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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

Douglas Terreson - ISI Group Inc., Research Division

Hootan Yazhari - BofA Merrill Lynch, Research Division

Jason Gammel - Macquarie Research

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

Alastair Roderick Syme - Citigroup Inc, Research Division

Peter Hutton - RBC Capital Markets, LLC, Research Division

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

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

Martijn Rats - Morgan Stanley, Research Division

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

Rahim Karim - Barclays Capital, Research Division

Irene Himona - Societe Generale Cross Asset Research

Jean-Luc Romain - CM-CIC Securities, Research Division

Colin Smith - VTB Capital, Research Division

Lucas Herrmann - Deutsche Bank AG, Research Division

Jason Kenney - Grupo Santander, Research Division

BP (BP) Q3 2012 Earnings Call October 30, 2012 10:00 AM ET

Operator

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

Jessica Mitchell

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 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. 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 U.S. 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.

Brian Gilvary

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 U.K. taxation of North Sea production announced in 2011. High refinery 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 U.S. 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 in 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 of $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.

Noncash costs also increased year-on-year mainly as a result of high depreciation, depletion and amortization associated with the new high-margin projects and high 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 to 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 3x higher than the previous quarter. Compared to the third quarter of 2011, this result reflects positive foreign exchange effects and the favorable impact of the tax reference price lag on Russian export duties in their 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 report our share of TNK-BP's production 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 stronger operation performance, with refining throughputs at the highest level for 7 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 prime and pricing of barrels into our U.S. 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're about to start the Whiting Refinery transitional outage to replace the largest of 3 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 2 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 high 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 or 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 a charge against income on that basis.

I would like to highlight that the U.S. 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 whilst 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 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 Deepwater U.S. Gulf of Mexico; the Sunray and Hemphill gas processing plants in Texas; our interest in the Draugen field in the Norwegian sector; and our Malaysian PTA interests. 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 sources and uses of cash in the first 9 months of 2011 and 2012. Operating cash flow in the first 9 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 9 months was $17.1 billion. We received $4.6 billion of divestment proceeds during the first 9 months with $1.4 billion in the third quarter. Organic capital expenditure in the first 9 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 then payment 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.

Robert W. Dudley

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 the 3rd of December 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 U.S. legal position.

As we announced last week, we have 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 the 18th of October. 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 2 seats on Rosneft's 9-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 new 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 plan TNK-BP and Rosneft developments in the Yamal peninsula and 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 Sakhalin, 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, Ruhr Oel. 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 U.S. 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 Plaintiffs' 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 the 25th of February, 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 U.S. 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 Risk function, the reorganization of the upstream business onto 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 the 3rd of December. 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 2 years, we have fundamentally repositioned BP through an extensive change program addressing 3 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 process safety events compared to the first 3 quarters of 2011.

In the downstream, our refining throughput hit a 7-year high in the third quarter, underpinned by sustained improvements in refining availability over the last 5 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 and 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 have made into turnarounds over the past 2 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 8 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, altogether, 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, deepwater, giant fields and gas value chains. The period of repositioning our downstream business to improve margin quality and efficiency of the portfolio will be significantly complete by the end of 2013 as the Whiting Refinery Modernization Projects comes onstream, and the divestments in the U.S. of the South West Coast fuels value chain and the Texas City refinery are finalized.

In addition, we continue to focus our Alternative Energy portfolio, exiting solar and canceling 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 9 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 deepwater, 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 a slide we showed you in February, which laid out our roadmap for growing value, our 10-point plan, which outlined the 5 things you can expect of us and 5 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 2 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. And 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 high-margin upstream projects all remain on track. We plan to use around half of this extra cash for re-investment and half 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, Clochas-Mavacola in Angola, and Devenick in the North Sea. Three more are very close to completion. We expect Angola LNG, PSVM and Skarv 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 3 new final investment decisions or FIDs this year and expect to make another 5 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 high-margin opportunities. We plan to deliver this through increased upstream re-investment 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 4 high-margin areas: Angola, Azerbaijan, the Gulf of Mexico and the North Sea. Over the next 5 years, we will invest to grow or maintain production in all 4 of these high-margin regions with major projects that include the CLOV, Pazflor Phase 2 and Kizomba satellites in Angola, another Chirag oil project, the Aziri subsea project and the Shah Deniz full field development in Azerbaijan, Phase 3 of the Na Kika project, the Thunder Horse water injection project, the Mars B project and the Mad Dog Phase 2 project in the Gulf of Mexico and the Kinnoull project in the North Sea along with Quad 204, Clair 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 have started up 9 new rigs in 2012 and we will be operating 55 by year end: 21 onshore and 34 offshore, including 12 in the deepwater. 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 4 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 2-year absence of drilling, we now have 7 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 re-investment 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 created a much larger prospect inventory, increasing our exposure to new exploration areas outside of our traditional focus areas. Half of our prospect inventory comprises new plays and half is in proven plays in known basins. We are excited about the quality and the 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 Namibia. 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 subsalt imaging. We've begun to test our new portfolio and expect to complete 9 wells this year, including wells in Angola, Brazil, the North Sea and Namibia. 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 on stream. With the recently announced divestments in the U.S., 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 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 re-investment 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 the 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 and confidence in our ability to deliver.

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

Right. We'll be taking calls today from both the U.K. and the U.S. We know we have some calls in the U.S. 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 U.S.

Douglas Terreson - ISI Group Inc., Research Division

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?

Robert W. Dudley

Doug, it's Bob. Well, there's a couple of things. TNK-BP has been a great investment for BP. It's been a joint venture, it's sort of run its course now. It has been very healthy in terms of its dividend flow. 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 6- to 8-year acceleration of dividends from the company. In terms of tax on that, the structures today, there is -- we don't see a capital gains tax on the payment to us from that sale.

Douglas Terreson - ISI Group Inc., Research Division

4% would be very positive.

Robert W. Dudley

Would be.

Jessica Mitchell

Right, we'll take the next question from Hootan Yazhari from Bank of America, Merrill Lynch.

Hootan Yazhari - BofA Merrill Lynch, Research Division

A few questions please. I would like to start with TNK-BP. Obviously, you actually kind of demonstrate this on one of the slides that you've put up, which shows the combined TNK-BP 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 2 coexisting 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 2 refineries?

Robert W. Dudley

This is Bob. Loosely regards synergies between Rosneft and TNK-BP, should that transaction occur the way you describe it for the full merger of the 2, we would expect there to be some. It's really a question for Rosneft. I note that on the 23rd of October, Rosneft webcast, Igor Sechin said that 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.

Brian Gilvary

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 a cent 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 2 things. I mean, 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'd 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 where our attention is there. On the refineries, what they contributed in terms of 3Q, just over half of the downstream result came from 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.

Jessica Mitchell

Moving now to Jason Gammel of Macquarie.

Jason Gammel - Macquarie Research

First of all, I just wanted to ask a question related to upstream margins in 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 pickup in margins moving forward as a result of the return of Gulf of Mexico and 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?

Robert W. Dudley

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 1/3 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.

Jessica Mitchell

Back to the U.S., Robert Kessler from Tudor, Pickering.

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

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 to -- or that group of assets to Tesoro? 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 x 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 queue 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 pre-drilled. So I'm wondering if you're queuing 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?

Robert W. Dudley

Okay, Robert, you 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, Tesoro 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 of this year. Brian, you want to comment?

Brian Gilvary

Yes, in terms of 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.

Robert W. Dudley

And on your question about Thunder Horse and rigs, let me give you just sort of broad description of the rig activity overall. We've got 7 rigs now running in the Gulf of Mexico, another 8th one there. We'll look at even bringing on another one next year. We have 2 on Thunder Horse, we have 2 on Na Kika and 2 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 the 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. We'll probably see its low point as we're doing this reinjection work and then it will come back strong through the decade. I'm not sure if I asked your -- answered your specific question.

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

Can I just clarify on the Thunder Horse rigs, those are -- you would have 2 independent floaters in addition to the drilling capability that you've got on the Thunder Horse platform, is that correct?

Robert W. Dudley

We've got 2 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 '13 or '14 or '15, we're still looking at the investment case which does look strong.

Jessica Mitchell

Right, we'll take the next question from Alastair Syme at Citi.

Alastair Roderick Syme - Citigroup Inc, Research Division

Can I just ask on TNK-Rosneft again. I mean, having so carefully realigned E&P around where you think you can add value, I wonder whether you think BP can bring anything operational to the Rosneft structure. And if the answer is that it's only a financial investment, I wonder how you would compare the value of Rosneft equity to your own equity.

Robert W. Dudley

So Alistair, we've been very careful during this transaction, working with Rosneft to be clear that 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.

Jessica Mitchell

The next question is from Peter Hutton at RBC.

Peter Hutton - RBC Capital Markets, LLC, Research Division

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 are sort of towards the end of that period, what the volume of production in 2014 is likely to be from the sum total of those projects?

Robert W. Dudley

So Peter, your question is a very detailed one about Alaska and the turnarounds in the Gulf. And I think it's probably best if you get back to IR, and they will be -- 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. There's 15 projects which are coming on, 3 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.

Jessica Mitchell

Okay, next Theepan Jothilingam from Nomura.

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

Three questions. Just following up, actually. Firstly, coming back to the cash cycle framework at $100 oil, I think you talked about the investment levels of 24, 25. 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? The second question, just -- can 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 intends 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. So I'm wondering about the opportunities with BP with Rosneft outside Russia.

Robert W. Dudley

I'll turn the first 2 over to Brian.

Brian Gilvary

So Theepan, on the cash cycle framework that we use, the plans and the target 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 down at $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 is actually more than well underpinned out to 2014, even at $80 a barrel. On the deferred tax asset, that just simply rolls off as we -- 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.

Robert W. Dudley

Theepan, 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.

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

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...

Robert W. Dudley

We're going to keep going though to make sure we meet that $38 billion target. We've got assets identified but Brian?

Brian Gilvary

Yes, Theepan. I mean, 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, ran 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.

Robert W. Dudley

And I would note that one of the slides that you saw, Slide 26, I mean, it is interesting to note that fully 50% of our upstream installations and pipelines are no longer in the portfolio in 1/3 of our wells. There 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 are going to keep going through it carefully.

Jessica Mitchell

We'll go next to Iain Reid from Jefferies.

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

A 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 a perhaps, a 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 wondered whether you can tell us what the situation is and what BP has got to do in order to satisfy the government there.

Robert W. Dudley

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 U.S. 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 where I've had a number of meetings with SOCAR, discussions with the President. I think we're 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 made a lot of progress in the last month on that.

Jessica Mitchell

The next question comes from Martijn Rats of Morgan Stanley.

Martijn Rats - Morgan Stanley, Research Division

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 in play, that was about to be misinterpreted because it sort of meant $33 billion of operating cash flow by 2014. But given that the warning 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 related 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?

Brian Gilvary

So Martijn, 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, a 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. Like if you swap the TNK dividend, and as Bob said earlier, you could actually describe this as we've accelerated $12.3 billion worth of dividend, 6 to 8 years' worth of dividends forward. But that number is 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 sort of $5, which is what we had originally assumed, it would be more close 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, I mean, 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 to churn at that sort of level. I'd fully anticipate we could do that going forward.

Jessica Mitchell

Next question from Oswald Clint of Bernstein.

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

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 '14? 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 kind of dollar-per-ton number that's implied by the CapEx numbers that we've seen in the last few weeks and months?

Robert W. Dudley

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 4 places alone. So as we finish the Whiting Refinery Modernization program in 2013, you should see an expectation, a percentage of our capital investment going more into the upstream. And in terms of exact guidance for CapEx, when we have our upstream investor-focused day on December 3, 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 a 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 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 are going to remain constructive about the possibility for it later in the decade. I think that's probably all I should say about that, Oswald.

Jessica Mitchell

Over now to Rahim Karim of Barclays.

Rahim Karim - Barclays Capital, Research Division

Two questions, if I may. The first was just around integrity spend. Bob, you talked about the realizations from the benefits from the high level of turnaround that we've seen in the past and how that -- it 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 secondees 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.

Robert W. Dudley

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, any secondees, we would be happy to have those skills and capabilities back in BP, assuming that this transaction goes forward. And in terms of Rosneft itself, I notice 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've just noted as what I see as a very real objective on the part of the CEO and the management team to bring as much global expertise as possible into the company. On the turnarounds, I'm going to ask Brian here.

Brian Gilvary

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 turnarounds 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.

Jessica Mitchell

Moving onto Irene Himona from Soc Gen.

Irene Himona - Societe Generale Cross Asset Research

Two questions, please. 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 E&A 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.

Robert W. Dudley

Yes, Irene, I'll start with the Alaska point, and then we're just going to just look quickly on the exploration point, exploration and 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, we do seismic work, but Brian has got the figures on that in a second. And on Alaska, I mean, 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 in the tidewater area of Alaska and build a multi-trained 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 the pacing of this construction of trains and the market itself. And then Brian on...

Brian Gilvary

Yes, Irene, on the exploration price, no, $4 billion is way higher than anything 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 phase gives some activity of expenditure. But I think the original 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.

Robert W. Dudley

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

Jessica Mitchell

All right. A question now from Jean-Luc Romain of CM-CIC.

Jean-Luc Romain - CM-CIC Securities, Research Division

I've got a question on exploration in Brazil. Recently, I know it was a regulatory declaration that was declined [ph], that's in basis of all records stated in a well drilled very close to a big discovery of Repsol in block, I think BM-C-33. Could you give us more details about that?

Robert W. Dudley

Well, we've got -- in our exploration program in Brazil, we've had some discoveries this year. But we have got to follow sort of 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 are able to.

Jessica Mitchell

Right. Colin Smith from VTB Capital.

Colin Smith - VTB Capital, Research Division

I wonder -- was wondering if you could give a little bit more color, if you're able to, about what do 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 a cash generation.

Brian Gilvary

I think so. Firstly, you'll 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, it's really how we think about the divi 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 to in terms of cover with dividend, that's not really something we look at in terms of financial frame.

Colin Smith - VTB Capital, Research Division

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?

Brian Gilvary

No. So we look at earnings per share, which is an important measure, and that's why we've said around the Rosneft transaction, we'll look to make sure that we're non-dilutive in terms of earnings per share, i.e., to getting back to this issue that we shrunk the equity, therefore, we need to shrink the share base.

Jessica Mitchell

Okay, Lucas Herrmann from Deutsche Bank.

Lucas Herrmann - Deutsche Bank AG, Research Division

Three, if I might. 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 -- I mean, leaving aside why, seeing you've sold 2 major refineries -- just to give us some idea of the CapEx that you will avoid as a consequence. And thirdly, I just wonder whether you can give any insight into the level of production that you'd expect Thunder Horse to trough at as we go through '13, '14, and you go through the work-over of that platform.

Brian Gilvary

So Lucas, I'll pick up the first piece around the dividend annual cycle. We typically as part of our annual planning cycle, will look in terms of what the financial frame can deliver in the subsequent year and see whether that can accommodate through our plans an increase in dividend provided we can see sustainably free cash flow coming through. We, effectively, this quarter, having got a lot behind us in terms of the $11 billion disposal proceeds, underpinning at 2014 in terms of the cash flow delivery, felt now was the time to actually reward our shareholders and come out with a revised dividend now. You should not that take as a guide for the future. We'll continue to come back to the annual plan cycle. And indeed, actually we review the dividend on a quarterly basis going forward. But effectively, it's part of our annual cycle that we do with the board.

Lucas Herrmann - Deutsche Bank AG, Research Division

But, Brian, the annual -- the next annual cycle starts when, as in when you comment in January, February, or has it just started now?

Brian Gilvary

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

Robert W. Dudley

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 to reward the patience of shareholders, we've done something here as we felt like we're able to early -- we won't certainly say when we'll do it, but we would like to get back to early part of '14. But I think we've said we'll increase the dividends with the rising, improving circumstances of the firm. There is certain flexibility there. On the CapEx obviation, I mean, 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 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.

Lucas Herrmann - Deutsche Bank AG, Research Division

Sorry, Bob, I was just -- I mean, 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?

Brian Gilvary

Lucas, Texas City and Carson have both been assets held for sale, so we haven't been capitalizing any of the expense in those -- it's been getting expensed, not capitalized.

Lucas Herrmann - Deutsche Bank AG, Research Division

Okay, forgive me.

Robert W. Dudley

And your third question, Lucas?

Lucas Herrmann - Deutsche Bank AG, Research Division

It was just some indication, Bob, on where you think Thunder Horse will trough.

Robert W. Dudley

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 redevelopment of Thunder Horse, as well as the overall package of assets from our 4 big hubs there. But we do see growth from Thunder Horse from 2014 out through the remainder of the decade.

Jessica Mitchell

And now to Jason Kenney from Santander.

Jason Kenney - Grupo Santander, Research Division

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'll 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, was it too early to comment on maybe other low-hanging fruit from Rosneft? And I'm thinking here of the Bazhenov shale oil resources thought to be bigger than the Bakken. I am sure you're anticipating some material value for BP by enhancing Rosneft earnings here. But I was just wondering when you envisage 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.

Robert W. Dudley

Yes, Jason, so first, your question about Arctic exploration. We don't know all the details of each of the agreements that have been made. Rosneft has signed agreements with Statoil, with ENI and with Exxon Mobil. But we understand that there is exploration carriers with those, so I think the answer is, given where we are today, we're not exposed to being -- to those projects other than as a -- would be, assuming again the transaction goes forward to 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 has -- 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.

Brian Gilvary

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, that will be fully funded this quarter. The payment going in is lower than the typical payment because it's [indiscernible] than 60 versus $1.25 billion, given the advance payments we've put in for 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're getting for these assets were quite extraordinary compared to what we're holding as net asset values. That created a stronger financial frame and allowed us to accelerate what we would have planned as a potential dividend increase next quarter.

Robert W. Dudley

Did you -- and the escrow account will be finished this quarter.

Brian Gilvary

Yes, the escrow account will be finished this quarter.

Robert W. Dudley

This quarter.

Brian Gilvary

15th of November, the final payment goes in.

Robert W. Dudley

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 to 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 the hurricane and are on the right side of the location this time. Ladies and gentlemen, thank you again for your questions. I think 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 is not done till it's done, but I think this is the outline for a transaction that's sort of win-win-win, even a 4-way win between Rosneft, BP and AAR and the Russian government, whose desire is to further privatize and 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 site 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 am confident, is on the right track, and I'm looking forward to being able to talk about the rest of the decade in December.

Jessica Mitchell

Thank you all.

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Source: BP Management Discusses Q3 2012 Results - Earnings Call Transcript
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