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Executives

Jessica Mitchell - Director of Group Investor Relations

Robert W. Dudley - Chief Executive Officer, Head of Disaster Management Unit, Executive Vice President and Executive Director

Brian Gilvary - Chief Financial Officer and Director

Analysts

Jon Rigby - UBS Investment Bank, Research Division

Martijn Rats - Morgan Stanley, Research Division

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Rahim Karim - Barclays Capital, Research Division

Douglas Terreson - ISI Group Inc., Research Division

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Irene Himona - Societe Generale Cross Asset Research

Hootan Yazhari - BofA Merrill Lynch, Research Division

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

Jason Kenney - Grupo Santander, Research Division

Guy A. Baber - Simmons & Company International, Research Division

Jason Gammel - Macquarie Research

Iain Reid - Jefferies & Company, Inc., Research Division

Kim Fustier - Crédit Suisse AG, Research Division

Joseph Tovey

Peter Hutton - RBC Capital Markets, LLC, Research Division

BP (BP) Q2 2012 Earnings Call July 31, 2012 9:00 AM ET

Operator

Welcome to the BP Presentation to the Financial Community Webcast and Conference Call. I'll now hand it over to Jessica Mitchell, Head of Investor Relations.

Jessica Mitchell

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 U.K. 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.

Robert W. Dudley

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 U.S. 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 U.S. 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. 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 midterm 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 U.S., 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.

Brian Gilvary

Thanks, Bob. As Bob noted, our earnings for this quarter have been impacted by falling oil prices, the pricing of crude into our U.S. refineries, in addition to upstream turnarounds in the Gulf of Mexico, all of which I will provide more detail on.

I'd like to start with the broader environmental context that underpin 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 the 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 largely duty lag effects in TNK-BP. This effect has also had an adverse impact on crude pricing into our U.S. refining 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 from unrealized profit in inventory, reversing the loss reported in the first quarter.

Our second quarter headline replacement cost profit includes a pretax non-operating 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 U.S. 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 trading on average around $9 per barrel lower than a year ago and Henry Hub trading at an average $2 lower than a year ago.

This softness in Henry Hub has reached a 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 offline production in the Gulf of Mexico. Underlying volumes, excluding TNK-BP and after adjusting for divestments and entitlement effects on 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 the 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 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 the 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 a 15-month shutdown, and Atlantis back online.

Looking ahead, we expect third quarter reported production to be slightly lower than 2Q. Although we have seen 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 4 high-margin areas will be slightly down in 3Q relative to 2Q 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 2 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 Q2, the export duty is relatively high. We have seen this effect in past quarters when the euros price dropped significantly below the tax reference price but not to this extent.

In addition, the weakening of the Russian ruble relative to the U.S. dollar in the second quarter, which is typically correlated to the decrease in oil prices, results in an 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 will 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 U.S. refining system. We commit to purchasing crude before take it into inventory based on the prior month's pricing, which in the time of rapidly falling crude prices typically results in a negative contribution. Negative foreign exchange effects and a weak supply in trading contribution, 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 3 crude units in our Whiting Refinery as part of our major project to upgrade the refinery in time for its expected startup 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 petrochemicals 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 instant 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 interests in the Alba and Britannia fields in the U.K. 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 was 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, whilst 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 U.S. obligations, generate sufficient cash to both grow distributions to 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 high decommissioning costs.

We continue to expect full-year underlying production in 2012 to be broadly flat with 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 at 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 the one-off charge of around $250 million to $300 million related to further changes to the U.K. taxation of North Sea production.

With that, let me hand you back to Bob.

Robert W. Dudley

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 2 significant uncertainties, that related to legal proceedings in the U.S. and that related to our interest in TNK-BP in Russia.

We are 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 U.S., 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 a trial date for other claims is not yet set.

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 with 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 the significant East Coast Krishna-Godavari, Cauvery 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 in 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 are 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 the 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 NEC 25 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 3 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 through 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 -- 5 things you can expect from BP and 5 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 paths and provides the context for plays on both sides of the Atlantic, where we have been increasing our participation.

Thus far in 2012, we have entered into new positions in Namibia and have been awarded 3 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 activity in these exciting new plays in coming years.

In the Gulf of Mexico, we acquired 43 new leases in June 2012 in the 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 9 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 4 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 2 U.S. 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 start up 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 6 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 baseload of longer-life cash flows.

Turning to the Gulf of Mexico. In 2Q, we continue 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 turnarounds at Mad Dog and Atlantis. We're progressing the planned divestments of our interest 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 in development activity in our 4 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 6 rigs operational, with the startup of the West Capricorn rig in July. We plan to have 8 rigs in place by the end of the year. Two of these rigs are currently working on production activities, 2 are drilling appraisal wells and 2 are working on plug and abandonment activity. By the end of the first quarter, next year, we expect to have 6 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 2 years.

On projects in 2Q, we had the startup of Galapagos. BP's first subsea tieback 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 3, a 2-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 multiyear 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 4 key drivers to the planned increase of around 50% in operating cash flow by 2014. Payments into the Trust Fund are expected to end in 4Q.

This approaches half of the expected increase. And as you have just seen, we are marching on to deliver our new projects in 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 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 a 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.

Question-and-Answer Session

Operator

[Operator Instructions]

Jessica Mitchell

All right. The first question today comes from John Rigby of UBS.

Jon Rigby - UBS Investment Bank, Research Division

Can I ask 2 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 just raised my eyebrows when you said you'd replaced the entire subsea system at Atlantis. I think I -- maybe I was mistaken. I was under the impression that most of the turnaround was work that was prompted in a 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 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 the 2 parties, plays into the fact that you apparently can't get agreement on the board on a specific payout? Is there a separate mechanism that ensures some form of clearing of cash back to the stakeholders?

Robert W. Dudley

This is Bob. Well, 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 it is, in fact, is probably going to come on within the next couple of weeks. It's 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 5 years ago to bring forward the economics of the Atlantis field and put them down there, knowing there was a design life of 5 years at that time. We and our partners have made that decision. And I think if there's 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 we'll 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 could 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. It's usually the third quarter. So no other sort of bigger conclusions to draw from that, John, 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 -- well 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's 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.

Jessica Mitchell

The next question we'll take from Martijn Rats of Morgan Stanley.

Martijn Rats - Morgan Stanley, Research Division

I have 3 shorts ones. You reiterated quite strongly the 50% growth in operating cash flow. But I was wondering if the sale of TNK-BP actually goes ahead, will that target still stand? I thought perhaps you could soften that target a bit given that this was under discussion. The second question I wanted to ask you is whether there is any results from drilling Block 26 offshore Angola. That seems a very interesting prospect. So if there is anything, any 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?

Brian Gilvary

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 were 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.

Robert W. Dudley

Yes, 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 drill stem test on right now. But those results are not public. And third, on the U.S. 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 operate under $4 a barrel -- or $4 in Mcf to be profitable. This has been a particularly brutal quarter in terms of low gas prices hitting a low $1.94. We have rebased our portfolio to move out of the dry gases on the Fayetteville, for example, moving into the wet gases is in Eagle Ford. And I think we've taken the number of rigs down. We're not a company that needs to drill to hold on to acreage. So by the end of 2011, we had 12 rigs running in North America. By the end of August, we'll be down to 7. And I would expect by the 1st of January at these kind of prices, we'll be down to 5 rigs. We still think it's a very, very significant resource base, but we'll be focusing on the wet gas.

Jessica Mitchell

Right. Over to the U.S. Robert Kessler from Tudor Pickering.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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 sort of normalized x one-off cash flow from operations would have been in the second quarter, if you were on plan?

Robert W. Dudley

Well, not to give you a specific number. I mean, we -- I would -- broadly, broadly, I think some of the calculations that were done on our cash flows and our earnings used an overall cash flow number or realizations 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?

Brian Gilvary

Yes, 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. So 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 affecting 1Q versus 2Q.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then as you look forward to the third quarter, you highlight even more significant maintenance in your 4 highest margin areas. Can you talk about whether that $1.1 billion increases in terms of the net detriment price being equal in the third quarter?

Brian Gilvary

Yes. So we'll see some ramp-up, some ramp-up from the GoM, 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 4 big hubs. But you will start to see that ramp back up in fourth quarter. The other thing that will impact cash flow is, of course, the price has 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 will be broadly below where we were in 2Q for those 4 big hubs.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And quick unrelated one for me. U.S. refineries' net of the impairments, can you disclose the book value of Texas City and the Southern West Coast fuels business?

Brian Gilvary

No, we don't make that available.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Even though it's held for sale?

Brian Gilvary

Even though it's held for sale. That will come up in the annual report and the [indiscernible] 20-F filing at end of the year.

Robert W. Dudley

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 to go back and -- for you to go back and look at the -- the tax reference price is set the month before a certain month for calculations. And what happened in this quarter is the first, second and third months of the quarter successively dropped, so the 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 it's not -- and that's actually not a cash number. It's earnings number.

Jessica Mitchell

Right. We'll take the next question from Rahim Karim of BarCap.

Rahim Karim - Barclays Capital, Research Division

A couple of questions, if I may. Just the first, to go back to U.S. 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 5 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 just 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 U.S. this quarter. Is there anything in particular that we should be aware of there?

Robert W. Dudley

Well, we haven't actually laid out our production geographically like that. I mean, you'll know that our barrel of oil equivalent production in North American gas will be over 300,000 BOE per day. Our activity, I think, will be, in fact, because it's something -- 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 price 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're prudently planning on keeping our activity level low and focusing what activity we have in liquids side of things. We did have a write-down in impairment [ph] in U.S. North American gas. It's 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's what you need to do under U.S. 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.

Brian Gilvary

Yes. On GoM in particular, if you look at the Stock Exchange announcement in the upstream, you'll see that our production in the United States is down first quarter versus second quarter by about 104,000 barrels a day. About 86,000 barrels a day of that is Gulf of Mexico production. So our net production in Gulf of Mexico for the second quarter was just over 170,000 barrels a day.

Jessica Mitchell

All right. The next question from Doug Terreson of ISI.

Douglas Terreson - ISI Group Inc., Research Division

I have a couple of questions on the downstream, 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 U.S. and refining I think in the release. But I wanted to see if there is 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 in mix is going to be affected in the specific quarter leading up to the midyear 2013 completion, if you have that.

Brian Gilvary

Yes. In terms of the valuation of the assets, the impairment charge we've taken is predominantly in the United States. It's as a consequence of the fact that we're marketing to refineries today. We have gone back and reassessed what we believe to be the values of refineries. There are a lot of refineries up for sale. And so therefore, we're taking impairments on that basis, Doug. So we believe the carrying value now is that much less than what we had in the books. And I'm sorry, Doug, the second question?

Douglas Terreson - ISI Group Inc., Research Division

Yes. So I want to see if you -- you talked about a transitional outage on the crude units in the release. And I 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 midyear 2013?

Brian Gilvary

Yes. That's pretty market-sensitive information at the moment, Doug. We will be giving more guidance on that going forward. The key part of the project it to upgrade the Whiting Refinery, take the largest of 3 crude units out, which is a 12-pipe still. We're currently going through the planning of that, and we will try and give more guidance on that in some future date ahead of going that turnaround.

Jessica Mitchell

Good. We'll take the next question from Theepan Jothilingam from Nomura.

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Just a follow-up question back on the GoM. Firstly, I think you've talked Mad Dog and Atlantis. So I just wanted to know, is there any further planned maintenance on Na Kika or Antijos [ph]? And is it right to think of an inflection point in the GoM with the Q2 numbers or should we think about more of a an inflection point in 2013? The second question, just on the downstream and U.S. refining, I just want 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 that 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 comments 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 assets swaps? I'm trying to sort of circle around wanting to remain in Russia but also potentially looking to sell TNK-BP.

Robert W. Dudley

Okay. Well, first, as we come out, I'll take the Gulf of Mexico and sort of describe the trajectory here. Certainly, in the second quarter, we have big assets down for the entire quarter. They're coming back during the third quarter and they will come back during the fourth quarter. So 4Q, we'll see much higher levels of production as we march out of this turnaround season. We'll go back into this turnaround season next year in the second quarter again. Some of that work will be done on Thunder Horse. It's not the kind of work that's being done on Atlantis, although we are evaluating a Thunder Horse redevelopment because we see multiple additional potential around that field. So that's an area of ongoing and active study. In Na Kika, we have a Phase 3 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 that 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 4 very big production hubs in the Gulf -- Thunder Horse, Na Kika, Atlantis and Mad Dog -- and that will be where we drive the future of ourselves in the Gulf, putting aside any [indiscernible] success in exploration we have. Let me turn it over to Brian.

Brian Gilvary

Yes. On the downstream question, the in-transit barrel effect that we had on 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. So that's -- broadly, that's what happened in 2Q versus 1Q. Of course, as prices have now started to increase again, we will see some of that coming back into the third quarter.

Robert W. Dudley

And Theepan, on Russia, there's -- for all of 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's no guarantee any transaction could follow. In Russia, there is a strategic law that limits our ownership to 50%. So 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 anyway. Whether our -- 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 in 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.

Jessica Mitchell

Right. We'll take the next question from Irene Himona of SocGen.

Irene Himona - Societe Generale Cross Asset Research

I had 3 questions, please. The first on TNK-BP, in all of 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 functioning one so it can start paying dividends and operating normally? And my second question, on the Gulf of Mexico, if you can perhaps give us a sense of the amount of integrity CapEx and OpEx that you incurred, let's say, a year-to-date, and what we can expect in the rest of the year, please. And then finally, on the U.S. legal proceedings. The U.S. trial date is set for January next year. Last year, in your legal seminar, you had outlined what's actually a multi-year potential court case. Of course, since then, you've reached agreement on part of those claims. Can you perhaps have update us on the potential timescale should the trial start in January given that we've got far fewer parties involved this time?

Robert W. Dudley

Great. Okay. So a wide variety of questions there, Irene. On TNK, there is no guarantee of a transaction, like you said. Do we have plans otherwise? Well, absolutely. We work under a shareholders' agreement. And we didn't -- we don't get up every morning thinking about how to take on litigation, but we certainly do have litigation paths if -- to get the venture functioning on a number of ways. But we have been working hard with our partners to try to reach a resolution with all the partners and all the different parties and partners for some time, and that's -- 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. And we're in this period now, 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?

Brian Gilvary

No, 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 with 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 in 2010.

Robert W. Dudley

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 the 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.

Jessica Mitchell

The next question comes from Hootan Yazhari from Bank of America Merrill Lynch.

Hootan Yazhari - BofA Merrill Lynch, Research Division

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 8. I just wanted to understand if that's the number that you're comfortable with, or is there scope to increase that 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 of from TNK-BP will be?

Robert W. Dudley

Okay. Good. On the Gulf of Mexico. Well, we have the 6th rig up and running now, and by the end of the year, we'll have 8 rigs in place. The 2 additional ones will be working with Mad Dog and Na Kika production wells, bringing it up to 8. What I would say is that there is an enormous amount of technical capability, rig crews, attention to operating 8 rigs -- in fact, 6. I was reading today that one of our competitors was moving up to 5 and didn't intend to go beyond that because of technical capability and people being a limiting factor. And I think for us, 8 rigs, going from 0 last year up to 8, 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 8 rigs running in the Gulf of Mexico before. So we have 2 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 6 that are working on those production activities out of the 8. Could we go above 8? We have talked about it. We have talked and considered going up to a 9th 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 that TNK-BP potential divestment hasn't really changed the pace of activity.

Jessica Mitchell

We'll move now to Pavel Molchanov from Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

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?

Brian Gilvary

So Pavel, it's Brian Gilvary. I mean, effectively we have 3 options, and the board will consider all 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 will also give us potential, assuming the transaction gets done, money which could be invested elsewhere in the portfolio. And they are the 3 options that we'll consider, and we'll consider that with the board and bring our proposal back to our shareholders.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

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 the -- what your expectations might be for the appeals process?

Robert W. Dudley

This is the case we -- went through the courts last year and was tossed out and sort of reentered and emerged again, where a minority shareholder that holds 0.00001% of TNK-BP has brought forward the damage claim. Rosneft themselves have said that there was 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'll appeal it. It's kind of no surprise to me, but we'll appeal through this process, and you just have to stay tuned on that.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Any sense of the timing on that?

Robert W. Dudley

I don't know the timing. I haven't gotten a review. I think, 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.

Brian Gilvary

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

Jessica Mitchell

Right. We'll now take a question from Oswald Clint from Bernstein.

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

My question on TNK is post a solution, and assuming we get back to normal operations, is -- and I know you're 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 Bering Sea, the Kara Sea, the Black Sea, et cetera. I just want to get a sense of is there still acreage out there that's attractive to BP. Secondly, just on the sort of the comments on ongoing sector inflation within the release, I guess last quarter you talked about 5% to 10% in terms of those numbers. 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 a 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?

Robert W. Dudley

Oswald, yes, a couple of things. Well, 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, 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 this world now for some time. Last year, it was a $111-year. So there was quite a bit of oil fuel 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 -- I'm 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, very prone to inflation. We're seeing some of that inflation come off onshore in the U.S. 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, we had the interest -- 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, 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 more -- 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 move forward the third train of that project, and I'm very satisfied that, that would be an economic good project for us. And we're also drilling before the end of the year, and 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, very advantageous for us.

Jessica Mitchell

All right. The next question come from Jason Kenney from Santander.

Jason Kenney - Grupo Santander, Research Division

Just on -- I think it was Slide 25, where you've 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 to be FID'd over to the next couple of years in terms of maybe value and cash flow support? Secondly, on Namibia, I wondered if you had any kind of pre-drill resources in place across your licenses there? And the same question for the Brazil equatorial margin.

Robert W. Dudley

Right. Well, on Namibia, let me take that one first. Namibia is a very interesting perspective. Wildcat Frontier, which is we and a number of other companies have identified this as having potential. We don't have pre-drill numbers yet that we would put out. We think there are 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 could see bringing FID in here going forward. Of course, the big one is Shah Deniz. That's certainly one full fuel development that we're working on. West Nile Delta gas is one that we have out there. Quad 204. We've got FIDs yet to do in Oman, Clair Ridge, Mad Dog Phase 2, Pike Phase 1. We've got additional -- [indiscernible] subsea projects, Pazflor Phase 2 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. I guess what I would describe from that is a very healthy project. Our issue going forward through into the next decade is being -- 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.

Jason Kenney - Grupo Santander, Research Division

Actually, Bob, I was going to follow up with the impact of bringing these FIDs into place and the medium-term CapEx outlook. Obviously, you're going through a major maintenance and turnaround program at the minute. Should we be -- I don't want you to give me a number. I don't think that you will give me a number, but should we be assuming kind of a lower-level project delivery CapEx than we're seeing at the minute as our maintenance CapEx drops off? Or is it likely just to stay at this kind of level for the medium-term outlook?

Robert W. Dudley

Well, CapEx of the group this year is around $22 billion. I have no doubt we could 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 5 years to the 24 to 25 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 rephase projects or divest some of them. I'm fairly sure of it.

Brian Gilvary

Yes. So Jason, we are still committed to the targets we've set for 2014, which is 50% for investment, 50% for other purposes like distribution. So those targets are still in place, so we are not expecting the capital appetite to increase beyond what we said to you in October and February.

Jessica Mitchell

Right. We'll take the next question from Guy Baber from Simmons & Company.

Guy A. Baber - Simmons & Company International, Research Division

I had another question on the downstream. But I was just hoping for a little bit more detail with respect to the 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 regulatory hurdles to clear? Is there certainty around those regulatory liabilities now? I know you all 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?

Brian Gilvary

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 with multiple parties. And in terms of any final transaction, of course, there will still be regulatory approval required in various jurisdictions, but we don't see that getting in the way at this -- at the moment.

Guy A. Baber - Simmons & Company International, Research Division

Okay. 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 unconditional footprint relative to maybe what you think is optimal for you all. Do you all 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?

Robert W. Dudley

I would say that for the liquids-rich shale, I think nobody has had enough of it. So I think everyone feels like they -- 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 so it's a 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. I spoke with the Governor. I spoke with the 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. We're not going to jump in too deeply. But I think the Utica is one area that we have I think that has additional promise.

Jessica Mitchell

Right. Could we take the next question from Jason Gammel of Macquarie?

Jason Gammel - Macquarie Research

A couple on the upstream, please. One of your partners had actually referenced delays at both PSVM and Skarv into next year, but appreciating your role as operator and seeing those on the startup schedule for 2012. I just wanted to think about how those will affect 2012 production. Should we be thinking of those as a very late year that have no effect or early 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 reinvolved in the process at some point?

Robert W. Dudley

On the 2 projects, Skarv and PSVM, they're both fourth quarter project, so as you model and think about it, then certainly the impact will be primarily in 2013, coming on. I've seen they 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 at issue with BP. There seem 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. For 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 possible for us to be, nor have we -- I know we have not been formally excluded.

Jessica Mitchell

Right. We'll move on then. The next question from Iain Reid from Jefferies.

Iain Reid - Jefferies & Company, Inc., Research Division

Brian, can I come back to the $1.1 billion you talked about, the difference between the first quarter and second quarter, on volumes? And if you go back to 2011, what was the kind of corresponding numbers for 2011? Was this quarter in a major way different to what you've seen before?

Brian Gilvary

No. So in the past, if you remember last year, in 2Q and 3Q, and as Bob pointed out, third quarter's -- third week of September was our low point in terms of production. We were having no rigs work [ph] at that point. This 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 as the oil price came off. So it's a standard effect. And 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.

Iain Reid - Jefferies & Company, Inc., Research Division

Okay. And Bob, a couple of questions about India. You gave a -- going back to your update on that. I just wonder how confident you are about the carrying value of your acquisition cost there. One of your partners talked about reducing reserves there recently. I believe you just completed reservoir modeling there. And is it possible to say what sort of increased gas price you need in order to justify the acquisition costs on India?

Robert W. Dudley

Iain, yes. One of our small partners reduced their reserves on the field just recently. I will tell you that they reduced it down to the near or at the values we've always had for the field. So I wouldn't read too much into their action because what we have always said is that 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. So I would expect that -- 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, very good investment for us down the road here.

Iain Reid - Jefferies & Company, Inc., Research Division

And any sort of view on what sort of gas price you need in order to justify what you pay for it? Something higher than where we are today, I presume.

Robert W. Dudley

Well, yes. The price was going to be renegotiated in 2014. But in addition, so, of course, but that's not the only reason we're in it. We believe we're going to find more resources, and those prices will be higher for the gas. In addition, we have multiple exploration blocks as well on the gas marketing joint venture. It's all part of the valuation that we did initially for the project.

Brian Gilvary

And let me add just bit of context. The domestic price that we have today is significantly by an order of -- 2 orders of magnitude, lower than what the import parity is, and that all will be part of the conversation around trying to renegotiate the domestic price.

Robert W. Dudley

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.

Iain Reid - Jefferies & Company, Inc., Research Division

It sounds like you can do that as well then?

Robert W. Dudley

Yes.

Jessica Mitchell

Okay. Now we'll take a question from Kim Fustier of Credit Suisse.

Kim Fustier - Crédit Suisse AG, Research Division

I have 2 question, 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 U.S. onshore gas position, which is under-earning at the moment given $2, $3 gas. So I was wondering if LNG exports in North America are on your radar at all to monetize part of these resources.

Brian Gilvary

So under the Stock Exchange announcement, you'll see in the Note 2 that it's been classified as litigation of the costs associated, Macondo litigation claims and other costs. So that's the broad bucket into which the $850 million has been put into.

Robert W. Dudley

And on the North America gas, Kim, you are right. We have been looking at that. I don't think we're in a position to go into a 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.

Jessica Mitchell

Right. Our next question from Joseph Tovey of Tovey & Company.

Joseph Tovey

One of the great strengths of British Petroleum relative to its competitors has been it's very high quality ability in production getting and producing cheaply on the whole. An area that has been not necessarily always good in comparison has been the downstream operations, refining amongst others. I'm 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 Phillips -- ConocoPhillips getting out of the refining business, separating off the production, and from the refinery end, would that make sense that you sell a greater portion of your downstream than you've already been doing and have already stated? Strategically and tactically, as well as a way of generating cash that might be better place elsewhere.

Robert W. Dudley

Joseph, this is Bob. On the first point of looking at, say, 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 busing. 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, with low prices, what will the gas be used for and there's different areas of petrochemicals and certain things that we are 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 2 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?

Brian Gilvary

Yes, I mean, the way we've structured the downstream, we've gone through a fairly very 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 dividend 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 2 parts.

Joseph Tovey

Let me if I may, 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 is, therefore, a greater demand for fuel for the European truckers. Does that change in the market, signifying 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 I'm, by the way, not denigrating nor ignoring the massive long-term efforts that you've as a firm have gone through in changing your refinery set up. This kind of thinking, with the technological changes in the last year or 2, may have said, well, maybe that ought to be re-examined and accelerated a bit.

Robert W. Dudley

Joseph, I think the big strategic question that you see or your 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've developed networks like that from scratch. We think there are probably others out there that will be able to devote that rather than us. In our case, we will focus on the very strong positions that we have in the [indiscernible] Valley and in Iberia and our development of clean fuels and run those refineries in the marketing networks with the fuels that we have.

Jessica Mitchell

Right. The next question is from Peter Hutton at RBC.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Sorry. A lot of question have already asked and answered, but 2 very quick ones. Can you give us a status on Galapagos? You mentioned that. How long is that going to take to ramp up? Is that relatively quickly? And the second one on India. I appreciate the messages on this huge value of India. Just putting this in context. So 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're at a stage we might see some more visibility on the near-term operating metrics of this, which is over $7 billion of big investment?

Robert W. Dudley

So you asked about, Peter, Galapagos. The tiebacks occurred in Na Kika, and it's ramping up. We've got a couple of wells on. There will be a number of other wells that will be on, and I expect it to be ramped up with within 2 to 3 months on Galapagos. And the project has come on very, very smoothly so far and slightly ahead of the sort of 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 D6, D1, D3 structure was going to be challenged. We did not believe via a reservoir engineer that 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 a near-term metric issues. I think you said in TNK-BP.

Peter Hutton - RBC Capital Markets, LLC, Research Division

No. 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. That's the point.

Robert W. Dudley

Oh, I see. Okay. Well, TNK-BP was over 1 million-barrel oil company. We did break out that very, very differently. We have not around the world broadly, broadly broken out the individual production of our fields in locations. But I think in time, as we move through this next year or so, you'll see us described 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.

Jessica Mitchell

Right. Thank you very much, everybody. That concludes our call for today.

Robert W. Dudley

Thank you, everyone. Good to talk with you today. Same for Brian.

Brian Gilvary

Thank you.

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