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, welcome, everyone. This is BP's third quarter 2013 results webcast and conference call. I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary. Before we start, I need 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, now over to Bob.
Thanks, Jess, welcome everyone. No matter where you are in the world or what time it is, thank you for joining us. July to September this year was another big step in moving towards both our medium and long-term goals at BP. We are reporting solid results in which the fundamental strengths of our businesses is apparent, despite the offsetting effects of divestments in the upstream and weaker refined margins in the downstream. In terms of business outputs, we are strongly focused on delivering our 2014 operating cash flow objectives, since we last spoke, have continued to see momentum in the business drivers that will deliver this growth. Beyond 2014, we have confidence in our ability to deliver sustainable growth and free cash flow. This will come through continued growth in operating cash from our underlying businesses and a strong focus on capital discipline.
It underpins our decision today to increase the dividend and gives us confidence that we can sustain a progressive dividend policy over the long term. A year ago, we also started talking with you about how we are reshaping BP to create a platform for growth that is simpler, more focused, and which offers a differentiated proposition by only investing in a strong pipeline of projects and opportunities that play to our strengths. In keeping with this approach, we've also announced today a commitment to a further $10 billion of divestments by the end of 2015, from which proceeds we plan to increase distributions to shareholders, primarily through buybacks. Today's agenda will follow a familiar pattern. Brian will take you through the third quarter numbers and the implications of today's announcements on our financial framework.
I'll give you an update on the legal proceedings in the U.S. and the progress of our investment in Rosneft. We'll give you the headlines of business progress upstream and downstream before opening things up for questions. Now, over to Brian.
Thank you, Bob. Starting with an overview of the third quarter financial results. Underlying replacement cost profit in the third quarter was $3.7 billion, down 26% on the same period a year ago. 36% higher than the second quarter of 2013. Compared to a year ago, the result mainly reflected the impact of divestments in the upstream, offset by higher realizations, lower downstream refining margins compared to the near record level seen a year ago, and the absence of earnings from the divested Texas City and Carson refineries, and a lower contribution from our shareholding in Rosneft compared to that from TNK-BP. Third quarter operating cash flow was $6.3 billion. As Bob noted, in line with our commitment to a progressive and sustainable dividend policy, we have also announced an increase in the third quarter dividend of 5.6% to $0.095 per ordinary share, payable in December.
This reflects our confidence in sustainable free cash flow growth, underpinned by the strong operational progress we are now seeing and a continued focus on capital discipline. Moving forward, the board will review the dividend level with the first and third quarter results each year. Turning to the highlights at a segment level. For the upstream, the underlying third quarter replacement cost profit before interest and tax of $4.4 billion was unchanged from a year ago and compares with $4.3 billion in the second quarter. The result versus a year ago reflects lower production due to divestments, primarily in the Gulf of Mexico and the North Sea, and higher non-cash costs for exploration write-offs and DD&A.
These effects were offset by higher liquids and gas realizations, improved underlying volumes in high margin regions, and a one-off benefit in the current quarter from cost pooling settlement agreements between the owners of the Trans-Alaska Pipeline System or TAPS. Excluding Russia, reported production versus a year ago was 2.3% lower, primarily due to the impact of divestments. However, on an underlying basis, after adjusting for divestments and entitlement effects, production increased by 3.4%. This underlying growth reflects new major project volumes in the North Sea and Angola, as well as the absence of seasonal weather-related downtime in the Gulf of Mexico. Compared to the second quarter, the result reflects higher liquids realizations and the benefit of the TAPS cost pooling, partly offset by higher non-cash costs, lower gas realizations, and lower production.
On the back of stronger than expected third quarter production, benefiting from the absence of seasonal adverse weather in the Gulf of Mexico, we now expect fourth quarter reported production to be broadly flat with the third quarter and costs to be higher with the absence of the TAPS pooling settlement benefit. This slide shows our share of earnings from Rosneft and historically from TNK-BP. BP's share of Rosneft underlying net income was over $800 million in the third quarter, significantly higher than in the previous quarter. The third quarter benefited from ruble appreciation against the US dollar, a positive duty lag, and higher Urals prices, partially reversing the negative impact of these factors in the second quarter. BP's share of Rosneft production in the third quarter was 965,000 barrels of oil equivalent per day, 2% higher than in the previous quarter.
BP's total production for the quarter, including this, was 3.2 million barrels of oil equivalent per day. In the third quarter, we received around $460 million, after tax, from our share of the Rosneft dividend that related to last year's earnings. We expect no further dividends from Rosneft this year. In the downstream, the third quarter underlying replacement cost profit before interest and tax was $720 million, compared with $3 billion a year ago and $1.2 billion in the second quarter.
The fuels business reported an underlying replacement cost profit of $345 million in the third quarter, compared with $2.7 billion in the same quarter last year, reflecting a significantly weaker refining environment versus the near record levels experienced in the same period last year, and the absence of earnings from the divested Texas City and Carson refineries in the U.S., which delivered unusually strong results in the third quarter last year due to the favorable environment. The lubricants business reported an underlying replacement cost profit of $325 million, compared with $310 million in the same quarter last year, demonstrating the strength of our premium Castrol brands. The petrochemicals business reported an underlying replacement cost profit of $50 million, compared with a loss of $20 million in the same period last year, with some contribution from increases in utilization and unit margins.
Looking forward to the fourth quarter, we expect fuels profitability to remain under significant pressure due to weak refining margins. In Other Businesses and Corporate, we reported a pre-tax underlying replacement cost charge of $380 million for the third quarter. Guidance for the year remains a charge of around $500 million on average per quarter. However, this can be expected to be volatile from quarter to quarter. The underlying effective tax rate for the quarter was 31%, compared to 34% a year ago, benefiting from a one-off adjustment of $100 million for changes in U.K. tax rates, higher equity accounted income, and beneficial income mix effects. Full year guidance for the underlying effective tax rate remains in the range of 36%-38%.
The charge for the Gulf of Mexico provision increased by $40 million in the third quarter due to the ongoing costs of running the Gulf Coast Restoration Organization. The total cumulative net charge for the incident to date is now $42.5 billion. This includes the cost of the $20 billion trust fund, for which a charge was recognized in 2010. The charge does not include any provision for future business economic loss claims that have yet to be received or processed within the Plaintiffs' Steering Committee settlement. In addition, as a result of the recent Fifth Circuit ruling that Bob will talk to shortly, we are now no longer providing for outstanding business economic loss claims offers that are yet to be paid. $400 million of previously provisioned business offers were therefore derecognized in the third quarter, as they can no longer be measured reliably.
We will continue to revisit this in each quarter. As a result of this change, at the end of the third quarter, the cumulative amount estimated to be paid from the trust fund decreased by $400 million to $19.3 billion. This increased the unallocated headroom available in the trust for further expenditures to $700 million. In the event the headroom is fully utilized, subsequent additional costs will be charged to the income statement. The cash balances in the trust and the qualified settlement funds amounted to $7.1 billion, with $20 billion contributed in and $12.9 billion paid out. The pre-tax BP cash outflow related to oil spill costs for the quarter was $400 million. As we have indicated in previous quarters, we continue to believe that BP was not grossly negligent and have taken the charge against income on that basis.
With respect to our divestment program, we have continued to focus our portfolio during 2013. We have completed the $38 billion divestment program and the sale of our share of TNK-BP to Rosneft for $27.5 billion. This brings the total divestments announced since the start of 2010 to around $66 billion, including TNK-BP, which can be seen in the context of our $135 billion market capitalization today. Following receipt of the net cash proceeds of around $12 billion from the divestment of our share in TNK-BP, we announced an $8 billion share buyback program, and as of the 25th of October, we have repurchased $3.8 billion of shares for cancellation. We now plan to divest a further $10 billion of assets by the end of 2015 as a means of unlocking further value as we continue to focus our portfolio.
The cash proceeds after tax will be predominantly linked to additional shareholder distributions with a bias to share buybacks. Moving now to cash flow, this slide compares our sources and uses of cash in the first nine months of 2012 and 2013. Operating cash flow in the first nine months was $15.7 billion, of which $6.3 billion was generated in the third quarter. Excluding oil spill-related outgoings, underlying cash flow in the first nine months of 2013 was lower than a year ago. Year-to-date cash flow has been impacted by a working capital build of around $5.5 billion, which we'd expect to unwind over time. In the third quarter, we received $400 million of divestment proceeds, bringing the total for the first nine months to $16.7 billion. This includes the net cash received from the divestment of our share in TNK-BP.
Organic capital expenditure was $17.5 billion in the first nine months and $5.9 billion in the third quarter. Net debt at the end of the third quarter was $20.1 billion, with gearing of 13.3% compared to 20.9% a year ago. Our intention remains to keep gearing in a target band of 10%-20% while uncertainties remain. This slide outlines our financial framework for 2014 and beyond. We continue to expect operating cash flow of $30 billion-$31 billion in 2014, representing more than 50% growth in operating cash flow versus 2011. In line with continued capital discipline, we expect BP's capital spending in 2014 to remain around the same level expected for this year in the range of $24 billion-$25 billion.
Beyond that, we expect annual gross capital expenditure to be in the range of $24 billion-$27 billion through to the end of the decade. We are confident in our ability to deliver material growth in operating cash flows beyond 2014, coupled with continued capital discipline. This will enable us to grow sustainable free cash flow to underpin progressive dividend growth into the future. We expect to divest a further $10 billion of assets before the end of 2015 and to use the post-tax proceeds for distributions, primarily through share buybacks. Beyond 2015, we will continue to actively manage our portfolio for value. We expect to outline the financial shape of the firm beyond 2014 in an investor update on the 4th of March next year. Now, let me hand you back to Bob.
Thanks, Brian. I will now turn to the U.S. legal outlook and an update on progress in Russia before looking at milestones in our business segments. First, an update on the status of legal proceedings in the United States. The first phase of the MDL 2179 trial commenced on the 25th of February in New Orleans, focusing on the causes of the accident and allocation of fault among the defendants, and ended on the 17th of April. While the court will ultimately decide, we believe that the evidence showed the accident was a result of multiple causes involving multiple parties. The second phase of the trial commenced on the 30th of September and completed just 11 days ago on the 18th of October.
This phase involved two main issues, source control, including attempts to stop the flow of oil from the well, and the quantity of oil spilled into the Gulf of Mexico. As it did after the conclusion of phase one, the court has ordered post-trial briefings, which will be completed by the 24th of January 2014. Again, while the court will ultimately decide, we believe that the evidence showed that BP mounted an extraordinary response, was neither negligent nor grossly negligent in its source control efforts, and the government's flow rate estimates are substantially overstated. We do not know when the court will issue a ruling on either phase one or phase two issues. The penalty phase in which the court will hear evidence regarding the penalty factors set out in the Clean Water Act will be the next phase of the trial.
The U.S. government, BP, and Anadarko will be parties in this phase, and we anticipate that the court will schedule it sometime in 2014. Turning to the settlement with the Plaintiffs' Steering Committee, as Brian mentioned earlier, BP was successful in challenging the claims administrator's interpretation of the business economic loss framework. The Fifth Circuit reversed the interpretation and ordered the district court to enter a preliminary injunction that suspends payments to claimants affected by the misinterpretation and to not have, quote, "actual injury traceable to loss from the Deepwater Horizon accident." Unquote. On the 18th of October, the district court issued the preliminary injunction to, among other things, temporarily suspend payments, except where the claims administrator determines that the matching of revenue and expenses is not an issue.
While a step forward, BP continues to evaluate its options to ensure that the Fifth Circuit's decision, including its directives related to causation, are given full effect. Further remand proceedings are scheduled to take place on the 2nd of December. In the meantime, oral arguments on the appeal, pending in the Fifth Circuit Court related to the fairness of the settlement itself, is scheduled for the 4th of November. Separately, former federal judge Louis Freeh's independent investigation of the claims facility continues, and we hope that it will lead to steps that ensure public confidence in the integrity of the claims process. MDL 2185 is a coordinated proceeding pending in federal court in Texas and includes a purported class action on behalf of ADS purchasers under U.S. federal securities law. A jury trial on this action is scheduled to begin on the 25th of August, 2014.
In summary, we are well prepared for the long haul on legal matters and continue to compartmentalize these activities from the running of our businesses, so as not to distract our workforce from delivering on our business goals. In regard to Russia, as Rosneft noted last quarter, the work to integrate TNK-BP is largely complete, including the Rosneft board approval of their revised business plan, incorporating the year-to-date acquisitions. In the third quarter, Rosneft paid its dividend, declared for 2012, with BP receiving its share around $460 million. This was the first dividend since the transaction was completed in March of this year. Following my election to the Rosneft Main Board of Directors in June, I've been actively participating in the board's activities, providing perspectives on how the company is progressing, including as a member of the board's strategic planning committee.
Rosneft is also continuing to implement its strategy, including the acquisition of the remaining equity in ITERA and its agreement to purchase gas assets in Yamal from Alrosa and Enel. Finally, most recently, Rosneft has initiated an offer to buy out the minority shareholders in TNK-BP Holding. We will continue to keep you informed of Rosneft's progress as it delivers on its strategy. BP's interest in Rosneft enhances our own scale and capability. The effect of this on our own key metrics is illustrated in the box at the foot of the slide. You will note how our equity share in Rosneft takes BP to being a 3.2 million barrel a day company with around 17.5 billion barrels of proved reserves.
More importantly, this strategic investment in Rosneft allows us to access to growth opportunities previously unavailable to us in Russia, one of the world's largest producers of oil and gas combined with unparalleled resource potential. We remain excited about what we can contribute from our own experience to support Rosneft's potential and look forward to deepening our involvement wherever we can add value. Moving on, let me update you on progress in our upstream. It was a great quarter for exploration. We made three discoveries, one in India, one in Egypt, and another to announce just today in Angola. We are keeping up our busy drilling program. The discovery in India was our second there this year, this time in the Cauvery Basin. Once again, it was very deep, 5,700 meters below sea level.
As with the KG-D6 discovery in 2Q, which we found underneath the existing producing reservoirs, this new play has been identified using the detailed geoscience expertise that we can bring to bear on our portfolio. The discovery in Egypt was also a significant and a record-breaking one. It was the deepest well ever drilled in Egypt's Nile Delta. It was called Salamat. On Block 21 in Angola, the Cobalt-operated Lontra well reached TD and confirms an oil and gas discovery. The well will be drill stem tested. The rig will then move to another structure on the block. We will likely have more information by year-end on Lontra. Overall, we expect to complete between 16 and 18 exploration wells in 2013. So far, we have completed 12 wells, and we have a further eight in progress today.
While in terms of access, we have continued to build our positions with new acreage in 3Q in China and Brazil. Our global projects organization continues to make progress with our major projects with the third startup of the year, more on which I will talk about in a moment. We have five major projects on track for startup in 2014. They are Na Kika-3 and Mars B in the Gulf of Mexico, Canoe in the North Sea, CLOV in Angola, and Sunrise Phase 1 in Canada. We have seen some important milestones in the last few months, but actually our major focus is not only on the discoveries of the startups that make the headlines, but the safe, reliable execution of what we do every day in all of our operations around the globe. In our global wells organization, 80% of our top 15 wells are now online.
In key regions such as Azerbaijan, the North Sea, and Angola, delivery of new wells is at or above 2012 levels. We are also seeing similar improvements in our global operations organization, where improvements in operations efficiency reflect the benefit of investing in turnarounds. We have now completed 17 of the 21 turnarounds planned for the year. Going forward, we expect the level of planned turnaround activity to continue to fall following the last couple of years, where we have carried out significant turnarounds on many of our key assets in many countries. Moving on, let me update you in more detail on our major projects. Our key 2012 startups continue to ramp up their production as planned. We have started up three more major projects in 2013.
As I mentioned, the North Rankin 2 field in Australia became the third of these, following the Atlantis North expansion in the Gulf of Mexico and the Angola LNG project. The Chirag oil project in Azerbaijan is on track for startup around the end of the year. Milestones are being passed on constructing or commissioning the startups that we have planned for 2014. All projects in the 2012/2014 portfolio are either online or have achieved over 75% of facilities completion, with commissioning work happening thereafter. These projects will, on average, deliver twice the operating cash margin of the upstream portfolio we held in 2011. Following the tragic events at the In Amenas site earlier this year, we now anticipate that the In Amenas and In Salah major projects will not be ready to start up in 2014.
We continue to work with the joint venture to bring these projects online a little later. Looking beyond 2014, we have a portfolio of over 15 major projects that are in the design or post-FID stage. In addition to these, we have a hopper of over 20 opportunities currently being appraised through resource and project appraisal activity. Our strict discipline in the reinvestment of capital from growing operating cash delivery has led to redesign and continued challenge in our projects hopper. This has increased their value for you and reflects capital discipline. For example, in the Gulf of Mexico, in the second phase of our Mad Dog field development, it is being retooled, and in Australia, where the Browse LNG project has been redesigned based on a floating LNG concept.
This is a brief roundup on a geographical basis, looking at four key regions that will underpin growth in the operating cash flow. In the Gulf of Mexico, we have completed the major brownfield replacement of the hurricane-damaged Mad Dog rig, which means we now have eight rigs operating. A further rig, which we expect to have drilling on Atlantis by year-end, is on location, undergoing acceptance testing. That's the highest number of rigs engaged in drilling operations in the Gulf since 2010. The Atlantis North expansion, which started up in 2Q, is showing initial strong reservoir performance and production. The Mars B platform was installed in 3Q, and work on the tension leg platform rig and commissioning activities for the topsides and subsea commissioning are progressing well. The Na Kika Phase 3 is on track for startup in early 2014, and drilling operations are near completion.
While turnarounds on three of our four hubs are now complete. In Angola, our Greater Plutonio asset has continued to show strong plant efficiency, averaging 95% year to date. While PSVM has ramped up to over 124,000 barrels per day. Angola LNG has now lifted its fourth cargo following the 2Q startup. In the North Sea, Skarv is ramping up well, with production averaging 148,000 barrels of oil per day. The offshore construction of Canoe is progressing well, with all the topsides under deck work having been completed and the final subsea tie-ins underway, and we have completed seven of the nine scheduled turnarounds. Finally, in Azerbaijan in August, we announced gas contracts for over 10 billion cubic feet per annum over 25 years to nine different European gas buyers via what we call the Southern Gas Corridor.
It's an important part of the value chain for monetizing the future Shah Deniz Phase Two gas development. As previously mentioned, we're making good progress with the Chirag oil project. With the platform jacket set and the topside safely installed in September. Focus is now turning to the commissioning activities in preparation for the startup around the end of the year. In summary, during 3Q, we have continued to deliver what we said we would in the upstream across exploration and access, projects, wells, and operations. Our key regions continue to deliver a pipeline of opportunities that, together with the rest of the portfolio, are set to drive a sustainable growth in operating cash flow. Turning to the downstream. This quarter, we continue to progress the Whiting Refinery modernization project as planned, and we remain on track to start up the coker in November.
Across the refining portfolio, Solomon refining availability has remained high at 95.3%, similar to the levels we saw at this time last year. In petrochemicals, construction on a new third PTA plant continues to progress at Zhuhai in Guangdong province of China. We've also approved the first of a series of investments to retrofit key elements of our latest PTA technology to existing PTA plants. We expect these planned investments to materially improve efficiency and reduce annual operating costs. Our lubricants business has also continued to perform well, increasing revenues through its strategy of exposure to growth markets. Technology investments and targeted marketing programs are underway. Over 50% of sales revenue are from growth countries in Q3 2013. The Whiting Refinery has continued to bring units on stream during the third quarter. As previously announced, the crude unit started operations in Q2 as planned.
Since then, the gas oil hydrotreater and the largest of two sulfur recovery units, along with other supporting infrastructure, have been commissioned. The coker is planned to be brought online during November as scheduled, and when combined with the gas oil hydrotreater, significantly increases the ability of the plant to produce high yields of low sulfur fuels from heavy, high sulfur acidic crudes. Once the coker is online, we expect the refinery to begin a three-month progressive transition to heavy feedstock, reaching full run rate capacity during the first quarter of next year. The revamp of a small number of complementary existing units will also take place in 1Q. This major investment transforms Whiting into one of the key advantage downstream assets in our portfolio and underpins the ability to deliver increased cash flow in 2014. To summarize, this was another quarter of moving ahead.
We've recently launched operations such as PSVM in Angola and Skarv in the North Sea that are now producing strongly. We have projects gearing up to start soon, such as the Chirag oil project in Azerbaijan. We have future operations taking shape very well, such as Clair Ridge, also in the North Sea. We are seeding the portfolio of the future with discoveries such as those as India and Egypt and Angola. All of this upstream activity is accompanied by a downstream that continues to perform well in a tough climate and nears completion of the major upgrade at the Whiting Refinery. These are all examples of the way we are putting our strategy into action. To be clear, that strategy aims to deliver a very simple set of outcomes that you can expect from us.
That is material growth in operating cash flow from 2014 through the back of the decade, coupled with a disciplined capital spending framework to drive growth and sustainable free cash flow in support of a progressive dividend policy. As well, we will look to use surplus cash to enhance distributions to shareholders. Today's announcement with respect to further divestments and their linkage to increasing buybacks is a good example of this. We are confident we will achieve these objectives by putting value before volume, with a portfolio of the right scale, shape, and quality to drive safety, reliability, efficiency, and performance. We will keep this portfolio constantly under review to achieve these objectives.
This portfolio will play to the strengths that we've developed over many years in exploration as well as deep water, giant fields, and gas value chains, as well as continuing to achieve very strong performance in cash generation from a very strong set of downstream businesses. At the same time, our holding in Rosneft forms an important part of our overall portfolio of assets and investments. It establishes us as a 3.2 million barrel per day company, and it gives us a stake in an enterprise that is well-placed to address Russia's massive potential in terms of energy resources, discovered and undiscovered. With that said, I'd like to conclude with a few words on the bigger picture of which this is all part. 15 years ago, BP and other majors embarked on the round of consolidation that created the so-called supermajors.
We then went through a phase of inorganic growth driven by the prospect of synergies and cost savings. In the last decade, the supermajors have undertaken their first wave of global investments with the objective of growing organically by making discoveries, building portfolios, and developing a new generation of projects. I saw the report that McKinsey circulated that the supermajors doubled their CapEx over 8 years from $60 billion in 2005 to around $130 billion in 2012. The question is whether the peer group can convert that wave of investment into the right level of cash flow and then repeat the cycle in successive ways. Right now, I think it's fair to say opinion is divided. The investments are now coming on stream rapidly, and the answer to that question will become clear in the next year or so.
We understand that we have to prove ourselves capable of running major global portfolios and balancing investment against returns. I think the approach we are taking in BP with an intense focus on high margin quality growth and capital discipline will prove to be the right one. I am confident that it will lead, as planned, to increasing cash flow and a progressive dividend as part of the growth in returns that our investors expect and deserve. With that, thank you for your attention, and now over to you for any questions.
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The first question today comes from Fred Lucas at J.P. Morgan. Go ahead, Fred.
Hi. Afternoon, guys. Thanks. Guys, can you give us your latest estimate of what illegitimate payments have been made, and those that have committed to be made by the trust fund? If you could put a dollars million number to that. Could you also clarify, looking 2015 beyond, what takes BP's CapEx from a level of $24 billion-$27 billion? What moves you from the low end of the range to the high end of the range? Is it more projects, or is it an inflation effect? Finally, if I may, could you quantify your receivable from Egypt? I notice $42.9 billion trade now that receivables on the balance sheet. How much of that is owed to you by the Egyptian government? Thanks.
Fred, I'll just take the first one around business economic loss claims. It's complicated, of course, and it's got lots of uncertainty around it. What we do know is as of the end of 3Q, we have now reduced the provision we had at 2Q by about $400 million. For business economic loss claims, in the original provision, we'd set aside $1.9 billion of the $7.8 billion when we first struck the deal with the PSC. That increased to $2.9 billion at the end of 2Q, and currently set to $2.5 billion. Therefore, some money has already been paid out. To the degree that we end up with a position when the court opines on the most recent ruling for the Fifth Circuit in terms of the interpretation of this mismatching.
You've called it illegitimate, but let me call it mismatching or claims that we don't believe to be fair or reasonable or reflect the original agreement. There is about $1 billion still in terms of determinations within the fund, which have now been held up as a result of the Fifth Circuit Court of Appeals ruling. To say that actually, these claims appear to be wrong in terms of what was agreed, has asked the judge to now opine on what the right interpretation should be.
The claims administrator has now submitted, as of last week, to the court, a series of criteria that would filter out those claims with a matching issue, which he believes What he said is he believes that will result in relatively few claims being paid out between now and the remand period out to the second of December, where that will get agreed by the judge on what the actual criteria should be for these claims. Of that billion, we believe we've appealed 93% of those claims. We believe 90% of that is associated with the matching issue. I hope that answers your question, Fred.
Can you add how much has actually been paid already, which you think is mismatched, not fair, or unreasonable?
I think, Fred, what we'll now need to do is go through the process with the court. Once the court opines on the interpretation, given what's come back from the Fifth Circuit, we'll go back and look at what claims have been paid out. To the degree that we believe they are unreasonable claims or do not match the interpretation of the way in which the fund should have treated these claims, we will then look to claw back those claims that have gone. I can't quantify that for you now.
Okay.
Fred, hi. This is Bob. Your question about major projects and your question about what will take us from the $24 billion to the $27 billion by the end of, I think you said 2017. We haven't actually said that. What we've said is between now and the end of the decade, we'll be working with a range of $24 billion-$27 billion. In 2013, we're between $24 billion and $25 billion. We're going to keep that in the same range for 2013. We'll come back in March. I think we've got a date of March the fourth now to have a strategy review with you laying out a little bit more detail, a lot more detail between now and the end of the decade. I think it's premature to assume we're going to go back up to $27 billion by 2017.
Fred, on the Egyptian receivable, we continue to monitor changing political events in Egypt closely. I think importantly, none of our operations have been impacted by the events that we've seen so far, and we continue to work closely with the Egyptian authorities. We've never actually quantified the scale of the receivable. We are working very closely with EGPC and the government in terms of bringing that receivable down. That receivable did come down through the third quarter from where we were at the end of 2Q. We're doing that through various management of liftings and so on. We don't actually quantify the scale of it.
If I could add a footnote to that. Through the quarter, we didn't miss a day of production in the Gulf of Suez in our oil operations. They've continued right through, in fact, all year.
Very good. Thanks, guys.
Yeah. Thanks, Fred.
Okay. We'll take the next question from the U.S., Robert Kessler from Tudor, Pickering.
Hi, good afternoon. I have two questions, if I could. One, the TAPS adjustment, the one-off benefit with respect to prior years for the FERC approval of the cost pooling settlement. Can you quantify the materiality of that for the third quarter? Secondly, as it relates to the divestment program, the $10 billion of the incremental divestments, can you give us some color on the assets up for sale on there? Is it upstream, and what level of production might be associated with that?
Yeah, Robert, hi. It's Bob. On TAPS, it's material because it's over $100 million, I think I'll just leave it at that. It's not publicly disclosed, but that's not a big part of the performance during the quarter. It is over $100. On the divestments, we don't have a list at the moment. We just constantly look at our portfolio. We can see assets all the way through it. We haven't put anything up for sale. I think it'll be a mixture of upstream and downstream projects. Could include everything from some of the exploration projects we have, maybe interest in some of the big mega projects we have. We'll look at all the other assets as well. This is early days. We had said that we would divest $2 billion-$3 billion a year. We've divested $38 now, $10 on top of that.
A company of our size should have a natural churn in the $2 billion-$3 billion range anyway. We see some other assets that we think will have more value to others, and we'll just head down that and announce them when we're ready. Thanks, Robert.
Bob, it almost sounds as though you've got a top-down approach when you say you don't have a list. Is it that you don't have a public list and you've identified assets internally, or are you rather saying, "You know what? $2 billion-$3 billion isn't where we should be. We got to crank that up and double it and just set that target and then go find assets to meet the target?
Robert, it's Brian. I think all roads lead back to strategy. As we look at our portfolio, we learned a huge amount from the $38 billion disposal program. That was quite significantly weighted towards late life assets, which were clearly attracted more value from other companies, and we got very good prices for them. This is just part of our usual annual review of all the asset portfolios. Bob said we'd always targeted $2 billion-$3 billion. We have a pretty substantive list of potential assets that could cover the $10 billion. We just think in terms of, as we look at the portfolio, Bob's right, this is a complete mix of early life through to late life assets. Strategically, we believe these are sort of bottom-end of the portfolio for us in terms of what would attract investment into the future.
Therefore, it's right that we realize that value. Today, we've gone the further step of linking the realization of that value with distributions to shareholders through buybacks.
At the right time, if there's an opportunity to deepen some of our existing projects, we'll also deepen in other things as well. It's not all going to be a one-way-out. Thanks, Robert.
Right. Thank you. We'll take the next question from Jason Kenney at Santander.
Hi there. Thanks for taking my question. I've got two, if I may. I'm looking at the Clean Water Act provision, which I think is around $3.5 billion. Regardless of the actual final amount for that fine, have you got a view of when the earliest period is that you could envisage paying that fine? Would it be before the end of 2014 or possibly later? Also, can you confirm if this provision is included in your 50% uplift in CFFO, or would it be on top of the CFFO delivery for 2014, obviously, if it's in that year? The second question, I was just looking back over the year, really, and in second quarter numbers, there was a material miss for BP.
As part of that, there was a comment from you guys that analysis of Russia was maybe not as sharp as it could be from Western analysts compared to the Russian analysts of Rosneft. In third quarter numbers, certainly in my calculations, we've got a material beat, 75% of which is UPIS and Other Businesses and Corporate. We actually seem to have got our Russian act together as a group of analysts. Obviously, the beat is exaggerated by lower tax as well. I'm wondering if there's a view in BP as to what analysts have got modeled wrong for the third quarter, really.
You sound like you've taken it personally, Jason.
It's not personal. I want to get this right for the fourth quarter.
Yeah, sure. Well, first, on your first question, Brian.
Yeah. Jason, maybe a little point in the second one, but I'll let Bob deal with it. On the first question, the $3.5 billion is what we set aside way back in July 2010. It was our best estimate at the time, and we see nothing that's changed since then to change that estimate. That's what we still carry as a charge. That is clearly not accounted for in terms of the operating cash flow targets. You will recall from 4Q last year when we booked the DOJ criminal settlement, that reduced our numbers for 2014. If you remember where we started with the original operating cash flow target of around $33 billion, we brought that down in line with what we saw.
In terms of the fine, you'd have to get basically to earliest point of time is very uncertain, Jason Kenney, so it's impossible for me to say. If our general counsel was next to me, he'd probably tell me to stop now. Clearly, you'd need to get through phase I, phase II, have judgments on phase I of the trial, phase II of the trial, and then phase III. As I understand it, phase III is due to start sometime next year.
Okay.
Yeah. Jason Kenney, on Russia, I think as we know at BP with the TNK-BP investment, the duty lag and the Russian accounting is not a simple thing to do. To give you something that'll, I think, help going forward, I'll give you our earnings in the second quarter were $218 million, and in the third quarter here, they're $808 million. Roughly $300 million of that is made up by foreign exchange because the ruble has strengthened, had a very weak second quarter, and Rosneft does their accounting in rubles, does IFRS accounting in rubles. There was $140 million swing in the duty lag. Oil prices were up, and that accounts for about $90 million of it, increased production was around $60 million. That'll give you some sense of the difference between 2Q and 3Q.
Jason Kenney, just in terms of the question, yeah, just to sweep on Bob Dudley, I think you've got an impossible task when you look at all the moving parts that we can see, that you have to come up with some point estimate of our earnings, given all of the moving parts we have. We try and give you rules of thumb to help, but for a 90-day window, I believe that to be near impossible for you. I think it's a thankless task, frankly.
Maybe just on that point then. In 2014, the big thing for a DCF of BP would be the kind of dividends that you're expecting now to Rosneft. It doesn't really matter what the earnings are as such. It's more how you're going to get the dividends out. Can you give us today some sort of indication of what confidence you have in a level of dividend from Rosneft over the next 12 months?
Jason, Rosneft reports or pays out a dividend once a year, and our share of the dividend which we received this quarter was right around $460 million. The government has reiterated several times that its policy would be a 25% dividend payout. There's actually been speculation of it rising. I think 25% I think is a good planning number for the dividends. Rosneft has consistently paid its dividends. They just do it on a different schedule than Western companies.
All right. I think we'll move on to Hootan Yazhari from Bank of America Merrill Lynch. Go ahead, Hootan.
Good afternoon, gentlemen. I've got two questions, if I may. The first two really relate around the release of working capital and your gearing targets. You mentioned that there was about $5 billion plus worth of working capital accumulated during the year, and that will unwind over due course. Just wanted to get a feel for how long you think that will take to unwind and what factors we should look at for that to happen. Related to that also, I wanted to see how comfortable you are with your 10%-20% gearing targets at the moment. Could this potentially be something you look to revise upwards to release further capital for shareholder distribution? Finally, I just wanted to get an update on the Gulf of Mexico. You've obviously been having a lot of success there with your turnarounds, et cetera.
Just wanted to understand when we should expect the kicker in production to really start coming through and for it to be visible in your cash flow generation. Thank you.
Maybe on the first question, Hootan. We have highlighted that we've seen a build of about $5.5 billion of working capital. It's not structural. It is a lot of different moving parts. Therefore, when we look at it isn't a structural increase, especially given that we've sold off a number of assets. In actual fact, the net number's coming down. As we've seen that build through this year, I think we're just flagging it so that it sort of helps you in terms of what this year would look like if that build hadn't happened. You can get a sort of a cut through the actual underlying operating cash flows. In terms of the unwinds, I see there's a lot of volatility around working capital.
If all things being equal from where we are today, the prices stayed where they are today, and that the operations are in line with what we expect, then I'd expect certainly over 70% or close to 80% of that to unwind in the next 12 months.
Hootan, on your other questions, you're right. That's a nice graph when you see the gearing levels drop out of above 20 down to the low teens, which is the range that we've said for some time, and the board supports us staying in the 10%-20% range in terms of prudence. That gives us a lot of flexibility for the future to do lots of different things. Right now, our prudent target is to remain within the range. Then on the Gulf of Mexico, you're right. The Gulf of Mexico is really important for us. It's central to the portfolio for decades to come. It's very high margin production. We've done some disposals in there, but that was strategic. We realized good value for that. We now have four big operated hubs that we're working with.
Guidance on production, we're not going to go through project by project, some clues here are our underlying production in this year is broadly flat with 2012, and that's after 50,000 barrels a day having been divested. We've completed three turnarounds now at Atlantis, Thunder Horse, and Na Kika. 2013 will be the low point of our production. We expect a further turnaround this year. The drivers for production increases next year will be continued development drilling now at Thunder Horse and Atlantis, and we'll ramp up the Atlantis North expansion, and we'll start up Na Kika phase III. Then beyond that, through the end of the decade, we'll have more development drilling in Thunder Horse, in Atlantis, both the north and the south part of that field, and Mad Dog.
We'll have water injection and expansion at Thunder Horse, and we'll ramp up Mars B, which is a major project we expect to come on next year. We've got eight rigs running now. We may have a ninth one running by the end of the year. We're back to work in the Gulf, and I'm very pleased with the prospects going forward, and this year is the low point for it.
All right. Thanks, Hootan. Back to the U.S. now. Blake Fernandez of Howard Weil. Go ahead, Blake.
Hi. Good afternoon, folks. Thanks for taking my question. It sounds like we're going to get some additional details on CapEx in March. I'll give this a go anyhow. I see the $10 billion of divestitures, and I guess I also see you maintaining the outer year CapEx of $24 billion-$27 billion. I guess my initial thought is that maybe there would have been some downward pressure on that. Which basically insinuates some additional capital intensity in the business. Is that a fair characterization of it, or is it just that you haven't identified specific assets yet, and therefore, you're not prepared to lower that range?
Yeah, Blake, when we looked at the whole portfolio about a year and a half ago, we looked at it and thought, we could spend over $30 billion a year from now to the end of the decade. We have gone through that very carefully. That's why we've initiated a lot of reviews of capital like Mad Dog, retooling that. Very much support the plans at Browse to relook at a better capital efficient way to develop that. We've got a variety of projects that we can defer and are optimizing, and I think $24 billion-$27 billion is the range we'd like to stay so we can continue this machine of BP of trying to become a cash generator for investors, and the only way to do that is pace and time these.
Of course, the most important thing, though, is the selection of projects that continue to generate higher margin production going forward. We'll tell you a lot more about this in March. I know that's sort of a less than satisfying answer, Blake, I think that's probably where I should leave it today.
No worries. The only other question I had for you was specifically on production in the quarter. The decline in Q3 relative to Q2 was not quite as severe as maybe we would've thought. Can you give us a sense of maybe the key drivers there?
Blake, well, the main thing is that there were no hurricanes in the Gulf of Mexico. Q2 production was, I think, 2.24 million barrels a day, this quarter's been 2.21 million barrels a day, excluding Russia. Primarily in the third quarter, we do assume some storm offsets, that hasn't happened in the third quarter, thankfully for everyone. That's why we're saying Q4 would be broadly similar to Q3 because of that absence of hurricanes.
Okay, great. Thank you, Bob.
Right. Thank you. Now to Irene Himona from Societe Generale. Go ahead, Irene. Irene, are you there? All right, we'll move on to Alejandro De Michelis from Exane.
Yes. Good afternoon, gentlemen. Just one quick question. In terms of this disposal program that you're talking about, the $10 billion. You're saying you could be doing about $3 billion for a company your size. If you're expecting to be $10 billion here, is this causing an impact on your long-term production process at all?
Well, I think what we want to do, I don't see it cutting into deeply into operating cash flow. I think what we want to do is make sure we go for value, and there are high-grading opportunities there within our portfolio. There's other things that we may step into at higher value as well. No, it's really the quest for value that reflects rather than Someone asked me if we're selling off the crown jewels of the company going forward. I don't believe we've done that at all with a $38 billion divestment program going forward. That's been, as Brian said earlier, a great review of the portfolio, and we've got other things that I can see in there that will generate value.
It's not that you're cutting into the muscle with this $10 billion?
Yeah, no, that's not the objective at all. We may get some great value for things that some others may see great value for, we've got a very big still portfolio around the world, the idea would not be to cut into the muscle.
Great. Thank you.
All right. Next question from Jon Rigby at UBS.
Oh, hi. Hi, Brian. Hi, Bob. Two questions, please. The first is just on the cash flow and the cash flow target. We're quite a way off, I think, as you noted, to getting to the 2014 target based on the run rate this year. I guess we also got the headwind of, under your assumptions, a lower oil price against the cash flow number that you're looking to get to. Could you just go through, maybe in rank order, the key things that need to happen to get us from where we are now to where we want to be in 2014 on the underlying cash flow? The second question is just around the PSC.
As I understood it, I may have misunderstood, but I think there was some talk about you, BP, actually taking part in appealing against the fairness of the PSC, which I think is coming up shortly. It occurs to me that hearing is coming before the establishment of what the new modus operandi, I thought, for that PSC is going to be. What is your exact stance with regards to the sort of ongoing appropriateness of the PSC sort of legally right now? Thanks.
Okay. Well, Jon, Brian on the cash flow, and I'll take a crack at a complicated legal question.
Probably going to get some general counsel advice on the second question. Jon, I think nothing has changed, I think, from where we were back in October 2011. It's the same components that make up the build-up of that operating cash flow target of $30 billion-$31 billion. If I did them in rank order, I mean, things will move around. It's a risked number, different things happen in year. Right now on our assumptions, it will probably be the biggest component will come from the upstream projects coming on stream this year and next, and the ones that have come on stream in previous years that continue to build. The second biggest component would be obviously around the Whiting Refinery Modernization Project.
Which is now ramping up, and we'll continue now over the next three months, as we ramp that project up, we'll start to process the heavy crudes, and that will take about three months to ramp up. We will also have other components across other businesses where we expect to see some underlying performance improvements that will come through back end of this year and into next. Of course, we talked about that build this year. If you looked at trajectory around working capital, if you just go through a through piece on the working capital and sort of say, look, if it was back to sort of a more typical year, then that will build us back towards the $30 billion-$31 billion.
We're fairly confident that as we look at all the things that we've laid out and the plans that we now have in place, that operating cash flow target is well underpinned. Hence, why we were confident around the increase of the dividend now this quarter, and that we discussed with the board.
Just to follow up though, Brian, is there a portion of some post-Macondo costs to do with the sort of corporate introspection and rechecking and so on that rightly took place post-2010 that will drop away, albeit that clearly there are some sort of structural costs that stay within the business? Is there still some efficiency that can be achieved just through the general running of the business?
Thanks, Jon. You will have seen in the OBNC results this quarter that actually the numbers are down versus the guidance. We're still guiding to half a billion dollars per quarter on average, which is obviously volatile. We did see a reduction in corporate costs, i.e., the costs here in the center, way above the operations. We continue to expect to see more efficiencies in those functions away from where the operations are. Certainly, in terms of the corporate center costs, we continue to expect to see those come down. That would be part of the overall makeup, but it's just one component amongst many components that make up the $30 billion-$31 billion.
Thanks.
Now, Jon, I'm going to take a crack at simplifying some of the legal questions. I'm doing this without legal advice here, it'll probably be simpler. For those of you who don't know what Jon's questioning about a fairness appeal versus something called a business economic loss appeal that are being heard by the Fifth Circuit Federal Court of Appeals in the U.S. The fairness appeal relates to the court's approval of the overall settlement and the certification of a settlement class. This is part of a legal process that was always going to be there, and BP filed its brief in late August of 2013 this year about the fairness appeal.
Following this decision on the business economic losses, BP filed a supplemental brief on that, where BP said in its briefing that in the fairness appeal, that if what we believe is an erroneous interpretation of the settlement agreement is in place, the business economic loss framework, if it's not corrected, this is the one that we've been challenging so much, then the court certification of the settlement class and approval of the overall settlement should not be sustained under the law. When the Fifth Circuit rendered their arguments on the business economic loss, it raised very substantial doubts about whether the settlement can be sustained if it allows payments to claimants who have suffered no injury that's traceable to the accident. In the bottom line, there will be a fairness hearing on the 4th of November.
There will be another hearing to determine the outcome of the business economic loss on the 2nd of December. I suspect that after the hearing on the 4th of November, maybe they'll wait until after December 2nd. If the claims administrator's policies with respect to the issues of loss calculation and the causation under the business economic loss framework are properly revised, the settlement could be returned to its original intended function. If it isn't, then the whole fairness of the settlement can be questioned. I suppose that's a really complicated way to look at two separate issues there, and apologies for those of you who haven't been following all that. We've got a great legal team who are working through this, and we'll just wait and see.
What we say inside the company, Jon, is we're an oil and gas company that's operating and doing well with its operations and running far more efficiently now. It's very important for our staff not to be distracted. I call it a litigation department inside of the company and make sure that it sort of stays separate. Each quarter, we'll keep you updated on this. Jon, did that help at all?
I think it's as clear as it could have been. Thank you.
Okay.
All right. Moving on. We'll take the next question from Theepan Jothilingam at Nomura.
Yeah, thanks, Jess. Hi, Bob. Hi, Brian. Just actually following up on the cash target. I guess the focus is on cash rather than earnings. The first question was just on depreciation for next year. Could you sort of maybe give any indications on how you see that moving? The second question alongside that is just in terms of the tax rate. Clearly, that's been quite volatile over a number of quarters, guidance for Q4 and 2014. The last question is just, you mentioned the Lontra discovery from Cobalt. I was just wondering if you saw that as commercial today or not. Thank you.
Theepan, on the first question, we haven't yet given guidance for 2014 on DD&A. As you've pointed out, it's not an operating cash flow measure. We did give guidance this year that as we were investing in some of the more higher margin areas, the depreciation associated with those is higher. I think from memory, we guided the market this year to $1 billion-$1.5 billion of further DD&A this year associated with those projects. We haven't yet given guidance for 2014.
Tax rate you've answered. On Lontra, Theepan, Cobalt today announced that that's in Block 20. It's reached TD and the drilling results do confirm a sizable section of oil and gas. We're going to drill stem test the well or Cobalt will drill stem test the well to assess what's there. We should be able to have more information on that well by year-end. There is gas in the well along with oil. Under the rights to the contract, Block 20 PSA does not include the gas rights, it's too early to speculate about the distribution of the types of hydrocarbons, we need to do that DST.
I think even if there's a lot of gas there, I suspect that the country will want that gas developed, and I think that might lead to further discussions with the country to make sure that it can be developed. It's too early to declare it definitely commercial, but there's a lot there.
Sorry, Theepan, what was the tax rate question you had, the second piece?
I just wanted to understand. It's been quite volatile for different reasons. For Q4, any guidance there? Does the full year stick? I think you talked about 36%-38% in previous remarks. For next year, is there a big impact once you've got these disposals out the way?
Sorry, Theepan. I think if you remember with 2Q, I stay with the long-term assumption is still 36%-38%. I think for your purposes, 36%-38% is still a good long-term planning assumption in terms of our portfolio. There's nothing that we see that would significantly impact that. Unfortunately, because we move the charge every quarter in any 90-day window, it can indeed go from 45% last quarter to 30-odd percent this quarter. I'm afraid that is just the nature of our business when you look at a 90-day window. The 36%-38% is still good for this year, and it's still good for future.
Yeah. Just in terms of cash taxes, there's no big change from, let's say, this year to future looking or forward-looking years either?
No. Cash tax rate is still running at around about the level that we've said previously, which is obviously, well, significantly below the tax charge of about 5%.
Yeah. Brilliant. Thank you.
All right. We're going to try Irene Himona again. Are you there, Irene?
Yes. Thank you. Good afternoon. I had two questions, please. Firstly, on the Whiting Refinery. You're guiding to weak refining margins in Q4. If we assume current margins and current crude differentials, what full year cash contribution should we expect from the refinery as all the upgrading units start up and ramp up? My second question was on Shah Deniz 2. You signed a couple of months ago the gas sales contracts. Can you indicate, please, the extent to which they are gas or oil price linked? Thank you.
Irene, on the first question around Whiting, obviously the current Canadian spreads, the heavy Canadian crude oil to WTI, they're currently 4Q to date over $31. We would not expect that on a go-forward basis. If they were to stay at those sort of levels, there would be significant surplus cash over and above the $1 billion that we've talked about around Whiting modernization. We've never actually given you the assumption that we've used around the investment in the Whiting case, but it's certainly a number well below the $30-odd a barrel. Therefore, I think one is it would be significantly higher. More importantly, I think as the Whiting units start to ramp up and that 100,000-barrel-a-day coker comes on stream, you'll see those spreads come down.
One of the reasons why you can see these big WTI heavy spreads right now is because actually that oil isn't being soaked up yet by Whiting. As the Whiting units come on stream, we would expect that differential to come down quite significantly.
Yeah.
Okay. On Shah Deniz, Irene, we haven't said what's the basis of those contracts, but they're very competitive with European gas contracts today. For those of you who don't know, this is one of the largest gas condensate fields in the world. Shah Deniz is a phase 2 project that should lead to bringing that gas to market in Europe. We've gone through and have those gas contracts in place, and they're quite competitive for European gas prices, and that's, I think, probably all I should say on that.
Thank you.
All right. From the U.S., Steven Simcoe of Morningstar.
Hi. Congratulations, everyone, on a good day. I had two basic questions. The first one was just given where North American natural gas prices are, I know BP isn't overly exposed, but you do still have a fair amount of exposure to North American natural gas. I'm just wondering if you would see any sort of bullish arguments that the period of under-investment that has been occurring the last 12, 18 months into new gas production outside of a very few plays could lead to a positive run of gas prices going forward.
The second question I had was, you just mentioned, Bob, the idea of the Rosneft's dividend payout ratio potentially being pushed above 25% in the future. I was just wondering how you personally felt about that relative to what's going on the ground in Russia right now and with the outlook for the next five, 10 years. Thanks.
Sure, Steven. Hi. Thanks for your comments. North American Gas, we do have a big position, has a very large and diverse resource base in seven of the top basins in the U.S. We've got about 8 billion barrels of oil equivalent reserves, so it's an important part of our portfolio. As you mentioned, most of our production or most of our portfolio is held by production, so we've got multiple dry gas that gives us some option to ramp up at the appropriate time, should gas prices strengthen. We've taken our rig count down in North America from 24 rigs that we operate in 2010 down to 12 in 2011, five in 2012, then we've got six rigs running now. It's a business that we're running to manage so that we break even cash between $4 and $5 Henry Hub.
I think we're not going to be making assumptions of prices much higher than $5 for some time, I think. I think it's good to see that some of the export projects have been approved, permitted, and look like they're going to go forward. We're going to manage to make sure that business can run break even, really at $4. On Rosneft, I think it's for the government to determine their policies on the kind of dividend levels they want from, whether it's Rosneft or any other companies where the government's involved. I think Rosneft's got a great future. It's got long-term oil price contracts that should certainly design to shore up the balance sheet going forward, and that should be a factor in determining the dividend levels. That's really up for the major shareholders in the government.
They are still, as a country, discussing the increase of the dividend payout for government-controlled entities from 25% to 35%, I'm not involved in those discussions.
All right. Great. Thanks a lot.
Okay. Mm-hmm.
All right. Next question from Alastair Syme at Citi.
Hi, Bob and Brian. Bob, I was very interested in your big-picture comments at the end of the call there about big oil recycling capital. I just wondered if you can talk a wee bit about profitability. It's a question I've asked you before. Clearly returns, return on capital, return on equity has come down over that 15 years you described. Do you think that BP has opportunities that are adequate, versus the inherent commodity price risk in the portfolio, et cetera?
Well, yes. It's been our objective to high-grade the portfolio and move to higher-margin projects. We see the returns coming out of the projects after these 15 major projects that we outlined in 2011, 2012, and 2013 into 2014, have doubled the margins of our overall portfolio. If you invest in the right projects, we think that the returns are there. In the longer term throughout the cycles, upstream and particularly oil projects, I think can provide very good returns. Gas is a much more regional thing. It's very different in North America than it is in Europe and than in Asia. There's a whole spectrum of kinds of returns from the gas projects, and we do have a bias towards the oil projects.
We've got to put ourselves in a diet and choose very carefully and manage our capital in the most efficient way. We're benchmarking the heck out of what we're doing now of IPA benchmarks to make sure that we're making the decisions and managing the capital carefully. The lifeblood of an oil and gas company is finding oil and gas. You've seen us rejuvenate that. That should lead to more and more projects going out in time for us to choose from. Some we won't do, some we will do, and high-grading and managing that and pacing it so that we can generate sort of a sustained level of cash flow that can be used for free cash flow for dividends. At the right time, if our shares, we think are good price for buybacks as well, that's what you see us doing today.
Can I just pick up on one thing? I mean, double the margins isn't necessarily a comment on returns, because that's just the numerator. Do you think the incremental projects are coming in at higher returns than the existing portfolio?
It's the cash margins that are important for us because, well, first, as everyone knows, because we have divested $38 billion of high margin, highly depreciated assets. The disposals we had divested projects that had 59% return on capital employed projects. Return on capital employed is probably not the best metric for us going forward, but we do absolutely see that metric rising. I think the other metric you should look for with us now that we're actively buying back shares is some of the returns per share metrics, which we haven't focused on before, but we will going forward.
The return on equity, for instance.
Yeah. Mm-hmm.
Thank you.
Right. Thank you. Next question from Colin Smith of VTB.
Yes, good afternoon. Thanks for taking my questions. You might actually partially have touched on the answer to Alastair's question. I'm interested in is, you've obviously ramped up the scale of disposals over the next couple of years, but in particular, you've highlighted the intention to recycle that cash back to shareholders. I'm just wondering why in particular that is what you are planning to do with the disposals and the thinking behind that. As you mentioned earlier, you think that you have the potential to spend a lot more than you're actually proposing to spend. I'm curious as to the decision between buying back shares and actually reinvesting for returns, since I assume that's what you would do otherwise. Thank you.
Yeah. Colin, it's actually both. We'll certainly generate cash in some of these. We will. If we have great investment projects, we will absolutely invest in them, and there'll be $24 billion-$25 billion this year and next year. Certainly, that's a lot of capital that we will invest to be able to generate cash going forward. We just think it's good discipline. The dividend is good discipline on management. The statement, we've heard shareholders that believe that our shares are a good investment right now. As long as they remain a good investment, we'll recycle some of that distributions back to the shareholders.
Colin, maybe just to add. I think there's a certain logic that when you shrink the equity base as much as we have, it's right that you should also look to, certainly in moments where the value of the stock is, in our view, severely below where we actually believe the market value is in terms of the assets, that you actually re-equalize that by reducing your share base. I think it becomes logical within the current financial frame.
Okay. Thank you.
Thanks, Colin.
Right. Next is Michele Della Vigna from Goldman Sachs. Now joining.
Good afternoon. Thank you for taking my question. First, I was wondering if we could come back to your 2014 cash flow target. What would be the impact if the U.S. gas prices and the refining environment did not recover from the current low level? Secondly, on your pace of buyback by quarter, I was wondering if that could accelerate or if it is fixed as a percentage of daily volumes. Thanks.
Let me pick up the latter question, which is, there are safe harbor rules that we have to operate within, around the buyback program, and they're linked to the primary stock exchange upon which we trade, which is the LSE. Therefore, there is a limit to how much we can buy back in a day. That historically over the last couple of quarters has been around $30 million-$35 million a quarter. Sorry, a day. Per average of a day over the quarter. On that basis, that's the limiting factor. We're looking at whether we can move outside those safe harbor bounds in terms of accelerating some of the buybacks as we look into next year.
Well, on North American gas prices, they're sensitive. You can comment on that. I'll just say on Whiting, we don't really talk about the light heavy spread assumptions on which the project was based, but I would say it is more than underpinned, that margin assumption for an incremental $1 billion in incremental cash from Whiting. It's more than underpinned at the current price set. As we've said before, we'll have the capability of running up to 80% of the Canadian heavy crudes in that. We don't know, but the benefits of that project could be significantly higher if the WCS differentials expand similar to what occurred in 2011, 2012. We'll see. This may not happen, but we feel pretty confident in the assumptions we've made there.
Michele, in terms of the gas price assumptions, I think we've got rules of thumb out there that you can see. For every $0.10 movement in the price per Mcf, it's about $50 million impact in terms of post-tax operating cash. A $1 would be around about $500 million post-tax operating cash. The original targets we put out there were at $5 Henry Hub, but the oil price is $100 a barrel. To the degree that Henry Hub may be lower, we may see a higher oil price, and those two things will probably cancel each other out.
Thank you.
Michele.
Next, Lydia Rainforth of Barclays.
Good afternoon. Two questions if I could. Firstly, on the upstream profitability in the U.S., even adjusting for the TAPS settlement, it does seem that it was quite a good quarter for the upstream there. Is there anything else special in the quarter we should be aware of, or is that a good underlying level of profitability to look at going forward? Then secondly, just a clarification. You talked about falling levels of turnarounds over the next 2-3 years. I was wondering, what sort of utilization of upstream capacity are you currently running at, and where could that actually ultimately get to? Thank you.
Lydia. Yeah. It was a good quarter. Underlying production up 3% in the U.S. I think mainly it's the lack of hurricanes in the Gulf of Mexico help everyone, the entire industry. They help us disproportionately because we're the biggest producer in the Gulf of Mexico. You see good results in the Gulf as well as some good wells coming on in Atlantis for example, have given a bit of a boost in the Gulf of Mexico. In terms of utilization and turnarounds, I think I'm going to ask you to get in touch with Jess on that. Broadly, we are seeing turnaround levels will go down as we finish this massive amount of turnarounds that we've had over the last 3 years, next year. Deferred production due to downtime is a metric we track internally, that's coming down globally for us as well.
Some of that's happened as well in the Gulf of Mexico, but primarily in the U.S., it has been the lack of downtime due to storms. In that case, it was a very unusual year.
Right. Next question, Lucas Herrmann at Deutsche.
Yeah, Jess, thanks very much. Bob, Brian, good afternoon. Just a couple, if I might. Firstly, just production as we go through the fourth quarter or go into the fourth quarter, same level as Q3. I guess I appreciate that this quarter hasn't been hurricane affected in the Gulf, but given the ramps that I would have thought were ongoing at Skarv, PSVM, that you're also likely to be seeing in the Gulf, my expectation would have been that you'd see some production improvement. My question, in essence, is why the lack of it? Is there a mix effect that one should anticipate in the fourth quarter either way? Secondly, just on exploration, as a question that one should have asked Mike Daly last week, thank you very much for that session.
As you look forward, given the increase in exploration spend, what level of exploration write-off from an accounting perspective should we be anticipating? Is the $500 million or so that we've seen this quarter typical of the level that you'd budget and that we should think about going forward? Should one be expecting that number to rise purely as a consequence of the greater risk you're taking with the drill bit, quite rightly in my view, but greater risk with greater likelihood of write-off? Thank you.
Lucas, hi, thanks. We do see the 4Q broadly level with 3Q. Part of that's coming up because we are continuing. We've completed 17 of the 21 turnarounds so far this year. We do have two turnarounds continuing into the fourth quarter. That's Magnus and Clair. We've got two others scheduled, one in Trinidad and Mad Dog in the U.S. We do have some rig activities in Trinidad. We're moving a rig from a field called Immortelle to Amherstia and Savonette, which are big, heavy lifts, and that will have an effect on the 4Q production. That's as a mix effect. That's lower margin production. I think the mix effect we'll see.
It doesn't mean that it won't be higher in the fourth quarter, but right now, that's where we're seeing it as flat, whereas traditionally, we see a little bit of uptick in the fourth quarter, usually due to some downtime in 3Q.
On the exploration write-offs, Lucas, we take a fairly conservative estimate internally. We don't disclose that externally. You would assume that as we've ramped the exploration program up, that you would start to see more and more success as you drill out the licenses associated with the early part of those programs. You would expect that to come down over time, and we do give Mike Daly full license to actually go and find oil and gas for us. We'd expect that would trajectory over time as you get more and more successful.
Lucas, as Jess just pointed out to me, we did have some downtime in the very first part of the quarter, of the fourth quarter, due to this tropical storm, Karen, in the Gulf, that has had some effect. It was not a very long sustained downtime, but it was some.
Right. Could I just ask one other follow-up to Lydia's almost, which is on utilization rate? You've made a considerable effort to improve the efficiency and uptime of facilities. Can you give us any sense, Bob, of where you expect uptime or plant availability to stand in the future relative to where it might have been 2010, 2011? In refining, you talk about plant availability a lot and getting product through is key. It's no different upstream, but I think we've got very little sense of what the potential improvement or opportunity actually may be on an effective 2 million-barrel a day business.
Well, Lucas, one of the things I've learned over time in talking about utilization rate in the upstream or optimum production rates is everyone has a different definition of this. As we look at the kind of uptime that we have projected in the past of where we're going, I just note that a 1% increase in uptime is worth about $100 million to us in higher operating cash flow. We're looking at, gosh, I hate to throw out a percentage, but much higher than that, 2%, 3% plus is certainly not unreasonable for the kinds of things that we've had. The uptime, I'll give you one example of Greater Plutonio in Angola, which was around 80%, is now up to about 95%, 96%, is just one big example of where our maintenance program we did has really turned around an asset.
The problem with this, Lucas, is definitions. I'm a little careful on the definitions because everyone interprets it slightly differently, but it is making a big difference, and it's part of that 3% underlying production improvement we've got, as well as the projects coming on.
Yeah. Bob, Brian, Jess, thank you very much.
Thanks, Lucas.
Okay, thank you. Next question from Ian Parr of Bernstein.
Afternoon. Thanks for taking my questions. Just thinking about Egypt, given the significant gas discovery there this quarter and your stated intention to high-grade the portfolio. I wonder if you could comment on how Egypt looks in terms of attractiveness versus the rest of the portfolio. Secondly, just a quick one on exploration. You said eight wells currently drilling at the moment, and I wonder if you could remind us what well results we might expect to see before the end of the year. Thanks.
Right. Okay, Ian. Egypt, BP's been operating in Egypt since the 1960s, and it's been a good business for us, and it's got oil in the Gulf of Suez and then significant gas production off of the Nile Delta, which has been a country that has wanted to export it, but actually now has a need internally for it. We have good business in Egypt. We believe the country will need energy going forward. It's got a population that wants prosperity. Like many countries, it goes through its ups and downs, and this is obviously a period of turmoil there. We work well in Egypt and have a great staff in Egypt. We have had a significant discovery.
Looks like more than one TCF of gas offshore, off the northeast part of the Delta, with a good structure there that has all the makings of a good commercial gas discovery offshore. For us, we're not unhappy with where things are today, and you have to see through these big cycles in time. In the exploration side, we've got eight explorations drilling. We expect to complete 16-18 during the year, where we did nine last year. The wells that are still going down, we just announced something on the Angolan well today at Hilo. I mean, with Lontra in Angola. We've got an exploration well that's down. It's not too far away from the objectives in Gila in the Gulf of Mexico. We're drilling a well right now in Brazil. We've got a well in Jordan. We're testing new plays.
We'll be drilling more in India as well. I don't have the exact full list for you, we've got a full set of activities around. If you want to ask about anything specifically, I can tell you.
I think that's it. Appreciate the extra color.
Yeah. Thanks, Ian.
Cheers.
Okay, now to Peter Hutton at RBC.
Hello, thank you very much for taking my question. Just a couple here. On the U.S. upstream, one area of focus I noticed liquids realizations were pretty flat against last quarter, up $0.70, although WTI was up about $11-$12. Was there any driver for that? Was there anything in terms of the mix? Was there anything in terms of the higher proportion of NGLs that we saw coming through in the third quarter of this year? The second area is India, one of my favorite subjects. Bob, can you give us an update of the discussions with the government on the implementation of the gas price? I know that had been announced, but there seem to be further discussions between yourselves and Reliance, and the government into where things stand at that at the moment. Thanks very much.
Yeah. Peter, thank you. Well, you're right to see that in the realizations in the U.S., most of our oil production and realization is weighted towards the Gulf of Mexico. In 3Q, the Gulf of Mexico grades did see a decrease in pricing compared to Brent on a lag basis. As a result, they decreased actually in the Gulf of Mexico quarter-on-quarter. There is a lot of crude bottled up around in the Gulf of Mexico area right now. I think there's been some refinery maintenance work in the Gulf in general that's held the crude there. There has been a dip. I think that's temporary. That's not really to do with NGLs. Brian, you want to add any other point on that?
No, I think in terms of your point on WTI, a lot of our production is linked off Brent. Actually, frankly, we don't price that many barrels off WTI, so you wouldn't see that come through.
In India, I was just there. I spent time and met most members of the government as they work through this decision to move to market-based pricing and time. For those of you who don't know, we have contracts there, the government has in place gas pricing that's around $4.20 an Mcf for all the offshore internal pricing. They've said that they want to move to market prices. They realize they're buying LNG at $15 plus bringing it into the country, and they want to create the incentives to invest more. They have a formula that begins to go in place sometime in 2014 that moves around to about $8 an Mcf, and then a mechanism that is yet to be determined on how it moves to market pricing over time.
There's a little bit of a dispute on the production sharing contract around the D6 field based on, and you all will know this, it's impossible to sort of project rates and reserves. They don't have experience so much with this. When you put a development plan in place, it's like a roadmap and a commitment you don't deviate from. There's a little bit of pushing and shoving on cost recovery there. Quite frankly, everyone I have spoken to wants to see India develop as much oil and gas and resources as it can because it knows it's going to need all of it, and it imports huge amounts and will be in the future. There's talk in India of an election early part of next year. I think that all enters into some of the discussions. They're ongoing.
I remain very optimistic about what we've done in India so far. These two discoveries are really good, and we have submissions in to develop the R series of fields there with the government right now. We'll see.
Thank you.
Okay. Neill Morton from Investec. Are you there, Neill?
I am indeed. Thank you, Jess, and thank you for taking my questions. Just a couple, please, on acquisitions and disposals. Firstly, on disposals. I think I remember, Bob, when you were undertaking the first big disposal program, you talked about sort of 2.1, 2.2 million barrels a day as being a sort of tipping point below which you wouldn't want to see BP go. Yet today you referred to BP as a 3.2 million barrel a day company, sort of implicitly incorporating the Rosneft barrels. I just wondered when you come to the disposal program over the next few years, whether that previous number, 2.1, 2.2, is a sort of, a threshold, if you like. Just secondly, on the CapEx projections. I just wondered again just to confirm that the 24, 27 is an organic number.
The reason I ask that is that you talk about $2 billion-$3 billion as being an ongoing level of disposals for a company of BP's size. I just wondered what an ongoing level of inorganic spend might be, and I'm thinking in terms of farm-ins, acreage acquisitions, signature bonuses, and you also made reference to deepening your interest in your favorite projects. Thank you.
Yeah. Neill, you've got a good memory. We did talk about that two years ago, the 2.1, 2.2, when we were 3 million barrels a day ex Russia, the 2.1-2.2 looked like the right size for where we can get to make sure we can generate cashflow and high margin barrels to keep the machine running in the way that we've described in the strategy. Lamar McKay and I met, in fact, just yesterday and went through looking out for the rest of the decade. We came to the same conclusion that 2.0-2.2 was about the right level for the kinds of projects that we have. The 3.2 comes from adding the Rosneft barrels. Some people like to see the whole together, and some people like it separated out.
You're right in that levels really haven't changed very much after more than two years. CapEx projections, we are referring to the organic number. We're not talking about net CapEx. It's the organic CapEx that we would spend. Inorganic spend, we don't know. There certainly will be inorganic spend in terms of acquisitions of access on the exploration side. There'll be deepening in some projects, but we don't have a target out there. If there are good opportunities that come along that are good investments, I think we'll make them. We don't want to mix the two, because you can play a lot of games with inorganic and organic CapEx, and we want to be very clear to you, we're talking about organic CapEx.
Okay. That's great. Thank you very much.
Thanks, Neill.
All right. We'll finish with just one or two questions from the web. The first one comes from Alex Stewart of Shore Capital, and it's in relation to dividend policy. The question is what range of either dividend cover or payout ratio are you targeting in the medium and long term?
Someone, I think the three, I mean, one is in a business as volatile as ours where oil prices can rise and fall. I think the key measure the board looks at is the sustainability of the dividend going forward. I think that's really the sort of key metric that we look at around the sustainable free cash flows that will underpin a progressive dividend policy. The board talk about three things. One is consistency, hence why we've come out and talked about now that we'll revisit the dividend at 1 Q and 3 Q results. Progressive in terms of how we grow the underlying business from a value perspective, then sustainable. They would be the three key things that we'd look at vis-à-vis dividend policy.
Right. The last one from Iain Armstrong of Brewin Dolphin, which I think we may partly have answered already. Can you give more detail of the possible working capital release next year? Is the return of Whiting a big factor in this?
Iain, good question. We undoubtedly built some inventories this year as Whiting was taken out of action as we were bringing the Coker on stream. That inventory is back in place now. That would not be a big part of any inventory lease that we see next year. Next year is really about what does a normal level of inventories look like given what we've seen this year. I think I said certainly through the fourth quarter and into next year, we'll probably see something like 70%-80% of the working capital build this year reverse out.
Right. That's all our questions. Thank you, everybody.
I'll just add. I just want to thank everybody for the time spending a lot with us today. I just want to just remind everybody that our strategy and what we're trying to do is deliver a very simple set of outcomes that you can expect, which is that material growth and operating cash flow through the back of the decade, disciplined capital spending framework, driving growth and free cash flow in support of that progressive dividend policy, and we'll look to use surplus cash from divestments to enhance distribution to you all. Again, thank you for spending time with us today, and we'll see you next quarter.