude prices.

Additionally, net income was reduced by the lagging effect of the export duty, which has a disproportionate effect in periods of falling prices.

This duty lag is unusually large in the second quarter.

Russia's crude oil and products export duty is linked to the tax reference price, which is set two weeks prior to the start of the month based on the average Urals price for the preceding 30 days.

So when prices fall quickly, as they did in 2Q, the export duty is relatively high.

We have seen this effect in past quarters, when the Urals price dropped significantly below the tax reference price, but not to this extent.

In addition, the weakening of the Russian ruble relative to the US dollar in the second quarter, which is typically correlated to the decrease in oil prices, results in a foreign exchange effect on deferred taxes.

Taken together, the price, duty lag and ForEx elements had an adverse impact of around $700 million on BP's second-quarter share of net income compared to the first quarter of 2012.

At current Urals prices, we would expect 3Q net income to show some positive reversal of the duty lag.

TNK-BP operation performance remains strong.

BP's share of TNK-BP production in the second quarter at 1.02 million barrels of oil equivalent per day was around 4% higher than the same period last year.

No dividend was paid by TNK-BP in the second quarter.

Now, turning to the downstream.

Underlying replacement cost profit was $1.1 billion for the quarter, compared with $1.4 billion a year ago, and $900 million last quarter.

The fuels business delivered an underlying replacement cost profit of $800 million, higher than both the same quarter last year and the first quarter of 2012.

Compared with the same period last year, the result benefited from the higher refining environment and continued strong refining feedstock optimization in the United States Midwest.

This was, however, largely offset by the adverse impact of prior month pricing of barrels into our US refining system.

We commit to purchasing crude before we take it into inventory based on the prior month's pricing.

Which, in a time of rapidly falling crude prices, typically results in a negative contribution, negative foreign exchange effects and a weak supply in trading contributions, leading to a loss in the first half of 2012.

Looking ahead, we expect refining margins in the second half to decline in line with seasonal trends.

And the level of turnaround activity to be lower than in the second quarter.

In addition, in the fourth quarter of 2012, we expect to commence and complete during the first half of 2013 a transitional outage to substantially reconfigure the largest of three crude units in our Whiting refinery as part of our major project to upgrade refinery in time for its expected start up in the second half of 2013.

The lubricants business delivered an underlying replacement cost profit of $320 million compared with $370 million in the same period last year.

It continued to deliver resilient profitability, both year on year and compared with last quarter, despite weaker demand, higher base oil prices and adverse foreign exchange effects.

The petrochemicals business delivered an underlying replacement cost profit of $30 million compared with $270 million in the same period last year.

This is driven by weak aromatics margins resulting from growing capacity and subdued demand.

Looking ahead, we expect the weak margin environment to continue for the remainder of 2012 in our petrochemical business.

In other business and corporate, we reported a pretax underlying replacement cost charge before interest and tax of $540 million for the second quarter.

Which is in line with the guidance given in February for an underlying quarterly charge averaging around $500 million per quarter for the year.

The increase in the charge relative to last quarter and the same period last year is mainly due to foreign exchange effects.

Next, I would like to provide you with an update on the costs and provisions associated with the Gulf of Mexico oil spill.

The second-quarter charge has been increased by some $850 million to reflect an increase in the provision for various costs and litigation relating to the Gulf of Mexico oil spill.

This brings the total cumulative net charge for the incident to date to $38 billion.

Pretax BP cash outflow relating to the oil spill costs and the $20 billion trust fund for the quarter was $1.7 billion.

At the end of the second quarter, the cash balances in the trust and the qualified settlement funds amounted to $10.1 billion, with $17.9 billion contributed in and $7.8 billion paid out.

As we indicated in previous quarters, we continue to believe that BP was not grossly negligent and we have taken the charge against income on that basis.

Turning to our divestment program, in the second quarter, we announced agreements to sell our interests in the Jonah and Pinedale upstream operations in Wyoming, for $1 billion.

And our interest in the Alba and Britannia fields in the UK North Sea for $280 million.

Announced divestments now stand at $24 billion since the start of 2010.

Of which $22.5 billion have been completed.

With agreements in place for a further $1.7 billion at the end of the quarter.

We will continue to focus our portfolio through divestments with a further $14 billion targeted between now and the end of next year.

Moving now to cash flow.

This slide compares our sources and uses of cash in the first and second half of 2011 and 2012.

Operating cash flow in the first half was $7.8 billion, of which $4.4 billion was generated in the second quarter.

After excluding Gulf of Mexico oil spill-related expenditures of $2.9 billion, underlying operating cash flow in the first half of the year was $10.6 billion.

We received $3.2 billion of divestment proceeds during the first half, $1.9 billion in the second quarter.

Organic capital expenditure in the first half was $10.6 billion, and $5.3 billion in the second quarter.

Operating cash flow for the first half reflects around $3 billion net working capital build, no dividend from TNK-BP in the second quarter, and the absence of high-margin barrels due to our second-quarter maintenance program.

At the end of the second quarter, net debt was $31.7 billion.

And gearing is 21.9% compared to 20.7% at the end of the first quarter.

This is in part due to a small increase in net debt, but primarily driven by the impact on equity of the impairments taken in the quarter.

As we deliver the next tranche of divestments, we expect gearing to reduce.

And as noted in February, with uncertainties remain, we are targeting gearing in the lower half of the 10% to 20% range over time.

Our intention remains to meet all of our US obligations, generate sufficient cash to both grow distribution for our shareholders over time as the circumstances of the firm improve, and invest to build our portfolio.

Before handing you back to Bob I would like to update you on our guidance for 2012.

Organic capital expenditure in the first half of 2012 was $10.6 billion.

And we expect the full year to be around $22 billion, in line with the guidance we gave you in February.

In February we told you the full-year depreciation, depletion and amortization for 2012 will be around $1 billion higher than in 2011.

We now expect it to be around $1.4 billion higher than 2011, with the revision mainly due to higher decommissioning costs.

We continue to expect full-year underlying production in 2012 to be broadly flat for 2011, excluding TNK-BP.

Reported production for the full year is expected to be lower than 2011 due to the impact of divestments, which we continue to estimate around 120,000 barrels of oil equivalent per day.

The actual outcomes will depend on the exact timing of divestments and project startups, OPEC quotas and the impact of the oil price on production-sharing agreements.

As I previously mentioned, guidance for the full-year effective tax rate remains in the range of 34% to 36%.

And in the third quarter, we expect a one-off charge of around $250 million to $300 million related to further changes to the UK taxation of North Sea production.

With that, let me hand you back to Bob.

Thank you, Brian.

Following that outline of the second-quarter results, I would now like to turn our attention to the longer-term.

And the work to reset the Company and create the platform to grow value for shareholders.

I will start with updating you on our efforts to resolve two significant uncertainties.

That's related to legal proceedings in the US and that related to our interests in TNK-BP in Russia.

We're also approaching the first anniversary of our alliance in India with Reliance industries.

So this is a good moment to pause briefly and update you on developments there before covering progress with our 10-point plan.

In the US, by the end of the second quarter, we had paid a total of $8.8 billion to meet individual and business claims and government payments.

Nearly $18 billion has been paid into the trust fund as of the end of the second quarter, with the final payments to complete the $20 billion funding scheduled for the fourth quarter this year.

As we announced at 1Q, we have reached definitive and fully documented agreements with the plaintiffs' steering committee to resolve the substantial majority of eligible private, economic and medical claims stemming from the Deepwater Horizon incident.

On May 2 this year, the court gave preliminary approval to the proposed economic and medical settlements.

And scheduled a fairness hearing for November 8 to determine whether to grant final approval of the settlements.

We estimate the cost of the settlement to be paid from the trust fund to be around $7.8 billion.

Further to these agreements, the court has scheduled a new trial date of the 14th of January, 2013, for the remaining proceedings under MDL-2179.

In MDL-2185, in Houston, the court has granted BP's motion to dismiss the dividend class action.

And the trial date for other claims is not set yet.

We have said all along that we are willing to settle if we can do so on fair and reasonable terms.

And this remains our position.

As anticipated, this is attracting considerable media attention.

But that is not the place to focus our energy.

And our commitment remains to update you as and when appropriate.

We've also been working to resolve uncertainties in Russia.

TNK-BP has been a very successful venture for both sets of shareholders and for the Russian government, despite periodic volatility.

The venture is almost 10 years old now and BP has been working hard to try to define a long-term solution that will bring clarity to the situation for all parties.

So far we have not been able to find such a solution.

Having received unsolicited indications of interest regarding a potential acquisition of our shares in TNK-BP, we notified Alfa Access-Renova on the 1st of June of our intent to sell, as required by our shareholders agreement.

On the 18th of July, Alfa Access-Renova notified us of their intention to enter into negotiations for the acquisition of BP's equity in TNK-BP.

We followed this notification with a statement indicating that BP would enter into a 90-day period of good faith negotiations of Alfa Access-Renova, as required by the TNK-BP shareholder agreement.

BP has also since announced that it will begin negotiations with Rosneft and any other interested parties in parallel.

There is, of course, no guarantee a sale will be completed as a result of this process.

The process itself could take several months, during which we will be bound by confidentiality agreements.

And we will adhere to the agreements methodically.

So we will provide additional information if and when we can.

This notification does not mean that we intend to leave Russia.

We have a long and successful history there.

And we continue to support many activities, including technology, educational and cultural initiatives.

And we'll continue to do so in the future.

BP hopes to continue to play a role in Russia's energy sector for many decades to come.

In India, our new strategic alliance with Reliance Industries has provided BP with a 30% share in this significant East Coast Krishna Godavari and Mahanadi Basins.

And also includes a 50-50 gas marketing joint venture.

This positions BP as the only IOC in the gas value chain in India.

And a potentially huge gas market, expected to grow at around 5% per year.

12 months on, our technical assessments continue to support strong resource potential to BP.

To date, we have booked only the remaining approved and developed reserves in the KG-D6 producing fields.

And all partners now share a comparable technical view of these existing fields.

We see the potential to increase these proven reserves through effective base production management.

We have deep operating experience in this arena.

And it is central to why we're involved in the alliance.

We maintain a view of D6 as a golden block.

It currently produces around 1.1 billion cubic feet per day gross, from around only 350 square kilometers of the approximately 7,500 square kilometers in the block.

In addition to the already-producing fields of D1, D3 and D26, there are 10 other discoveries within KG-D6.

Reliance as operator is currently performing seabed surveys so that development of this 5-plus TCF of already-discovered gas can begin.

In 2013 we expect to sanction and begin developing the satellites and R series with any AD-C25 projects beyond that.

We also expect to restart the exploration program in 2013 and are aiming to sanction a new floating storage and re-gas facility in the first half of the year to import LNG into energy-hungry India.

We're also looking for a review of pricing terms.

The current KG-D6 gas price of $4.20 per MMBtu is fixed until April 2014.

Today imported spot LNG is around $16.

Recognizing that a transparent arms-length and competitive pricing framework is essential for India to enhance exploration and production activity, and develop its own energy security, we see considerable potential for a more market-linked pricing regime to be in place post-2014.

In summary, we see three very clear sources of value.

Firstly, from the substantial medium-term opportunities for developing the already discovered gas.

Secondly from finding new oil and gas for the restart of exploration activities.

And thirdly from establishing our gas marketing joint venture in one of the fastest-growing markets in the world.

So progress is being made on a number of important fronts.

But we're also focusing on the core of BP.

Which brings me to our 10-point plan.

In October last year we laid out a roadmap through 2014 for growing value.

Five things you can expect from BP and five things you can measure.

By now you are familiar with this framework.

With our intention to play to our strengths.

With our drive to be safer, stronger, simpler, more standardized.

And with the way we intend to grow value from a portfolio of the right size.

We expect this to generate the operating cash flow to both invest in a reloaded pipeline of projects and exploration prospects.

And to grow distributions to shareholders, as Brian described.

In February, we said 2012 would be a year of milestones as we increase investment activity.

And that 2013 and 2014 would bring financial momentum.

So that by 2014, you can expect an increase of around 50% in operating cash flow based on an oil price assumption of $100 a barrel.

About half from ending Gulf of Mexico trust fund payments and around half from operations.

So let me update you on our progress.

We're playing to our strengths in exploration, and activity is ramping up.

We continue a strong run of new access in core areas.

This map shows how the continents of South America and Africa reconstruct in the geologic past.

And provides the context for plays on both sides of the Atlantic where we have been increasing our participation.

As far in 2012, we have entered into new positions in Namibia and have been awarded three new offshore blocks in Uruguay, subject to government approval.

And we have increased our acreage in the equatorial margin plays of deepwater Brazil, together with Petrobras.

Extensive seismic acquisition and exploration drilling are underway in Angola and Namibia.

We aim to increase activities in these exciting new plays in coming years.

In the Gulf of Mexico, we acquired 43 new leases in June 2012 in a lease-sale, which will be awarded subject to regulatory review.

And in North Africa, we have lifted Libya's force majeure, a first step towards reinstating exploration activity, both offshore and onshore.

We have also added to our growing North America liquids-rich shale position with entry into the Utica shale formation in Ohio.

And we expect to complete around nine exploration wells this year, including wells in Angola, Brazil, the North sea, and Namibia.

This is part of a clear plan to test 15 new plays in the next four years.

At the same time we're moving ahead with our planned program of divestments.

Our focus is on value, not volume, with a simple objective to own assets where we have distinctive capabilities and the potential to grow returns.

At the same time, this process improves the balance of risk in our portfolio, as we reduce our footprint in areas that are non-core but carry higher operational risks.

As Brian said, in the near term, our intention remains to divest $38 billion of assets by the end of 2013.

To date we have announced $24 billion against this program, representing some 8% of our reserves and 8% of our production.

Brian has already updated you on our recent transactions.

And we continue to pursue a wide range of options to complete this program.

Progress continues to be made with the planned divestment of two US refineries and some associated marketing assets.

We are in advanced discussions on both assets and it remains our expectation to announce both of these deals by the end of the year.

And we are also currently marketing certain non strategic assets in the Gulf of Mexico, as previously announced.

Longer-term we will continue to actively manage our portfolio as we reshape, resize and strengthen the portfolio to grow value.

This includes continuing to actively divest to drive quality and reduce risk.

But could also include acquiring selectively for strategic advantage.

So let's look in more detail at the progress being made towards our operating cash flow objective.

We have a number of significant milestones in sight to deliver our planned increase in operating cash flow by 2014.

Our pipeline of 15 new projects planned for startup by the end of 2014 is a significant driver of this cash flow growth.

These are world-class projects focused on our highest margin production areas.

With around twice the average unit operating cash margin of our 2011 portfolio at a $100 per barrel oil price.

In the second quarter we have seen the startup of Galapagos in the Gulf of Mexico.

And Clochas Mavacola in Angola.

And we remain on track to start up six projects this year.

The pipeline is also robust for the longer-term.

Over 10 major project FIDs are expected through the period to 2014.

We are increasing investment in our core growth engines of deepwater, gas value chains and giant fields.

As outlined in February, we anticipate that deepwater, with its conventional stronger returns, will remain a core building block at least through the end of this decade.

But complemented by a measured increase in unconventional projects.

Providing a base load of longer-lived cash flows.

Turning to the Gulf of Mexico.

In 2Q we continued to complete the necessary integrity work to support a long-term leadership position in this world-class basin.

And to reinforce the Gulf of Mexico as a platform for future growth.

As mentioned by Brian, we have completed major turnaround at Mad Dog and Atlantis.

We're progressing the planned divestments of our interests in Marlin, Horn Mountain, Holstein, Ram Powell, and the Diana Hoover fields to really focus our Gulf of Mexico footprint.

These are essential foundations of a strategy to increasingly focus our production and development activity in our four major production key hubs in the Gulf.

While working to unlock the exploration potential of our leading leasehold position.

And we're marching forward on drilling and projects.

We now have six rigs operational with the startup of the West Capricorn rig in July.

We plan to have eight rigs in place by the end of the year.

Two of these rigs are currently working on production activities, two are drilling appraisal wells, and two are working on plug and abandonment activity.

By the end of the first quarter next year, we expect to have six deepwater rigs engaged in production-enhancing activity.

In particular, this activity will focus on restoring production on Thunder Horse and Atlantis as we work to offset the decline from the reduced drilling over the last two years.

On projects in 2Q, we had the start up of Galapagos.

BP's first subsea tie back to Na Kika, which is expected to add around 25,000 barrels per day net at its peak.

In 2013, we will start up Na Kika Phase III, a two-well subsea expansion of Na Kika.

In exploration I've already mentioned our participation in the June lease sale.

And we continue to appraise and test our Paleogene portfolio through the drilling of Kaskida.

And expect to spud an appraisal well on the Moccasin discovery in 3Q.

We also expect Gila exploration and Tiber appraisal to start in 2013.

This is a multi-year journey.

Looking out to 2014, after the divestments, and with the return to an appropriate level of activity, we expect to see a return to underlying volume growth.

But the rate of growth will depend on the actual pace of the drilling activities and the reservoir performance so the timing of the ramp-up is difficult to predict.

But I am confident in the long-term future of our position in the Gulf of Mexico.

So, as noted in February, there are four key drivers of the planned increase of around 50% in operating cash flow by 2014.

Payments into the trust fund are expected to end in 4Q.

This approach is half of the expected increase.

And as you have just seen, we are marching on to deliver our new projects and restoring high-value production.

Construction of the Whiting refinery modernization project remains on track to come onstream in the second half of 2013.

This has the ability to generate significant additional cash flow from a modernized refinery capable of processing over 80% lower cost heavy crudes.

So in a $100 a barrel world, the expectation of an increase in operating cash flow by 2014 remains strongly supported by the progress being made.

To summarize, the quarter has been challenging.

But we will move ahead on multiple fronts and our eyes do remain firmly on the goals we have set out.

We are a company going through a major transformation.

Safety is our continuing priority.

And our extensive turnaround and maintenance program is an investment in building a safe and reliable platform for the future.

We are working hard to reduce uncertainty and you are well aware what the large ones are.

And in the meantime we have line of sight on a number of significant milestones in 2012 and beyond.

We remain confident in the financial momentum you can expect to see coming through to 2014.

And our ability to deliver our objective of growing operating cash flow by 50% by 2014 at $100 per barrel.

All of this will enable us to make investment to grow our reshaped and reloaded portfolio.

While also growing distributions for shareholders in line with the improving circumstances of the firm.

I am determined that we will deliver long-term sustainable value for shareholders.

Today's quarterly results are one part of the story reflecting one, 90-day window.

But I would ask you to take a look at the really important story of what we're doing for the long-term in our portfolio, in our investments, in our developments, and in our workforce, to build a company of sustainable quality for many years to come.

That concludes my remarks.

And now, Brian, Jess and I will be happy to take your questions.

(Operator Instructions) Jon Rigby, UBS.

Can I ask two questions?

The first is, can we just go back to what's going on in the Gulf of Mexico?

And perhaps could you talk a little more about the actual work that you're doing?

I raised my eyebrows when you said you'd replace the entire subsea systems at Atlantis.

I think maybe I was mistaken.

I was under the impression that most of the turnaround was work that was prompted in the broad fashion from Macondo and just a check over the continuing integrity of the assets that were there.

But it seems to be wider than that.

If you could talk a little bit more about that.

And then perhaps what the implications are for those pieces of infrastructure going forward.

Will they return back to something like the production capability that they had?

And then the second question just on TNK, I note the comments and everything about the dividend.

Can you say how the original agreement, which I think had a fixed payout ratio agreed between two parties plays into the fact that you apparently can't get agreements on the board on a specific payout?

Is there a separate mechanism that ensures some form of clearing of cash back to the two stakeholders?

Thanks.

Jon, this is Bob.

First taking your question about the Gulf of Mexico, on Atlantis and I'm sure that the scope of that, where the Atlantis field had been brought down from a planned 132 days.

And is in fact probably going to come on within the next couple of weeks at something around 120, 125 days.

We did, in fact, remove the entire subsea infrastructure and manifolds and brought them up and have replaced them.

It was a decision that was made five years ago to bring forward the economics of the Atlantis field and put them down there knowing there was a design line for five years at the time.

We and our partners had made that decision.

And I think if there is a relationship to Macondo, it was that we decided not to extend and go beyond the design life that was put in at that time.

That system will be down and will be able to handle the volumes that we had before, and it will have some additional flexibility in fact to do more tiebacks in the future.

In fact, we will, later this year, be looking at an additional tieback to the Atlantic system.

So that is not something that you can draw a bigger conclusion about the state of the assets.

But you'll know that the second quarter every year is our heavy turnaround season in the Gulf of Mexico, and the North sea is usually the third quarter.

So no other bigger conclusions to draw from that, Jon, except it will be good for us to get the Atlantis field back on and operating.

On TNK, Brian is here with me, he's on the board.

But we do have terms under our shareholders agreement, which we've talked about many times, that 40% of the net income is available for dividends.

Unless there is a concern with the liquidity of the firm.

What I would say is, we knew that our shareholders were, our partners in the venture were likely to -- they did, in fact, say no at a meeting we had about 10 or 12 days ago.

They just decided to wait to put a press release out the day of our earnings.

So it was really nothing new for us.

We did the right thing with our shareholders in requesting that dividend.

Those terms are in place and if we need to pursue, we could take them to arbitration on that but we don't see any need to do that.

And I think that's all I'll say there.

Okay.

Martijn Rats, Morgan Stanley.

Three short ones.

You reiterated a request for only the 50% growth in operating cash flow.

But I was wondering if the sale of TNK-BP actually goes ahead, whether that target still stands?

I thought perhaps you could soften the turf a little bit given that this was under discussion.

The second question I wanted to ask you is whether there's any result from drilling Block 26 offshore Angola.

That seems a very interesting prospect.

So if there is anything, any new news on that, I'd be quite interested in that.

And finally, with regards to the impairment of shale gas assets in the United States, can you give us an update on what gas price you're now assuming in the long run?

Thanks, Martijn.

So let me take the first question.

In terms of the targets we've laid out, actually TNK won't have an impact on that.

The dividends that we took out in 2011 were $3.7 billion.

And we were not assuming that level of dividend in our 2014 projections.

In fact, we are expecting something more like the 40% of earnings since the dividends that we took out in 2011 were quite high.

So the 50% cash flow is still underpinned and that won't be an issue going forward.

Martijn, on Block 26 in Angola, that's a well that we participate in with Petrobras.

It is a -- you'll know this expression -- it's a tight hole.

That well has been down.

We're evaluating results, determining whether or not it's the right thing to do a drillstem test on right now.

But those results are not public.

And third, on the US gas prices, we don't normally give our internal gas prices out.

But I would say we have rebased our business in North America to be able to be operates under $4 an Mcf to be profitable.

This has been a particularly brutal quarter in terms of low gas prices, hitting a low of $1.94.

We have rebased our portfolio to move out of the dry gases, on the Fayetteville, for example, moving to the wet gases in the Eagle Ford.

And I think we've taken a number of rigs down.

We're not a company that needs to drill to hold onto acreage.

So by the end of 2011, we hit 12 rigs running in North America.

By the end of August will be down to 7. And I would expect by the first of January, at these kind of prices, we'll be down to 5 rigs.

We still think it's a very significant resource space but we'll be focusing on the wet gas.

All right.

That's very helpful.

Thank you.

Robert Kessler, from Tudor Pickering.

Bob and Brian, clearly the cash flow from operations in the second quarter was below plan.

You cited a number of factors influencing earnings.

I'm wondering if you can quantify what a normalized ex one-off cash flow from operations would have been in the second quarter if you were on plan?

Not to give you a specific number -- I would broadly, I think some of the calculations that were done on our cash flows or our earnings used an overall cash flow number realization for our portfolio using the entire portfolio.

And missed the fact that we had so many high-margin barrels down planned, and down in the Gulf of Mexico.

Brian?

Maybe just to add a flavor.

Something like $1.1 billion of cash was missing associated with the volumes that we took down in 2Q versus 1Q.

And about $0.5 billion on price.

And then there were some other movements around cash costs.

But the big move was really having that volume out of service, if you look at the delta.

It's something like $1.5 billion to $2 billion.

And you also have on top of that, Robert, the $700 million move that you saw in the TNK duty lag also affect 1Q versus 2Q.

And then as you look forward to the third quarter you highlight even more significant maintenance in your four highest-margin areas.

Can you talk about whether that $1.1 billion increase is in terms of the net detriment, price being equal?

Yes.

So we'll see some ramp-up from the (inaudible) restarts, which should be coming over the next couple of weeks.

But we will be taking the North Sea down.

So net-net, you will see the high-margin production 2Q, 3Q, slightly down, is what we said, around the four big hubs.

But you will start to see that ramp back up in fourth quarter.

The other thing that will impact cash flows, of course, the price is now recovered, both in terms of the oil price, Brent, and the natural gas price.

So there will be some upside in that but the volumes would be broadly below where we were into 2Q for those four big hubs.

Okay, thanks for that.

And a quick unrelated one for me.

US refiners, net of the impairments, can you disclose the book value of Texas City and the southern West Coast Fuels business?

No.

We don't make that available.

Even though it's held for sale?

Even though it's held for sale.

That will come up in the annual report and 20-S filing at the end of the year.

Thank you.

I would say on the $700 million for TNK-BP, as you work your models and you look at how that works, it's probably good for you to go back and look at that.

The tax reference price is set in the month before a certain month for calculations.

And what happened this quarter is the first, second and third months of the quarter successively dropped.

So that tax reference price was far above the actual realizations in Russia.

And so it's a bit unusual, but keep your eye on that in the future.

These things will partially reverse but in a time of falling oil prices it hits very hard, as it did this quarter.

And that's actually not a cash number.

It's an earnings number.

Rahim Karim, Bar Cap.

A couple of questions, if I may.

Just the first, to go back to the US gas business and just to maybe understand a little bit more about how you see production moving forward.

I know, Bob, you talked about rig rates, rigs falling to about five at the end of the year.

But with the impairments, do you now see that you can run off a higher level of activity, given that breakeven in terms of earnings will be falling with the DD&A charge reducing?

And then the second question, perhaps if you could lust quantify what the actual level of production was in the Gulf of Mexico in the second quarter.

And the impacts of some of the maintenance there?

And then finally, exploration expense seems to be running relatively high in the US this quarter.

Is there anything in particular that we should be aware of there?

We haven't actually laid out our production geographically like that.

You'll know that our barrel of oil equivalent production in North American gas would be over 300,000 BOE per day.

Our activity I think will be, in fact -- because much of the activity in North American gas has a fairly fast payback activity.

So in terms of large onshore developments.

So what we will do is be very responsive to the price environment.

Now, the pricing environment has moved up from the $1.94 low.

And I believe yesterday it closed at $3.21, so certainly there's some incentive there.

It's heading in the right direction for us to get back to work.

But we are prudently planning on keeping our activity level low.

And focusing what activity we have in the liquids side of things.

We did have a write-down on impairment US North American gas.

Primarily Fayetteville, dry gas areas.

Those of us companies who work under IFRS have taken our write-downs in accordance with IFRS.

I don't believe that is what you need to do under US GAAP.

But that's where those write-downs, exploration write-offs, would have occurred is the actual write-down for the North American gas piece, rather than a specific exploration activity.

Yes.

And on [Goleman] in particular, if you look at the stock exchange announcement on their upstream, you will see their production in the United States is down first quarter versus the second quarter by about 104,000 barrels a day.

About 86,000 barrels of that is Gulf of Mexico production.

So our net production Gulf of Mexico for the second quarter was just over 170,000 barrels a day.

Thanks.

Doug Terreson, ISI.

I have a couple questions on the downstream and specifically refining and marketing.

First I wanted to see if you could provide a little bit better functional and geographical clarity on the charge that was taken in the period.

Meaning you highlighted US and refining, I think, in the release but I want to see if there was more information.

And then, second, I wanted to see if you also could provide color into the transitional outage on the crude units to which you referred in the release.

And specifically how you expect production and mix is going to be affected in the specific quarter leading up to the midyear 2013 completion, if you have that.

Yes.

In terms of the valuation of the assets, the impairment charge we've taken is predominantly in the United States.

It's a consequence of the fact that we're marketing to refineries today.

We've gone back and reassessed what we believe to be the values of refineries.

There's a lot of refineries up for sale.

And so therefore we've taken the impairments on that basis, Doug.

We believe the carrying value now is that much less than what we had on the books.

Sorry, Doug, the second question?

You talked about a transitional outage on the crude units in the release.

And just wanted to see how you expected production and mix effects would unfold in the quarters leading up to the completion of the project around mid year 2013.

Yes.

That's pretty market sensitive information at the moment, Doug.

We'll be giving more guidance on that going forward.

A key part of the project is to upgrade the Whiting refinery.

Take the largest of the three crude units out, which is the 12 pipe still.

We are currently going through the planning of that and we'll try and give more guidance on that in some future date ahead of going into that turnaround.

Okay, great.

Thanks a lot.

Theepan Jothilingam, Nomura.

Just a follow-up question, back on the GoM, firstly.

I think you've talked about Mad Dog and Atlantis.

I just want to know, is there any further planned maintenance on Na Kika and T-horse?

And is it right to think of an inflection point in the GoM with the Q2 numbers?

Or should we think about more of an inflection point in 2013?

The second question, just on the downstream, and US refining, I just wanted to find out whether you could quantify the impact of the FX and the pricing of the barrels.

Again, forecasting the downstream is incredibly difficult, but I think that it seems like the underlying numbers have certainly deteriorated versus some very good results in 2010 and 2011.

I'm not sure if that's a fair comment or not.

And then the third question comes back to Russia.

Again, I know it's difficult to make comment on ongoing process, but you have mentioned you'll do what's right for BP shareholders.

When one thinks of a potential transaction, should we think of a straight cash deal?

Or is BP prepared to potentially take shares in Russian companies, as you proposed last year?

Or could we also think of asset swaps?

I'm trying to circle around wanting to remain in Russia but also potentially looking to sell TNK-BP.

Thank you.

Okay.

Theepan, thank you.

First, as we come out, I'll take the Gulf of Mexico and describe a trajectory here.

Certainly the second quarter we have big assets, down for the entire quarter there.

They're coming back during the third quarter.

And they will come back during the first quarter.

So 4Q we'll see much higher levels of production as we march out of this turnaround season.

We'll go back into a turnaround season next year in the second quarter again.

Some of that work will be done on Thunderhorse.

It's not the kind of work that's being done on Atlantis.

Although we are evaluating our Thunderhorse redevelopment because we see multiple additional potential around that field.

So that's an area of ongoing and active steady.

In Na Kika, we have a Phase III development project that I don't think will be affecting the production from Na Kika going forward.

But what you have done with your question is highlight where we intend to head, given the strategic divestments that we have announced and not closed yet in the Gulf of Mexico, is get down to the four very big production hubs in the Gulf.

Thunderhorse, Na Kika, Atlantis and Mad Dog.

And that will be where we drive the future of our sales in the Gulf, putting aside any paleogene success in exploration we have.

Let me turn it over to Brian.

On the downstream question, the in transit barrel effect we had in ForEx was around about $900 million impact 1Q into 2Q.

And that was negated by higher refining margins that we were seeing in terms of the overall environment.

And quite a significant amount of optimization out of the Midwest refining system given the dislocation you can see between WTI and Brent, Theepan.

Broadly, that's what happened in 2Q versus 1Q.

Of course, as prices have now started increasing again we will see some of that coming back into the third quarter.

Theepan, in Russia, for all the confidentiality agreements we've got, I can't say too much there.

But I want to say that BP remains committed to Russia.

We've been there, we have been successful.

We have initiated a process now that could lead to nothing.

There is no guarantee any transaction could follow.

In Russia there is a strategic law that limits our ownership to 50%.

There's a lot of stories about us increasing our ownership in TNK-BP.

There's no indication that those laws can be or should be circumvented in any way.

Whether the offers, as we negotiate through this period with multiple parties, we will look carefully at value.

And how we do that in terms of combinations, whether it's all cash or whether it's shares and cash, far too early to say.

But I think as shareholders of BP, they should be open to a number of different combinations there.

I think that's all I should say, Theepan.

Sorry.

Okay.

Thank you.

Irene Himona, Soc Gen.

I had a few questions, please.

The first on TNK-BP.

In all your communications, you're careful to state that there is no guarantee of a transaction.

My question is, if there is no sale, is there a plan to convert the venture to a sanctioning one so you can start paying dividends and operating normally?

My second question, on the Gulf of Mexico, if you can perhaps give us a sense of the amounts of integrity CapEx and OpEx that you incurred, let's say, year to date, and what we can expect in the rest of the year, please.

And then finally, on the US legal proceedings, the US trial date is set for January next year.

Last year in your legal seminar, you had outlined effectively a multi-year potential court case.

Of course, since then you've reached agreement on part of those claims.

Can you perhaps update us on the potential timescale should the trial start in January, given that we've got far fewer parties involved this time?

Thank you.

Great.

Okay.

Wide variety of questions there, Irene.

On TNK, there is no guarantee of a transaction, like you said.

Do we have plans otherwise?

Absolutely.

We work under a shareholders agreement.

And we don't get up out of every morning thinking about how to take on litigation.

But we certainly do have litigation paths to get the venture functioning on a number of ways.

But we have been working hard with our partners to try to reach resolution with all the partners and all the different parties and partners for some time.

We haven't been able to do that to ours and their satisfaction, which is why we've gone down the path of notification of sale.

And I think that's probably all I should say about that.

We're in this period now of a quiet period of negotiating in good faith with all parties.

And I think it's just -- Irene, I just have to say, stay tuned.

On the Gulf of Mexico, Brian?

Irene, there's no disproportionate amount of uptick in terms of maintenance integrity spend.

This is effectively the costs 1Q, 2Q, are up just over $200 million.

And that's all to do predominantly around the maintenance programs and the usual turnarounds that we have in 2Q and 3Q.

So the pattern of spend is the same as it was in 2011 and certainly 2010.

And on the Department of Justice trial, now scheduled for the 14th of January, we have moved forward with the plaintiffs' attorneys' steering committee.

We expect a fairness hearing on that around the 8th of November this year.

The Department of Justice and the trials that are planned, it's very hard for me to comment on it, Irene.

It's a possibility that that also could go on for a long time.

But as we have said all along, that we are interested and willing to settle on fair and reasonable terms.

Fair and reasonable has to be on something that protects the Company and the shareholders, as well.

And so it would just be pure speculation on my part to say anything other than there's a trial date out there and we'll see where we get to.

That's a long time from now.

Thank you.

Hootan Yazhari, Bank of America Merrill Lynch.

Two questions, if I may.

First of all, regarding the number of rigs that you'll be operating in the Gulf of Mexico by the end of the year, you allude to eight.

I just wanted to understand if that's the number that you're comfortable with or is there scope to increase that's so as to accelerate any further drilling activity in the Gulf for next year?

And the second question I had was really regarding the interplay between the sale of TNK-BP and your ongoing disposals program in the background.

To what degree have you slowed down the underlying disposals program as you see what the outcome from TNK-BP will be?

Thank you.

Okay, good.

On the Gulf of Mexico, we have the sixth rig up and running now, and by the end of the year, we'll have eight rigs in place.

The two additional ones will be working with Mad Dog and Na Kika production wells, bringing it up to eight.

What I would say is that there is an enormous amount of technical capability, rig crews attention to operating eight rigs.

In fact, the six.

I was reading today that one of our competitors was moving up to five and didn't intend to go beyond that because of technical capability and people being the limiting factor.

And I think for us, eight rigs, going from zero last year up to eight, is about as far as we want to go, to be able to maintain the attention and the technical rigor with this.

And we've never had eight rigs running in the Gulf of Mexico before.

We have two rigs that are currently working on production enhancing activities, such as workovers or recompleting wells.

And by the end of the second quarter next year we'll have six that are working on those production activities out of the eight.

Could go above eight?

We have talked about it.

We have talked and considered going up to a ninth rig next year.

But we have not made that decision yet.

And now, on the sale of TNK-BP, how much has it impacted our divestment program.

I would say that we are going to be systematic and careful and cautious at what is the market around the divestment of assets for us.

We were, of course, in 2010 and part of 2011 in a position where we needed to sell things to make sure we could stabilize the Company.

We're way beyond that now.

So there's just a lot of care being taken.

And I would say the TNK-BP potential divestment hasn't really changed the pace of activity.

Understood.

Thank you very much.

Pavel Molchanov, Raymond James.

Another one on the TNK-BP potential sale.

If there is a successful transaction, what would be your priorities for using the cash that you would receive associated with that?

Pavel, it's Brian.

Gilvary.

Effectively we have three options and the board will consider all of those options.

The first one would be to pay, effectively deleverage the Company, in terms of bringing gearing down.

We could also look at any potential distributions to shareholders.

And the third piece is that would also give us potential, assuming the transaction gets done, money which could be invested elsewhere in the portfolio.

And they're the three options that we will consider, and we will consider that with the board and bring the proposal back to our shareholders.

Okay.

Another one on TNK-BP.

The ruling last week by the Siberian court in relation to $3.1 billion in damages, can you give your thoughts on the ruling and what your expectations might be for the appeals process?

This is a case that we went through the courts last year and was tossed out and reentered and emerged again.

We're a minority shareholder that holds 0.00001% of TNK-BP's brought forward a damage claim.

Rosneft [and sales] have said that there were never any intention to invite TNK-BP into the projects in the Arctic because they did not have that capability of working in the Arctic.

We will appeal it.

It's no surprise to me.

But we'll appeal through this process.

And you'll just have to stay tuned on that.

Any sense of the timing on that?

I don't know the timing.

I haven't got a review.

I actually don't know.

I don't think it's very quick.

But if it is quick, that's fine because the case doesn't have any merit.

Pavel, just to be clear, there is no contingent liabilities in our accounts associated with that number because we don't believe there's any credibility to it.

Appreciate it.

Oswald Clint, Bernstein.

My question on TNK is, post a solution, and assuming we get back to normal operations, and I know you've always been very interested in the offshore Arctic, Russia, is there still blocks there that are available and which are of interest to BP?

Obviously a lot of them have been awarded to some of your peers recently in the Barents Sea, the Kara Sea, the Black Sea, et cetera.

And I just want to get a sense of is there still acreage up there that's attractive to BP.

Secondly, just on the comments on ongoing sector inflation within the release, last quarter you talked about 5% to 10% in terms of those numbers.

So I just wanted to get a sense of whether that's still a valid assumption at this point in the year.

And then, finally, just smaller one on the Tangguh LNG agreement, with this LNG going more domestically.

Can you give any indication of the price being ascribed to that LNG?

Is it the same as your existing LNG exports from Indonesia?

Thank you.

Oswald, yes, a couple things.

First, it's important to know that as we have thought about and are going down the path on a possible sale here, there's nothing that has motivated or driven the sale for any consideration of doing anything in the Arctic.

I would say that the Arctic is a very large place.

Most people estimate that the amount of Arctic prospect acreage in the northern hemisphere in the Arctic is roughly 60% of that, would be in Russian waters.

A number of the companies there have a number of blocks that they have not let out in the future.

It will take many decades to develop the Arctic.

So we haven't been thinking about it and having our eyes on it but there's a lot yet to happen in the Arctic.

Sector inflation.

We've been working in this world now for some time.

Last year was a $111 year.

So there was quite a bit of oilfield inflation.

We're seeing that now stay through, even though there's been a temporary price drop.

And we see oilfield inflation around 5% to 10% this year.

Sorry, between 10% and 15% -- it depends on where you are.

Some of the onshore trucks in the hot areas around the globe, onshore remain very prone to inflation.

We are seeing some of that inflation come off onshore in the US in the natural gas fields because, as the prices come down, some of the rates have come down.

Offshore rigs continue to be healthy cost increases.

And on Tangguh -- Tangguh came on as a project back about a decade ago.

And it came on at the absolute low point of Asian LNG prices.

And locked into some pricing.

For example, into Sempra in Mexico, south of the California border at very low prices.

We've reached agreements on the project to redirect some of those cargoes now.

And, in fact, the project was able to very much help Japan after the Fukushima disaster with something closer to world market pricing.

Indonesia itself is short of gas.

And so the idea that we can produce gas in Indonesia with a price reflecting what is relatively short transportation from Papua into Java, are the kinds of things we expect to get from the project.

And I think there's widespread agreement that that's the direction the project will be going on.

We just had meetings with the Energy Minister of Indonesia on this and moved forward the third train of that project.

And I'm very satisfied that that will be an economic good project for us.

And we're also drilling, before the end of the year, we'll know sometime in the first half of the year, another deep well in Indonesia that may be able to prove up resources for the fourth train.

Which I think the timing for that to come on in the world market would be very advantageous for us.

Thank you very much, Bob.

Jason Kenney, Santander.

Just on I think it was slide 25 where you highlighted the key projects, I think you mentioned 10 FIDs over the period to 2014.

Presumably in addition to the projects you've got on that slide.

I wondered if you could just remind us of the most significant projects that are likely to be FID'd over the next couple of years in terms of maybe value and cash flow support.

Secondly, on Namibia, I wondered if you had any pre-drill resources across your licenses there?

And the same question for the Brazil equatorial margin.

On Namibia, let me take that one first, Namibia is a very interesting prospective wildcat frontier.

Which is we and a number of other companies identified this as having potential.

We don't have pre-drill numbers yet that we would put out.

We think there's structures there.

We do think it's a little bit like Uruguay across the water where we've also taken up some acreage.

So it's very early to do that.

And let me just go through some of the big platforms and projects that we can see bringing in and FID'ing in here going forward.

Of course, a big one is Shah Deniz.

That's certainly one full field development that we're working, West Nile Delta Gas is one that we have that we have out there.

Quad 204.

We've got FIDs yet to do in Oman, Clair Ridge, Mad Dog Phase II, Pike Phase I. We've got additional series of subsea projects.

Pazflor Phase II in Angola,.

That's just a few of them there.

Block 31, additional developments in Block 31.

The Tangguh expansion is another one.

Kaskida, Tiber Gila, maybe down the road.

Those, of course, way down the road and requires much more appraisal.

What I would describe from that is a very healthy project.

Our issue going forward through the end of the next decade is having to have very careful capital discipline.

And being very careful about what we select in this set of projects.

And I would actually say I don't believe we can do them all.

So that gets back to what we've said about portfolio management.

There may be some that we don't in the end do ourselves.

Actually, Bob, I was going to follow-up with the impact of bringing these FIDs into place.

And the medium term CapEx out, obviously you go through a major maintenance and turnaround program.

I don't want you to give me a number, I don't think you will give me a number, but should we be assuming a lower level project delivery CapEx than we're seeing at the minute, as that maintenance CapEx drops off?

Or is it likely just to stay at this ground level for the medium-term outlook?

CapEx for the group this year is around $22 billion.

I've no doubt we can spend by the end of the decade easily, $30 billion a year.

We won't do that.

But I would say a gentle increase in CapEx over the period here, over the next five years, to the $24 billion to $25 billion range feels reasonable and very doable for us, ensuring that we have enough cash flow and enough free cash flow then that we can use for distribution to shareholders.

But for us to do that, we're going to either have to re-phase projects or divest some of them.

I'm fairly sure of it.

Jason, we're still committed to the targets we've set for 2014, which is 50% reinvestment, 50% for other purposes like distribution.

So those targets are still in place.

And so we're not expecting the capital appetite to increase beyond what we said to you in October and February.

Okay.

Many thanks.

Guy Baber, Simmons & Company.

I had another question on the downstream.

But I was just hoping for a little bit more detail with respect to progress on the divestment front, especially as it relates to Texas City in light of the settlement with OSHA on the majority of citations there.

Are there any other regulatory hurdles to clear?

Is there certainty around those regulatory liabilities now?

I know you stated that you're expecting to announce the sale of both Texas City and Carson before the end of the year but I'm just trying to get a sense of how the process has progressed relative to initial expectations.

And how levels of interest have been for the assets, to the extent you can comment.

And anything else you would share there.

Yes.

So you're right to say that actually getting the OSHA behind us was a big step in terms of getting Texas City ready for sale.

As Bob said earlier, both refineries are well advanced in terms of negotiations of multiple parties.

And in terms of any final transactions, of course, there will still be regulatory approval required in various jurisdictions.

But we don't see that getting in the way at the moment.

Okay.

Thanks.

And then also in North America you mentioned the transition to liquids-rich drilling.

But strategically I'm just curious as to how you assess the size of your current liquids-rich, focused on commercial footprint relative to maybe what you think is optimal for you.

Do you have the scale you think that you need?

And do you believe the Utica addition provides you adequate exposure there?

Or is this a space where you could be looking at potential acquisitions?

And how do you weight those opportunities relative to others globally?

I would say that for the liquids-rich shale, I think nobody's had enough of it.

I think everyone feels like having more liquids-rich is the right thing to do with the shales.

Leading all the way down the spectrum to oil shales.

Ours has been redirecting, step by step by step, over places like the Eagle Ford.

We have taken a sizable position of around 86,000 acres in the Utica.

We are looking to see if we might expand there.

I was just there last week.

Spoke with the governor, spoke with people to get a sense of their commitment to this industry.

I got nothing but encouragement about that, and nothing but encouragement to have BP in Ohio.

So I think that's one area that we will look at.

And then we're going to be measured and we're going to be careful about it.

Were not going to jump in too deeply but I think the Utica is one area that I think has additional promise.

Thank you.

Jason Gammel, Macquarie.

A couple on the upstream, please.

One of your partners had actually referenced delays of both PSVM and [Garve] into next year.

Appreciating your role as operator and seeing those on the startup schedule for 2012, just wanted to think about how those will affect 2012 production.

Should we be thinking of those as very late year that have no effect on really more 2013 events?

Second question, related to the renegotiation of the ADCO contract.

I believe that you've currently been excluded from that renegotiation.

Should we think about that as production, albeit very low margin production that we should be taking out of our future forecasts?

Or would you expect to potentially be re-involved in the process at some point?

Jason, thank you.

On the two projects, Garve and PSVM, they're both fourth-quarter projects.

So as you model and think about it, certainly the impact will be primarily in 2013 coming on.

I've seen and had no reviews, which suggests anything other than that they are during the fourth quarter rather than slipping into 2012.

But you're right in terms of the impact, primary impact.

On the recognition or the renegotiation of the ADCO contract in Abu Dhabi, we've been part of that concession for 75 years.

I have read this in the press, about us not being invited to participate.

I have spoken to people at multiple levels.

And it does not appear to be an issue with BP.

There seems to be some other issues here.

And so we're taking a very low response to it.

And we'll see what happens in time here.

Those of you who don't know, the ADCO contract requires capital inputs and a per barrel fee of $1 per barrel.

And we have reserves there booked through the 2014 period only up until the renegotiation.

So, Jason, I really don't know whether we will be involved with that or not.

I hope so after these many years.

But if the terms are as they are today, I think we might be less than enthusiastic about it.

So let me just leave it with that.

I'd say yes, it's possible for us to be.

I know we have not been formally excluded.

Iain Reid, Jefferies.

Brian, can I come back to the $1.1 billion you talked about difference between the first quarter and second quarter on volumes?

And if you go back to 2011, what was the corresponding numbers for 2011?

Was this quarter in a major way different to what you've seen before?

In the past, if you remember last year in 2Q and 3Q, and as Bob pointed out third quarter, third week in September, was our low point in terms of production, with having no rigs working at that point.

The issue is simply if you look at the margin associated with these barrels, last year we had Angola and Gulf of Mexico out, so there was an impact of last year.

And this year, it's been a very big impact given the initial marked uptick in the oil price.

And then now as the oil price came off.

So it's a standard effect but if you take out these margin barrels, the margin associated with these barrels is more than double the average of the portfolio.

So it's not surprising it has that sort of impact.

Okay.

Bob, a couple questions about India, going back to your update on that.

I just wondered how confident you are about the carrying value of your acquisition costs there.

One of your partners talked about reducing reserves there, recently.

I believe you just completed reservoir modeling there.

Is it possible to say what sort of increased gas price you need in order to justify the acquisition costs on India?

Iain, yes.

One of our small partners reduced their reserves on the field just recently.

I'll tell you that they reduced it down to near or at the values that we've always had for the field.

So I wouldn't read too much into their action.

Because what we have always said is we're the only IOC that has a major position in the gas value chain in India.

We are producing gas in a field that we knew the rates were going to decline.

That has a whole set of satellites around it.

It's a fixed gas price between now and April 2014 at $4.20 an Mcf.

We have been actively working in India to note that market pricing gas is what the country really needs to be able to unlock its own resources.

And I think that's heading in the right direction.

We're doing the seabed surveys.

We're starting the subsea engineering work on the satellites nearby.

There's something called the R series nearby.

And we've got additional well work now that we're putting in place in the field to arrest the decline.

But we always knew that decline was going to be there.

So that combined with the 50-50 joint venture for gas marketing where we have made proposals to bring in gas import terminals into India, which is importing gas at $16 to $17 an Mcf, we think is going to still prove to be a very good investment for us down the road here.

But any view on what gas price you need in order to justify what you paid for it?

Something higher than where we are today, I presume?

Yes.

The price was always going to be renegotiated in 2014.

So, of course.

But that's not the only reason we're in it.

We believe we're going to find more resources and the prices will be higher for the gas.

In addition we have multiple exploration blocks, as well, in the gas marketing joint venture.

It's all part of the valuation that we did initially for the project.

Just a bit of context, the domestic price that we have today is significantly, by two orders of magnitude lower than what the import parity is.

And that will all be part of the conversation around trying to renegotiate domestic price.

Yes.

As we've said to the government there, it's probably not their intention for us to develop high-cost gas in Australia and import it into India.

And that would be more economic than these low prices.

And I think they understand that.

Sounds like you can do that as well, then.

All right, thanks, guys.

Kim Fustier, Credit Suisse.

I have two questions please.

Firstly, just a quick one on Macondo.

You've increased your Macondo provision by $850 million to $38 billion.

I'm just wondering if you could provide any color or breakdown within that $850 million between different cost categories.

And, secondly, just a bit of a portfolio question.

Some of your integrated peers are considering exporting LNG from North America.

You obviously have a very large US onshore gas position which is under-earning at the moment, given $2 or $3 gas.

So I was wondering if LNG exports from North America are on your radar at all to monetize part of these resources?

Under the stock exchange announcement, you'll see in the note 2 that it's been classified as litigation of the costs associated with Macondo litigation claims and other costs.

So that's the broad bucket into which the $850 million has been put into.

And on the North American gas, Kim, you are right.

We have been looking at that.

I don't think we're in a position to go into high capital development projects to build LNG export terminals.

But being in a role with some of the brownfield sites today that are being redeveloped for export, tolling agreements to global markets that we have in place is most certainly something that we are looking at.

Joseph Tovey, Tovey & Company.

One of the great strengths of British Petroleum relative to its competitors has been its very high-quality ability in production, getting unit producing cheaply on the whole.

An area that has been not necessarily all is good in comparison has been the downstream operations, refining amongst others.

Rather wondering, with some of the changes taking place in natural gas end of the business, including the adoption, at least by a fair number of trucking companies, of natural gas as a direct fuel for their 18 wheelers, would that be one change in the industry that would give you an advantage relative to some of your competitors?

Number one.

Number two, in view of some of the changes that have already taken place, and some of the structural changes such as Marathon and ConocoPhillips getting out of the refining business, at least separating oil from production and from the refinery end, would that make sense that you sell a greater portion of your downstream than you have already been doing and have already stated?

Strategically and tactically as well as a way of generating cash that might be better placed elsewhere?

Joseph, this is Bob.

Thank you for your question.

On the first point of looking at compressed natural gas and being able to use it for transportation, this is a strategic question mark, whether this is going to evolve or not.

If these prices stay low, there will likely be a market there.

But it will probably be for the mass transportation fleets of rail and certain trucking and bussing.

But I would say for us right now, and our need to focus, that's not a direction we're heading down at the moment.

I do think that it's one of the big questions in the United States, that with low prices, what will the gas be used for.

And there's different areas of petrochemicals and certain things that we're looking at, as well.

But probably not the trucking and transportation aspect of it.

On the downstream, we have as a company reviewed -- we've actually reviewed multiple times.

And as part of an almost constant review of strategy, we do note that others out there have separated out the upstream and the downstream.

For us, the unlocking of value through that remains quite a big question mark.

And we've studied the two companies you mentioned, Marathon and ConocoPhillips.

And we haven't seen that value emerge yet.

It doesn't mean that it won't.

But for us right now, we remain very committed to an integrated model.

And the downstream generates cash.

It's very important for the group as we go forward.

Brian, do you want to add anything?

The way we've structured downstream, we've gone through a fairly big rationalization program over 10 years.

By the end of next year we'll have sold 12 refineries in 12 years.

And I think the portfolio we have today is a very good, high-quality portfolio.

We're very happy with it and we continue to invest in it.

But effectively, as Bob described it generates cash which we can then deploy in terms of dividends to our shareholders and reinvestment in the upstream around these high-margin barrels that we've been talking about.

So we're very happy with the integration of the two parts.

Let me, if I might, carry this a little bit further.

The European market is generally far more geared to trucking as a way of moving goods than, say, rail.

And there's therefore greater demand for fuel for the European truckers.

Does that change in the market signify a basic change that would make it more useful for you to be, compared to other companies, focusing on CNG or other ways, rather than on your refinery structure as it currently exists?

And by the way, not denigrating nor ignoring the massive long-term efforts that you have gone through in changing your refinery set up, I'm just thinking that the technological changes in the last year or two may have said, maybe that ought to be re-examined and accelerated a bit.

Joseph, I think the big strategic question that you see or observation out there is very real.

We have talked about this.

And given that we have so many things happening on many fronts, as a company, we have decided to focus and have decided not to go down this path.

It takes a great deal of time, talent, people, and complexity when you develop networks like that from scratch.

And we think there are probably others out there that will be able to devote that rather than us.

And in our case, we will focus on the very strong positions that we have in the Rhine Valley and in Iberia in our development of clean fuels.

And run those refineries in the marketing networks with the fuels that we have.

Thank you very much.

Appreciate the answer.

Peter Hutton, RBC.

A lot of questions already asked and answered, but two very quick ones.

Can you just give us the status on Galapagos?

You mentioned that.

How long is that going to take to ramp up?

You said relatively quickly.

And the second one on India.

I appreciate the messages on the future value of India.

Just putting this in context, though, TNK, that was agreed in 3Q '03 and within a quarter we were already seeing a breakdown in terms of volumes and profits.

When do you think we are at a stage when we might see some more visibility on the near-term operating metrics of this, which is over $7 billion, a big investment?

You asked about, Peter, Galapagos.

The tiebacks occurred in Na Kika.

It's ramping up.

We've got a couple wells on.

There will be a number of other wells that will be on.

And I expect it to be ramped up within two to three months on Galapagos.

The project has come on very smoothly so far.

And slightly ahead of the minute plan that we have with it.

On India, I think India is a long-term investment.

It's not about the near-term earnings.

We always knew that the management of the D1, D3 structure was going to be challenged.

We did not believe, if you're a reservoir engineer, the connectivity interstitial gas migration across the reservoir.

Our projections have, in fact, played out.

But we are also incredibly enthusiastic about the satellites nearby.

And even potentially deep potential below the field itself.

So I'm not sure I understood when you said by 3Q '03 there was near-term metric issues, I think you said in TNK-BP?

That's right.

From the very quarter it was agreed, BP was already breaking down some reporting.

And 15 months later in India, we don't even know what the volume is at that point.

I see.

Okay.

TNK-BP was over a 1 million barrel a day oil company.

We did break out that very differently.

We have not around the world broadly broken out the individual production of our fields and locations.

But I think in time as we move through these next year or so, you'll see us describe this.

But we've got to make some decisions here on these satellites before we get to a point of talking about them.

It's competitive, actually, and we have regulatory issues we're working through.

Thank you very much, everybody.

That concludes our call for today.

Thank you, everyone.

Good to talk with you today.

Same from Brian.

Thank you.