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 Q3 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 Gilvari, 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.
Thank you, Jess. Today is the presentation of our Q3 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 Q3 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.
Thanks, Bob. I'd like to start with an overview of the Q3 financials. BP's 3rd quarter underlying replacement cost profit was $5,200,000,000 down 5% on the same period a year ago, but 40% higher than the Q2 of 2012. As we described in our 2Q results, this includes a 1 off $260,000,000 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 3rd quarter results in our downstream business.
More stable oil prices have resulted in some positive reversal of the unusual price effects seen in the Q2. As noted at the time, our earnings in the Q2 were negatively impacted by particularly volatile oil price movements, which led to a large duty lag and foreign exchange effects in TNKBP and adverse pricing of our feedstock into our U. S. Refineries. 3rd quarter operating cash flow was $6,300,000,000 In the 4th quarter, we will make a final payment of $860,000,000 to complete the $20,000,000,000 funding of the Gulf Mexico Trust Fund.
We would like to announce that the 3rd quarter dividend payable in the 4th 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 3rd quarter replacement cost profit before interest and tax was $4,400,000,000 compared with $6,300,000,000 a year ago and $4,400,000,000 in the 2nd 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 the investments 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 startups and improved operating performance in Angola and increased volumes in other areas. Underlying volumes excluding TNKBP 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 high decommissioning costs. As we said last quarter, the 3rd 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 4th quarter reported production to be higher than the 3rd quarter as we exit the maintenance season and see the continuing benefit of our major project startups. 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 TNKBP. 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 TNKBP underlying net income was $1,300,000,000 in the 3rd quarter, 38% higher than a year ago and almost 3 times higher than the previous quarter. Compared to the Q3 of 2011, this result reflects positive foreign exchange effects and the favorable impact of the tax reference price lag on Russian export duties in the rising price environment, reversing the adverse impact seen in the 2nd quarter. Compared to the Q2, the combined price, duty lag and foreign exchange impacts had a beneficial impact of around $800,000,000 on BP's share of net income. No dividend was paid by TNKBP in the 3rd quarter.
Following the agreement with Rosneft announced last week, BP's investment in TNKBP 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 TNKBP's production reserves until the transaction closes. In the Downstream, underlying replacement cost profit for the quarter reached the record level of $3,000,000,000 compared with $1,700,000,000 a year ago and $1,100,000,000 last quarter. The fuels business made an underlying replacement cost profit of $2,700,000,000 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 operational performance with refining throughputs at the highest level for 7 years.
The refining marker margin averaged $19.50 per barrel for the quarter, the highest third quarter since 2,005 driven by refinery closures in the Atlantic Basin and low gasoline and diesel inventories globally. The 3rd quarter results also benefited from positive prime and pricing of barrels into our U. S. Refining system, which substantially mitigated the negative impact seen in the Q2 and a rebound in the supply and trading contribution to more normal levels. Looking ahead, we expect refining margins in the 4th 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 twenty thirteen. In addition, we expect to carry out major turnarounds at 2 of our refineries in the Q4. The lubricants business delivered an underlying replacement cost profit of $310,000,000 reflecting robust performance significantly higher than the same period last year despite a continued difficult market environment.
The Fetched Chemicals business delivered an underlying replacement cost loss of $20,000,000 compared with a profit of $235,000,000 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 4th quarter. In other businesses and corporate, we reported a pretax underlying replacement cost charge before interest and tax of $570,000,000 for the 3rd quarter, an increase of $170,000,000 versus the charge a year ago, primarily reflecting higher corporate and functional costs. Guidance remains a charge of around $500,000,000 on average per quarter, but remains volatile quarter to quarter. The effective tax rate on underlying replacement cost profit for the 3rd quarter was 33% compared to 30% a year ago.
Excluding the $260,000,000 impact of the 1 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 3rd quarter charge has been increased by some $60,000,000 to reflect an adjustment to provisions plus the usual quarter expenses of the Gulf Coast restoration organization. This brings the total cumulative net charge for the incident to date to $38,100,000,000 Pretax BP cash outflow relating to the oil spill cost and into the $20,000,000,000 trust fund for the quarter was $1,500,000,000 At the end of the Q3, the cash balances in the trust and the qualified settlement funds amounted to $10,900,000,000 with $19,100,000,000 contributed in and $8,200,000,000 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 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, say for those claims for which we have already provided. Turning to disposal program. We've made strong progress with our program of divestments in the Q3. Since the end of the Q2, we have announced $11,000,000,000 of asset sales.
These include our Carson and Texas City refineries in the United States together with some related logistics and marketing assets interest 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 dragom field in the Norwegian sector and our Malaysian PTA interests. Including the proposed transaction with Rosneft for the sale of our share in CNKBP, this brings the total of announced divestments to over $62,000,000,000 we have now announced more than $35,000,000,000 against our original target of $38,000,000,000 Moving now to cash flow. This slide compares our sources and uses of cash in the 1st 9 months of 20112012.
Operating cash flow in the 1st 9 months was $14,100,000,000 of which $6,300,000,000 was generated in the 3rd quarter. After excluding an outflow of $3,000,000,000 from post tax Gulf of Mexico oil spill related expenditures, underlying operating cash flow in the same 1st 9 months was $17,100,000,000 We received $4,600,000,000 of divestment proceeds during the 1st 9 months with $1,400,000,000 in the 3rd quarter. Organic capital expenditure in the 1st 9 months was $16,500,000,000 $5,900,000,000 in the 3rd quarter. In the 4th quarter, we expect to receive disposal proceeds of $6,000,000,000 and to make our final payment of $860,000,000 into the $20,000,000 Gulf of Mexico Trust Fund. We now expect full year capital expenditure for 2012 to be $22,000,000,000 to $23,000,000,000 slightly ahead of previous guidance.
The TNK BP divestment is expected to close in the first half of twenty thirteen. At the end of the third quarter, net debt was $31,500,000,000 leaving Gearing at 20.9% compared to 21.9% at the end of the second 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 the 3rd 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 TNKBP and to update you on our U.
S. 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 percent share of Russia's leading oil company, equivalent to just under $27,000,000,000 based on the Rosneft closing share price on the 18th 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 term 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 twenty twenty. 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 $8,000,000,000 TNKBP has returned $19,000,000,000 of dividends to BP. The venture has also paid over $180,000,000,000 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, Ross Nest oil production was over 2,400,000 barrels per day and its oil reserves exceeded 18,000,000,000 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 190,000,000,000 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 Ross Neff illustrates, the combination of TNKBP and Ross Neff assets offers both increased scale as well as considerable opportunity for optimization.
The close location of planned TNKBP and Rossneft developments in the Yamal Peninsula and Eastern Siberia along with the addition of TNKBP'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 4,500,000 barrels of oil equivalent per day. Ross Neft 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 an exploration of Saracochelan, further cemented through our participation in their initial public offering in 2006.
And in May 2011, we entered into a fifty-fifty partnership in the German refining joint venture, Ruhr 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 Ross Neff'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 Q3, we had paid a total of $8,800,000,000 to meet individual and business claims and government payments. Over $19,100,000,000 has been paid into the trust fund as the end of the third quarter with the final payments to complete the $20,000,000,000 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-two thousand one hundred and seventy nine to the 25th 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 on the functional lines and a major recruitment drive to deepen capability. And finally, 1 year ago, we laid out the 10 point plan, which included specific guidance for operating cash flow, divestments and project startups 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 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 two 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 1st 3 quarters of 2011. In the downstream, our refining throughput hit a 7 year high in the 3rd quarter underpinned by sustained improvements in refining availability over the last 5 years.
Since the start of 2,008, 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 Q3 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 $35,000,000,000 of divestments against our $38,000,000,000 divestment target or $62,000,000,000 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 reserve space 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 their portfolio will be significantly complete by the end of 2013 as the Whiting Refinery Modernization Projects comes on stream and the divestments in the U.
S. Of the Southwest 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 access 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 today, let me turn to the future. This is the 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 10 point plan with our commitment to grow operating cash flow. 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 4th quarter and our 15 high margin upstream projects all remain on track. We plan to use around half of this extra cash for reinvestment 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, Claucus Mavicola in Angola and Devonik in the North Sea. 3 more are very close to completion.
We expect Angola LNG, PSVM and Scarve to all start up before the year end, an average of 1 major project each month. All 15 major product startups 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 on stream before 2014 to deliver twice the average operating cash margin of our 20 11 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 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 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 Clove, Pazalore Phase 2 and Kazamba satellites in Angola another Shiregg oil project, the Azeri Subsea project and the Shaktadis full field development on Azerbaijan. Phase 3 of the Nikika 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 Canoole 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 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 resources of some 4,000,000,000 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 1 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 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 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're excited about the quality and the materiality of our exploration prospects. Our drilling program is expected to test 15 completely new plays between 20122015 in addition to deepening in our existing core areas. And about 35 of our exploration wells should target prospects with resource potential greater than 0.25000000000 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 3 d seismic surveys in Australia, Angola and Namibia. In 2013, we plan to acquire large 3dseismic 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 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 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 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.
Right. We'll be taking calls today from both the U. K. And the U. S.
We know we have some callers 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. Go ahead, Doug.
Good morning, everybody, and congratulations on your results.
Thanks, Doug.
My first question is on Russia and specifically the likely tax implications on the divestiture of TNKBP. And then second, TNKBP returns on capital were very high in recent years and they were much higher than Ross Nest. And so it seems that Ross Nest 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 ROSNIP 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, hi, this is Bob.
Hi, Bob.
Good to hear from you.
You too.
Well, there's a couple of things. TNKBP 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. 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 TNKBP. 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 TNKBP, but we do look at the $12,300,000,000 of cash coming out of TNKBP.
One way to look at it is a 6 to 8 year acceleration of dividends from a 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.
Okay. Thank you. 4% would be very positive. Would be.
Yes. Right. We'll take the next question from Houtan Yazari from Bank of America Merrill Lynch.
Good afternoon, gentlemen. A few questions, please. I would like to start with TNKBP. 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. It 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 Ross Neff were to buy 100% of the entity. Next question really is with regards to dividends. We know that the sale of the TNKBP 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 Q3 how much of this exceptional performance was down to these 2 refineries? Thank you.
Hooten, hi, this is Bob. Thanks for your question about TNKBP. As it regards synergies between Rawsonpt and TNKBP 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 Rossnap.
I'd note that on the 23rd October Rosneft webcast, Igor Sechin said that he hoped to realize some $3,000,000,000 to $5,000,000,000 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 conservative estimate that was made by Ross Neft. Let me turn the question to Brian on the dilution. We've been talking to shareholders and also the refining question.
Yes. Thanks, Houten. So specifically on the question around the increase in dividend that was really as a consequence of the fact that we delivered $11,000,000,000 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 percent 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 $12,300,000,000 of disposal proceeds. So don't read across the two 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 do with our $12,300,000,000 As a minimum, we calculate the dilution on an earnings per share basis at around $3,000,000,000 to $4,000,000,000 3% to 4% which would require a reduction in the share base of around $4,000,000,000 as a minimum.
And I think it's reasonable to say if you've sold $38,000,000,000 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 the what they contributed 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.
Moving now to Jason Gammel of Macquarie. Go ahead Jason. Yes.
Thank you very much. First of all, I 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 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?
Jason, thanks. So we've said that we expect the number of TARs in 2013 to be about the same as 2012. Of the numbers we had 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 Q3, 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 Q2 and then you have the hurricane season in the second and third quarters. We do expect production to come back on in the 4th quarter and you would expect to see a margin increase in the 4th quarter.
Thanks very much, Bob.
Okay. Back to the U. S. Robert Kessler from Tudor Pickering.
Hi. 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 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 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 Q 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?
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 to SORO 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 $22,000,000,000 to $23,000,000,000 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 of the 2014 being around $24,000,000,000 to $25,000,000,000 So in terms of the medium term, it's around $24,000,000,000 to $25,000,000,000 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 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 Nikhika and 2 on Atlantis that are doing primarily productive well work and we have 1 on the Quesquita 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 produced about 15% of the resources still there with 85% yet to go. This is a project for the next decade that we'll probably see its low point as we're doing this reinjection work and then it'll come back strong through the decade. I'm not sure if I asked your answered your specific question.
Yes.
Thanks for that. 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?
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 2013 or 2014 or 2015. We're still looking at the investment case which does look strong.
Okay. Thanks very much.
We'll take the next question from Addis Saime at Citi.
Yes. Thanks, everyone. Can I just ask on T and K Rosneft again? I mean, having so carefully realigned E and 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?
So Alistair, I we've been very careful during this transaction working with Rosneft to be clear that this was a divestment of our interest in TNKBP and 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 Rossneft 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.
Right. The next question is from Peter Hatton 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 a understanding of what the turnaround effect 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 a lot of those are sort of towards the end of that period, what kind what the volume of production in 2014 is like 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 and there'll 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. Those 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.
Okay. Thank you. Okay.
Next, Teepan Joffe Lindgren from Nomura. Go ahead, Teepan.
Thanks, Jess. Good afternoon, Bob. Good afternoon, Brian.
Hi, Thipan.
Three questions just following up actually. Just firstly, coming back to the cash cycle framework at $100 oil. I think you talked about the investment levels of $24,000,000 $25,000,000 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 could you talk a little bit about the deferred tax assets still sitting on the balance sheet for the GOM 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. I was just wondering about the opportunity for BP with Rosneft outside Russia. Thank you.
I'll turn the first two over to Brian.
Yes. So Thifan, 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 a cash breakeven in the range of $80 to $100 a barrel depending on what the margin mix is and the volume mix. And 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 announced today is actually more than well underpinned out to 20.14 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 United States as a consequence of Macondo.
And T Pen on the investment with Rosneft internationally, we have not had discussions 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 $38,000,000,000 you're pretty much there. Are there any plans to increase that?
No.
We're going to keep going though to make sure we meet that $38,000,000,000 target. We've got assets identified. But Brian?
Yes. Tapan, I mean, you should assume on a go forward basis once the $38,000,000,000 is achieved that we'll continue to look to churn the portfolio as we've done historically around about $2,000,000,000 to $3,000,000,000 of disposals per annum beyond the $38,000,000 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, I mean 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. There's 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. Yes.
We'll go next to Ian Read from Jefferies.
Hi, 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?
Secondly, 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. Would you feel confident enough to get out there and use that cash in 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 wonder whether you can tell us what the situation is and what BP has 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 Rossneft about any specific Arctic Projects and Ventures. I would note that Rossneft still has many, many licenses in the Arctic, but that was not the basis of our discussions. And if assuming this transaction closes the way we 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 to the portfolio. So you would not expect BPV 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 Sokar, discussions with the President. I think we're on track now to solve the issues around production in 20 13 and going forward.
So I don't want to speak for Sokar 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.
Okay. Thanks a lot.
Thanks, Ian.
The next question comes from Martin Ratz at Morgan Stanley.
Yeah. 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 disposals of C and KBP came into play, that was relatively easy to interpret it because it sort of meant $33,000,000,000 of operating cash flow by 2014.
But given that the wording is unchanged, does this still mean $33,000,000,000 of operating cash flow by 2014? Or should we adjust that now for the difference in the dividend between T and K and the dividend of Rosneft? That was one question that I had. And the other question relates to the $2,000,000,000 to $3,000,000,000 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 EUR 2,000,000,000 to EUR 3,000,000,000 of disposal every year what will be the impact of that on operating cash flow?
So Martin I'll take both of those. So first 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 20.40, we've now said more than 50%. If you take 10 ks BP out and the €3,700,000,000 of dividend in 2011, a dividend that we were planning in was lower than that by a factor of at least 50%. So now the target that would have been €33,000,000,000 looks more like €31,000,000,000 to €32,000,000,000 If you swap the TNK dividend and you could as Bob said earlier, you could actually describe this as we've accelerated €12,300,000,000 worth of dividends 6 or 8 years worth of dividends forward.
But that number is now €31,000,000,000 to €32,000,000,000 depending on the Henry Hub price. If the Henry Hub price stays where it is today, it's more towards the €31,000,000,000 If it's up at sort of $5 which is what we'd originally assumed it'd be more close to the 32. 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 $32,000,000,000 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.
Okay. Thank you.
Next question from Oswald Clint at Bernstein. Go ahead, Oswald.
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 kind of dollar per ton number that's implied by the CapEx numbers that we've seen over the last few weeks months? Thank you.
Oswald, great question. As we do look out over the decade beyond 2014, 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 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 of 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 $30,000,000,000 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 8.
And we're 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.
That's great, Bob. Thank you very much.
Over now to Raheem Karim of Barclays.
Hi, 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 high 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 T and K BP. I was just wondering if there were any BP secondees that were currently with T and K 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 at some of the numbers on your questions on the turnarounds, I'll take the last question, Raheem. We do have people from BP that are working inside of TNKBP. And certainly, I can't remember the number right now, but certainly in secondees we would be happy to have the skills and capabilities back in BP assuming that this transaction goes forward. And in terms of Ross Neft 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 T and KBP managers are left and are working in Ross and ex BP employees are working in Ross Neff. That's not a coordinated plan that we have with Ross Neff. 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, Raheem. 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, 2015, 2016.
Perfect. Thanks very much.
Moving now to Irene Himona from SocGen.
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 E and A spend previously was about EUR 4,000,000,000. 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 $65,000,000,000 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 expiration point. Exploration and appraisal point certainly $4,000,000,000 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 Thompson 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 train LNG project with pipelines that go up and down. And you took the capital cost and the operating cost 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 the construction of trains and the market itself.
And then Brian on
the Yes. So, Irina on the exploration price, I know $4,000,000,000 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 inflations come through and some higher project costs and the phasing of some activity of expenditure. But I think the original guidance we gave you this year was $22,000,000,000 It may be the $22,500,000,000 close to $23,000,000,000 but that's not associated with exploration or appraisal.
Thanks so much.
Yes. And Irene, I believe if you look at the CapEx piece alone of exploration, it's about $1,000,000,000 this year on exploration. It'll probably be about the same on the exploration and appraisal in 2013 as well.
Thank you.
All right. A question now from Jean Luc Romain of CMCIC. Go ahead Jean Luc.
Good afternoon. I've got a question on exploration in Brazil. Recently, I know it was a regulatory all were constricted in a well drilled very close to a big discovery of Repsol and block I think BMC 43. Could you give us more 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 some of the regulatory process and approval there of the government. We're evaluating those 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're able to.
Thank you very much.
Right. Colin Smyth from VTB Capital.
Yes. Good afternoon, gentlemen. I wonder I 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 would have seen that our depreciation DD and A has gone up this year as the higher margin barrels we pursue clearly have high DD and 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 to in terms of cover 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.
Okay. Lucas Hermann from Deutsche Bank. Go ahead, Lucas.
Cheers, gentlemen. Good afternoon. 3, 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? And leaving aside Whiting, you've sold 2 major refineries, just to give us some idea of the CapEx that you'll 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 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 sustainably free cash flow coming through. We effectively this quarter having got a lot behind us in terms of the $11,000,000,000 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 a 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 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 Q4 of 2,000 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 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 2014.
But I think we've said we'll increase the dividends of the rising and improving circumstances of the firm. There's certain flexibility there. On the CapEx, 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 $1,000,000,000 and that will be turned in we think could be incremental operating cash flow of $1,000,000,000 So that will be a significant step for the company. That will bring down the CapEx levels of our refining and marketing business broadly, broadly in levels equal to depreciation.
Sorry, Bob.
No, it
was just I mean Texas City and Carson must require significant spend as well. You've been spending €4,000,000,000 on refining in recent years. Should we expect that to move to nearer €2,000,000,000 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 expense not capitalized.
Okay. Forgive me.
And your third question
Lucas? It 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 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 4 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.
And now to Jason Kenney from Santander.
Hi, 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 3rd 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 Bayzanov shale oil resources thought to be bigger than the Bakken. I'm sure you're anticipating some material value for BP by enhancing Rosneft's 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.
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 the details of each of the agreements that have been made. Rostemp has signed agreements with Statoil with ENI and with Exxon, OXO Mobile. 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 as would be assuming again the transaction goes forward to shareholder in Rosneft. 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 Bayashnov 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 be able to create the incentive for people to go into the shale oil projects like the Bastionov.
I believe ExxonMobil 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.
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 we that will be fully funded this quarter. The payment going in is lower than the typical payment because it's around €860,000,000 versus €1,250,000,000 given the advance payments we put in from some of the recoveries.
But this is really about the fact that actually the disposals we are 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 a stronger financial frame and allowed us to accelerate what we would have planned as a potential dividend increase next quarter.
Great. Thanks.
Yes. Did you and the escrow account will be finished this quarter?
Yes. The escrow account will be finished this quarter. This quarter. 50th November the final payment goes in.
Okay. We don't have any other perseverance. I can imagine 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 the hurricane and are on the right side of the location at 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 or even a four way win between Rosneft BP and AAR 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. 1 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.