英國石油 (BP) 2012 Q3 法說會逐字稿

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

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

Hello, and welcome to BP's Third 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.

Today is the presentation of our third quarter results.

It is also a quarter during which a great deal has happened at BP.

Most notably, last week's announcements of our plans to reposition our interests in Russia, bringing with it much greater clarity to a lingering uncertainty for the group.

And it is exactly a year now since we announced our 10 point plan.

So it feels like the right time to update you on our strategic progress, and give you a sense of the direction we're taking and why I remain confident we're on the right path.

Our agenda today will start with Brian taking you through the results for the third quarter, and then we will take a more detailed look at developments in Russia, and on the US legal front.

I'll then come back to the plans we laid out to you last October, and show you what we've done to reposition the Company, and how we intend to drive growth over the next decade.

This is all part of our vision to be a focused oil and gas Company that creates value by growing long-term, sustainable free cash flow through safe and reliable operations.

We will do this with a disciplined and prudent financial framework, and a portfolio biased to high margin opportunities.

First, let me hand you over to Brian.

Thanks Bob.

I'd like to start with an overview of the third quarter financials.

BP's third quarter underlying replacement cost profit was $5.2 billion, down 5% on the same period a year ago, but 40% higher than the second quarter of 2012.

As we described in our 2Q results, this includes a one-off $260 million deferred tax charge related to further changes to the UK taxation of North Sea Production announced in 2011.

High refining margins and good operational performance have supported third quarter results in our downstream business.

More stable oil prices have resulted in some positive reversal of the unusual price effects seen in the second quarter.

As noted at the time, our earnings in the second quarter were negatively impacted by particularly volatile oil price movements, which led to a large duty lag and foreign exchange effects in TNK-BP and adverse pricing of our feedstock into our US refineries.

Third quarter operating cash flow was $6.3 billion.

In the fourth quarter, we will make a final payment of $860 million to complete the $20 billion funding of the Gulf of Mexico Trust Fund.

We would like to announce that the third quarter dividend payable in the fourth quarter will be increased to $0.09 per ordinary share.

This increase reflects the progress we have made with the significant divestments announced this year, and our future confidence of the underpinning of the 10 point plan.

We will continue to review the dividend level on an annual cycle, and adjust it in line with the improving circumstances and underlying growth of the firm.

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

The result versus a year ago largely reflects a weaker price environment, with Brent trading on average around $4 per barrel lower, and Henry Hub trading at an average $1.40 lower.

Production was around 3% lower, primarily due to divestments and entitlement impacts in our production sharing agreements, natural field decline, and the seasonal impacts of maintenance activity.

This was partly offset by major project start-ups and improved operating performance in Angola, and increased volumes in other areas.

Underlying volumes excluding TNK-BP and after adjusting for divestments and entitlement effects, increased by more than 3% year-on-year.

Non-cash costs also increased year-on-year mainly as a result of high depreciation, depletion, and amortization associated with the new high margin projects and higher decommissioning costs.

As we said last quarter, the third quarter result is flat with slightly higher average realizations offset by slightly lower reported volumes.

Major project production ramp-up and the completion of turnaround activity in the Gulf of Mexico were offset by seasonal maintenance activity in the North Sea and Alaska, and the impact of Hurricane Isaac in the Gulf of Mexico.

We expect fourth quarter reported production to be higher than the third quarter, as we exit the maintenance season and see the continuing benefit of our major project start-ups.

The extent of the increased production will likely be muted by the timing of some significant divestments in the Gulf of Mexico, and North Sea expected to be completed during 4Q.

As we said in July, 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 the impact of divestments, which we continue to estimate at around 120,000 barrels of oil equivalent per day.

The actual reported production outcome for the year will depend on the exact timing of divestments and project start-ups, OPEC quotas and entitlement impacts in production sharing agreements.

BP's share of TNK-BP underlying net income was $1.3 billion in the third quarter, 38% higher than a year ago, and almost three times higher than the previous quarter.

Compared to the third quarter of 2011, this result reflects positive foreign exchange effects and a favorable impact of the tax reference price lag on Russian export duties in the rising price environment, reversing the adverse impact seen in the second quarter.

Compared to the second quarter, the combined price, duty lag, and foreign exchange impacts had a beneficial impact of around $800 million on BP's share of net income.

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

Following the agreement with Rosneft announced last week, BP's investment in TNK-BP now meets the criteria to be classified as an asset held for sale.

We will therefore cease equity accounting, and it will not feature in future earnings from the announcement date.

We will however, continue to record our share of TNK-BP's production and reserves until the transaction closes.

In the downstream, underlying replacement cost profit for the quarter reached the record level of $3 billion, compared with $1.7 billion a year ago, and $1.1 billion last quarter.

The fuels business made an underlying replacement cost profit of $2.7 billion, significantly higher than both the same quarter last year and the previous quarter.

This was driven by a combination of high refining margins and strong operation performance, with refining throughputs at the highest level for seven years.

The refining market margin averaged $19.50 per barrel for the quarter, the highest third quarter since 2005, driven by refinery closures in the Atlantic Basin, and low gasoline and diesel inventories globally.

The third quarter result also benefited from positive priorment pricing of barrels into our US refining system, which substantially mitigated the negative impact seen in the second quarter, and a rebound in the supply and trading contribution to more normal levels.

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

As previously indicated, we are about to start the Whiting refinery transitional outage to replace the largest of three crude units as part of our major upgrade project.

This will temporarily reduce the crude capacity of the refinery by more than 50%.

We expect this work to be completed by the middle of 2013, in time for the start-up of the project in the second half of 2013.

In addition, we expect to carry out major turnarounds at two of our refineries in the fourth quarter.

The lubricants business delivered an underlying replacement cost profit of $310 million reflecting robust performance, significantly higher than the same period last year, despite a continued difficult market environment.

The petrochemicals business delivered an underlying replacement cost loss of $20 million, compared with a profit of $235 million in the same period last year, driven by continued weakness in margins globally, resulting from recent aromatics capacity additions in Asia, high feedstock prices for BP's mix of products and lower demand.

Looking ahead, we expect petrochemicals margins to remain depressed in the fourth quarter.

In other businesses and corporate, we reported a pretax underlying replacement cost charge before interest and tax of $570 million for the third quarter, an increase of $170 million versus the charge a year ago, primarily reflecting higher corporate and functional costs.

Guidance remains a charge of around $500 million on average per quarter, but remains volatile quarter-to-quarter.

The effective tax rate on underlying replacement cost profit for the third quarter was 33%, compared to 30% a year ago.

Excluding the $260 million impact of the one-off deferred tax charge on North Sea production, the underlying effective tax rate for the quarter was 30%.

We now expect the full year effective tax rate to be at the lower end of the 34% to 36% range.

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

The third quarter charge has been increased by some $60 million to reflect an adjustment to provisions plus the usual quarterly expenses of the Gulf Coast Restoration Organization.

This brings the total cumulative net charge for the incident to date to $38.1 billion.

Pretax BP cash outflow relating to the oil spill cost and into the $20 billion trust fund for the quarter was $1.5 billion.

At the end of the third quarter, the cash balances in the trust and the qualified settlement funds amounted to $10.9 billion, with $19.1 billion contributed in, and $8.2 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.

I would like to highlight that the US Department of Justice has been conducting an investigation into the incidents regarding civil and criminal laws.

We are in ongoing discussions with the DOJ and other federal agencies regarding a possible settlement of these claims.

And once we are ready to settle on reasonable terms, a number of unresolved issues remain.

And there is significant uncertainty as to whether an agreement will ultimately be reached.

We therefore believe that it is not currently possible to reliably measure any potential exposure and cost to BP arising from some of these claims, save for those claims for which we have already provided.

Turning to the disposal program, we have made strong progress with our program of divestments in the third quarter.

Since the end of the second quarter, we have announced $11 billion of asset sales.

These include our Carson and Texas City refineries in the United States together with some related logistics and marketing assets, interests in a number of non strategic oil and gas fields in the deep-water US Gulf of Mexico, the Sun Ray and Hemphill gas processing plants in Texas our interest in the Dragon Field in the Norwegian sector, and our Malaysian PTA interest.

Including the proposed transaction with Rosneft for the sale of our share in TNK-BP, this brings the total of announced divestments to over $62 billion.

And we have now announced more than $35 billion against our original target of $38 billion.

Moving now to cash flow.

This slide compares our source and uses of cash in the first nine months of 2011 and 2012.

Operating cash flow in the first nine months was $14.1 billion, of which $6.3 billion was generated in the third quarter.

After excluding an outflow of $3 billion from post tax Gulf of Mexico oil spill related expenditures, underlying operating cash flow in the same first nine months was $17.1 billion.

We received $4.6 billion of divestment proceeds during the first nine months, with $1.4 billion in the third quarter.

Organic capital expenditure in the first nine months was $16.5 billion, and $5.9 billion in the third quarter.

In the fourth quarter, we expect to receive disposal proceeds of $6 billion, and to make our final payment of $860 million into the $20 billion Gulf of Mexico trust fund.

We now expect full year capital expenditure for 2012 to be $22 billion to $23 billion, slightly ahead of previous guidance.

The TNK-BP divestment is expected to close in the first half of 2013.

At the end of the third quarter, net debt was $31.5 billion leaving gearing at 20.9% compared to 21.9% at the end of the second quarter.

As we work to complete our divestment program and end payments into the trust fund, we expect gearing to reduce.

And we continue to target gearing in the lower half of the 10% to 20% range over time while uncertainties remain.

Let me now hand you back to Bob.

Thanks Brian.

Now let's turn to the future.

I'd like to start to outline with you today our thinking about the longer-term direction of BP ahead of a more detailed Investor Day focused on the upstream.

I'm pleased to announce we'll hold this on December 3 at our London campus in Sunbury.

However before I do that, I would like to spend a few minutes discussing our recent agreement with Rosneft for the proposed sale of our share in TNK-BP, and to update you on our US legal position.

As we announced last week, we've taken a major step forward in repositioning BP within Russia through our intention to divest our share of TNK-BP in exchange for cash and an 18.5% share of Russia's leading oil Company, equivalent to just under $27 billion based on the Rosneft closing share price on October 18.

With the resulting 19.75% share, we expect to be able to account for our share of Rosneft's earnings, production, and reserves on an equity basis.

In addition, we expect to have two seats on Rosneft's nine person main Board.

In accordance with the heads of terms, BP and Rosneft have an exclusivity period of 90 days to negotiate a fully termed sale and purchase agreements.

Subject to signing definitive agreements, completion would be subject to governmental and regulatory approvals and would be anticipated to occur during the first half of 2013.

We are currently evaluating how the cash proceeds will be used.

At a minimum, our intention is to use part of the cash proceeds to offset any dilution to earnings-per-share as a result of this proposed transaction.

Let me put this transaction into a broader context.

Russia is the largest oil and gas producing country in the world with the largest reserves.

It also has significant and potentially unparalleled future resource potential through brownfield development, offshore exploration and unconventional oil.

We are proud of our history in Russia.

BP has been involved in Russia for over 20 years, with the opening of our first retail site there in 1990.

Since it was created in 2003 for an initial investment of around $8 billion, TNK-BP has returned $19 billion of dividends to BP.

The venture has also paid over $180 billion in taxes and duties to Russia.

However, our venture has now run its course.

The Russian industry is moving into a few phase of opportunity and consolidation.

The transaction we've announced should give BP shareholders timely and direct economic exposure to the industry leader.

We expect to become a significant equity holder in a Company with the largest oil reserves and production globally.

Last year, Rosneft's oil production was over 2.4 million barrels per day and its oil reserves exceeded 18 billion barrels.

It has a strong portfolio of new fields, and significant potential for development in its gas reserves base.

It also has the largest offshore license portfolio on the Russian shelf, with estimated recoverable resources of 190 billion barrels.

This slide gives you a sense of the global ranking of our industry following such a transaction.

Through this transaction, Rosneft will not only be able to count itself among the largest listed NOCs in the world, but it also acquires a much stronger platform for growth.

As this chart, shown last week by Rosneft illustrates, the combination of TNK-BP and Rosneft assets offers both increased scale as well as considerable opportunity for optimization.

The close location of planned TNK-BP and Rosneft developments from the Yamal Peninsula in Eastern Siberia, along with the addition of TNK-BP's associated gas assets to those of Rosneft, and the potential combination of research efforts, all provide the opportunity to realize natural industrial synergies.

Combined production would be 4.5 million barrels of oil equivalent per day.

Rosneft is also a Company which is busy transforming itself, developing its asset base with new technologies, and improving its management processes and corporate governance.

It is becoming an increasingly attractive proposition for independent investors, with its dividend payout recently increased to 25% of net income, and aspirations towards a greater degree of privatization.

BP has a long track record of working with Rosneft, initially in exploration offshore Sokolin, further cemented through our participation in their initial public offering in 2006.

And in May 2011, we entered into a 50/50 partnership in the German refining joint venture, Rural Oil.

All of this gives us confidence that the shares offer a differentiated investment proposition, and we intend to hold them as a long-term investment.

We look forward to being able to contribute to Rosneft's success, and add value through our participation on its Board.

Let me also update you on the US legal position.

By the end of the third quarter, we had paid a total of $8.8 billion to meet individual and business claims and government payments.

Over $19.1 billion has been paid into the trust fund as the end of the third quarter, with the final payments to complete the $20 billion funding scheduled for 4Q this year.

The fairness hearing to determine whether to grant final approval of the settlements with the Plaintiff Steering Committee is scheduled for next week on November 8, with the cost of the settlements to be paid from the trust fund.

The trial date has now been moved back for the remaining proceedings under MDL-2179 to February 25, 2013.

As Brian noted, we have said all along that we were willing to settle if we can do so on reasonable terms, and this remains our position.

At the same time, we continue to prepare vigorously for trial, and we will continue to update you as and when appropriate.

Now that I have updated you on Russia and the US uncertainties and our work to resolve them, I would like to turn to discuss the progress we've made in repositioning our core business.

First of all, I'd like to refresh you on the journey so far.

In 2010, we focused on responding to the Gulf of Mexico oil spill and meeting our cleanup and restoration commitments.

Then in 2011, we began the process of resetting the Company, including the creation of the Safety and Operational of Risk Function, the reorganization of the upstream business on the functional lines, and a major recruitment drive to deepen capability.

And finally one year ago, we laid out the 10 point plan which included specific guidance for operating cash flow, divestments, and project start-ups by 2014.

Our intention today is to give you a stronger sense of the longer term vision for BP, ahead of our planned upstream Investor Day on December 3.

We will start by covering what we've achieved so far, how BP is positioned today, and our near term agenda to 2014.

So what have we achieved so far?

In the last two years, we have fundamentally repositioned reposition BP through an extensive change program addressing three main areas.

First is safety and reliability.

18 months ago, we created the new Safety and Operational Risk Function to lead the safety agenda across the Company, and to provide independent assurance on operating performance.

The rigorous and consistent use of our operating management system remains a key priority, with a particular emphasis on process safety and risk management.

While still early days in what is a long journey, our process safety metrics for the group are improving this year so far.

In losses of primary containment, we are seeing a continuation of a multi year improvement trend with year-to-date incidents 25% below the equivalent period last year.

And we have seen an around 40% reduction in processes safety events compared to the first three quarters of 2011.

In the downstream our refining throughput hit a seven year high in the third quarter, underpinned by sustained improvements in refining availability over the last five years.

Since the start of 2008, a strong focus on operational performance has translated into an improvement in process safety metrics, with a 60% reduction in the loss of primary containment, and a 30% reduction in our process safety index over the period.

Good safety is good business.

And as Brian highlighted earlier, the high levels of refining availability in operating performance in the third quarter have allowed the downstream to capture a record profit in a high refining margin environment.

In the upstream too, we're now beginning to see the signs of the benefits of the investment we had made into turnarounds over the past two years.

In 2011, we delivered 47 turnarounds, or TARs, a historically high number.

We are now beginning to realize the benefits from this investment.

We are seeing a greater than 60% decrease in unplanned outages from the facilities we worked on in 2011.

We expect to see this trend continue in 2013, as we have now completed around 80% of the TARs this year and will have a further eight completed by year end.

We intend to continue our investment in systematic execution of our TAR program, and expect the 2013 program to be similar to 2012.

And again, we expect overall outages to continue to reduce.

We are also delivering significant portfolio change.

As Brian already mentioned, we have announced over $35 billion of divestments against our $38 billion divestment target, or $62 billion in total including the proposed transaction with Rosneft.

At the same time as unlocking cash and increasing our financial flexibility, these divestments have increased the focus of our core portfolio on our areas of distinctive capability, and they have removed significant operational complexity from our portfolio.

Simplification and risk reduction comes from many steps.

Looking at the statistics since 2010, all together, the strides made are significant.

Since the divestment program began, we have removed around 50% of our upstream installations, 32% of our wells, and 50% of our pipelines, while only divesting around 10% of our reserves base and 9% of our production.

We have traded smaller, mature assets with declining cash flows to focus on those that can grow.

And we have concentrated geography and assets to leverage management and operating capability.

We have fundamentally reshaped and repositioned our upstream portfolio to offer a differentiated proposition, which plays to our strengths in exploration, deep-water, giant fields and gas value chains.

The period of repositioning our downstream business to improve margin quality and efficiency to the portfolio will be significantly complete by the end of 2013, as the Whiting Refinery Modernization Projects comes onstream, and the divestments in the US of the Southwest's coasts Fuels Value Chain, and the Texas City refinery are finalized.

In addition, we continue to focus our alternative energy portfolio.

Exiting solar, and cancelling our plans to build a commercial scale cellulosic ethanol plant in Florida.

We have also made significant progress in our renewal of the upstream.

Recent new access in the upstream has strengthened existing focus areas, and opened up new exploration opportunities.

Since early 2010, we have accessed around 400,000 square kilometers of new acreage, roughly twice the size of the United Kingdom.

This is more than double the acreage accessed in the combined nine years prior to 2010.

We will continue to actively secure new acreage both in core areas as well as new frontiers.

Access is the lifeblood of our renewal effort, creating the portfolio from which we will deliver exploration discoveries and replenish our development options portfolio.

To recap, we have made significant progress in safety and reliability, portfolio change, and upstream renewal.

These changes have created a strong foundation for the future.

It's distinctive for a more focused and lower risk footprint with strengthened incumbent positions, a leading position in deep-water, a unique position in Russia through our proposed Rosneft investment, a reloaded exploration prospect inventory, and a portfolio of world class downstream businesses that generate strong free cash flow for the group.

Now, having reviewed our progress to date, let me turn to the future.

This is the slide we showed you in February, which laid out our road map for growing value.

Our 10 point plan, which outlined the five things you can expect of us and five things you can measure us by.

This remains our clear agenda to 2014, and I have already touched on the progress we've made in many of these areas in reducing operational complexity and focusing the portfolio, and in creating a simpler and more standardized organization.

We're also seeing early improvements in safety and reliability.

We still have more to do over the next two years to begin to realize the full potential of BP's asset base, and we're on the case.

A key part of the 10 point plan was our commitment to grow operating cash flow.

In reflecting our proposed transaction with Rosneft, we remain confident in delivering more than 50% growth in operating cash flow by 2014, assuming an oil price of $100 a barrel.

Payments into the trust fund are expected to end in the fourth quarter, and our 15 higher margin upstream projects all remain on track.

We plan to use around 50% of this extra cash for reinvestment, and 50% for other purposes including shareholder distributions.

A key element of delivering the operating cash growth is new project delivery, so let's look at these in more detail.

Our major projects are progressing well.

Three projects have already started up in 2012, Galapagos in the Gulf of Mexico, [Klokas Mavikola] in Angola, and Devenick in the North Sea.

Three more are very close to completion.

We expect Angola LNG, PSVM and Scarve to all start up before the year end, an average of one major project each month.

All 15 major project start-ups by 2014 are on track.

Overall, the 2012 to 2014 portfolio has moved from 55% complete at the beginning of the year, to 75% complete today.

Expanding our margin is the primary source of operating cash growth to 2014.

On average, we expect the 15 new major projects coming onstream before 2014 to deliver twice the average operating cash margin of our 2011 portfolio at $100 a barrel.

And there's more to come as we develop the project pipeline beyond 2014.

We've made three new final investment decisions or FIDs this year, and expect to make another five in 2013.

So let me now turn to our longer term direction.

My vision for BP is a focused oil and gas Company that creates value by growing long-term sustainable free cash flow through safe and reliable operations, a disciplined and prudent financial framework, and a portfolio biased to higher margin opportunities.

We plan to deliver this through increased upstream reinvestment to drive growth in higher margin areas, and to sustain the pace of our increased exploration and access activity.

This increase in upstream reinvestment is in part funded by increased free cash flow from our other activities.

Let's start with the growth in high margin barrels.

Our development spending focuses on our four high margin areas, Angola, Azerbaijan, the Gulf of Mexico, and the North Sea.

Over the next five years, we will invest to grow or maintain production on all four of these high margin regions.

With major projects that include the Clove, Pazflor phase two and Kizomba satellites in Angola, another oil Chirag Oil project, the Azeri subsea project, and the Shah Deniz full field development on Azerbaijan, phase three of the Nikika project, the Thunder Horse water injection project, the Mars B project, and the Mad Dog phase two project in the Gulf of Mexico, and the [Kanul] project in the North Sea along with quad 204, Claire Ridge and the Hod redevelopment.

With continued access and exploration, we expect to maintain this pace over the longer term.

In addition, we're ramping up our investment in wells activity to keep our existing hub facilities filled.

Across our whole portfolio, we've started up nine new rigs in 2012, and we will be operating 55 by year end.

21 on-shore and 34 offshore, including 12 in the deep-water.

This trend is expected to increase to around 70 operated rigs in 2014.

You can see from the chart that the Gulf of Mexico remains one of our important sources of medium and long-term growth.

The recent sale of the package of non-core assets demonstrated the value of our position, which is now concentrated on our four operated hubs.

Our Paleogene appraisal program, and our exploration acreage.

We've only produced around 20% of the resources from our existing hubs including our non operated positions, leaving 80% still to be recovered.

In total, we have remaining net resources of some 4 billion barrels of oil equivalent.

Our approach is to extract this value.

While it is taking time to get production back after the two year absence of drilling, we now have seven rigs operating in the Gulf of Mexico with one more due to start shortly.

We are managing production from Thunder Horse until its redevelopment with new water injection facilities are installed in 2014.

This is good reservoir management and it is protecting the long-term value of the resources.

Thunder Horse is expected to reach a low point in 2013, as we have a 50 day turnaround plan, primarily for the water injection project tie-ins.

The field is expected to resume growth in 2014, and continue to grow for the remainder of the decade.

In 2013, we expect total production for the Gulf of Mexico normalized for 50,000 barrels of oil equivalent per day of divestments to be broadly flat with 2012.

We then expect production to increase in 2014, and continue to grow for the remainder of the decade.

The second focus of our increased upstream reinvestment is to sustain the higher pace of our increased exploration and access activity.

Exploration is one of our core strengths, where we have deep expertise, technology, and a compelling historic track record.

As I said previously, we have a created a much larger prospect inventory, increasing out exposure to new exploration areas outside of our traditional focus areas.

50% of our prospect inventory comprises new plays, and 50% as improving plays in known basins.

We're excited about the quality and materiality of our exploration prospects.

Our drilling program is expected to test 15 completely new plays between 2012 and 2015 in addition to deepening in our existing core areas.

And about 35 of our exploration wells should target prospects with resource potential greater than 0.25 billion barrels of oil equivalent.

We're balancing the higher risk reward opportunities found in new plays with the more predictable outcomes of the proven plays.

Over the last several years, we have roughly doubled our spend on exploration seismic, and intend to invest at this higher rate into the future.

In 2012, we acquired large, 3D seismic surveys in Australia, Angola, and in Mibia.

In 2013, we plan to acquire large 3D seismic surveys in Trinidad, Indonesia, and Uruguay.

We continue to push the boundaries of seismic acquisition and processing, and have particular expertise in sub salt imaging.

We've begun to test our new portfolio an expect to complete nine wells this year, including wells in Angola, Brazil, the North Sea, and in Mibia.

We expect the number of wells to increase to 15 to 25 wells per year going forward.

In the downstream, we have a portfolio of world class businesses that are expected to generate even more free cash flow once the Whiting Refinery modernization project is onstream.

With the recently announced divestments in the US, the period of repositioning the downstream is planned to be significantly complete by 2013.

As with the rest of BP, our downstream is focused on quality starting with safety, and the delivering of strong growing cash flows to the group.

We aim for a combination of attractive absolute returns, generating good cash flows, and maintaining financial discipline.

The reliability of the returns and cash flows is maintained in a volatile margin environment through the right mix of Value Chain businesses and capabilities as we showed you a year ago.

In summary, I would like to leave you with a few key messages for BP.

We have made significant progress in repositioning BP for sustainable growth into the future through a significant change program addressing safety and reliability, the shape of our portfolio, and the renewal of the upstream.

We remain on track to deliver the 10 point plan, and expect to grow our operating cash flow by more than 50% by 2014 from 2011 levels, excluding TNK BP and assuming an oil price of $100 a barrel.

The vision for BP is for a focused oil and gas company that creates value by growing long-term sustainable free cash flow through safe and reliable operations.

We have simplified and reduced risk with 50% less upstream installations.

¶ We will have a disciplined and prudent financial framework, and a portfolio biased to high margin opportunities.

We plan to deliver this through increased upstream reinvestment to drive growth in higher margin areas, and to sustain the pace of our increased exploration and access activity.

And finally, it is our intention to grow distributions over time in line with improving circumstances of the firm, and we will continue to maintain a progressive dividend policy.

Our dividend announcement today is a measure of this commitment in confidence in our ability to deliver.

That concludes my remarks, and now Brian, Jess, and I will be happy to take your questions.

(Operator Instructions)

Right.

We'll be taking calls today from both the UK and the US.

We know we have some callers in the US that have been struggling to get through because of Hurricane Sandy.

We do also have our web open for questions for those that may try to come in that way.

But we'll start first with a question from Doug Terreson of ISI in the US.

Go ahead, Doug.

Good morning everybody, and congratulations on your results.

My first question is on Russia and specifically the likely tax implications on the divestiture of TNK-BP.

And then second, TNK-BP returns on capital were very high in recent years and they were much higher than Rosneft's.

And so it seems that Rosneft's management has been pretty confident about the outlook for the combined entity, and so Bob highlighted a few minutes ago that scale and optimization were likely to be pretty significant opportunities.

But with Rosneft being one of your biggest investments I just wanted to see if you could provide your initial expectations for operational or financial performance for the new Company.

That is, if it's not too preliminary.

Doug hello, this is Bob.

Hello Bob.

Good to hear from you.

You too.

Well there's a couple of things.

TNK-BP has been a great investment for BP.

It's been a joint venture that's sort of run its course now.

It has been very healthy in terms of its dividend flow.

And it has moved through the brownfield phase, moving more into greenfield mixture of projects.

So we did expect the dividend stream to thin out of TNK-BP.

Looking at Rosneft, we've obviously studied carefully the potential of the Company.

We see it has a potential to have a production growth of roughly 4% a year through the decade.

I think it's too early to really be able to project with any greater insight from our team.

We think the dividend stream will be probably lower than what we've had out of TNK-BP, but we do look at the $12.3 billion of cash coming out of TNK-BP.

One way to look at it is a six to eight year acceleration of dividends from the Company.

In terms of tax on that, the structures today, there's -- we don't see a capital gains tax on the payment to us from that sale.

Okay.

Thank you.

4% would be very positive.

Would be.

Yes.

[Hutan] [Usari] from Bank of America-Merrill Lynch.

Good afternoon gentlemen.

A few questions please.

I would like to start with TNK-BP.

Obviously, you actually kind of demonstrate this in one of the slides that you've put up, which shows the combined TNK and Rosneft entities.

Seems like there's a lot of overlap.

Maybe you can give us some preliminary estimates of the sort of synergies you expect this entity to pull out if we assume that Rosneft were to buy 100% of the entity.

Next question really is with regards to dividends.

We know that the sale of the TNK-BP stake was mildly dilutive to your earnings, and there has been suggestions that you would look to mitigate that via buybacks.

Is today's increase in dividends instead of that or can you see the two co-existing together later on?

And then the third question, largely around the refining side.

Obviously you've sold Carson.

You've sold Texas City.

I just wanted to see in the third quarter how much of this exceptional performance was down to these two refineries.

Thank you.

Hutan hello, this is Bob.

Thanks for your question about TNK-BP.

This regards synergies between Rosneft and TNK-BP, should that transaction occur the way you describe it for the full merger of the two.

We would expect there to be some.

It's really a question for Rosneft.

I'd note that on the 23rd of October, Rosneft Webcast the Igor Sechin said he hoped to realize some $3 billion to $5 billion of synergies from the acquisition.

I know personally from those assets that there is significant industrial synergies, real industrial synergies because of developments that are near each other that aren't connected and pipelines planned in different directions.

So that's probably a very realistic or a conservative estimate that was made by Rosneft.

Let me turn the question to Brian on the dilution.

We've been talking to shareholders and also the refining question.

Yes thanks Hutan.

So specifically on the question around the increase in dividend, that was really as a consequence of the fact that we delivered $11 billion of announcements around divestments in 3Q.

We've gone back and reviewed our plans around the 10 point plan for 2014.

They are well underpinned.

And so, with that renewed confidence around the cash flow targets, we felt we could comfortably move the dividend up $0.01 earlier than we'd originally planned in terms of the financial frame.

And that is not in lieu of anything that we choose to do around the $12.3 billion of disposal proceeds.

So don't read across the two things.

This is really about confidence in terms of the plans that we have laid out in front of us.

And we have been talking to shareholders about what we do with that $12.3 billion.

As a minimum, we calculate the dilution on an earnings-per-share basis at around $3 billion to $4 billion -- 3% to 4%.

Which would require a reduction in the share base of around $4 billion as a minimum.

And I think it's reasonable to say if you've sold $38 billion of assets, you've shrunk the equity, you should also shrink the share base.

So that's kind of what our intent is there.

On the refineries, what they contribute in terms of 3Q, just over half of the downstream result came from the United States in 3Q.

But the majority of that result in 3Q came from assets which we'll be retaining in the portfolio going forward.

Very clear.

Thank you very much, gentlemen.

Jason Gammel of Macquarie.

Yes, thank you very much.

First of all, just wanted to ask a question related to upstream margins and the maintenance program.

Bob, you mentioned that you would expect the TAR amount to be about the same in 2013 as 2012.

Can I assume that's number of turnarounds and not necessarily the amount of production that is affected by turnarounds?

And then second of all just as it relates to the upstream margin, we are forecasting that we'll see a pretty nice pick-up in margins moving forward as a result of the return of Gulf of Mexico, North Sea in particular, but we haven't really seen that yet.

Would you expect 3Q to be let's say an inflection point in the upstream margin and that we would start to see growth in the margin per barrel in 4Q and forward?

Jason thanks.

So we've said that we expect the number of TARs in 2013 to be about the same as 2012.

Some of the numbers, we had allowed -- 47 of them in 2011, we've been down to 30 roughly this year.

We expect 27 next year.

But the number of days, the turnaround days next year in 2013, we'd expect to be about a third lower than 2012.

In terms of the upstream margins, during the third quarter we've had significant outages, planned maintenance outages in the North Sea like we've said, in the North Sea and also in Alaska.

Typically you see the Gulf of Mexico do a lot of its turnarounds in the second quarter, and then you have the hurricane season in the third -- second and third quarters.

We do expect production to come back on in the fourth quarter, and you would expect to see a margin increase in the fourth quarter.

Thanks very much, Bob.

Robert Kessler from Tudor Pickering.

Hello, good day everyone.

Three quick questions for me.

One is on the Carson refinery sale, have you received first response from the FTC regarding approval for the sale of that asset or that group of assets to Disoro?

And then I suppose somewhat related to that, is a medium term CapEx question.

Now that you've sold a bunch of assets and in line with your comments around confidence in the dividend, can you give us a medium term CapEx number ex-divestments?

And then finally in the Gulf of Mexico, thanks for the color on Thunder Horse and the timing around the 2014 water injection project.

That was something I was wondering seeing this cue of injector well approvals you've received.

I also see a number of producer well approvals.

And I'm wondering -- and a few of those have already been predrilled.

So I'm wondering if you're cueing up producers to the point that you start the injection, or might we see some producer wells come online before the 2014 water injection program?

Okay Robert, you've got a whole menu there of questions.

On Carson, yes, we have received the first response.

I think as often happens, it's a long list of questions for us, and no doubt Disoro to answer.

So we're working through a very long set of responses and questions there.

And in terms of CapEx going forward, we're in the $22 billion to $23 billion range in CapEx this year.

Brian, you want to comment?

Yes.

No in terms of the medium term, around the 10 point plan, we see the gross CapEx out to the 2014 being around $24 billion to $25 billion.

So in terms of the medium term, it's around $24 billion to $25 billion.

And that's consistent with what we said around the 10 point plan.

And on your question about Thunder Horse and rigs, let me give you a just sort of broad description of the rig activity overall.

We've got seven rigs now running in the Gulf of Mexico, another eighth one there.

We'll look at even bringing on another one next year.

We have two on Thunder Horse.

We have two on Nikika, and two on Atlantis that are doing primarily productive well work, and we have one on the Kaskida appraisal well which is going down right now.

I think in 2013, you'll see us with the injection wells.

You'll see us having to take down that facility for a while to be able to tie in the new facilities in there, and I think this is what we regard as sort of a beginning of a redevelopment of Thunder Horse.

We've produced about 15% of the resources still there, with 85% yet to go.

This is a project for the next decade that will probably see its low point as we're doing this re-injection work, and then it will come back strong through the decade.

I'm not sure if I asked you or answered your specific question.

Thanks for that.

Can I just clarify on the Thunder Horse rigs, those are -- you would have two independent floaters in addition to the drilling capability that you've got on the Thunder Horse platform, is that correct?

We've got two working on the Thunder Horse platform itself.

We are looking at a redevelopment of Thunder Horse that would take other floaters and do other work out in that field, whether that's 2013 or 2014 or 2015, we're still looking at the investment case, which does look strong.

Okay.

Thanks very much.

Alastair Syme at Citi.

Yes, thanks everyone.

Can I just ask on TNK Rosneft again, having so carefully realigned E&P around where you think you can add value, I wonder whether you think BP could bring anything operational to the Rosneft structure?

And if the answer is it's only a financial investment, I wonder how you would compare the value at Rosneft equity to your own equity.

So Alastair, we've been very careful during this transaction, working with Rosneft to be clear this was a divestment of our interest in TNK-BP.

An all cash transaction is just simply not possible.

And one of our objectives through this was to remain with a solid position in Russia, which we look at as a great oil and gas province for decades to come.

So this step was a conversion with equity, Rosneft equity.

We know Russia well.

We see that Rosneft has many opportunities to increase efficiency that can increase the value of that Company.

And we hope to be able to provide suggestions through our role in the Board, and that's probably about all we can say now.

Thank you.

Peter Hutton at RBC.

Good afternoon.

Just a couple of quick questions.

Can you quantify the impact of the Alaska maintenance in the second quarter?

I'm just trying to get an understanding of what the turnaround in fact was on the Gulf of Mexico.

And also on the list of projects that you've got coming through to 2014, can you just give an indication as to of those given the ramp-up, and although those sort of towards the end of that period, what kind of -- what the volume of production in 2014 is likely to be from the sum total of those projects?

So Peter, your question is very detailed one about Alaska and the turnarounds in the Gulf.

And I think it's probably best if you get back to IR.

Our IR team, and they'll be able to give you what we can in terms of making sure it's not selective disclosure.

And we have been very careful not to give guidance on specific production rates from these projects, and the overall production for the Company.

Those 15 projects which are coming on, three are on now already.

I can just say that the margins from those projects will be double the average margin of our upstream portfolio.

But as they come on, we'll lay out production volumes from the projects as they come on.

But I think Peter, we're not going to be able to lay those out in the detail you'd like.

Okay.

All right.

Thank you.

[Tipam] [Jothelindgram] from Nomira.

Thanks Jess.

Good afternoon Bob, good afternoon Brian.

Three questions, just following up actually.

Just firstly, coming back to the cash cycle framework at $100 oil, I think you've talked about the investment levels as $24 billion, $25 billion.

I was just wondering what sort of cushion do you really want when you think about the dividend in terms of sort of oil prices in that framework?

Second question, just could you talk a little bit about the deferred tax assets still sitting on the balance sheet for the Gulf spill, how that's being used, and tends to be used and any impact on group taxes?

And then lastly, early days and clearly the focus is on investment in Russia with Rosneft or investment by Rosneft in Russia, which I'm wondering about the opportunity for BP with Rosneft outside Russia.

Thank you.

I'll turn the first two over to Brian.

Yes so Tipam, on the cash cycle framework that we use, the plans and the targets we laid out we showed you at $100 a barrel.

We look to make it cash breakeven in the range of $80 to $100 a barrel depending on what the margin mix is and the volume mix.

Now obviously as that margin mix gets stronger over time and certainly beyond 2014, we get more robust than $80 a barrel.

We also run stress tests below $80 a barrel as to what we would do in those circumstances to protect the dividend.

So we feel pretty confident.

If you look at the cash flow that we're seeing come out of the business in 2014 and you look at the uses of that cash flow, we feel confident that the increase we've announced today actually more than well underpinned out to 2014 even at $80 a barrel.

On the deferred tax asset, that just simply rolls off.

As the income is realized in the United States, we utilize that tax asset going forward.

And we will be doing that in the years to come around those items which are tax deductible in the United States as a consequence of Macondo.

And Tipam on the investment with Rosneft internationally, we have not had discussions or have no commitments on international investments outside of Russia with Rosneft.

But clearly, that's an option going forward.

That's the kind of thing that you could expect us to do, just as we do with other national oil companies around the world.

So clearly it's a possibility, but it has not been the basis of our discussions.

Okay, great.

And just one last question.

I guess you've got the disposal target of $38 billion.

You're pretty much there.

Are there any plans to increase that, that program?

We're going to keep going though to make sure we meet that $38 billion target.

We've got assets identified.

But Brian?

Yes Tipam, you should assume on a go forward basis once the $38 billion is achieved, that we'll continue to look to churn the portfolio as we've done historically, around about $2 billion to $3 billion of disposals per annum beyond the $38 billion.

So you should assume that's part of our financial frame going forward.

Okay, great.

That's very helpful, thank you.

And I would note that on the slides that you saw, slide 26, it is interesting to note that fully 50% of our upstream installations and pipelines are no longer in the portfolio in a third of our wells.

So this has been a tremendous reshaping of the portfolio.

We may not have upstream steps to take that are quite as massive as we've done already, but we're going to keep going through it carefully.

Jess.

Iain Reid from Jefferies.

Hello, good afternoon.

Couple of questions, please.

Bob in the negotiations with Rosneft was there any discussion of BP getting involved again in one of these big arctic exploration ventures?

Which they've obviously done with other companies now.

Is there any kind of other pieces of acreage which they're looking to joint venture with, and did you discuss that with them?

Second on the use of cash, I take your point about the buyback.

But I wonder whether BP now feels confident enough, obviously you do from a kind of dividend perspective, but do you feel confident enough to get out there and use that cash in perhaps more proactive way by trying to add to your portfolio inorganically?

And just to finish, on Azerbaijan, there's obviously been a lot of news flow around that recently.

I just wonder whether you can tell us what the situation is and what BPs' got to do in order to satisfy the government there?

Right.

Ian, thanks.

So on the arctic ventures, we did not have any discussion with Rosneft about any specific arctic projects and ventures.

I would note that Rosneft still has many, many licenses in the arctic, but that was not the basis of our discussions.

And assuming this transaction closes the way we've described it, we would effectively have ownership of 20% of all the arctic projects with some of the exploration carried.

And in terms of acquisitions for us, I think now is not the right time for BP to be on the acquisition hunt.

There's no doubt portfolios out there that might make sense, but this is a transition of the Company.

We need to make sure we meet our obligations in the US.

We've just taken some big steps with the portfolio, so you would not expect BP to be out there on the acquisition hunt right now.

And in Azerbaijan, our upstream leadership team has been down there last week.

I've had a number of meetings with SOCAR and discussions with the President.

I think were on track now to solve the issues around production in 2013 and going forward.

So I don't want to speak for SOCAR here, but I think they've made some public statements about BP's role there and I think we're on the case.

We know what the issues are, and have made a lot of progress in the last month on that.

Okay.

Thanks a lot.

Thanks Ian.

Martin Rats at Morgan Stanley.

Yes, good afternoon.

Two questions.

First of all, I saw the statement about 50% growth in operating cash flow repeated.

Now earlier in the year before the disposal of TNK-BP came into play, that was bound to be misinterpreted because it meant $33 billion of operating cash flow by 2014.

But given that the wording is unchanged, does this still mean $33 billion of operating cash flow by 2014, or should we adjust that now for the difference in the dividend between TNK and the dividend of Rosneft?

That was one question that I had.

And the other question relates to the $2 billion to $3 billion of ongoing disposals.

Given that you've now done so many disposals already, is it still easy to find disposal targets that you can sell but that don't hurt operating cash flow all that much?

I.e., if the ongoing plan is $2 billion to $3 billion of disposals every year, what will be the impact of that on operating cash flow?

So Martin, I'll take both of those.

So first of all, you're right on the target.

You will have noticed what we've now said is in terms of 50% more operating cash in 2014, we've now said more than 50%.

If you take TNK-BP out and the $3.7 billion of dividend in 2011, our dividend that we were planning in 2014 was lower than that by a factor of at least 50%.

So now the target that would have been $33 billion, looks more like $31 billion to $32 billion.

And if you swap the TNK dividend and then you could, and Bob said earlier, you could actually describe this is with accelerated $12.3 billion worth of dividends, six or eight years of dividends forward.

But that number's now $31 billion to $32 billion depending on the Henry Hub price.

If the Henry Hub price stays where it is today, it's more towards the $31 billion.

If it's up at $5, which is what we'd originally assumed it would be more closer to $32 billion.

So that's the first piece.

And then on the second piece, there is, for a portfolio of our size and scale, the way to think about this is we've sold off something like $32 billion of our upstream properties, representing 10% of our reserves.

There is plenty in the portfolio where we'll choose not to invest, other investors will invest.

And I think it's right that we materialize that value back within the financial frame.

So we've got a long history of being able churn at that level.

I'd fully anticipate we could do that going forward.

Okay.

Thank you.

Oswald Clint at Bernstein.

Yes, thank you very much.

Good afternoon.

You made some comments within your press release this morning about moving beyond 2014 about the expectation to increase investment within the upstream, and a focus again on higher margin areas.

Just in the context of that statement, could you talk about that in terms of what it means for the CapEx levels beyond 2014?

And also do you still see a lot of high margin areas out there in order to actually go after?

The second question was kind of related to your gas Value Chains again, and some of the comments we've seen recently on Alaska LNG, and is that one of them?

And how does that fit with the $1 per ton number that's implied by the CapEx numbers that we've seen over the last few weeks and months?

Thank you.

Oswald great, great question.

As we do look out over the decade beyond 2014, well let me start with where we are today with 65% of our operating cash flow from the high margin areas collectively of Azerbaijan, Angola, the North Sea, and the Gulf of Mexico.

As we look out in the decade, we see projects in those areas as well.

So if we look out 10 years from now, we still see very healthy contributions and high margin contributions from those four places alone.

So, as we finish the Whiting Refinery Modernization Program in 2013, you should see an expectation of the percentage of our capital investment going more into the upstream.

And in terms of exact guidance for CapEx, when we have our upstream Investor Focus Day on December 3rd, we'll give you more insight into that.

I will say as a Company, when you look at the portfolio and kinds of projects that we see in the next decade, we intend to maintain discipline in our capital frameworks.

Because we could identify projects of $30 billion or more a year later out in the decade.

We don't intend to operate at that kind of level of CapEx.

We want to balance our operating cash flows and our investments to make sure that we have suitable free cash flow for distributions going forward.

We'll give you a little more insight into that in December.

And on Alaska LNG, Alaska probably has a window where with its fiscal system where it needs to create the right incentives to create the framework for investments like that.

We would like to see both the liquids hydrocarbon financial framework there, which is a pretty onerous one, improve.

And that will be part of improving the circumstances for a big LNG investment there as well.

We continue to give our views to Alaska and the government there as I'm sure some of our partners have views as well.

So, it would be good to see that Alaskan gas monetized.

It sort of missed the window of bringing it down by pipeline to the Lower 48.

And we're going to remain constructive about the possibility for it later in the decade.

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

That's great Bob.

Thank you very much.

Rahim Karim of Barclay's.

Hello Jessica.

Thank you very much.

Good afternoon gentlemen.

Two questions, if I may.

The first was just around integrity spend.

Bob, you talked about the realization of some of the benefits from the higher levels of turnaround that we've seen in the past, and how that will fall over time.

I was wondering if you could give us some sense of how costs associated with those will evolve and whether we should see a decline in overall costs associated with those.

And then, just to go back to another question associated with TNK-BP.

I was just wondering if there were any BP seconDs that were currently with TNK-BP, and whether those will come back to BP or whether they will remain with Rosneft as part of the joint venture that you have with them.

Thank you.

While we're looking up some of the numbers on your questions on the turnarounds, I'll take the last question Rahim.

We do have people from BP that are working inside of TNK-BP, and certainly I can't remember the number right now, but certainly the sekon Ds we would be happy to have the skills and capabilities back in BP, assuming that this transaction goes forward.

And in terms of Rosneft itself, I noticed that they're on a recruitment drive for international expertise.

I see that happening.

And I see even some of the ex-TNK-BP managers have left and are working in Rosneft, and ex-BP employees are working in Rosneft.

That's not a coordinated plan that we have with Rosneft.

I just noted as what I see as a very real objective on the part of the CEO and the management team to bring in as much global expertise as possible into the Company.

On the turnarounds, I'm going to ask Brian here.

Yes Rahim, we don't normally break out the integrity spend.

But I think the key message is going forward that will trend down, given we've gone through a big intensive period of turnaround in 2011, 2012.

Again as Bob has highlighted in 2013, that will start to trend down as we get out -- come out of 2013, into 2014, '15, and '16.

Okay.

Thank you very much.

Irene Himona from Soc Gen.

Yes, thank you.

Good afternoon.

Two questions, please.

So firstly, you're increasing the capital expenditure guidance somewhat for this year.

Can you remind us what the exploration number is for this year.

I believe the ENA spend previously was about $4 billion.

And is that why you're raising the guidance?

And then secondly, can you talk a little bit perhaps about a recently publicized plan for LNG in Alaska?

I believe the press was mentioning a $65 billion investment over 10 years.

Thank you.

Yes Irene, I'll start with the Alaska point.

And then we're just going to just look quickly on the exploration point.

Exploration, appraisal point, certainly $4 billion is certainly higher than our capability would allow us to do in terms of exploration spending.

We do exploration spending, appraisal spending, and we do seismic work.

But Brian has got the figures on that in a second.

And on Alaska, I think there is a tremendous gas cap and the point Thomson field in Alaska that doesn't have a market today.

And if that program were to move at pace and you were to bring something down on the tide water area of Alaska and build a multi-train LNG project with pipelines that go up and down, and you took the capital costs and the operating costs, maybe that's an estimate that's been put out there.

There is engineering work being done on that project, but it's very early days to give an estimate like that in terms of both a pacing of the construction of trains and the market itself.

Yes.

So Irene on the exploration appraisal, no $4 billion is way higher than anything that we've carried historically.

The inflation that we're seeing this year is not coming from the exploration side.

It's some sector inflation's come through, and some higher project costs, and the phasing of some activity of expenditures.

But I think the regional guidance we gave you this year was $22 billion.

It may be in the $22.5 billion close to $23 billion but that's not associated with exploration or appraisal.

Okay.

Thanks so much.

Yes, and Irene I believe you look at the CapEx piece alone of exploration, it's about $1 billion this year on exploration, and probably would be about the same on the exploration appraisal in 2013 as well.

Thank you.

Jean-Luc Romain of CM CIC.

Good afternoon.

I've got a question on exploration in Brazil with [semsee].

I know it was regulatory declaration.

But the client that you're all weapon stated in a well drilled very close to big discovery of red salt.

And block icing BMC for (inaudible).

Could you give small details about that.

Well we've got in our exploration program in Brazil, we've had some discoveries this year, but we have got to follow through the regulatory process and approval there of the government.

We're evaluating the discoveries as well.

So it's not right for us to comment about a specific discovery, and what we'll do is give you some guidance when we -- when we're able to.

Thank you very much.

Collin Smith from VTB Capital.

Yes.

Good afternoon gentlemen.

I wonder, was wondering if you could give a little bit more color if you're able to, about what you think earnings might do.

Because obviously it's been a tremendous focus on the improved cash generation.

And in connection with that, I'd be interested to know how you think about dividends as it fits with earnings as well as in relation to your ability to pay it as a result of the cash generation.

Thank you.

I think, so firstly, you will have seen that our depreciation DD&A has gone up this year, as the higher margin barrels we pursue clearly have high DD&A to go with them.

So therefore, I'm not sure how helpful earnings are.

If you go to EBITDA or cash conversion to get to operating cash flow, and then how we use that operating cash flow is really how we think about the divvy.

And therefore, the focus really out to beyond 2014 will be around free cash flow and sustainable free cash flow delivery.

But In terms of earnings and its conversion in terms of covered with dividend, that's not really something we look at in terms of financial frame.

And that's true when it comes to the Board discussion, there's not a consideration about payout ratios or anything of that nature in relation to earnings?

No.

So we look at earnings-per-share which is an important measure, and that's why we said around the Rosneft transaction, we'll look to make sure that we're non dilutive in terms of earnings-per-share i.e.

getting back to this issue that we've shrunk the equity therefore we need to shrink the share base.

Okay.

Thank you.

Lucas Herrmann from Deutsche Bank.

Jess, gentlemen, good afternoon.

Three if I might.

The first, Brian, was just to ask if you could clarify a comment you made earlier.

You said you review the dividend on an annual cycle.

Given this is the second increase through the course of this year, I just wonder if you could make sense, some greater sense of the statement.

Secondly, can you comment at all on the CapEx obviation that you're effectively going to see in the downstream, and leaving aside Whiting, you've sold two major refineries, just to give us some idea of the CapEx that you all avoid as a consequence.

And thirdly, I just wondered whether you can give any insight into the level of production that you'd expect Thunder Horse to trough at as we go through 2013, 2014 and you go through the work over of that platform.

Thanks very much.

So Lucas, I'll pick up the first piece around the dividend and annual cycle.

We typically as part of our annual planning cycle will look in terms of the financial frame can deliver in the subsequent year, and see whether that accommodate through our plans an increase in dividend, provided we see can sustainably free cash flow coming through.

We effectively this quarter, having got a lot behind it in terms of the $11 billion in disposal proceeds, underpinning of 2014 in terms of the cash flow delivery felt now was the time to actually reward our shareholders and come out with revised dividend now.

You should not take that as a guide for the future.

We'll continue to come back to the annual plan cycle and indeed actually we'll review the dividend on a quarterly basis going forward.

But effectively it's part of our annual cycle that we do with the Board.

But Brian, the next annual cycle starts when?

As in when you comment in January, February or has it just started now?

We would typically go to the Board with our plans in the fourth quarter of 2000 -- of this year for next year.

Thanks very much.

Yes, I think I'll just add Lucas, the idea of being able to create consistency is obviously the objective of the Company and the Board as well.

I think we reward the patience of shareholders.

We've done something here as we felt like we're able to too early.

We won't certainly say when we'll do it, but we would like to get back to early part of 2014.

But I think we've said we'll increase the dividends with the rising and improving circumstances of the firm.

There's certain flexibility there.

On the CapEx obviation, I would expect when the Whiting Refinery Modernization Program is done, we'll go from, say, an annual CapEx spending on that project maybe next year of around $1 billion, and that will be turned in, we think could be incremental operating cash flow of $1 billion.

So that will be a significant step for the Company.

That will bring down the CapEx levels of our refining and marketing business, broadly in levels equal to depreciation.

But -- sorry, Bob.

No it was just Texas City and Carson must have required significant spend as well.

You've been spending $4 billion on refining in recent years.

Should we expect that to move to nearer $2 billion once Whiting is completed?

Yes.

No Lucas, Texas City and Carson have both been assets held for sale.

So we haven't been capitalizing any of the expense and that's been getting expensed, not capitalized.

Okay, forgive me.

And your third question, Lucas.

Was just some indication, Bob on where you think Thunder Horse will trough?

I think what we'll do when we lay this out in December is give you an indication of the overall Gulf of Mexico and the plans that we have for the redevelopment of Thunder Horse, as well as the overall package of assets from our four big hubs there.

But we do see growth from Thunder Horse from 2014 out through the remainder of the decade.

Okay.

Bob, thanks very much.

Okay.

Thanks, Lucas.

Jason Kenney from San Tan Deux.

Hello, good afternoon and what a difference a quarter makes.

Good to hear the numbers today.

I've got a couple of questions.

A follow-up on an earlier question on arctic exploration in Russia.

And I just wanted to confirm that as a partner in Rosneft, you will essentially not be exposed to any arctic exploration costs, because they will be carried by the third party licensees in those arctic territories.

And whilst on Rosneft, is it too early to comment on maybe the low hanging fruit from Rosneft?

And I'm thinking here of the Bazhenov shale oil resources thought to be bigger than Nyvakin.

I'm sure you're anticipating some material value for BP by enhancing Rosneft to earnings here.

But I was just wondering when you envision that to potentially happen.

And then finally on the dividend, coming back to the dividend, I think most people would have expected some sort of dividend commitment once the cessation of the escrow commitment had finished.

And obviously that's 2013.

You've seen a smashing early cash boost from the downstream in Q3.

Is that essentially why you jumped early into the dividend increase?

And is the dividend increase therefore supported by the escrow cessation next year?

I'm just trying to toy with the makeup of the commitment there.

Yes Jason, so first, your question about arctic exploration.

We don't know all of the details of each of the agreements that have been made.

Rosneft has signed agreements with Stat Oil, with E&I and with Exxon Mobil.

But we understand that there's exploration carries with those, so I think the answer is given where we are today, we're not exposed to being -- to those projects other than would be, assuming again the transaction goes forward a shareholder in Rosneft.

And again, we did not discuss arctic exploration projects with them in detail and certainly none with us during this transaction negotiation.

On the low hanging fruit, the Bazhenov shale oil clearly has great potential.

The tax structure in Russia has not afforded much incentives to develop that kind of shale oil or heavy oil.

However, earlier this summer draft legislation was put forward to change the structure to be able to create the incentive for people to go into the shale oil projects like the Bazhenov.

I believe Exxon Mobil is working towards doing that kind of cooperation with Rosneft.

And just without knowing the specifics of all the basins and the geology, I believe that Russia has significant potential in shale oil and even heavy oil in some places.

So let me turn it over to Brian to your question on the dividend.

Yes Jason, just to reconfirm on the dividend, there was no real read across in terms of the commitments around the trust fund.

The key is that will be fully funded there this quarter.

The payment going in is lower than the typical payment, because it's around $860 million versus $1.25 billion given the advanced payments we've put in from some of the recoveries.

But this is really about the fact that actually the disposals, we're well ahead of our original schedule.

Some of the proceeds we were getting for these assets were quite extraordinary compared to what we're holding as net asset values.

That created the stronger financial frame and allowed us to accelerate what we would have planned as a potential dividend increase next quarter.

Great stuff.

Thanks.

And the escrow account will be finished this quarter.

Yes, the escrow account will be finished this quarter.

15th of November the final payment goes in.

Okay.

We don't have any other questions.

And first I'd like to say those of you on the East Coast, thank you for your perseverance.

I can imagine sort of what kind of day it is.

And I know that there are some people who have sent us notes and are not able to get even phone lines out of the East Coast.

Doug Terreson you must be feeling good in Alabama that you haven't had to deal with a hurricane, and are on the right side of the location this time.

Ladies and gentlemen, thank you again for your questions.

I think and just as a summary remark, I'd like to say that the Company continues to move through this transition.

It's been not a simple transition.

We've had major uncertainties overhanging the Company in Russia.

And Russia's not done until it's done.

But I think this is the outline for a transaction that's sort of win, win, win, even a four way win between Rosneft, BP and AR, and the Russian government whose desire is to further privatize, increase the value of Rosneft.

So that's an important direction we're heading in.

The increase and the decision by the Board to increase the dividend is a reflection not just of a good quarter, but the confidence that the Company has now in terms of sight and rebuilding its businesses and rewarding very impatient shareholders, and getting started on that process.

So it's a good quarter.

One quarter does not make a Company.

But the Company I'm confident is on the right track, and I'm looking forward to being able to talk about the rest of the decade in December.

Thank you all.