英國石油 (BP) 2013 Q3 法說會逐字稿

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

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

Hello, and welcome everyone.

This is BP's third-quarter 2013 results webcast and conference call.

I am Jess Mitchell, BP's head of Investor Relations, and I am here with our Group's 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 UK and SEC filings.

Please refer to our annual report, stock exchange (inaudible) SEC filings for more details.

These documents are available on our website.

Thank you, and now over to Bob.

Thanks, Jess, and welcome, everyone.

No matter where you on 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 strength 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.

And 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 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.

So today's agenda will follow a familiar pattern.

Brian will take you through the third quarter numbers, and the implications of the day's announcements on our financial framework.

I will then give you an update on the legal proceedings in the US, and the progress of our investment in Rosneft.

And then we will give you the headlines of business progress upstream and downstream, before opening things up for questions.

So 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, and 36% higher than the second quarter of 2013.

Compared to the 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 levels seen a year ago and the absence of earnings from the divest of Texas City and Carson refineries, and the 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 highlights at a segment level.

Upstream, the underlying third quarter replacement cost profit before interest and tax of $4.4 billion was unchanged from year ago, and compares with $4.3 billion in the second quarter.

The result versus a year ago reflects low 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 [write-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 high euro 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 a 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 dividend 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 dollars 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, reflect 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 US, 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 cash flow 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 fuel's profitability to remain under significant pressure due to weak refining margins.

This is due to a combination of high gasoline stocks on both sides of the Atlantic, new competitive capacity additions, as well as lower seasonal demand.

In other business and corporate, we reported a pretax underlying replacement cost charge of $380 million for the third quarter.

Guidance for the year remained 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 UK 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% to 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 plaintiff's 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 de-recognized 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 head room 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 $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 through 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 working capital build of around $5.5 billion, which we would 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 at a target band of 10% to 20%, while uncertainties remain.

This slide outlines our financial framework for 2014 and beyond.

We continue to expect operating cash flow of $30 billion to $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 at around the same level expected for this year, in the range of $24 billion to $25 billion.

Beyond that, we expect annual gross capital expenditure to be in the range of $24 billion to $27 billion through to the end of the decade.

We are confident in our ability to deliver material real 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.

And 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 US 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 that the accident was the 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 1, 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 efforts are substantially overstated.

We do not know when the Court will issue a ruling on either Phase 1 or Phase 2 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 US 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 plaintiff's steering committee as Brian mentioned earlier, BP was successful in challenging the claim's administrator of interpretation of 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 did not have, quote, actual injury traceable to the loss from the Deepwater Horizon accident, unquote.

On the 18th of October, the District Court issued a preliminary injunction that 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 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 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.

And finally, MDL 2185 is a co-ordinated proceeding pending in Federal court in Texas, and includes a purported class action on behalf of ADS purchases under US 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 of around $460 million.

This was the first dividend since the transaction was completed in March of this year.

And following my election to the Rosneft' main Board of Directors in June, I have been actively participating in the Board's activities, providing perspective 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 NL.

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 the 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.

And 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.

The deepest well ever drilled in Egypt's Nile delta was called Salamat.

On Block 21 in Angola, the Cobalt-operated launcher well reached TD, and confirmed an oil and gas discovery.

The well will be drillstem tested, and the rig will then move to another structure on the block, and 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 8 in progress today.

While in terms of access, we have a 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 a third start up of the year, more on which I will talk about it a moment.

And we have five major projects on track for start up in 2014.

They are Na Kika 3 and Mars B in the Gulf of Mexico, Kinnoull in the North Sea, CLOV in Angola and Sunrise Phase 1 in Canada.

So we have seen some important milestones in the last few months, but actually our major focus is not only on the discoveries or the startups that make the headlines, but the safe, reliable execution of what we do everyday 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 turnaround on many of our key assets in many countries.

So moving on, let me update you in more detail on our major projects.

Our key 2012 start-ups continue to ramp up their production as planned, and we have started up three more major projects in 2013.

As I mentioned, the North Rankin 2 field in Australia became a third of these, following the Atlantis North expansion in Gulf of Mexico and the Angola LNG project.

The Chirag oil project in Azerbaijan is on track for start-up around the end of the year.

Milestones are being passed on constructing or commissioning the start-ups 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, but we continue to work with the joint venture to bring those 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 project's hopper.

This has increase their value for you, and reflects capital discipline.

And 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 round-up on the 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 have to drilling on Atlantis by year-end, is on location undergoing acceptance testing.

That is 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 which was installed in 3Q, and work on a tension leg platform rig and commissioning activities for the topsides and subsea commissioning are progressing well.

Na Kika 3 is on track for start-up 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 start-up.

In the North Sea, Scarv is ramping up well, with production averaging 148,000 barrels of oil per day.

The offshore construction of Kinnoull is progressing well, with all the topsides underdeck 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 2 gas development.

As previously mentioned, we are 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 start-up around the end of the year.

So 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.

Now 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 in China.

We have 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.

And 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 under way.

Over 50% of sales revenue are from growth countries in 3Q 2013.

The Whiting refinery has continued to bring units on stream during the third-quarter.

As previously announced, the crude units started operations in Q2, as planned.

Since then, the gas oil hydrotreater and the largest of two sulphur recovery units, along with 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 advantaged downstream assets in our portfolio, and underpins the ability to deliver increased cash flow in 2014.

And so to summarize, this was another quarter of moving ahead.

We have recently launched operations such as PSVM in Angola and Scarv in the North Sea that are now producing strongly.

We are 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.

And we are seeding the portfolio in the future with discoveries, such as those in 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 the completion of the major upgrade at the Whiting refinery.

These are all examples of the way we are putting our strategy into action.

And 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 have 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 would 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 super majors.

We then went through a phase of inorganic growth, driven by the prospect of synergies and cost savings.

In the last decade, the super majors 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 of McKinsey circulated that the super majors doubled their CapEx over eight 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 waves.

Right now, I think it is fair to say opinion is divided.

But the investments are now coming onstream rapidly, and the answer to that question will become clearer in the next year or so.

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 and returns that our investors expect and deserve.

And with that, thank you for your attention, and now over to you for any questions.

(Operator Instructions)

So the first question of today comes from Fred Lucas of JPMorgan.

Go ahead, Fred.

Afternoon, thanks.

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, on how much of that?

Could you also clarify, looking 2015 and beyond, what takes BP's CapEx from a level of $24 billion to $27 billon?

So 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 affect?

And finally if I may, could you quantify your receivable from Egypt?

I noticed $40.9 billion trade net of receivables on the balance sheet.

How much of that is owed to you by the Egyptian government?

Thanks.

I will take the first one around business economic loss claims.

It is complicated, of course, and it has got lots of uncertainty around it.

But 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.

So for business economic loss claims, in the original provision we had 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 Q2 and currently sits at $2.5 billon.

There is about -- and so 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 of the Fifth Circuit, in terms of interpretation of this mismatching, this what, you 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 determinations within the Fund which have now been held up as a result of the Fifth Circuit Court of Appeal ruling.

To say that actually these claims appear to be wrong, in terms of what was agreed, and have asked the judge to now opine on what the 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 the matching issue which he believes, based on what he said, is he believes that resulted in relatively few claims being paid out between now and the remand period after the 2nd of December that was agreed to by the judge on what the actual criteria should be for these claims.

Of that $1 billion, we believe that we have appealed 93% of those claims, and we believe 90% of that is associated with the matching issue.

I hope that answers your question, Fred.

Can you say how much actually has been paid already, which you think is a mis-match, not fair or unreasonable?

I think, Fred, what we will now need to do is go through the process with the Court.

Once the court opines on the interpretation, given on what has come back from the Fifth Circuit, then we will go back and look at what claims have been paid out.

And to the degree that we believe they are unreasonable claims, or do not match the interpretation of the way in which the funds should have treated these claims, we will then look to clawback those claims that have gone.

But 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 $24 billion to $27 billion by the end of -- I think you said 2017.

We haven't actually said that.

What we have said is, between now and the end of the decade, we will be working within a range of $24 billion to $27 billion.

In 2012, we are between -- in 2013, we are between $24 billion and $25 billion.

We are going to keep that in the same range for 2013, and then we will come back in March.

I think we have got a date of March 4 now, to have a strategy review with you laying out in a little bit more detail, a lot more detail between now and the end of the decade.

So I think it is premature to assume we are going to go back up to $27 billion by 2017.

And Fred, on the Egyptian receivable, we continue to monitor change in political events in Egypt closely.

I think importantly, none of our operations have been impacted by the events that we have seen so far, and we continue to work closely with the Egyptian authorities.

We have never actually quantified the scale of the receivable.

We are working very closely with ETP and the government, in terms of bringing that receivable down.

And actually in fact, that receivable did come down to the third-quarter from where we were at the end of 2Q, and we are doing that through various management (inaudible) through listings and so on.

But we don't actually quantify the scale of it.

Okay.

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, but continued right through, in fact, all year.

Very good.

Thanks.

Thanks, Fred.

Okay.

We will take the next question from the US, Robert Kessler from Tudor Pickering.

Hi, good afternoon.

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?

And then secondly, as it relates to the divestment program, the $10 billion of incremental developments.

Can you give us some color on the assets up for sale in there?

And is it upstream?

At what level of production might be associated with that?

Robert, hello.

This is Bob.

On TAPS, it is material, because it is over $100 million.

But -- and I think I will just leave it at that.

It's not publicly disclosed.

But that is not a big part of the performance during the quarter.

It is over $100 million.

And then 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 will be a mixture of upstream and downstream projects.

It could include everything from some of the exploration projects we have, maybe interest in some of the big mega projects we have, and we will look at all the other assets as well.

But this is early days.

We had said that we would divest $2 billion to $3 billion a year.

We have divested to $38 billion now, and $10 [billion] on top of that.

It is -- a company of our size should have a natural churn in the $2 billion dollar to $3 billion range anyway.

So we see some other assets that we think will have more value to others.

And we will just head down that, and announce them when we are ready.

Thanks, Robert.

Bob, it almost sounds as though you have 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 have identified assets internally?

Or are you rather saying, $2 billion to $3 billion isn't where we should be.

We have got to crank that up and double it, and just set that target, and then you will find assets to meet the target?

Yes, Robert, it's Brian.

I think all roads lead back to strategy.

And as we look at our portfolio, we learned a huge amount from the $38 billion disposal program.

And that was a quite significantly weighted toward late-life assets, which we 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.

As Bob said, we always target $2 billion to $3 billion.

We have a pretty substantive list of potential asset that could cover the $10 billion.

But we just think in terms of -- as we look at the portfolio.

And Bob is right, this is complete mix of early life to late life assets.

But strategically, we believe these are sort of bottom-end of portfolio for it, in terms of what would attract investments in the future.

And therefore, it is right that we realize that value.

And today, we have gone the further step of linking the realization of that value distribution to shareholders through buyback.

And at the right time, if there is an opportunity to deepen some of our existing projects, we will also deepen in other things, as well.

So it is not all going to be a one way out.

Thanks, Robert.

All right.

Thank you.

We will take the next question from Jason Kenney at Santander.

Thanks for taking my question.

I have got two, if I may.

So I am looking at the Clean Water Act provision, which I think is around $3.5 billion.

And regardless of the actual final amount for that fine, have you got a view of when the earliest period is, that you can envisage paying that fine?

Would it be before the end of 2014, or possibly later?

And then 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 is in that year?

And the second question, I mean, I was just looking back over the year, really.

And in second-quarter numbers, there was a material miss for BP.

And as part of that, there was a comment from you that analysis of Russia was maybe not as sharp as it could be, from Western analysts compared to the Russian analysts of Rosneft.

But then in third-quarter numbers, so my calculations, we have got a material beat, 75% of which is [UPIS] and other business and corporate.

And we actually seem to have got our Russian act together, as a group of analyst's.

So I am wondering how that -- and obviously, the beat is exaggerated by lower taxes as well.

So I am wondering if there is a view in BP, as to what analysts have got modeled wrong for the third quarter, really?

You sound like you have taken it personally, Jason?

(Laughter).

It's not personal, but I want to get this right for the fourth quarter.

Yes, sure.

Well, first on your first question.

Yes.

Jason, maybe a little point in the second, but I will let Bob talk to you.

So on the first question, the $3.5 billion is what we set aside, way back in July 2010.

And it was our best estimate at the time, and we see nothing that has changed since then to change that estimate.

So that is what we still carry as a charge.

That is clearly not accounted for in terms of the operating cash flow targets.

And 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 original operating cash flow target of around $33 billion, we brought that in line with what we saw.

In terms of the fine, you have to get basically -- the earliest point of time is very uncertain, Jason, so it is impossible for me to say.

And our General Counsel is next to me, he would probably tell me to stop now.

But clearly, you have get through Phase 1, Phase 2, have a judgment on Phase 1 of the trial, Phase 2 of the trial, and then Phase 3. As I understand it, Phase 3 is due to start sometime next year.

Okay.

Yes, Jason, on Russia, I think --as we know, and BP with the TNK-BP investment, the duty lag and the Russian accounting, is not a simple thing to do.

But to give you something that will, I think help going forward, I will give you, our earnings in the second quarter were $218 million.

And in third quarter here, they are $808 million.

Roughly $300 million of that is made up by foreign exchange, because the ruble has strengthened.

It had a very weak second quarter.

And at, 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.

And then, increased production was around $60 million.

So that will give you some sense of the difference between 2Q and 3Q.

And Jason, just in terms of the -- just a rule of thumb -- I think you have 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 the moving parts we have.

We try and give you a rules of thumb, but for a 90 day window, I believe that may be nearly impossible for you.

So I think (inaudible).

Maybe, just on that point, then.

I mean, in 2014, the big thing for a DCF at BP, would be the kind of dividends that you are expecting out of Rosneft.

It doesn't really matter what the earnings are.

It is more, how you going to get the dividends out.

So can you give us today some sort of indication of what confidence you have in a level of dividend from Rosneft over the 12 months?

Yes, 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 has actually been speculation of it rising.

But, I think that is a good -- 25% I think, is a good planning number for the dividends.

I mean, Rosneft has consistently paid its dividends, they just do it on a different schedule than Western companies.

Okay.

Thanks.

All right.

I think we will move on then to Hootan Yazhari from Bank of America Merrill Lynch.

Go ahead, Hootan.

Good afternoon, gentleman.

I have 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% to 20% gearing targets at the moment?

Could this potentially be something you look to revise upwards to release further capital for shareholder distribution?

And finally, I just wanted to get an update on the Gulf of Mexico.

You have 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 have seen a build of about $5.5 billion of working capital.

It is not structural.

It is lots of different moving parts.

And therefore, when we look at it, it [isn't] a structural increase, especially given that we sold off a number of assets.

So in fact, the net number is coming down.

But as you have seen that build through this year, I think we just are flagging it, so it sort of helps you in terms of what this year would look like, if that build hadn't happened.

So you can get a sort of a cut through the actual underlying operating cash flows.

And in terms of the windows I see, there is lots of volatility around working capital.

But if all things being equal from where we are today, the prices were -- stayed where they are today, and that the operations are in line with what we expect, then I would expect certainly over 70% or close to 80% of that to unwind in the next 12 months.

Hootan, on your other questions, you are right.

That is a nice graph, when you see the gearing levels drop out of above the 20% down to the low teens, which is the range that we have said for some time, the Board supports us paying the 10% to 20% range in terms of prudence.

That gives us a lot of flexibility for the future to do lots of different things.

But right now, our prudent target is to remain within the range.

And then, on the Gulf of Mexico, you are right.

The Gulf of Mexico is really important for us.

It is central to the portfolio for decades to come.

It is very high-margin production.

We have done some disposals in there, but that was strategic.

We realized good value for that.

We now have four big operated hubs that we are working with.

Guidance on production, we are not going to go through project by project, but some clues here.

Our underlying production in this year is broadly flat with 2012, and that is after 50,000 barrels a day having been divested.

We have completed three turnarounds now at Atlantis, Thunderhorse, and Na Kika And 2013 will be the low point of our production.

We expect a further turnaround this year.

The drivers between -- for production increases next year, will be continued development drilling now at Thunder Horse and Atlantis, and we will ramp up the Atlantis North expansion, and we will start up Na Kika Phase 3.

And beyond that, through the end of the decade, we will have more development drilling in Thunder Horse, in Atlantis both the North and South part of that field, and Mad Dog.

We will have water injection and expansion at Thunder Horse, and we will ramp up Mars B, which is a major project we expect to come on next year.

We have got eight rigs running now.

We may have a ninth one running by the end of the year.

So we are back to work in the Gulf.

And I am very pleased with the prospects going forward, and we are at -- this year is the low point for it.

All right.

Thanks, Hootan.

Back to the US now.

Blake Fernandez of Howard Weil, go ahead, Blake.

Hi, good afternoon, folks.

Thanks for taking my question.

It sounds that we are going to get some additional details on CapEx in March.

But I will 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 to $27 billion.

I guess my initial thought is that maybe there would have been some downward pressure on that, which basically insinuates some addtional capital intensity in the business.

Is that a fair characterization of it, or is just that you haven't identified specific assets yet, and therefore, you are not prepared to kind of lower that range?

Yes, 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.

And we had gone through that very, very carefully.

That is why we initiated a lot of reviews of capital like Mad Dog, retooling that, very much support the plans at Browse to re-look at a better, capital efficient way to develop that.

And we have got a variety of projects that we can defer and are optimizing.

And I think $24 billion to $27 billion is the range that we would 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.

But we will tell you a lot more about this in March.

I know that is sort of a less than satisfying answer, Blake, but I think that is 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 3Q relative to 2Q was not quite as severe as maybe we would have thought.

Can you give us a sense of maybe the key drivers there?

Yes, Blake, well, the main thing is that there were no hurricanes in the Gulf of Mexico.

2Q production was I think, 2.24 million barrels a day, and this quarter has been 2.21 million barrels a day, excluding Russia.

But primarily in the third quarter, we do assume some storm upsets, and that hasn't happened in the third quarter, thankfully for everyone.

And that is why we are saying 4Q would be broadly, broadly similar to 3Q, because of that absence of hurricanes.

Okay.

Great.

Thanks, Bob.

All right, thank you.

Now to Irene Himona from [Exane].

Go ahead, Irene.

Irene?

Irene, are you there?

All right.

We will move on to Alejandro Demichelis from Exane.

Yes, good afternoon, gentlemen.

Just one quick question.

In terms of the disposal program that you are talking about, the $10 billion.

You are saying you could be doing about $3 billion for company your size.

If your strategy is to be $10 billion here, is this causing an impact on your long-term production prospects at all?

Well, I think what we -- 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 hydrating opportunities there within our portfolio.

There is other things that we may step into higher value as well.

So, no.

It's really -- the quest for value that, that reflects, rather than -- someone asked me if we are selling off the crown jewels of the Company going forward?

I don't believe we have done that at all, with the $38 billion divestment program going forward.

That has been, as Brian said earlier, a great review of the portfolio.

And we have got other things I can see in there that will generate value.

So it is not that you are cutting into (inaudible) with this $10 billion?

Yes.

No, that's not the objective at all.

And we may get some great value for things, that some others may see great value for in.

But we have very big still portfolio around the world.

And the idea would not be to cut into the muscle.

All right.

Thank you.

All right.

Next question from Jon Rigby at UBS.

Hi, Brian, hi, Bob.

Two questions, please.

The first is, just on the cash flow and the cash flow target.

We are quite the way off, as I think you noted to getting to the $24 billion target, based on the run rate this year.

And I guess we have also got the headwind of on your assumptions of lower oil price, against the cash flow number that you are looking to get to.

So 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 cash flow, underlying cash flow?

And the second question is just around the PSC.

As I understood it -- sorry, I may have been -- misunderstood.

But I think there was some talk about you, you BP actually, taking part in the appeal against the fairness of the PSC, which I think is coming up shortly.

But it occurs to me that that hearing is coming before the establishment of what the new modus operandi for that PSC is going to be.

So 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 will take a crack at a complicated legal question.

(Laughter).

Probably you will get General Counsel advice on the second question.

So, Jon, I think nothing has changed I think from where we were back in October 2011.

It is the same components that make up the build for that operating cash flow target of $30 billion to $31 billion.

If I did them in rank order, I mean things will move around.

It is a risked number, so different things happen in year.

But right now, on our assumptions, it would probably be the biggest component will come from the upstream projects coming onstream this year and next.

And the ones that come on stream in previous years, will continue to build.

The second biggest component would be, obviously, around the Whiting refinery modernization project, which is now ramping up.

And will continue now, over the next three months, start the process.

As we ramp that project up, we will start the process for 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 backend of this year and into next.

And, of course, we talked about that build this year.

If you looked at the trajectory around working capital, if you just go through a piece on the working capital and sort of say, look it is back to a sort of more typical year.

And then that will build us back towards the $30 billion to $31 billion.

So we are fairly confident that as we look out all the things we have laid out, and the plans that we now have in place that, that operating cash flow target is well underpinned, hence why we were confident around the increase in the dividend now this quarter, and that we have discussed with the Board.

And just, Brian, is there a portion of cost, post-Macondo costs to do with the corporate introspection and rechecking and so on that took -- that rightfully took place post 2010 that will drop away, albeit that clearly, there is some structural cost that stays with it.

Is there still some efficiency that can be achieved through just the general running of the business?

Yes, thanks, Jon.

You will have seen in the OB&C results this quarter, they are actually -- the numbers are down versus the guidance.

We are still guiding to $0.5 billion a quarter, and (inaudible) over time, but we did see a reduction in corporate costs, i.e.

the costs here in the center, way above the operations.

And we continue to expect to see more efficiencies in those functions, away from where the operations are.

But certainly, in terms of the corporate center's cost, you can continue to expect to see those come down.

And that would be part of the overall makeup, which is just one component amongst many components that make (inaudible)

Perfect.

Thanks.

Now, Jon, I m going to take a crack at simplifying some of the legal questions.

I am doing this without legal advice here.

So, I am probably going to be simpler than -- so for those of you who don't know what Jon's question about a fairness appeal, versus something called a business economic loss appeal, that are being heard by the Fifth Circuit Court -- the Federal Court of Appeals in the US, the fairness appeal relates to the Court's approval of the overall settlement, and the certification of a settlement class.

And this is part of a legal process that was always going to be there, and BP filed this 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 is not corrected, this is the one that we have 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.

So 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 is traceable to the accident.

So 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, that may be they will wait until after December 2. But 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.

But if it isn't, then the whole fairness of the settlement can be questioned.

So I suppose that is a really complicated way to look at a very -- what were two separate issues there.

And apologies to those of you who haven't been following all that.

But we have got a great legal team, who are working through this, and we will just wait and see.

But what we say inside the Company, Jon, is we, we are an oil and gas company that is operating, and doing well with its operations and running far more efficiently now.

And it is very important for us not to be distracted.

So I call it a litigation department inside of the company, and make sure that it sort of stays separate.

So each quarter, we will keep you updated on this.

Jon, did that help at all?

(Laughter).

I think it is as clear as it could have been.

Thank you, Bob.

Okay.

All right.

Moving on then, we will take the next question from Theepan Jothilingam at Nomura.

Yes, thanks, Jess.

Hi, Bob, hi, Brian.

Just actually pulling up on the cash target.

I guess, the focus is on cash rather than earnings.

So the first question was just on depreciation for next year.

Could you sort of maybe give any indications on how you see that moving?

And then, the second question alongside that, is just in terms of the tax rate.

Clearly, that has been quite volatile for a number of quarters.

So guidance for Q4 and 2014.

And the last question is just -- you mentioned the long-term 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 pointed out, it's not operating cash flow measure.

But we did give guidance this year that as we were investing in some of the more high margin areas, the depreciation associated with those is higher.

And I think if you remember, we guided the market this year to $1 billion to $1.5 billion of further DD&A this year associated with those projects.

We haven't yet given guidance for 2014.

Tax rate, you answer.

So on Lontra, Theepan, Cobalt today announced that, that is in Block 20, has reached TD.

And the drilling results do confirm a sizable section of oil and gas.

We are going to drillstem test the well, or Cobalt will drillstem test the well to assess what is there.

We should be able to have more information on that well by year-end.

There is gas in the well, along with the oil.

Under the rights of the contract, Block 20 PSA does not include the gas rights.

But it is too early to speculate about the distribution types of hydrocarbons, and we need to do that DST.

And I think even if there is a lot of gas there, I suspect that the country will want that gas developed.

I think that might lead to further discussions with the country, to make sure that it can be developed.

But it is too early to declare it definitely commercial, but there is a lot there.

Yes, sorry, Theepan, what was the tax rate question you had, the second one?

No, I just wanted to understand.

I mean, it has been quite volatile, and for different reasons.

But post -- well, for Q4, any guidance there, does the full year stick?

I think you have talked about 36% to 38% in previous remarks.

And then actually for next year, is there a big impact once you have got these disposals out-of-the-way?

So, if you remember, with 2Q, I kind of stayed with the long-term assumption, still 36% and 38%.

I think for your purposes, 36% to 38% is still a good long-term planning assumption, in terms of our portfolio.

There is nothing that we see that would significantly impact that.

And unfortunately, because we move the charge every quarter, in any 90 day window, it can indeed go from 45% last quarter to [30%-odd] this quarter.

That is just the nature of our business, when you have got a 90 day window.

So the 36% to 38% is still good for this year, and it is still good for future.

Yes.

And just in terms of cash taxes, there is no big change from let's say, this year to future looking or forward-looking years either?

No.

Cash tax rates are still running round about the level that we set previously, which is obviously, well, significantly below the tax charge of about (inaudible).

Yes, brilliant.

Thank you.

All right.

We are 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.

I mean, you are guiding to weak refining margins in Q4.

If we assume current margins and current crude differentials, what full-year contribution, cash contribution should we expect from the refinery, as all the upgraded operating unit start up and ramp up?

And 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 of which they are gas or oil price linked?

Thank you.

So, Irene, around the first question around Whiting, obviously, the current Canadian spreads, the heavy Canadian crude off the WTI, they are currently for 4Q to date over [$31] booked.

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 talked about around Whiting modernization.

We have never actually given you the assumption that was used, around the investments in the Whiting upgrade.

But certainly, a number well below the $30-odd a barrel.

So therefore, I mean, I think, one is, it would be significantly higher.

But more importantly, I think as the Whiting unit starts to ramp up, and that 100,000 barrel a day coker comes on stream, you will see those spreads come down.

One of the reasons why you see can these big WTI heavy spreads right now, is because, actually that oil isn't being soaked up yet by Whiting.

As the Whiting unit comes onstream, we would expect that differential to come down quite significantly.

And on Shah Deniz, Irene, we haven't said what is the basis of those contracts.

But they are very competitive with European gas contracts today.

For those of you that don't know this, this is a big -- 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.

But we have gone through and had those gas contracts in place and they are quite competitive for European gas prices.

And that is, I think, probably all I should say on that.

Okay.

Thank you.

All right.

From the US, Stephen Simko of Morningstar.

Congratulations, everyone, on a good day.

I had two basic questions.

And 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.

And I am just wondering if you would see any sort of bullish arguments that the period of underinvestment that had been occurring the last 12, 18 months into new gas production outside of a very few plays, could lead to a positive -- a positive run of gas prices going forward?

And then the second question I had was, you just mentioned, Bob, the idea of the Rosneft dividend payout ratio potentially being pushed above 25% in the future.

And I was just wondering how you personally felt about that, relative to what is going on the ground in Russia right now, and with the outlook for the next 5 to 10 years?

Thanks.

Sure, Stephen, hi.

Thanks for your comments.

North American gas, we do have a big position, have a very large and diverse resource base in seven of the top basins in the US.

We have got about 8 billion barrels of oil equivalent reserve, so it is an important part of our portfolio.

As you mentioned, most of our production, most of our portfolio is held by production.

So we have got multiple dry gas, that gives us somewhat an option to ramp up at the appropriate time, should gas prices strengthen.

We have taken our rig count down in North America from 24 rigs that we operated 2010, down to 12 in 2011, and 5 in 2012.

And then, we have got 6 rigs running now.

And it is a business that we are running to manage, so that we breakeven cash, between $4 and $5 Henry Hub.

I think -- I think we are not going to be making assumptions of prices much higher than $5 for some time I think.

I think it is good to see that some of the export projects have been approved, permitted.

It looked like they are going to go forward.

But we are going to manage, to make sure that business can run, breakeven really at $4.

On Rosneft, I think it is 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 is involved.

I think Rosneft has got a great future.

It has got long-term oil price contracts that should, certainly designed to shore up the balance sheet going forward.

And that should be a factor in determining the dividend levels.

But that is really up for the major shareholders and the government.

They are still, as a country discussing the increase in the dividend payout for government-controlled entities from 25% to 35%.

But I am not involved in those discussions.

All right.

Great.

Thanks a lot.

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.

And I just wonder if you can talk a little bit about profitability.

It is a question that I have asked you before.

Clearly, returns, retun 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.

When we look at the -- it has been our objective to high-grade the portfolio, and move to the higher-margin projects.

And so, we see the returns coming out of the projects, after these 15 major projects that we outlined in 2011, '12 and '13 and '14 have doubled the margins of our overall portfolio.

So if you invest in the right projects, we think the returns are there, in the longer-term, throughout the cycle.

So upstream, and particularly oil projects, I think can provide very good returns.

Gas is a much more regional thing.

It is very different in North America, than it is in Europe, and then in Asia.

So there is a whole spectrum of kinds of returns from the gas projects.

And we do have a bias towards the oil projects.

We have got to -- we have got to put ourselves on a diet, and choose very carefully and manage our capital in the most efficient way and we are benchmarking the heck out of what we are doing now.

I pay a benchmarks to make sure that we are making the decisions and managing the capital carefully.

The lifeblood of an oil and gas company is finding oil and gas.

You have 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 the sustained level of cash flow, that can be used for free cash flow for dividends.

And at the right time, if our shares we think are a good price for buybacks, as well.

And that is what you see us doing today.

Can I ask one thing?

I mean, double the margins isn't necessarily a comment on returns?

Because that is just the numerator.

I mean, did you think the incremental projects are coming in at higher returns than existing portfolio?

It is the cash margins that are important for us.

Because the returns -- well, as everyone knows, because we have divested $38 billion of high-margin, highly depreciated assets.

We have got the -- disposals we had divested projects that had 50%, 59% return on capital deployed projects.

So we -- we are -- so return on capital is probably not the best metric for us going forward.

But we do, absolutely, the that metric rising.

I think the other metric you should look for with us, now that we are actively buying back shares with some of the returns per share metrics, which we haven't focused on before.

But we will, going forward.

So a return on equity process?

Yes.

Okay.

Thank you.

All 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.

What I am interested in is, you obviously have ramped up scale of disposals over the next couple of years.

But in particular, you have highlight the intention to recycle that cash back to shareholders.

And I am wondering why, in particular, that is for what you are planning to do with the disposals and the thinking behind that?

Because as you mentioned earlier, you think that you have a potential to spend a lot more than you are actually proposing to spend.

And I am curious as to the decision between buying back shares and actually reinvesting for returns, since that is what I would assume that is what you would do otherwise?

Thank you.

Yes, Colin, it's actually both.

I mean, we will certainly generate cash, and some of these -- we will.

If we have great investment projects, we will absolutely invest in them.

And there will be $24 billion to $25 billion this year and next year.

And certainly that is a lot of capital that we will invest, to be able to generate cash going forward.

But we just think it is good discipline, the dividend.

It's good discipline on management.

And the statement -- we have heard shareholders that if -- I believe that our shares our a good investment right now.

And so as long as they remain a good investment, we will recycle some of that distribution back to the shareholders.

And Colin, maybe just to add.

I think there is a certain logic that when you shrink the equity base as much as we have, it is 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.

But you actually, we equalize that by reducing the share base.

So I think it becomes logical within the current financial frame.

Okay.

Thank you.

All right.

Next is Michele Della Vigna from Goldman.

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 US gas prices and the refining environment did not recover from the current low level?

And then, 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 pickup this, the latter question, which is, there are Safe Harbor rules that we have to operate within, around the buyback program.

And they are linked to the primary stock exchange upon which we trade with the [VLSV].

So therefore, there is a limit to how much we can buy back in a day.

And that historically, over the last couple of quarters,has been around $30 million to $35 million a quarter.

Sorry, a day, per average a day over the quarter.

And on that basis, that factor is the limiting factor.

We are looking to whether we can move outside those Safe Harbor bounds, in terms accelerating some of the buyback, as we look into next year.

Well, on North American gas prices, their sensitivity, you can comment on that.

I would just say on Whiting, we don't really talk bout 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 dollars of incremental cash from Whiting, it's more than underpinned at the current price set.

And we will have -- as we have said before, we will have the capability of running up to 80% of the Canadian heavy crudes in that.

So we don't know.

But the benefit of that project could be significantly higher if the WSC differentials expand, similar to what occurred in 2011, 2012.

So we will see.

This may not happen.

But we feel pretty confident in the assumptions we have made there.

And then Michele, in terms of the gas price assumptions, I think we have got a rules of thumb out there, but you can see that it's $0.10.

For every $0.10 movement in the price per Mcf, it's about $50 million impact, in terms of the (inaudible) operating cash.

So $1 would be right around $[500] million post-tax operating cash.

The original targets put out, they were $5 Henry Hub, a fuel price of $100 a barrel.

So if we agree that the Henry Hub may be lower, we may see a higher oil price, and those two [cancel each other out].

Thank you.

All right.

And next is Lydia Rainforth of Barclays.

Yes, good afternoon.

Two questions, if I could.

Firstly, on the upstream profitability in the US.

Even adjusting for the TAPS settlement, it just seemed that was quite a good quarter for the upstream.

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.

And then secondly, just a clarification.

You talked about falling levels of turnaround during the next two to three years.

I was wondering, what sort of utilization of upstream capacity are you currently running at, and where could that ultimately get to?

Thank you.

Lydia, yes.

It was a good quarter, underlying production up 3% in the US.

I think mainly, it is the -- the lack of hurricanes in the Gulf of Mexico helped everyone, the entire industry.

But they help us disproportionately, because we are the biggest producer in the Gulf of Mexico.

So if 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 am going to ask you to get in touch with Jess on that.

But broadly, broadly, we are seeing turnaround levels will go down, as we finish this massive amount of turnarounds that we have had over the last three years next year.

The deferred production due to downtime is a metric we track internally, and that is coming down globally for us, as well.

And that -- some of that has happened, as well, in the Gulf of Mexico.

But primarily, in the US, it has been a lack of downtime due to storms.

In that case, it was a very unusual year.

Thank you.

All right.

Next question, Lucas Herrmann at Deutsche.

Yes, Jess, thanks very much, and 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 the same level as Q3.

I guess I appreciate the term, this quarter hasn't been hurricane affected in the Gulf.

But given the ramps that I would have thought were ongoing, at Star, PSVM that you also likely to be seeing in the Gulf, my expectation would have been that you would see some production improvement.

So my question in essence is, why the lack of it?

And is there is a mix effect that one should anticipate in the fourth quarter, either way?

And secondly, just on exploration, as a question that one should of asked of Mike Daley 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 have seen this quarter, typical of the level that you budget, and we should think about going forward?

Or should one be expecting that number to rise, purely as a consequence of the greater risk you are taking with the drill bit, quite rightly in my view -- but greater risk and greater likelihood of write-off?

Thank you.

Lucas, hi.

Thanks.

We do see 4Q broadly level with 3Q.

Part of that is coming up, because we do -- we are continuing, we have completed 17 of 21 turnarounds so far this year.

We do have two turnarounds continuing in the fourth quarter.

That's Magness and Claire, and we have two others scheduled, one in Trinidad and with in Mad Dog in the US.

We do have some rig activities in Trinidad, where we are moving our rig from a field called [Imartell] to [Hameressian] 7, which are big heavy lifts.

And that will have an effect on the 4Q production.

But that is a mix effect.

It is lower margin production.

I think we will -- I think the mix effect, we will see.

I don't want to -- it doesn't mean that it won't be higher in the fourth quarter.

But right now, that is where we are seeing it as flat.

Well, as traditionally, we see a little bit of uptick in the fourth quarter, usually due to some downtime in 3Q.

And then on the exploration write-off, Lucas.

I mean, we take a fairly conservative estimate internally.

We don't disclose that externally.

But you would assume that as we have ramp 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.

So you would expect that to come down over time.

We do give Mike Daley full license, to actually go and find oil and gas for us.

So we would expect that, (inaudible) trajectory over time, as you get more and more successful.

And, 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 the tropical storm Karen in the Gulf that has had some effect.

It was not a very long sustained downtime from this storm.

Right.

If I could ask one other follow-up to Lydia's almost, which is on the utilization rate.

I mean, you have made a considerable effort to improve the efficiency and uptime of facilities.

Can you give us any sense, Bob, if where you expect uptime or plant availability to stand in future, relative to where it might of been 2010, 2011?

In refining, you talk about plant availability of lot, and getting product through it is key.

It is no different upstream.

But I think we have 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 have learned over time, in talking about utilization rate in the upstream or optimum production rates, is everyone has a different definition of this.

But if we look at the kind of uptime that we have projected in the past, of where we are going, I would just note that a 1% increase in uptime is worth about $100 million to us in higher operating cash flow.

And we are looking at, gosh, I hate to throw out a percentage, but much higher than that -- 2% to 3% plus, is certainly not unreasonable for the kind of things that we have had.

The uptime, I will give you an example of greater Plutonio in Angola which was around 80%, is now up to about 95%, 96%, is just one big example of where a maintenance program we did, has really turned around an asset.

And we have got -- the problem with this, Lucas, is definitions.

And I am a little careful on the definitions, because everyone interprets it slightly differently.

But it is making a big difference.

And it is part of that 3% underlying production improvement we have got, as well the projects coming on.

Yes.

Well, Brian, just thank you very much.

Thanks, Lucas.

All right.

Thank you.

Next question from [Ian Hahn] at Bernstein.

Afternoon, and thanks for taking my questions.

Just when you mentioned 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?

And 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, well, Egypt, BP has been operating in Egypt since the 1960s, and it has been a good business for us.

And it has 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 a good business in Egypt, and we believe the country will need energy, going forward.

It has 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.

But we work well in Egypt and have a great staff in Egypt.

So we have had a significant discovery, looks like more than 1 TCF of gas offshore, offshore the northeast part of the delta with a good structure there, that has all the makings of a good commercial gas discovery offshore.

So for us, we are not unhappy with where things are today.

And you have to see through these big cycles in time.

And in the exploration side, I mean, we have got eight explorations drilling.

We expect to complete 16 to 18 during the year, where we did 9 last year.

The wells that are still going down, we have got a -- we just announced something on the Angolan well today at [Hilo] -- I mean with Lontra in Angola.

We have got an exploration well that is down,not too far away from the objective at [Gila], in the Gulf of Mexico.

We are drilling a well right now in Brazil.

We have got a well in Jordan.

We got -- we are testing new plays.

We will be drilling more in India, as well.

I don't have the exact full list for you.

But we have got a full set of activities around.

If you want to ask about anything specifically, I can tell you.

I think that's great.

Appreciate the extra color.

Yes, thanks, Ian.

Okay.

And now to Peter Hutton at RBC.

Hello, thank you very much for taking my question.

Just a couple here.

On the US upstream, I am wondering if I could ask -- liquid realizations were pretty flat against last quarter, up $0.70.

when -- though the WTI was up about $11 to $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 in the third quarter of this year?

And the second area, is India, one of my favorite subjects.

Can you, Bob, can you give me the date of discussions with the government on the implementation of the gas price?

I know that had been announced, but there seems to be further discussions between yourselves and Reliance and the government into where things stand at that at the moment?

Thanks very much.

Yes, Peter, thank you.

Well, you are right to see that in the realizations in the US, and most of our oil production and realization is weighted towards the Gulf of Mexico.

And in 3Q, the Gulf of Mexico grades did see a decrease in pricing, compared to Brent on a lagged basis.

And 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.

And I think there has been some refinery maintenance work in the Gulf, in general, that has held the crude there.

So there has been a dip, and I think that is temporary.

And that is 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.

And actually, frankly, we don't price that many barrels off the WTI, so you wouldn't see that.

And 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 in time.

For those of you who don't know, we have contracts there.

And the government has in place gas pricing that is around $4.20 an Mcf, for all the offshore, internal pricing.

And they have said, that they want to move to market prices.

They realize they are buying LNG at $15 plus, bringing it in 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, and 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 is -- there is a little bit of a dispute on the production sharing contract around the D6 field based on -- and you all will know this -- it is impossible to project rates in reserves.

And so they don't have experience so much with this, so when you put a development plan in place, it is like a roadmap and a commitment you don't deviate from.

So there has been a little bit of pushing and shoving of cost recovery there.

But quite frankly, everyone that I have spoken to, wants to see India develop as much oil and gas and resources as they can, because it knows it is going to need all of it, and it imports a huge amounts, and will be in the future.

There is talk in India of an election, early part of next year.

And so I think that all enters into some of the -- some of the discussions.

So they are ongoing.

And I remain very optimistic about what we have done in India, so far.

These two discoveries are really good, and we have got submissions into developed the R series of fields there with the government right now.

We will see.

Okay.

So Neill Morton from [Investec].

Are you there Bill?

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 have undertaken the first big disposal program, you talked about sort of 2.1, 2.2 million barrels of a day.

as being sort of a tipping point below which you wouldn't want to see BP go.

And yet today, you referred to BP as 3.2 million barrel a day company, so 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 will like?

And then just secondly, on the CapEx projections, I want to again confirm that the $24 billion to $27 billion is an organic number.

And the reason I ask that, is that you talked about $2 billion to $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 am thinking in terms of farm-ins, acreage acquisitions, signature vortices, and you also made reference to deepening your interest in your favorite projects?

Thank you.

Yes, Neil, you have got a good memory.

We did talk about that two years ago, the 2.1, when we were a 3 million barrels a day ex-Russia.

That 2.1, 2.2 looked like the right size for where we can get to, to make sure we could generate cash flow and high-margin barrels to keep the machine running in the way that we have described in the strategy.

Lamar McKay and I met, in fact, just yesterday and went through, looking out the rest of the decade.

We came to the same conclusion, that 2.0 to 2.2 was about the right level for the kinds of projects that we have.

And the 3.2 comes from adding the Rosneft barrels, because some people like to see the whole together, and some people like it separated out.

But you are right.

And that level really hasn't changed very much, after more than two years.

CapEx projections, we are referring to the organic number.

We are not talking about net CapEx.

It is 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.

And then there will 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 will make them.

But 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 are talking about organic CapEx.

Okay.

That's great.

Thank you very much.

All right.

So we will finish with just one or two questions from the web.

So the first one comes from Alexander Stewart of Shore Capital.

And it is in relation to the dividend policy.

And the question is, what range of EBITDA dividend cover or pay out ratio are you targeting in the medium- and long-term?

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.

And I think that is really the sort of key metric that we look at, around the sustainable free cash flows that will underpin a progressive dividend policy.

And the Board talked about three things.

One is consistency, hence why we come out, and talk about how we will revisit the dividend at 1Q and 3Q results.

Progressive, in terms of how we grow the underlying business from a value perspective, and then, sustainable.

So those are the three key things that we would look, at for the dividend policy.

Alright.

And the last one from Iain Armstrong of Brewin Dolphin, just think we may partly have answered already.

Can you give more detail of the possible working capital release next year?

And is the return of Whiting a big factor in this?

Iain, good question.

We have undoubtedly to built some inventory this year, as Whiting was taken out of action as we were bringing the coker on stream.

That inventory is back in play now.

So that would not be a big part of our (inaudible) inventory release that we see next year.

And next year is really about what, does a normal level of inventory look like, given what we have seen this year.

And I think I said, certainly through the fourth quarter and into next year, we will probably see something like 70% to 80% of the working capital build this year reverse out.

All right.

So that is all our questions.

Thank you everybody.

I will 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 are trying to do is to build a very simple set of outcomes that you can expect, which is that material growth in 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 will look to use surplus cash from divestments to enhance distribution to you all.

And again, thank you for spending time with us today, and we will see you next quarter.

Thank you.