英國石油 (BP) 2015 Q3 法說會逐字稿

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

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

Hello and welcome.

This is BP's third-quarter 2015 results webcast and conference call.

I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary.

Also with us for the Q&A, is the Chief Executive of our Upstream, Lamar McKay, and Tufan Erginbilgic, Chief Executive of our Downstream.

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 we note on this slide, and in our UK and SEC filings.

Please refer to our annual report, stock exchange announcement, and SEC filings for more details.

These documents are available on our website.

Thank you, and now over to Bob.

Thank you, Jess.

Today we are reporting our third quarter results in what has been another consistent quarter of operational delivery for BP.

It is also a quarter where we have all seen continued volatility in the environment, and our industry remains under pressure as it undergoes a major transformation.

So it feels like a good time to update you on the direction we are taking at BP, and why I remain confident about the future.

Our agenda will start with Brian taking you through the results for the quarter.

I would then like to take you through the enduring principles that form the foundation of our strategy to grow value for shareholders.

This section is in response to your request as shareholder feedback, to have more visibility on our direction, our portfolio, and growth prospects.

It is slightly longer than usual, and we trust you will find it useful.

I will then hand it back to Brian to address more specifics on our financial framework out to 2017.

Then after summarizing, there will be time for your questions.

So first, over to Brian for the results of the third quarter.

Thanks, Bob.

Starting with the environment, Brent oil has averaged around $50 per barrel this quarter, down from $62 a barrel in the second quarter.

Although global demand has been stronger and US production has begun to decline, OPEC production is running higher than the 2014 average, and inventories continue to increase.

As we have mentioned before, there is also the prospect of Iranian production coming onto the market in 2016.

Henry Hub gas prices averaged $2.77 per million British thermal units in the third quarter, slightly higher than the second quarter as United States gas power generation expanded, and year on year production growth slowed.

European and Asian spot prices have remained weak throughout the year.

The global Refining Marker Margin averaged $20 per barrel in the third quarter, the highest level for three years, as margins continue to be supported by strong gasoline demand.

Meanwhile, light-heavy US-Canadian crude spreads recovered from a six year low of $8.29 per barrel in the second quarter to $14.52 per barrel in the third quarter.

We expect the usual seasonal decline in refining margins in the fourth quarter.

Turning now to the results, BP's underlying replacement cost profit in the third quarter was $1.8 billion, down 40% on the same period a year ago, and 39% higher than the second quarter of 2015.

Compared to a year ago, the result reflects significantly lower Upstream realizations, partly offset by lower cash costs across the Group, and strong performance in the Downstream.

Compared to the previous quarter, the result reflects lower cash and non-cash costs, partly offset by the lower Upstream realizations.

Third-quarter operating cash flow was $5.2 billion.

We have also taken a further $151 million non-operating restructuring charge in today's results, bringing the cumulative charge close to $1.1 billion since the fourth quarter of 2014.

The third quarter dividend payable in the fourth quarter remains unchanged at $0.10 per ordinary share.

Turning to the highlights at a segment level.

In the Upstream, the underlying third quarter replacement cost profit before interest and tax of $820 million, compares with $3.9 billion a year ago, and $490 million in the second quarter of 2015.

Compared to the third quarter last year, the result reflects significantly lower liquids and gas realizations, partly offset by lower costs including benefits from simplification and efficiency activities, and strong gas marketing and trading results.

Excluding Russia, third quarter reported production versus a year ago was 4.4% higher.

After adjusting for entitlement and portfolio impacts, underlying production decreased by 2.2%, mainly due to higher seasonal turnaround activity.

Compared to the second quarter, the result reflects lower exploration write-offs, lower costs from simplification and efficiency, and strong gas marketing and trading results, partly offset by lower liquids realizations.

Third quarter production benefited from the absence of seasonal adverse weather in the Gulf of Mexico.

We expect fourth quarter reported production to be slightly higher than the third quarter, mainly reflecting recovery from planned seasonal turnaround activity.

In the Downstream, the third quarter underlying replacement cost profit before interest and tax was $2.3 billion, compared with $1.5 billion in the third quarter last year, and $1.9 billion in the second quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $1.9 billion, compared with $1.1 billion in the same quarter last year, and $1.4 billion in the second quarter.

Compared to a year ago, this reflects improved refining margins and strong refining operations, cost benefits from simplification and efficiency programmes, and strong fuels marketing delivery reflecting retail volume and margin growth.

Compared to the second quarter, the result reflects stronger fuels marketing performance and reduced turnaround activity.

The lubricants business delivered an underlying replacement cost profit of $350 million in the third quarter, compared with $340 million in the same quarter last year, and $400 million in the second quarter of 2015.

The petrochemical business reported an underlying replacement cost profit of $40 million in the third quarter.

Looking forward to the fourth quarter, we expect reduced refining margins and low seasonal demand to adversely impact fuels margins and volumes compared to the third quarter.

Turning to Rosneft, based on preliminary information, we have recognized $380 million as our estimate of BP's share of Rosneft's underlying net income, compared to $110 million a year ago, and $510 million in the second quarter.

Our estimate of BP share of Rosneft's production for the third quarter is just over 1 million barrels of oil equivalent per day, broadly similar compared with a year ago, and 1.4% lower than the previous quarter.

In July, we received our share of Rosneft's 2014 dividend, which amounted to $271 million after all taxes.

In other business and corporate, we reported a pre-tax underlying replacement cost charge of $230 million for the third quarter, compared with $290 million a year ago, and $400 million in the second quarter.

The average quarterly charge for the first nine months of 2015 is $300 million.

This is lower than our guidance, and reflects benefits from our simplification programmes, and improved performance in our other businesses.

The underlying effective tax rate for the third quarter was 39%, compared to 41% a year ago, and 35% in the second quarter.

Compared to the second quarter, the rate is higher mainly due to the effect on deferred tax balances of the strengthening US dollar.

Turning to the Gulf of Mexico oil spill costs and provisions.

As previously announced, BP Exploration & Production reached agreements in principal with the United States government and five Gulf coast states to settle all federal and state claims arising from the Deepwater Horizon oil spill.

The settlement provides for principal payments of up to $18.7 billion over a period of 18 years, as fully set out in our announcements in July.

During the third quarter, we have continued to move forward with these agreements in principal.

The vast majority of local government entities elected to participate in the settlement, signed releases, and were paid from funds previously provided, and within the Trust fund.

Early this month the United States government filed a proposed consent decree with the court which began a 60-day public comment period, and the court has scheduled a hearing for the final consent decree on March 23, 2016.

We also signed the definitive economic settlement agreement with the five Gulf Coast states, which is conditioned upon the court's approval of the proposed consent decree.

The settlements do not include claims relating to 2012 class action settlement with the Plaintiffs Steering Committee, including business economic loss claims not provided for, private claims not included within the class action settlement, or private securities litigation in MDL 2185.

The charge taken for the accident for the third quarter was $430 million, which takes the total cumulative pre-tax charge to the $55.0 billion.

This reflects around $460 million related to business economic loss claims not provided for, credits to other provisions, and the ongoing costs of the Gulf Coast Restoration Organization.

It is still not possible to reliably estimate the remaining liability for business economic loss claims, and we continue to review this each quarter.

Of the $20 billion paid into the Trust fund, $17.8 billion has now been paid out.

Costs not provided for, are being charged to the income statements as they arise each quarter.

The pre-tax cash outflow on costs related to the oil spill for the third quarter was $210 million.

Moving to cash flow, this slide compares our sources and uses of cash in the first nine months of 2014 and 2015.

Operating cash flow in the first nine months was $13.3 billion, of which $5.2 billion was generated in the third quarter.

This compares with $25.5 billion in the first nine months of 2014, and $9.4 billion in the third quarter of 2014.

Excluding oil spill related outgoings, underlying cash flow in the first nine months was $14.3 billion.

This reflects the impact of lower oil prices on earnings, as well as a build in working capital of $1.8 billion, which we expect to mostly unwind in the fourth quarter.

Organic capital expenditure was $13.2 billion in the first nine months, and $4.3 billion in the third quarter.

We received divestment proceeds of $2.6 billion in the first nine months of this year, including $290 million in the third quarter.

I will now hand you back to Bob.

Thanks, Brian, and I think that is a good set of results.

Obviously, the landscape has changed for everyone, but I think the numbers show that BP is competing well in the current environment.

I will come back to the reasons for that and to our future plans, but let me start by taking a step back, and looking at how we got to where we are today.

Late last year, we moved quickly and decisively to reset BP for what we expected could be a sustained period of low oil prices.

Not everyone shared our view at the time.

Earlier this year, the forward price strip for Brent oil pointed to prices of almost $80 before the end of the decade.

Some even speculated that prices might rebound quickly, to previous levels.

The market is now pricing at a much flatter trend for the oil price to 2020 and beyond.

This is driven mainly by the expectation that supply will continue to be strong, and there is a more cautious outlook on Chinese demand growth.

This reinforces the need for a business model that can withstand a longer period of lower oil prices, and we have been resolved to that for some time.

More importantly, we believe we are well-positioned in our industry to take advantage of the opportunity this brings.

This new environment has provided a much-needed catalyst to rebase our industry, and instill greater efficiency right across our sector, and there are advantages for those who are most adaptable.

The ability to adopt a more efficient business model will become a point of differentiation.

It is an environment that encourages companies, both producers and the service sector to work closely together, and innovate in the way we work with each other, and with resource holders.

And it calls on resource holders to do more to incentivize investment in their regions, all of which will help reestablish better long-range returns in our sector.

In turn, better supporting the dividend model for those that invest.

If there is one thing we have shown you over the years, it is that BP has the ability to adapt to changing circumstances and navigate through uncertain times.

It is part of who we are.

It is a legacy that has come from the learnings of decades, and our more recent troubled past.

And it comes from how we think about and engage with the world, during both good times and trying times.

Our history has given us a strong desire to be pioneering, and to be good at business, always looking to see and capture the opportunity in any situation.

But we are very clear that, before we do anything else, we need to be a strong operator, producing, refining and delivering energy safely and reliably, year in and year out.

At the same time, we also know that we will only succeed, if we always work with others for a mutual advantage, by maintaining strong relationships with governments, national oil companies, partner IOCs, customers, suppliers and other stakeholders.

So while the current circumstances are challenging, I remain very optimistic about BP's ability to adapt and prosper in this new world, which brings me to our proposition for value growth.

If we are going to succeed, we need to hold on firmly to the things that matter for our business long-term, regardless of the environment.

In July, we began to talk with shareholders about the enduring principles that drive our Business.

You will see them listed on this slide.

Above all, good business starts with a relentless focus on safe and reliable operations.

This is a job that is never complete, but we are delivering an increasingly safe, reliable and efficient set of assets.

In terms of the portfolio, since 2010 we have divested almost $75 billion of assets, including our interest in TNK-BP.

We now have a stronger re-focused, re-balanced portfolio.

It is a portfolio that is well aligned to our distinctive capabilities, the things that we do best, and it enables us to develop the highest quality opportunities from a broad set of options.

It is purposely balanced to withstand lower prices, while providing options for growth of the long-term.

In the Upstream, this means investing in a balanced range of resources, geographies and profit models.

And in the Downstream, it means selectively investing in a very focused portfolio of manufacturing assets with strong competitive advantages, and marketing businesses that are differentiated from the competition.

We will continue to actively manage this portfolio for value over volume, constantly looking for ways to optimise it whether through inorganic activity, or alternative ways to run our businesses such as you have seen in the US Lower 48.

We know that capital and cost discipline are fundamental to our business model long-term.

Strict capital discipline means we will only sanction the most competitive projects.

Meanwhile we are rapidly making significant structural changes to our cost base, and we are adding organizational controls to ensure these are sustainable for the future.

This all works towards the most important of our enduring principles, that of growing sustainable free cash flow, and shareholder distributions over the long-term.

Of course, the plan also needs to see us through the medium-term.

And Brian will take you through that shortly, including the steps we are taking on resetting the capital and cost base of the Company.

He will also show you our financial framework out to 2017, which underpins our commitment to sustaining our dividend, while we rebalance our sources and uses of cash in the current environment.

For now, let me take you through these principles in a little more detail, starting with running safe and reliable operations.

Over the last five years, we have taken many steps to build a safer and more reliable business, since the Deepwater Horizon accident.

You have heard many times about the increasing focus on process safety, right across the business and the investments we have made in the integrity of our assets.

We have seen encouraging trends as a result of this work.

In both Upstream and Downstream, we are seeing fewer Tier 1 process safety events, fewer leaks and spills, and fewer recordable injuries.

At the same time, the reliability of our assets has improved.

We believe safety and reliability go hand-in-hand with efficiency and financial results.

Improve one, and you improve the other.

I will come back to more on this later, but I do want to be clear and upfront on this important point.

Simply, safety is good business.

As we continue to transform our business in the current environment, we expect to drive greater efficiency into how we operate, while keeping that relentless focus on safety.

Now moving on to our portfolio.

Here the key is balance.

Balance between different geographies, different resource types, different parts of the value chain, and different parts of an asset's lifecycle.

Getting the right balance, provides resilience and longevity.

Resilience in the current environment comes firstly from being an integrated business, with global Upstream and Downstream operations and well-established trading capabilities.

This provide some cushion to oil price volatility, as downside pressures in one part of the Group, can create opportunities in another.

In the Upstream, we are further insulated by around one-third of our production coming through production sharing agreements, as well as by having a series of high-quality gas projects in countries that are short of domestic gas.

Around 80% of our potential investments are currently expected to break-even below a $60 Brent oil price, and we would expect this break-even to move lower, as we further take advantage of deflation.

The second point, and I will come back to the detail on this later, is that ours is a portfolio with growth and optionality for the future.

In the Upstream, we have a balance of deepwater, gas value chains, and giant fields with an increasing bias to gas over the next decade.

Our new major project pipeline includes well-defined sources of future production growth.

Over half of our production from new major projects out to 2020 is already under construction, and we have a deep portfolio of over 50 options to move through sanction, should we choose so.

We continuously add to the option pool through new access or deepening of existing positions.

The overall balance we now have in this portfolio, not only makes it more resilient to industry price cycles, it diversifies our exposure to fiscal and political risks, and it minimizes the risk of over exposure to one or two dominant resource types.

In the Downstream, we expect our future cash flows to reflect a balance between manufacturing and marketing with a strong orientation towards marketing growth.

We have reshaped our refining portfolio in recent years, and are now well-positioned to drive top quartile competitive performance.

We continue to carefully focus and optimise our petrochemical activity to create a stronger business.

And in fuels marketing and lubricants, we focus investment on growth markets, technology, and premium global brands.

We are working closely with leading retailers and lubricants partners to deliver differentiated products and customer offers.

Four years ago, we said that we would actively manage our portfolio for value over volume.

While we are confident in the balance and make-up of our portfolio as we see it today, we still keep it constantly under review.

At its simplest, we will look to divest assets which no longer fit with our strategy, and deepen our involvement in assets which add the most value.

More broadly, the process includes looking at innovative ways to work with our portfolio harder.

A recent example is the new business model we are developing in the Lower 48, as is the new direction we have taken in the Palaeogene in the Gulf of Mexico, where we have farmed out part of our interest in order to diversify risk, and encourage technical collaboration.

At the same time, we drive returns through disciplined investment into the best projects.

It means getting the right balance of capital between our different business segments, and pacing our investment in each business to capture the greatest value through the cycle.

Right now, in the Upstream, this means giving particular attention to managing the timing of investments.

We are looking to ensure that we are capturing the maximum benefits of industry deflation, while at the same time preserving our future growth objectives.

In the Downstream, it means a step-down in capital spend, compared to the capital intensive phase of the Whiting refinery modernization.

At the same time, we continue to invest selectively to drive strong performance and growth.

Specifically out to 2017, we expect to sustain a lower level of capital expenditure for the Group in the range of $17 billion to $19 billion.

We are near completion of our current $10 billion divestment programme, and expect a further $3 billion to $5 billion of divestments in 2016, with $2 billion to $3 billion per annum thereafter.

And Brian, will give you more details on this in a moment.

Turning now to each of our businesses, starting with the Upstream, we continue to build on the strategy we outlined to you in December last year.

The efficient execution of our activities is delivered through a well-established functional operating model, which is delivering, I think, great results.

As a brief reminder, this strategy again starts with the safety and reliability of our operations, which continue to improve.

Second, we focus on value over volume.

And we deliver value through the efficient execution of our base activities, a quality set of major projects, and by leveraging our access and exploration expertise.

At the same time, we invest in a very disciplined way.

We are continuously improving the economics and break-even points of our major project and appraisal pipeline.

And finally, we continue with the journey we started back in late 2013, to reset our Upstream cost base.

Looking more closely at our base business.

This comprises around 350 oil and gas fields, with thousands of reservoirs, and over 50 rigs operating, and it also employs the largest proportion of our Upstream staff and agency contractors.

Here we have seen improvements across the board, as a result of disciplined operating over the past five years.

We have improved safety performance, and a combination of improved reservoir management, drilling efficiency, and operations efficiency has delivered additional production to the base, and lowered the decline rate of our Business.

We have increased BP-operated plant reliability from around 86% in 2011, to 95% year to date, actually reaching 96% for the month of September.

We have seen some strong performance improvements in the UK North Sea in particular, where our asset specific plans have helped to improve BP-operated plant reliability from 74% in 2011, to 88% in the third quarter of this year.

We continue to run efficient turnaround programmes with 13 completed so far this year, including at some key assets such as Thunder Horse, Shah Deniz, and Claire.

We have one more currently underway, and another yet to start in the fourth quarter.

We expect in-year production from new wells and wellwork to reach around 160,000 barrels of oil equivalent per day, benefiting in part from our continued focus on reducing non-productive time in our drilling activities.

Non-productive time is currently at the lowest level since 2011, and to give an example, in Azerbaijan we have improved the efficiency in our drilling operations on ACG by 24% since 2013.

Finally on performance, we continue to increase base asset production through system optimisation and reservoir management, including well monitoring and 4D seismic.

We have seen some great examples of this on some of our key assets, including Thunder Horse in the Gulf of Mexico, ACG in Azerbaijan, and Greater Plutonio in Angola.

We expect all of these efforts will allow us to keep the average managed base decline through 2016 at around 2%, and this 2% is an important number for you to take note of.

The long-range view of managed base decline remains at the 3% to 5% level we have described in the past.

Looking ahead, we continue to have more opportunities than our capital frame enables us to progress, and more than are required to sustain our underlying production growth in the longer-term.

In order to make choices, we apply our rigorous capital value process.

In the current environment, we expect to allocate capital in the following proportions: around 10% to integrity management on our producing assets; around 45% to new projects; around 35% to drilling on existing assets; and the remainder to exploration.

The ability to exercise quality through choice, and to flex our capital allocation means that the new project and drilling spend will only get sanctioned when it is right.

This means we aim to achieve a rate of return on our new greenfield major projects in the mid teens at an oil price now of around $60.

And our drilling programmes around existing assets and follow-on projects will only progress, if they return over 20% on the same basis.

Confidence in our ability to achieve these thresholds comes from the very good resources we hold.

For instance, and contrary to some suggestions, we don't think that the deepwater has played out.

Of course, there is a wide spectrum of quality in any resource category across the industry.

For us, it is not about water depth, it is about the quality of our reservoirs, and we hold some very strong deepwater investments going forward.

We continue to optimise project economics by maximizing opportunities to capture deflation, rescoping and rephasing the spending appropriately.

We also have enough uncommitted spend and flexibility to manage the pace of investments as needed.

When it comes to progressing projects, our approach is focused on creating value and improving project performance from concept, appraisal, to execution.

This includes, having a single concept development team that appraises projects through to concept selection.

Before any projects are progressed to sanction, they must go through an explicit optimisation phase focused on scope, costing, phasing, and front-end loading to ensure they are both competitive and as good as they can be.

This chart shows how break-even prices of our pre-sanctioned projects have fallen over the past 12 months, with an average reduction of around 15%.

We test robustness of our projects through a range of hydrocarbon prices, And as you can see, around 80% of our projects appraise to define pipeline now breaks-even below a $60 oil price, which reflects the quality of the portfolio, some deflation, and the benefits of our ongoing project optimisation efforts.

Those projects on the right-hand side of the chart that do not meet the investment criteria I mentioned, will not progress as they currently stand.

They will continue to be technically and commercially optimised, but are not included in our current production and financial outlook.

At the same time, we look to accelerate the sanctioning of new quality projects with strong returns, and focus on safe and reliable execution through to operations.

These value improvements reflect our efforts in a number of areas, including contract renegotiation in the supply chain, standardization and increasing use of industry solutions, simplification and scope optimisation, and an increased focus on front-end loading and cost management, from the beginning to the end of our projects.

Also on both current major projects and future projects and drilling opportunities, we prioritise the development of higher returning resources.

We have applied this approach on the West Nile Delta project, and I will use this and the Thunder Horse South expansion projects, which were both sanctioned this year to illustrate this process in action.

So firstly, West Nile Delta: this project is a significant opportunity to bring gas directly into a growing domestic market.

It offers almost 4 trillion cubic feet of production, net to BP, going out beyond 2030.

Over the last 12 months, we have optimised the development plan which will accelerate production in the near-term.

At the same time, the capital expenditure has been smooth, reducing the capital spend in the near-term.

This work has reduced the life of project capital spend by 6%, while it's increasing production volumes 1%.

The acceleration of production and rephasing of capital has reduced this project's break-even price by 12% against a year ago, with an associated improvement in returns.

Our confidence in the quality of this project is highlighted by our commitment to sanction the development this year, despite the current climate.

The second example is the Thunder Horse South expansion project in the Gulf of Mexico.

This is one of several infield projects that will sustain, and grow quality deepwater oil production from our existing hubs.

In the last 12 to 18 months, a focus on scope and cost has optimised this project through standardization and simplification, improved competitive contracts, and reduced drilling costs.

At the same time, the production forecast for this project has improved by 10%, and the expected start-up date has remained unchanged.

As a result, the expected development cost per barrel is now over 25% lower than before.

We now expect this project to produce around 90 million barrels of oil equivalent gross, with a return well about our investment thresholds.

So where does all this leave our expected production from new projects?

We have a robust pipeline of projects delivering growth through 2020.

With 2014 start-ups now reflected in our base, we expect new project start-ups between 2015 and 2020 to deliver over 800,000 barrels per day of new production by 2020 net to BP.

This is broadly consistent with the outlook we shared with you in December.

Following first oil on the Kizomba Satellite Phase 2 and Greater Plutonio Phase 3 projects in Angola earlier this year, the Woodside operated Western Flank A project in Australia, in which BP has a 17% share started production last week.

And in Algeria, the In Salah Southern Fields project continues to progress toward start-up around the end of the year.

We are also seeing great progress on other projects, with facilities work on Quad 204 in the North Sea now over 85% complete, ahead of the new FBSO sail-away from Asia later this year.

In the Gulf of Mexico, the facilities at the Thunder Horse water injection project are set for completion around the end of this year in readiness for well tie-ins during 2016.

By 2020, over 500,000 barrels of oil equivalent per day of new project production is anticipated to come from the delivery of seven key projects, which are progressing well.

These include the substantial long-life gas profiles of the Oman Khazzan project, in Trinidad, the West Nile Delta and the Shah Deniz Phase 2 projects that will grow and maintain production in these new and existing integrated gas value chains.

Some of our post 2018 projects include exciting new discoveries made in the last 18 months, including Atoll in Egypt, and Vorlich in the North Sea.

As shareholders, you have given us feedback to be clearer about our pipeline of projects.

While this slide is not so easy to read quickly, it will be available on our website.

In addition to the projects under construction that I just mentioned, we have a deep hopper of over 50 pre-execute and appraisal projects, some of which are also shown on this slide.

We expect to take final investment decision on a number of these projects.

While some of this may change as we selectively progress and optimise the portfolio, we believe this inventory remains balanced across our asset themes and geographies, and will allow us to continue on our growth trajectory.

Looking further out, we have the options, discovered resources, and acreage in our portfolio to extend production growth well beyond 2020.

Putting aside Russia for a moment, we have a hopper of 44 billion barrels of oil equivalent underpinning this growth, 11 billion barrels of which represent proved reserves from existing base assets and projects that have passed final investment decision.

The progression of the remaining 33 billion barrels underpins our continued growth beyond 2020.

Around 70% sits within our base assets, and these are being prioritised and optimised in area development planning process, which seeks to progress the very best barrels.

The remainder represents our major projects and resource appraise options that have not passed the final investment decision, and that continued to be matured and optimised to meet our investment criteria.

In addition, we have a diversified exploration pipeline with a mix of oil and gas, conventional oil and deepwater oil, and unconventionals.

This includes incumbent positions in world-class hydrocarbon provinces like the Gulf of Mexico, the Caspian Sea, the North Sea, and the Nile Delta in Egypt.

Successful new access over recent years has also created the potential for future production centers from new regions and plays.

We are also building a material position through our relationship with Rosneft.

Our longer-term production growth framework will be fed from three main areas.

Firstly, the pool of major project options covering all of our resource types.

Secondly, the pull-through of current discovered near field resources around our key hubs such as Claire in the North Sea, and Thunder Horse in the Gulf of Mexico, and in oil and gas unconventionals.

And thirdly, through success stemming from our ongoing level of investment into exploration, access and appraisal.

We will also seek opportunities that arise in the current environment to deepen existing positions, as we did earlier this year in Shah Deniz for example, as well as acquiring or accessing new ones.

We continue our agenda on cost, simplification and efficiency in the Upstream.

Since we started the programme to reset Upstream costs in 2013, we have reduced unit production costs by around 20% as the chart shows.

We are focused on managing the activities that drive cost in the business.

This means right-sizing our organization, reducing our third-party spend, influencing our partners where we are not the operator, and doing all of this without compromising safety as our number one priority.

We now have 10% fewer Upstream employees, and 42% fewer agency contractors than we had in 2013.

We are also leveraging local capability to manage levels of expatriation.

In our third-party spend, we continue to capture market deflation, and have achieved average cost reductions of around 15% to date.

We have accelerated competitive bidding programmes across a wide range of third-party spend.

In operations, for example, we expect to have awarded new or revised contracts representing 40% of our third-party spend by the end of 2016.

And in our wells organization, we are rebidding around 60% of our oil services spend in the next six months.

We are not only focused on contract renegotiations, but are also looking at the scope and efficiency of all of our operations and projects.

Some examples of this include a 15% reduction in 2015 Trinidad logistic costs through deflation, efficiencies, and working together in the industry.

An 18% cost reduction versus forecast in our light well intervention campaign west of Shetland in the North Sea through scope optimisation and improved execution.

We have seen $32 million of gross rig cost savings in the Gulf of Mexico through the end of this year, via materials tracking and management of services, as well as a focus on equipment rentals and rates and a 23% reduction in land lease costs during the construction period for the expansion of our South Caucasus pipeline in Azerbaijan and Georgia, as a result of optimising the period of these leases.

Given the significance of spend made on our behalf by other operators, we are also ensuring a similar focus on efficiency and costs across this activity.

By finding more efficient ways of working, we expect to be able to sustainably embed the benefits from these improvements, ensuring that this cost reset is truly sustainable, and that the legacy of the current environment is a permanently leaner and more efficient business.

Moving onto the US Lower 48, where we have a material resource base with 7.5 billion barrels across 5.7 million net acres.

The transformation programme of the last 18 months has empowered the Lower 48 team to focus on safety, innovation and performance in a way that is fit for purpose in that business.

The 12 rigs currently operating represents the highest since 2012,and material improvements are also being delivered in cost and capital efficiency.

Year-to-date unit cash costs are about 17% lower than the last year, and we are seeing improved capital efficiency through some real innovations to well design and execution, more of which I will talk about in a moment.

This means the activity is delivering improving and competitive returns.

It is competing well for investment with the rest of BP's portfolio of drilling opportunities.

The team is also focused on optimising this portfolio both through reenergizing the development of previously underworked acreage, and also by selectively screening opportunities for inorganic activity that may complement existing assets.

Here we can see how this is all starting to deliver an improvement in capital efficiency.

Development costs are benchmarked across the regions, against competitors, and also versus previous performance in the same plays.

As you can see from the chart, significant improvements in capital efficiency are happening in the areas shown, which in turn is beginning to deliver competitive performance with top quartile results in some places.

The most recent wells have been delivered at lower costs, as the learnings from earlier wells have been incorporated.

Activity is being designed and executed with more innovation, and the benefits of deflation are being captured.

Most notably so far in 2015, development costs in the Woodford are half of what they delivered in 2012, and the lowest versus competitor-operated wells.

And in the San Juan, we are seeing a significant reduction in development costs compared to the last time we drilled in the basin back in 2009, with wells currently being developed at an average of $0.45 per thousand cubic feet.

We are also seeing encouraging early performance on a first co-planar dual lateral well in the basin.

So it's early days, but the decision to manage our Lower 48 business differently is starting to show material improvements in performance and competitiveness.

Let's look now at the Downstream, where the focus remains on delivering resilient and improving performance and growth.

The disciplined execution of our strategy is illustrated by our record year to date pre-tax profit and returns.

In addition, as you can see here, net income per barrel has increased to the top half of the competitive range.

Pre-tax returns are significantly higher in 2015 than recent years, even when adjusting for the impact of the recent high refining margins.

This demonstrates that we are improving underlying performance, and creating a more resilient Downstream business.

Our strategic agenda is focused on a quality portfolio.

Our advantage manufacturing continues to build a top quartile refining business, which is underpinned by operations excellence, and is significantly more robust to environmental volatility.

And in marketing, we continue to invest in higher returning growth opportunities.

Our simplification and efficiency programmes are central to our strategy, and further enhance our resilience to the volatility of the environment.

And all of this is underpinned by safe and reliable operations.

Now looking at the portfolio, here you see what we mean by advantaged manufacturing and marketing growth.

We continue to build a top quartile and focused refining business through operating reliability, feedstock advantage, and efficiency improvements to our already competitively advantaged portfolio.

In the US, our three refineries have advantaged access and proximity to Canadian crudes and US shale oil, both of which typically price at a discount to other crudes.

In Europe, we have a top quartile refining portfolio in terms of scale, and a smaller exposure than our primary competitors.

And our refineries in Africa and Australia are industry-leading in their regions, in terms of scale with top quartile profit capability.

In petrochemicals, we are taking steps to significantly improve the cash break-even performance of the business through portfolio repositioning, improved operational performance, and efficiency benefits.

In addition, we are working to create additional value from distinctive technologies, such as the recently announced licensing agreements for BP's latest generation PTA technology in Oman and China.

Together, this creates improved earnings potential, and makes the business more resilient to a bottom of cycle environment.

In marketing, our fuels marketing and lubricants business delivers strong pre-tax profits with attractive returns and generate reliable cash flows.

Both fuels and lubricants are key to our profitable growth strategy.

Our retail business is proving to be a significant sort of growth, with volume growth of around 3% year to date.

To reinforce a differentiated position, we partnered with leading retailers in six countries to create distinctive offers, which deliver attractive returns and material growth potential.

So here in the UK, for example, we have a partnership with Marks and Spencer.

This quarter, we launched our BP fuels with Active technology in Spain, ahead of a wider European roll-out.

These fuels deploy proprietary technology to remove dirt from the engine, and in turn increase fuel economy.

In lubricants, our sustained focus on growth markets and premium products has resulted in year on year pre-tax earnings growth of over 25%, when adjusted for foreign exchange impacts.

With continued growth in premium lubricants, and more that 50% of our pre-tax earnings sourced from growth markets, we have an excellent base for further business expansion and sustained profit growth.

And our technology continues to support the development of differentiated premium lubricants with enhanced growth potential.

We continue to see significant year on year benefits from our focus on cost efficiencies in the Downstream.

Year to date cash costs are some 15% lower than the same period in 2014, reflecting our simplification and efficiency programmes, along with foreign exchange impacts.

We continue to right-size the organization.

And as we shared last quarter, we have simplified our fuels organization, reducing the number of businesses from nine to three.

We have also significantly simplified our lubricants business, and we are in the process of making our petrochemical business simple and leaner, in line with strategy.

In our head office functions, we have taken actions which will lead to around a 40% reduction in costs, through the streamlining and eliminating of activities.

And across our refining operations, our first priority remains safe and reliable operations, while we continue to implement a set of plans which deliver performance improvement, and increase our cost competitiveness.

Our focus on third-party spend has resulted in a significant reduction compared to last year.

Together these programmes accelerate delivery of the Downstream underlying efficiencies which we highlighted in February, with further additional opportunities identified beyond this.

Now let me briefly remind you of our track record, and I think, unique position in Russia.

BP has successfully been doing business there for over 25 years, and over recent years we have taken some significant steps.

We have acquired a 19.75% shareholding in Rosneft, with myself and my BP colleague, Guillermo Quintero, on the nine member Board of Directors.

This equity interest in Rosneft makes BP, a 3.1 million barrel a day company, with 18 billion barrels of proved reserves.

Rosneft is the largest oil producer in Russia, and has a strong portfolio of existing and future opportunities.

They are also an extremely efficient operator, with the world's leading lifting cost of under $3 per barrel.

In the current environment, they continue to deliver solid operational and operational performance, demonstrating the resilience of their business model.

Our commitment to Rosneft as a partner has allowed us to build the strong relationships we regard as so important, and to successfully deliver value over time.

Since we acquired our stake in Rosneft, progress has been rapid.

We are not now simply a major investor, but also a JV partner.

Beyond our shareholding, we have a 20% equity share in Rosneft's Taas-Yuriakh in Eastern Siberia.

It is currently on stream, and Taas is expected to produce around100,000 barrels a day by the end of the decade, with further potential for significant gas development.

In addition, we have entered into three conventional exploration areas of mutual interest with Rosneft.

One that is proximate to Taas in a relatively under-explored region, with the other two in the already prolific Western Siberian hydrocarbon basin, and we have an agreement to form a joint venture in the Volga Urals region to explore and develop non-shale unconventional tight-oil prospects.

The exploration areas for all of these areas cover 375,000 square kilometers.

That is nearly 5 times the size of Scotland.

We are mindful of the geopolitical constraints, but we remain committed to working in Russia, to these projects, and to the long-term potential of the region.

We will continue to look for other opportunities to work with our partners, as we aim to build upon our successful involvement in Russia.

We see Russia, one of the world's largest hydrocarbon provinces, as an important part of BP's long-term strategy offering material value potential.

So that explains the principles that drive our business long-term, and how these principles reflect, and the make-up of the portfolio for the Group, and the strategies of our businesses.

In the Upstream, we have a very material resource base, with quality rocks and the technical capability to exploit them.

Over the last five years, we have built the expertise, systems, and discipline to run safe, reliable and efficient operations, and we have strong relationships with host governments and partners, and the commercial strength to negotiate the deals that offer real value.

In the Downstream, we have a quality portfolio with top quartile refining capability, a strong footprint in growing markets, and differentiating technology and brands.

We have a business that is delivering strong performance today, which is very focused on delivering ongoing improvement in its underlying performance.

We recognize that all of this only matters, if it works within an overall financial framework that gets us beyond the challenges of the current environment, and back to growing sustainable free cash flow, and distributions to you, our shareholders over the long-term.

So I will hand you back to Brian, to take you through the medium-term financial frame.

Thanks, Bob.

Now that you have the overall perspective, Bob presented, I will start by outlining the key elements of our financial outlook for the next few years, as we continue to recalibrate to the current price environment.

Our principal objective over the medium-term is to reestablish a balance in our financial framework, where operating cash flow covers capital expenditure, and the dividend.

As Bob laid out, we aim to do this while maintaining safe and reliable operations, preserving core growth activities, and sustaining the dividend.

This reflects a belief that our dividend is set at a level consistent with the long-range cash generating capability of our underlying businesses.

With the steep fall in oil prices late last year, as Bob highlighted, we acted quickly to reset the Company for a period of sustained lower prices, a transition we expected to take about two years.

We are making strong progress, on resetting both the capital and cash cost base of the Group.

We now expect organic capital expenditure to be in the range of $17 billion to $19 billion per annum through to 2017.

Group controllable cash costs are expected to reduce by over $[6] billion by 2017 compared to 2014.

With these plans in place and continued strong operating performance across our businesses, we expect to rebalance organic sources and use of cash by 2017, at an average Brent oil price of around $60 per barrel.

Organic free cash flow is expected to grow thereafter at constant prices.

This underpins our ongoing commitment to sustaining the dividend as a first priority within our financial framework, and restoring growth in distributions to shareholders over the long-term.

On divestments as Bob noted, we are approaching completion of our $10 billion divestment programme by the end of 2105, and expect to announce a further $3 billion to $5 billion of divestments in 2016.

From 2017, we expect divestments to average the historical norm of around $2 billion to $3 billion per annum.

We will continue to manage gearing with some flexibility around the 20% level.

Turning to these points in more detail, and starting with capital expenditure.

As mentioned, we now expect organic capital expenditure to be in the range of $17 billion to $19 billion through 2017, although closer to $19 billion this year.

For 2015, this compares to our original guidance of $24 billion to $26 billion for the year, subsequently revised at the mid year to below $20 billion.

The reduction in 2015 spend largely reflects the rephasing and optimisation of activity in the Upstream.

In exploration, we have focused activity into high-value near field opportunities, with less frontier exploration.

We have shelved some marginal projects and reprioritised activity in the base.

At the same time as Bob described, there are examples of strong deflation in the sector.

We will continue to pace the timing of our investment decisions to best realize the deflationary opportunity, while actively driving capital efficiency into the way we build, and operate projects.

So we will continue to take final investment decisions on projects, but only when we think the timing is right for each project.

In our Downstream and other businesses, we are only advancing very carefully selected projects that complement our strategy.

As we lock in deflation over the next few years, this structurally lower capital frame still supports a level of activity we consider optimal to grow value for shareholders, from our portfolio of options over the longer-term.

Turning to cash costs, we continue to make strong progress on right-sizing the Group's cash cost base, while seeing the benefit of the investment we have made in improving asset integrity.

Our intensified efforts across the whole of the Group to structurally reset the cost base in response to the low price environment have also taken hold, and they are increasingly evident in our results.

Non-operating restructuring charges are now expected to approach $2.5 billion in total by the end of 2016, as we continue with these efforts.

This compares to the $1 billion of restructuring charges we initially announced in December of last year for the period to the end of 2015.

Total Group controllable cash costs for the nine months year-to-date are $3 billion lower than the same period last year.

As you have seen the actions we continue to take are wide ranging across both the Upstream and Downstream, and we remain very focused on further simplification within our functional and corporate activities.

This rapid progress in part builds on initiatives already started in 2013, and where we now benefit from having made a head start.

Looking ahead, we still see a material opportunity to further reduce the cost base.

By 2017, we expect total Group cash costs to reduce by over $6 billion compared to 2014, with nearly half of this already captured.

Looking at free cash flow beyond 2017, by 2017, we expect to be working off a reset and structurally more efficient platform, both Upstream and Downstream, with sources and use of cash for the Group balancing organically at oil prices of around $60 per barrel.

In this environment, and based on our planning assumptions, we would expect the cash flow growth from 2018 restoring our capacity to grow distributions to shareholders.

In the Upstream, growth in operating cash flow will be driven by continuous organic growth from the start-up of our next tranche of major projects, and the ongoing efficient management of our base, at the same time as maintaining our strong focus on capital and cost discipline.

Any recovery in the price environment would offer further upside as illustrated on this chart.

Equally, in the event oil are prices below this level, more deflationary correction will be required than currently built into our plans.

At the same time, continued strong performance from our Downstream, through delivery of further efficiencies and marketing growth brings a degree of resilience to this outlook.

Turning to divestments, total divestments since 2010 as Bob described are now approaching $50 billion, or nearer $75 billion including the sale of our interest in TNK-BP.

Today we have agreed $7.8 billion of our $10 billion programme for the 2014 to 2015 period, and expect the cumulative total to approach $10 billion by the end of the year.

As already noted, we expect $3 billion to $5 billion of divestments in 2016, and ongoing divestments averaging around $2 billion to $3 billion in per annum thereafter.

The divestments we have made over the last five years, initially included the necessary steps we took in the aftermath of the oil spill, but went on to divest non-strategic assets, capturing prices commensurate with $100 per barrel oil price.

In the current environment, we continue to pursue divestments as part of our ongoing strategy to actively manage our portfolios as Bob described.

In addition to this strategic objective, the cash proceeds provide flexibility for the balance sheet to manage continued oil price volatility, and to meet our Deepwater Horizon payment commitments to the United States.

Lastly, just a few words on gearing, at the end of the third quarter, gearing stands at 20%, including the impact of the consent decree and agreements with the Gulf states.

This compares to the 10% to 20% target band we established in 2010, to allow greater flexibility for uncertainties of which Deepwater Horizon was the most significant.

As mentioned with the recent filings in the United States, we have moved a step closer to finalizing these agreements, which provide for payments over an extended period.

With that context, we will manage gearing going forward, allowing some flexibility around a 20% level, while volatile market conditions remain.

I will now hand you back to Bob.

Thank, Brian.

To sum up, we believe we are navigating through the current challenges in a way that is characteristic for BP.

I am confident we will adapt to this new world, and do so with competitive advantages.

We have worked hard to build a track record of delivery.

In 2011, we laid out a 10 point plan, and you saw it delivered in 2014.

In February, we laid out a set of priorities to respond to lower oil prices, and you can see us delivering on those priorities in our results today.

And we are very energized about our plans for the future.

With our recent agreements on the largest remaining legal exposures in the Gulf of Mexico moving toward closure, we are able to focus fully on this future.

Our strategy is built around maximizing the potential of a strong and well-balanced portfolio.

I remain convinced of the potential of this portfolio in any environment.

Together with our ongoing focus on capital and cost discipline, this gives us confidence in being able to grow free cash flow and distributions over the long-term.

Near-term, it is a challenging time for our industry, but we are making the sustainable changes that are needed without compromising our longer-term goals.

Our financial framework shows us rebalancing organic sources and uses of cash by 2017 in a $60 world.

This supports our commitment to sustaining the dividend, and it remains a strong priority.

So I believe we have set a clear course.

It is based on a set of enduring principles that reflects our proven ability both to innovate and find new ways of working, as well as to deliver as an operator day by day.

It's often said in business, that it is the most adaptable who survive and succeed.

BP has adapted many times in its history, the recovery of the early 1990s, the expansion of the late 1990s, and the rebuilding here of the last five years.

I am very confident we will once again adapt, as we take on the challenges of today's world, and continue to deliver value into the years and decades ahead.

So on that note, thank you very much for listening, a little longer this time.

And now, let's take your questions.

(Operator Instructions)

Hello, everybody.

Welcome back, and thank you for holding on, to those who have been on the phone for some time.

I believe some folk may be having problems with the telephone lines, in which case, please do submit questions also via the web.

In the meantime, we will take the first question from Oswald Clint of Sanford Bernstein.

Are you there, Oswald?

Okay, I am not hearing anything from Oswald.

So moving to Gordon Gray of HSBC.

Are you there, Gordon?

No.

Okay.

Sorry, we seem to be having some technical difficulties, and we have no questions working at the moment.

Perhaps we could just pause for a moment, and we will get back to you as soon as we can.

Okay.

So we do have one question, coming through on the web from Richard Griffith of Canaccord.

And that is, what oil price is required to balance sources and uses of cash if Deepwater Horizon payments are included?

Thanks, Richard.

It's Brian Gilvary.

It is a pretty simple calculation.

From 2017 onwards, the payment schedule looks like about $1 billion a year over the 18 years, in terms of the settlement.

So that is the difference.

In terms of additional revenue you would need, there's a dollar per barrel you could put on that.

But actually, the way we are thinking about this, is that the key's, we need to ensure that the dividend and CapEx is covered by operating cash flow.

And that's the commitment, in terms of 2017 at $60 a barrel, and choosing $60 as being the number that's currently in the forward strip.

And that any commitments associated with Deepwater Horizon settlements will come from ongoing divestment proceeds, and we have said, there is $2 billion to $3 billion of churn going forward.

So they will be accommodated by that.

But that's not the way we are thinking about it, in terms of oil price.

Okay.

Thank you.

We have another question.

What is the expected time line for Whiting to return to their heavy sour slate it was running before the recent corrosion issues?

And that question comes from Jack Hogan.

Thank you, Jack.

Thanks, Jack.

I think that outage was only for 15 days.

After that, we actually went back to normal levels of running, which is not -- Whiting is capable of running more than 400,000 barrels per day total production.

And also capable of [280,000] to 300,000 barrels per day heavy as part of that.

So it was only for 15 days.

We actually went back to our normal levels.

Okay.

And another question from [Barak Salmon], thank you.

It is a question on refining margin outlook.

Can you give us some color on your refining margin projections for 4Q 2015 and 2016?

Okay, I think for 4Q 2015 is, as we highlighted in our presentation.

It -- margins effectively went back to seasonal levels that you should expect, because in 2Q and 3Q, what has been driving the margins, refining margins was mostly gasoline cracks.

In this season, obviously gasoline demand goes down, but also gasoline pool, you can actually put other things into gasoline pool because of the spec requirements.

So it is expected that 4Q margins will be lower, and we already see that at this point in time.

When it comes to 2016, I think the way that you may want to think about, we expect refining capacity increase next year around 1 million barrel per day.

And right now, the consensus demand increase for the next year is around 1.3 million barrels per day.

But that includes some biofuels and NGL as well.

So you should take out [0.2 million barrels per day] or [0.3 million barrels per day] of that.

As a result, I think this demand will continue to support refining margins in 2016.

But surplus refining capacity will be higher than 2015.

That is how you should keep the refining margins in your mind, I suggest.

Thanks, Tufan.

And we will stick with the web questions, for the moment while we are sorting out the phones.

Thank you for your patience.

So I have two questions here from Biraj Borkhataria of RBC.

The first one being, regarding new projects, $60 per barrel break-even for the majority of them, what would it take for you to sanction them today?

Hi, this is Lamar, Biraj.

The graph that we showed you shows break-even for a range of prices.

And if you -- the point was that about 80% of our projects break-even below $60 a barrel, a significant majority of those are quite below $60.

So some of those are going to get sanctioned.

As Bob said, as they get worked and they are understood as to the optimum approach to the market, the optimum timing, and are we ready to go, and do they compete in the portfolio.

But the majority of those are going to work through the system, based on their current break-even prices.

However, I will reiterate one thing Bob said, that graph is moving downward still.

We are still pretty early in the deflationary cycle on this, on these major projects, so that graph is still dropping.

So we'll see improvement over the whole spread, and some of those are going to be ready for FID, this year or next year and beyond.

Okay.

A second question from Biraj, looking for an update on Oman.

Would you like to go with that again, Lamar?

Yes, and the editorial point of Biraj's question is, it is a big source for us of cash flow in 2017, 2018-plus.

Oman is going well.

We are drilling wells, we are having good well results, we are on schedule, we're on time.

The facility is being built, it will be on as Biraj has mentioned in 2017, 2018.

It is a good and solid source of cash.

We are pleased with our progress on the project.

So like many of our projects that are in execute right now, these major mega projects, they are on schedule, if not ahead of schedule, and on plan as far as their resource development, as well as our costs.

Next question from Theepan Jothilingam of Nomura.

He is asking a question about the cash costs being driven down by another $3 billion, and he is looking to understand if we can split that, between what is variable to price, and what is sustainable for the future?

And also, what is related to lower activity levels?

Okay.

Thanks, Theepan.

The [bulk] of the cash costs, we are talking about are cash fixed costs.

So therefore, they are sustainable on a go forward basis.

In terms of the break-down, it is pretty much across the piece.

Upstream, the bulk of it is in the Upstream, pretty close to half of the $6 billion is coming from the Upstream.

But a very big proportion is coming out of Downstream, and out of the corporate and functions restructuring that we put in place back in 2013.

So in terms of this next phase, more than 50% will be coming out of the Upstream, 30% to 35% out of the Downstream, and the balance out of corporate and functions, given that we have taken quite a big chunk out of that area already.

In terms of the types of activities, it's across the piece.

But maybe Lamar, can give just a couple of examples in the Upstream, in terms of what is happening versus people, deflation and so on.

Yes, if you -- our progress on cost has been strong, and as Brian said, a majority of that is going to be Upstream.

If you want to dimension roughly where it is coming from, 35% to 40% of that is third-party spend, 35% to 40% is headcount, and probably about 25% is operated by others costs, all going down.

We have seen reduction in everything, from very, very small items to very large items.

And as I said earlier, we are bit early in this deflationary cycle I think, and we expect to see more deflation -- not only in the CapEx side, but also on the operating side, and we are seeing people work very hard to get more efficient, minimize duplication, and maximize standardization.

Theepan, you have a second question about, what is the average margin of your new barrels versus the current base E&P portfolio at $60 per barrel?

Well, of course, this is a moving [fee], as prices are changing and our projections of cost are changing.

But the -- in effect, the oil projects will have higher margin than the current segment average at $60, and the gas projects will have lower margins.

The average and the aggregate is about right at the segment average.

And it will vary project by project, year-by-year.

So I think -- we can't say that the new projects going forward are double the cash margin of the segment average, as we were a few years ago, with some projects that came through.

But we do have very solid projects, both on the oil side, and on the gas side coming through.

Okay, great.

We will take the next question here from Blake Fernandez on the web.

He is looking for some direction on the DD&A for 2016?

Yes, so Blake, in terms of DD&A, we typically give guidance as we go into the fourth quarter results, in terms outlook for next year, and we will do the same again in February.

But the basic assumption you should assume, is it is flattening right now, given that the CapEx has come down quite so significantly.

But we still have the depreciation, that we are working off of the previous investments.

So we still have a big chunk of projects in train, that Bob described.

That DD&A will flow through the system, but I think it's fairly reasonable assumption to assume it flattens off into the future.

But we will give you some more guidance around that, in the February with the 4Q results.

Okay.

And a second question from Blake regarding the recent LNG contracts in China, looking for some color on S curves being included, and the terms in relation to existing contracts?

Yes, Blake.

So those -- it's a 20 year -- the deal that you saw announced last week, was a 20 year supply deal into China.

We don't normally share the contractual arrangements around those deals, but they sit as part of our global LNG portfolio, and they will be managed as part of that, and sourced from different options that we have within the portfolio.

Moving on now to Martijn Rats from Morgan Stanley.

He has a question related to those sources and uses of cash.

He is asking, with the dividend of around $7.5 billion and the CapEx's guidance that we have provided, whether we are effectively guiding for operating cash flow of around $25 billion to $26 billion?

And he'd like to know how that splits between Upstream and Downstream and Rosneft, and what the underlying assumption for refining margins is in our plans?

Thanks, Martijn, and yes, your math is absolutely correct.

So that is exactly the way to look at it.

So you are in the right range, in terms of balancing things up, and we have never given a sub split of cash flow by segment.

So and we wouldn't plan to start now.

But of course, it looks very different at $50 or $60 per barrel than it looked at $100 per barrel.

But no, we don't really give the breakdown in terms of sub segmentation of cash.

So thanks for those questions, Martijn.

And turning now to Oswald Clint from Sanford Bernstein, who would like to know what we need to do to get US RCOP back to profitability?

And whether that is continued production, cost reduction, or gas price and NGL prices that need to rise?

Let me take that, Jess, this is Lamar.

Oswald, I take it by your question, you probably mean Lower 48 rather than all of US, Alaska, Gulf of Mexico, refineries, et cetera.

So I will talk about Lower 48.

We want to get that business where it is profitable, at basically about $3 an Mcf.

Now we're below that, quite a bit below it as of today, and get that free cash flow positive around $3.

Now that is not the easiest thing in the world, but that is what we have given the team to shoot for, and they have made massive progress on cost, where I think we are basically competitive in each basin that we operate.

And they are making fast progress on capital, as Bob showed you on the slide.

And those green dots, by the way on that slide that you saw, basically go top to bottom sequentially.

So we are making good progress.

Yes, $2.10 is not going to be great, but the business, I guess, will adjust to that over time.

But really, we are thinking something more towards $3 to have a really viable business there, and having chance to develop the assets that we have.

So just sticking with Oswald's questions for the moment.

He has one asking, whether sustainably embedding the cost savings is realistic, given that the industry is terrible for witnessing re-inflation when prices rise?

What is BP doing to ensure that inflation doesn't filter through BP again?

Well, Oswald, that is a great question.

We are doing several things.

One is the approach we are taking, and I hope our contractors would back me up on this, is that we are not trying to slash and burn everything, and beat people to a pulp to get rates down.

We are trying to work with our contractors to, in effect to acknowledge that we are in business together, that we have got to do something that is sustainable, whichever way prices go.

So we are trying to work constructively with terms, with length contracts, with flexibility for ourselves and contractors to do this the right way.

We are also doing some things that are -- they may say -- they may sound kind of small, but I think they are important.

As we consolidate footprints and consolidate building spaces around the world, which by the way in Houston we're doing, southern UK we're doing quite aggressively.

We plan on sticking with that, and not expanding that footprint into the future.

We are working our plans on cost, much harder than we have in the past.

And we see that as a line item to manage at the same intensity going forward, as we do production or anything else.

So there have been some changes, and we talk about this quite a bit.

There is no silver bullet, of course, and we are not immune to any pressures that may occur.

But we will do everything we possibly can, to make sure that we hang on to the margin the best way we can, if these things turn around in any way in terms of prices.

Tufan, you want to say something?

Yes, let me add to that, from a Downstream perspective.

First of all, is so far, our cost are 15% lower.

And as third particles, as well as internal costs, similar reduction we achieved, and none of that actually has anything to do with deflation, because we don't actually experience any deflation in Downstream.

What we are doing is, in addition to the third party reductions I mentioned, internally we are simplifying our business model, and actually we took one layer out.

We eliminated significant activity in the Downstream head office, therefore we expect 40% lower costs in the Downstream head office costs.

And then in the businesses, we are eliminating duplication, and effectively all the businesses, fuels, lubricants and petrochemicals, we are making them simpler, no duplication, and actually leaner models.

So they are all sustainable because of that.

Why, thank you.

So just to give an update, we are still having technical difficulties with the telephone lines, but we are successfully getting questions through on the web.

And so, could we please ask, that for the time being you continue with your web questions, and we will keep you updated.

So we have a question here from Guy Baber of Simmons.

He is asking about the level of capital guidance, and he is looking for confirmation as to whether this level of spend needs to be accompanied by some level of inorganic activity to 100% to replace reserves and growth through the cycle?

And he is asking, because he sees the implicit F&D cost of that framework as being further below, where it has been recently trending, and what deflation might imply?

Guy, yes, let me address that.

The range of CapEx we've described, we believe that we can grow the Company moderately as we have said.

Now if you look at reserve replacement, obviously that is going to be weak right now.

We do think as Bob said, he mentioned an approach to renewing the Company, and if I just repeat that in a little bit different words.

We do have an organic exploration that we will continue.

We are not sizing that organic exploration to 100% replace reserves, because we are also working on discovered resources we have, as well as resources within the portfolio that we think technology and deflation will unlock.

And then, we are also very active in accessing unconventional resources such as Oman, such as the Chinese deal that we have talked about earlier, or you have seen earlier this week.

And there may be places as Bob said, for deepening another acquisition.

So I think the way we are looking at renewal is organic exploration, pull through of resources we already have, new unconventional access, and the potential for acquisition.

And those are all viable, and of course, they will be lumpy from year to year, but they are all viable sources of renewal.

Next question from Lydia Rainforth of Barclays Capital.

And her first one is on costs.

She says, I think Bob mentioned adding additional organization controls.

Can you outline further what they are, and how they help the cost reduction programme?

And also related to that, does 2017 represent the perfect BP from a cost perspective, or is this still a multi-year process?

Thanks, Lydia.

I am not sure there is a perfect BP.

But what I can say on the costs, what we have done, if you go back to the divestment programmes we had, and we divested over $50 billion.

I've said it before, our overhead did not properly adjust to that big reduction in assets.

So we were already in action, and had been in action, really since late 2013 adjusting our cost base.

Since then a group of senior executives have met consistently and frequently, and looked at a whole series of changes, and all that work is accelerated now.

We've looked at hiring, we looked at projects, we looked at sponsorships, we've looked at consulting spending.

And those decisions have now been pulled in, with a group of people who work very closely together at the highest levels of the Company.

And that is how we were able to, I think help drive these reductions in cost through the company, because we have been working on it, before this drop in the oil prices.

And I think I could talk about that for quite a bit, but I think I will stop there.

On the dividend, talk about how you see the Scrip programme evolving in 2017 and beyond, Brian?

Yes, Lydia, I mean, I think the Scrip take -- I mean, the Scrip is something we introduced in 2010, and it was heavily supported by the investors at the time when it was introduced.

We also recognized that least a degree of dilution, although the Scrip take up for the last four quarters has only been around 5% or 6%.

We have offset the dilution in the past with the buyback programme that we had post the TNK Rosneft transaction.

And we are very cognizant of the fact that, in offering a Scrip which is taken up by our shareholders, that we need to think about the consequence of dilution going forward.

Hence this balancing in 2017, includes the Scrip in part of that balance, to ensure that we can actually cover the cost of that Scrip, and reduce the share counts accordingly.

All right.

So now Kunal Kothari of Old Mutual Global Investors would like to know what drove the strong gas marketing results this quarter?

Thank you for that question.

It was mostly out of our international LNG operation, although we had a very solid set of results out of our base gas marketing and trading out of North America, and globally.

But the difference versus typical quarters, it is above our average quarter for gas trading.

We typically have each year, an above average quarter for both oil trading and gas trading.

And in this quarter, it was for the gas trading.

And it was certainly a couple of hundred [million] dollars above what we had the previous quarter.

But it came mostly out of our international LNG optimisation.

And Jason Gammel from Jefferies, would like to know whether we can identify how much of the controllable cost reductions are in the corporate centre, and how much arise in the operating segments?

Are you sacrificing any organizational capabilities to achieve these cost savings?

Jason, hi, this is Bob.

I would -- well, first off, every part of the company is being reviewed, and we are in fact simplifying the corporate centre as well.

A lot of the complexity built up after 2010, moved into the Company, and a lot in the corporate centre.

We question all things and the work that we drive, and we realized we're driving a lot of the complexity in the Company ourselves.

So there has been, and will be changes in the corporate centre.

In the operating segments, there is, of course, a lot of change in the operating segments as well.

We know the breakdown between them.

We are probably not -- we're not talking about that so much publicly, but maybe Lamar and Tufan, you can talk about the reductions broadly in your segments?

Yes, maybe I will go first.

As you said Bob, it is happening everywhere.

So we are obviously already pretty far into this, so we can see where results are occurring, and they are recurring in every single region in the Upstream, every single function.

Everybody is at work.

We are, of course, trying to involve the whole organization in this, so that we can get thousands of small ideas, as well as pretty big ideas.

I am pleased with the way this is working.

And, of course, we are concentrating, as well on staying safe and reliable as we do this.

And so, it is across every single category of cost in the Company, and I think people have taken to this, and are pretty proud of the progress they are making.

Just to add to that -- I think again, our 15% reduction on the total costs is coming from everywhere.

We are restructuring every business as we go along.

Obviously some businesses, especially head office we can actually restructure more quickly.

Some European businesses take more time, but within the time frame we are talking about, we expect those savings to come in.

But it is everywhere.

One thing I would say, also manufacturing efficiency, we are actually driving as well.

But one point on capabilities, the way we are doing this, in line with our strategy, we are actually adding some capability in some places.

We have, an example for you, we have a reliability programme to improve the availability of our refining.

We are bringing world-class experts to build the capability there, in line with our strategy.

So this is definitely not taking the capability out.

Right.

So now Alastair Syme from Citi has a question about the portfolio.

He would like to know about how we think about renewal?

And as we look into the next decade, whether we think the exploration programme is enough to renew the hopper, or whether we need to look at supplementing this in some way?

Thanks, Alastair.

Well, we do have more than enough investment options in front of us, that we know we are going to have to prioritise.

There is no question about that, and that is a good place to be.

A decade or 15 years ago, it was harder.

Do we have enough?

We are certainly going to repace the rate of exploration.

We have enough exploration acreage acquired over the last three years, is more than we had in the nine years before that.

We have a number of exploration appraisal activities going on today, that could lead to projects not on that list, that we'll reprioritise those options going forward.

And some of those will certainly take us into the next decade.

Is the exploration programme enough to renew the hopper, do you need to look at supplementing it?

I think that the kind of projects we have done for example, in Oman over the years, the kinds of things we are actually doing in Russia today, are the other kinds of things that can supplement renewal of the resource base reserve base, rather than just pure exploration.

Would you expect to see an increase in spending -- let's see.

You also asked me about things that are not on our list, for example, the KG-D6, which is discoveries we have had underneath the D6 field in India.

At the moment, they are not in our list of projects.

They are out there as possible options.

Today the conditions in terms of gas pricing are not economic to do that, but we remain hopeful, but the capital can't really flow into there, until it's much clearer.

Lamar, you want to talk about the other questions in the Gulf, Palaeogene I think?

Yes, I just wanted to comment, Bob, that there are 50 or so major projects that we have out there.

We did not list every one.

I do expect some to rotate in, that are not on that list.

We are working them hard, and I think they for various reasons, deflation, scope, contracts, those kind of things, terms, that I do expect some of those to rotate in.

So this list will evolve.

I think the basic point is, I think between the resources we have in the company, plus our resized exploration, plus access to unconventionals, I think that is enough to renew the hopper.

And as I've mentioned, we will look for opportunistic things to do, if there are some that we can deepen in our own portfolio through acquisition.

Right.

Moving on now to Bertrand Hodee from Raymond James.

He has a first question, I'm looking for an update on Mad Dog South.

What our latest cost estimates are, relative to the around $10 billion back in July, and whether we expect the cost to still go down further?

And also, whether we are confident on FID of this late in 2015, or in 2016?

Let me take that, Jess.

On Mad Dog, we are still working, it is improving.

It is more than likely -- very, very likely to be below $10 billion.

We are trying to understand exactly when the optimum timing for that is.

We are working with our partners, and I do have confidence that we will get to sanction here, probably in early 2016.

We will see.

We will see where we and our partners get to.

But I do feel good about that.

And I feel like -- back to Bob's point earlier about returns on new projects, I do think that will put Mad Dog in a competitive return window, and structurally lock in those costs going forward, to build a very, very important Miocene project in the Gulf of Mexico.

And his second question, from Bertrand, when looking at the break-even at $60 per barrel, what is our weighted average cost of capital?

We don't disclose that, I believe in the annual report of accounts.

We don't actually normally give out our weighted cost of capital, and it stayed pretty stable, over the last -- over the last five years.

There was a slight uptick, post Macondo, but it is back to sort of where it was in pre Macondo levels.

Okay.

Turning now to Gordon Gray from HSBC, Gordon would like to know whether the new CapEx guidance, which represents a near 30% fall from the old guidance, whether this spending level is driven by the financial framework as opposed to other factors?

In other words, he says what is the confidence level you can give us, that this level of spend is enough to sustain growth past, post 2017 and post 2020?

And would we expect to see an increase in spending, in an outcome of crude prices above the $60 per barrel scenario in the medium or long-term?

Well, let me take it from an Upstream perspective.

I think from what we can tell, the activity level that we would set for the Upstream within that frame, represents what we would like to do.

Portfolio is quality enough that we think we can grow it moderately.

Now if prices go up and we get some inflation, as I said earlier, we will do everything we can to maintain the capital efficiency, eat inflation if at all possible.

And I don't think -- the implication is not here, that if prices go up a little bit, we explode CapEx.

We have a very, very, I think, good quality portfolio that we are going work hard to stay within this frame, and do every we can to not have inflation eat us up.

So we are not choking back activity to fit a frame, if that is what you mean.

Obviously on the margins, we've got some things we are sliding around and rephasing and rescoping.

But it's not a big choke back on capital, that we would explode, if the prices went back up.

All right.

And Chris Kuplent of Bank of America is looking for some guidance on depreciation, other business and corporate, and the underlying effective tax rate in 2015 and beyond?

Thanks, Chris.

I think we said earlier, that we expect DD&A to continue to flatten.

So it is around $15 billion, which is where we came in guidance this year, and I would expect to see that trend going forward.

So I would expect kind of flat.

On other corporate, we are trending about $100 million a quarter below the guidance that we have for this year, that's because we are seeing some of the cost simplifications coming through.

But also some positive results out of our other businesses that we hold under the corporate line.

And then in terms of underlying effective tax rate for 2015, the last five-year range has been in the range of 30% to 36%.

I think we guided you at the start of this year, below last year, which was up from memory 35% or 36%.

And I think it will be in that range of 30% to 36% going forward.

I think that's a pretty good range.

Moving on, Iain Armstrong of Brewin Dolphin would like to know whether the resetting of BP to a $60 environment going -- is going to be backend-loaded in 2017, or will it be a smooth progression?

Iain, hi, this is Bob.

We have been -- we started to see the results come through in the second and the third quarter this year, fairly rapidly.

In fact, I think we are going into 2016 with lots of momentum.

I think it will not be backend-loaded.

I think part of the question is, how fast with our suppliers will the deflation come through for part of it?

And the other question is around labor flexibility.

Different geographies, you can move faster in terms of reduction of cost.

That is why some of those will be well out into 2017, but there will be a lot of activity in 2016.

I think it is going to be a smooth progression.

And so now, Aneek Haq of Exane has a question to put to Lamar.

He would like to know, whether given the reset in project costs that we are currently experiencing, whether we can comment on areas of our portfolio where we are incrementally more positive than we were a year ago?

And on the offset, those where we are seeing less cost deflation on a relative basis?

On the two big areas where I feel much more positive than I did a year ago, one I knew that Lower 48 would react fast.

There was zero doubt in my mind about that.

What I didn't know, and didn't realize is, that actually the rest of the world is reacting pretty fast, in terms of deflation and minimizing duplication, and getting more and more efficient.

So incrementally more positive, that this is broader and more significant, in terms of this speed of deflation than what I thought a year ago.

Second dimension is that, it's not only CapEx, it's operating cost as well.

And partly is that that's our own efforts within BP, but also the efforts of our contractors in our producing areas.

So I do feel more positive overall about the rate of progression here.

There are areas that are obviously they are more aggressive than others, where rigs and things like that, seismic pretty aggressive, other things may be a bit slower.

But I feel I feel more positive about how this is deflating, than I did a year ago.

And then Aneek also has a question for Bob.

Can you talk us through the latest thoughts on buy versus development of production?

Aneek, right.

Certainly, any developments we are going to do, have to meet these hurdles that Lamar described, and we described in the presentation.

We think those are good investments.

I think the first thing in terms of buy, is when people approach us about deepening in our existing projects and fields in production, some of that is starting to happen now.

But I think -- what I think I don't want to signal, is we are going to be out looking for acquisitions.

They have to be very good deals.

They need to be tailor-fit our portfolio, and that is probably all -- the best thing to say right now.

Turning now to Neill Morton.

Neill, would like to know whether the reduction in capital expenditure from the $24 billion to the $26 billion original guidance, down to the $17 billion, $19 billion, whether we give a rough split of that, between lower activity and lower cost of deflation?

I will give you an Upstream perspective, first.

Obviously, I don't have a number on this, and I don't want to give a percentage, But I would say that the majority of it, if not the vast majority of it, is lower cost and deflation.

There is attenuation of activity of some lower return activity and the rephasing of things.

But it is mostly lower cost and deflation, and how we're optimising the scope and standards by which we do things.

So we were already at work at much of this, which was a good thing.

And I think the deflation has been a wind at our back to help us get some of this done.

And Neill is also asking for the refining marker margin assumption behind the 2017 cash neutrality position?

Neill, it is Brian, and I'll pass you off to Tufan.

But the -- I think you will see it on the slides, we have it there, it is $15 is the assumption we have used out in 2017, along with $3 Henry Hub, and $60 oil.

But remember, the marker margin is just a marker, it does not actually tell you what is going on in the real refinery.

So I'm sure Tufan, will give you a lot more detail behind that.

Thanks, Brian.

Just Neill, I think how you may want to think about this, $15 obviously lower than this year's margin environment.

Early on, I talked about 1.3 million barrels increase in the demand for 2016.

Current assumptions for 2017, similar demand increase expected.

If those increases happen, I think we expect that refining margins will continue to be supported, not at the current in 2015 level, but around the levels that Brian mentioned.

Okay.

Next question from Irene Himona of Societe Generale.

Irene would like to know what industry cost deflation assumption we factor in behind the reduction in CapEx, and the over $6 billion cash cost saving?

Given that Upstream spends about 85% of the capital, Lamar?

Okay.

Thanks, Bob.

Irene, there is not -- Irene, there is not as you can imagine, there is not one assumption on industry cost deflation.

We have looked at all of our major spending categories, we talked to our contractors, and we've also looked at our activity set going forward, and come up -- have come up with some pretty detailed plans about how we are going to accomplish the cash cost savings, as well as the CapEx programmes.

So it varies.

We normally see a lag of one to three years, in terms of all of the deflation filtering through, and we've thought about that, and worked that.

And we have multiple assumptions on every line that -- of types of services that we get.

But so I'm not going to give you one [flat] factor, but we see things 15% to 30% reductions over a three-year period in most every service.

And then, we've obviously got activity, rephasing and rescoping that we talked about which adds to the savings.

So we work it in a very, very granular manner, rather sort of gross assumption basis.

So Irene is also annualizing the nine month year to date operating cash flow of $14 billion to get to a number of $19 billion annualized with Brent at $55.

She would like to know what Henry Hub price we are anticipate in 2017, and what others sources of improvement in operating cash flow we expect out to 2017?

Thanks, Irene.

So we're assuming, I think as I mentioned early, a similar Henry Hub price than what we've seen to date, as the year to date average, and we are assuming $3 for 2017, as a planning assumption.

In terms of sources of the cash improvement, the bulk of it is from the costs that we can see coming through, in terms of what we already have this year.

Remember that next year, you get a full year impact of those cost savings, without the restructuring charges associated with them, that go on as one-off cash payments this year.

So you get an extra kick in 2016 and 2017, hence Bob's early answer to Iain's question, around the loading of it, it will be quite continuous through 2016 and 2017.

So it is [not absolutely], not backend-loaded.

And also then, from the new projects coming on [straight] stream, and the revenues associated with that.

And then all the various pieces that both Tufan and Lamar have explained in earlier answers to questions around the sources of improvement.

But it is basically all coming from, what I call the top line, in terms of the overall improvement out to 2017.

I think to add, I think Irene asked about the annualization of cash flows, and I know at the second quarter, we said you can't annualize the cash flows based on the quarterly earnings -- I know we are three quarters of the way through the year, but we still probably can't, and shouldn't answer that.

Yes, thanks, Bob.

I forgot about that part.

We do have a working capital build this year of $1.8 billion already year to date.

We should expect the bulk of it to unwind.

So you are not a million miles away from where the absolute number may come out, but it's a lot -- there's that still can happen between now and the end of the year.

But you are right, it's year to date, it is about $14 billion.

Some working capital reversal to come through, and then some more benefits on the cost come through in 4Q.

Right.

Some questions now from Jon Rigby of UBS, and we will start with a couple for the Downstream.

The first is, is the existing $1.6 billion cost improvement in the Downstream included in the new cash cost reduction guidance of $6 billion?

And also while we are on the Downstream, he is asking a question about petrochemicals, saying your portfolio has meant you have missed the petchem top of cycle.

BP's petchem is well below recent year's profitability.

Is that re-achievable, and what needs to happen?

Okay.

Thanks, Jon.

On the first question, I think, short answer is yes, it is included in the $6 billion.

And we actually -- I talk about 15% reduction.

That represents a good acceleration of that $1.6 billion cost efficiencies.

I think, in addition, we now see further opportunities, which is also part of $6 billion.

Coming to the petrochemicals question.

Let us -- let me remind you first of all, why we have narrow portfolio [Acetyl] that are Aromatics.

These two businesses grow higher than normal bulk of growth of petrochemical business around 5% to 7% growth between them you actually see.

And we have technology, and therefore cost advantage versus competition

So coming to your question what has been happening the industry, especially in China PTA.

Between 2011 and 2015, industry actually build up more than 20 million tonnes capacity.

And as a result of that, margins went on up.

What we see going forward, we still see 6%, 7% growth in PTA China.

So it is still continued strong growth, which was the case this year as well.

And now we have better visibility, in 2016 and 2017 additional capacity coming into PTA China.

And I can tell you, given additional capacity, we don't actually foresee loss of capacity to come in, in 2016 and 2017.

As a result, we expect utilization to start to go up in 2016, 2017 in China PTA, and also one should expect margins to go up in line with that.

But let me tell you what we are doing.

At a constant, we said, our agenda at a constant margin, we going to expand the earnings potential of the business.

This is exactly what we are doing.

If you look at this year's numbers, nine months you have these numbers, nine months improvement in petrochemicals is around $150 million.

And environment, versus last year, more or less the same.

So similar environment, $150 million better performance, it is all coming from efficiency, operating improvements and portfolio restructuring.

And we will continue on this agenda, and you should expect more improvements to come as a result of that.

Thank you, Tufan.

Jon would also like to know whether when we look at increasing shareholder distributions, whether we would focus on buybacks?

Jon, hi, this is Bob.

We will keep all of these things in our toolkit, most certainly.

I'd just say focus on buybacks is probably not right.

We have had many of the discussions about UK shareholders generally having a bias towards dividends.

US shareholders having a bias towards buybacks.

We balance that but I think for the moment, we are just -- absolutely priority is to maintain the dividend through this period, make sure we balance the sources and uses of funds.

And then, we will have all options open to us, because I think you will see that we have -- we will see a growth in free cash flow out towards the end of the decade, and that will give us lots of choices.

And I have a couple of questions now coming in from Fred Lucas of JPMorgan.

The first would be, he is looking for a real and material example of standardization in Upstream operations or projects?

Hi, Fred.

This is Lamar.

Several things going on here.

Over the past several years, when prices went up above $100 and stayed there.

I think -- and I don't think we are that much different than other majors at least, where there was a lot of up spec-ing and [bespoke] systems and equipment used for new projects.

And I mean that all the way from valves to trees, to compressor packages, everything.

We have kind of regrouped, and decided that on most of the things we do -- not everything, but most of the things we do -- it is probably been built before, and we should be able to get something that someone else has built, and get another version of that built.

Or to make sure that we use industry-standard equipment.

And I will give you specific examples like valves, like subsea trees, like compressor packages, use industry-standard -- which by the way, the contractors know very well.

And if we don't want to use an industry standard for something, there has to be a conscious reason and justification and logic for doing that.

So we have kind of a flipped the D&A hopefully a little bit here, where we use what has worked, and we go outside that industry-standard, if we really need to.

And that will cover things like trees, valves, metallurgy, hull design, compressor packages.

Those are lower cost.

They are easier to do because they have been done before, and can be replicated, and they are lower risk on delivery.

Now those are probably going to affect projects that are in the -- new projects in the Gulf of Mexico, big and small, Egypt, Trinidad and potentially Angola.

So and in the Op -- and it will bleed into the operational front, as we continue to standardize, where we will have an easier time to maintain things as we get the same types of valves, the same types of compressors around the patch.

A second question from Fred, does the goal of sustaining the dividend make BP more [pro cyclical], and less able to capture low cycle opportunities, either to invest, or buy more and be more tactical?

Yes, Jess, and then, I'll ask Brian to comment as well.

I mean, the uncomfortable reality here, is after five years, only this year, can we begin to plan the company with a reasonable sense of certainty after the events in the Gulf of Mexico.

And I say that, in a sense of certainty, at least uncertainty at the same level as the rest of the industry right now.

So I think it is good for all seasons, to make ourselves very fit, very lean, a more focused company.

It's got a portfolio after divesting well over $50 billion, we like the portfolio that we have, and we want to build a company that is fast and quick, and very, very competitive.

So I think all that is good for all seasons.

When and if a really good opportunity unfolds, I think we will also have the flexibility to deal with that.

But Brian?

Yes, no actually, not a lot to add to that, Bob.

And I think, don't forget we have a quite a strong balance sheet.

We now have clarity on those uncertainties that Bob described going forward.

So you have to remember that last year, we were surplus cash, Fred.

Quite significantly surplus cash, and our net debt came down accordingly.

We are through this, we're way into this transition phase now, having got out ahead of the eight ball quite early, in terms of what we could see happening with the price.

I think it puts us in a very strong position.

And if provided things are accretive, which I think is important for our shareholders, and they fit strategic options for us in terms of the portfolio, absolutely we will look at them.

But in terms of the balance sheet and where we are, we are in a pretty strong position.

Lastly from Fred, when does BP expect the Upstream deflationary cycle to bottom out?

Fred, we have looked at history here, and it generally says one to three years is where -- if things stay relatively stable on a price basis, one to three years is when the cycle kind of find its stability.

So I think, I don't see any real reason to think it's different this time.

But this as I said earlier, feels like people have -- this is a pretty progressive and aggressive deflating period right now, it feels to me.

So perhaps it doesn't take quite as long.

But that's been the history -- some with several different examples really one to three years.

Next question now from Thomas Adolff of Credit Suisse.

Firstly, what are you doing differently with front-end loading on major projects?

Thomas, we are doing all the things we have been doing, plus I think the major change we have made which relates to what Fred was asking, is how do we approach a major project?

And we spend a lot more time as an Executive team with the functional heads now before we -- let's say we have a discovery or a new access, we get together very, very early on, and determine what this project ought to look like.

We give some help to the teams, in terms of what we would expect in terms of the scope and scale of the project, based on the best information we can gather.

And we do it less sequentially than we used to.

That has offered some opportunities.

This is what I mean by rotating some projects in.

It's offered opportunities that I think are going accelerate some things, and we will do those at industry-standard, and do those faster than we have done before.

So we, the difference for us is kind of changing our attitude towards, how do we do things in major projects?

And I think it is really making -- it will really make a difference.

And a second question from Thomas related to the point of 80% of pre FID projects breaking even below $60 per barrel.

Thomas is looking to know if we are referring to the 33 billion barrels of oil equivalent in contingent resources, and how much of that resource base is linked to Henry Hub?

Thomas, the 80% pre-FID below $60 represents some of the 33 billion barrels in contingent resources, certainly not all of that.

But they're all the projects in the project hopper that Bob mentioned.

The resource base that is directly linked to Henry Hub is 7.5 billion barrels, which is a Lower 48 resource base.

So I -- other things, you could argue are related in some way to Henry Hub through baskets and other things of price weighting, but directly it is 7.5 billion.

Right, and Guy Baber, back in again from Simmons, with a couple of questions on the Lower 48, really looking for us to expand on the points about reinvigorating underworked acreage, and selective inorganic activity, as well as discussing capital allocation in the context of the broader portfolio returns metrics that we highlighted in the prepared commentary?

Yes, Guy, good questions.

We -- the fact is our acreage has been underworked over the last several years.

We were down to two Company-operated rigs in 2014.

We have got 5.5 million acres, about 1 million acres -- or over 1 million acres of mineral interest.

So it is just not been worked very hard over the last 10 years.

We are going to work it hard.

And what we have asked the team to do, and effectively what we're demanding of the team is to get your cost competitive basin by basin.

That's is pretty much there.

And then, show us that you can do capital execution and efficiency to a degree, such as you can have returns that are competitive with the rest of the Upstream portfolio.

We have been relatively lenient in capital this year.

That is tightening up, as we go forward, and their returns I am happy to say, on their incremental activity have been good.

And they are using new technologies, and obviously looking at what's going on around us.

And I feel pretty good and capital allocation will be a normal allocation process with the Lower 48, and it will be competitive.

So the return thresholds will be the same for the Lower 48.

We've, as I said we have been a bit lenient this year, and I am happy to say that in effect, we are an experimentation phase with the new leadership team, and they are doing a bang up job.

So I feel good about where that is going.

Great.

Thanks, Lamar.

Turning now to Rob West of Redburn, a first question.

What investment hurdle would you have for any potential inorganic uses of capital?

Thanks, Rob.

Like any investment, we look at the usual economic indicators, in terms of us, our existing portfolio.

But any capital that we'd look to put into those potential acquisitions, we'll have to stack up with the alternative uses of that cash.

As Bob described earlier, we have a very flexible financial frame, that maybe it'd better to actually buy back stock versus buying assets.

So I think, providing it is accretive and it hits our economic indicators, versus organic investment, then those options will stack up.

And ultimately, they have to lead back to strategy, in terms of being supported by the strategy where we are heading.

A second question from Rob, can you allay the potential fear that rephasing spending, tacitly means deferring maintenance?

Have all of your turnarounds occurred at the same scope as they were originally designed for, or have any been slimmed down?

So Rob, yes.

This is something we talk about a lot, and I think I have a webcast with about 2,000 Senior-level leaders this week to talk partly about this.

We do not intend to, and are trying everything we can to make sure no one in the Company delays any spending that is required, appropriate, necessary for safety and reliability and maintenance.

And the first priority, when I go through in terms of my checklist, in terms of our capital programme, is staying safe and staying reliable, and spending appropriate money on the base.

I will repeat that, and repeat that, and repeat that.

Have all of the turnarounds occurred at the same scope as they were originally designed?

Yes, pretty much.

If they haven't, if they have been slimmed down -- and some have been slimmed down, they have slimmed down for a reason.

And through the operations function, not by a dictate from me, or anybody else in St.

James or Houston or anywhere else.

So obviously, what we do want to do, is when we do turnarounds, or we do any sort of spending including safety, is we spend every single dollar, the best possible way it can be spent, to get the best possible results.

And we are seeing savings in that area as well.

We are 24% ahead of schedule on our turnarounds this year, but they have been delivered within scope and on time -- sorry, ahead of time and within cost.

So it is something that we concentrate on.

You cannot imagine how dedicated I am, to not go backwards in terms of safety and reliability.

And Rob, if I could add from our standpoint.

Actually, it has almost become such second nature to us, and we should put it in the presentation, we talk about it.

This is absolutely the number one thing that we talk about, when we review our capital budgets, and our spending.

Whether that is the Downstream or the Upstream, we are not going to sacrifice safety.

We are not going to defer things to fit a financial framework.

In this area, we have been really clear.

We are not going to reduce or stop any kind of safety critical training of our employees.

There is no company that is more aware of this, I think than we have become.

And I would note that this year, alone in 2015, we had double the number of turnarounds we did in 2014.

That's what I was going to say, yes.

Rob is lastly is asking about us relinquishing 100% stakes in three ultra deepwater blocks off Uruguay, what drove this decision, and with it, was due to gas [prone-ness] in the basin?

Rob, well, I am not going on comment on individual blocks and individual prospectivity, but you can assume that if we drop anything, it is because it wouldn't fit into the portfolio at the prospective returns that we want to get out of it.

So that is all I will say on that.

Right.

Jason Kenney from Santander is looking for some underlying tax guidance for 2016.

Sorry, Jason, you are probably going to be disappointed.

But it's, refer back to my earlier answer.

But it's-- the range of the last five years of 30% to 36% is still pretty good.

We are trending below 36% this year.

We will give you guidance in February of next year, but something in that range would be a reasonable assumption going forward.

Thanks, and I think we have Chris Kuplent coming in again from Bank of America, asking what business segment do we expect the 2016 and 2017 disposals to come from?

And on the assets you have earmarked for disposal, what would have been the expected contribution to CapEx, cash flow, earnings, and any other operational metric as we look at it?

Thanks, Chris.

It is a very different portfolio that we are looking at going forward, than the ones we did during the big divestment phase, where we sold out of big countries and big producing hubs.

And if you look at the sort of nature of the disposals this year, a big chunk of those will actually come out of the Downstream, a mix of terminals, assets.

We'll continue to look at also -- dispose of early life assets that aren't generating cash today, and you saw that with the Paleogene earlier this year that we did.

So it is a mix, and we wouldn't normally give you guidance by segment.

The bulk of them this year have come out of Downstream.

It will be a mix going forward, and there's a whole chunk of options within the portfolio.

In terms of effect on CapEx and cash, that is all been into that financial framework I have given you for 2017.

And Iain Armstrong of Brewin Dolphin is asking whether we expect to take a write-down on both basin probable reserves, in view of the lower for longer assumption on oil prices?

Iain, too early to say at this point.

We don't know where long run assumptions will be on oil prices.

We still [ring] the $80 -- for the long long-term.

And we will go through the whole reserves calculations through the fourth quarter.

No early indications at this stage.

We went through a whole series of tests in the third quarter, looking at the asset base.

We have similar plans in place for 4Q.

We didn't take any measuring permits at the end of 3Q, but you have to wait for 4Qresults.

Turning now to Lucas Herman from Deutsche Bank, who is putting a question to Brian.

Does dividend cover on RCOP accounting basis mean anything to BP?

And if so, what level of cover what the Company like to move towards, and over what time line?

That is a trick question from an accountant, Lucas (laughter).

But I think you and I both know, that ultimately you have to have the earnings to justify your distribution of dividends.

So absolutely, that is one of the things that we take into account, but we don't target at a specific number.

Historically, it has been around 25% of earnings at the $100 per barrel, or certainly in that range of something in terms of retained earnings.

So clearly, as we have moved to $50 a barrel, we are still in the process of transitioning.

But absolutely, on a point forward basis, it is something that we would look at.

And then, Lucas would also like to put to Tufan two questions.

Firstly, at Whiting, have the facilities stabilized?

Or simplistically, what is the further non-market related opportunity for performance uplift from here?

And secondly, are you seeing any benefit in lubricants as yet, from base oil price falls or is that to come?

Thanks, Lucas.

First Whiting question.

I think as you rightly said, the first task is to stabilize, and Whiting is very reliable.

Then I think two more opportunities, we see on the Whiting performance.

One is this is a new kit, once it is stable, reliable operations, we are looking to -- we are doing some work on optimising the new kit.

You can actually unlock some limitations, and we believe that is going to unlock some value.

And the second thing is, once it is stable, we are going to be able to drive some efficiencies in Whiting that we haven't been able to do so far.

So those are two opportunities which are not market related.

And on lubricants, yes, we have seen base oil price falls this year, definitely.

But I think -- here is what, how you should think about our lubricants business.

Base oil price falls are there.

On opposite direction though, a couple of things going on.

Because of the base oil price falls, you get price pressures in the market.

So that is one thing.

Second thing is most of our lubricants business is outside the United States.

And given stronger dollar, two significant negative hits we had in lubricant business this year, one is transaction ForEx impact, when the ForEx depreciated in --against dollar in most of the countries.

And then the second thing is, translation impact obviously which is self-explanatory.

So our performance improvement this year is actually coming from growth markets.

We are achieving a improvement there, our RCOP improvement definitely.

And it is coming from efficiencies, and we are actually improving our premium ratio which has a much better margin profile.

So that is where it is coming from.

Turning back to Richard Griffith of Canaccord.

How much harder and how long would it take to rebalance sources and uses of cash, if you used $50 a barrel instead of $60 a barrel?

Thank you, Richard.

I think, first of all, let me clarify, because we have got some questions early this morning.

We have not chosen $60 because we believe it will be $60 in 2017.

We just simply took, what forward strip, as a point in time in 2017 as we transition through to rebalancing the company at a lower oil environment.

So that is the first point of clarification.

If we, and in terms of this year, we laid out at plans out at $50 a barrel is what we assumed, as we looked at our source and uses, as part of this transition.

So that is what we set the plan for this year.

We are in the same process, in terms of next year.

And I don't think any of us are expecting a major uptick in oil prices from where we see today.

I mean, the supply and demand outlook still, I think is a bearish one, in terms of where the oil price will stay absolutely in the short to medium term through the first half of next year, and probably into the second half.

In terms of 2017, if it transpires in the back half of next year, that we are at $50 or some lower price, of course, we will expect further deflation to come into the system.

And I think Bob alluded to that in his presentation.

So $60 is not a point in time that we are banking everything on for 2017.

It is just simply what the forward curve is saying, and we've looked at our sources and uses for that year.

So to the degree the price is higher than $60, that will lead to a position, obviously where we have surplus cash.

To the degree it is below $60, our rules of thumb will tell you, a $10 a barrel drop, that would be over $2 billion of cash we would need to make up.

We would expect to see further deflation come through in the back end of next year.

So I think, it's just important that we are not locking into a specific price, because a lot of things can happen between now and 2017.

Okay, and we now have another question from Anish Kapadia, outside of the US where do you expect liquids growth to come from, to the end of the decade and beyond?

Anish, hi, Lamar.

Well, where our major projects will be in terms of oil developments will, of course, include the Gulf of Mexico.

But also Angola, the North Sea, we have some big projects coming on over the next few years, and there are other projects after that.

We believe Azerbaijan will have more oil opportunity as we go forward.

And then, we have got exploration plays in Brazil, in Nova Scotia, and in Egypt that we think and believe could be oil.

And, of course, we got our Canadian heavy positions that could -- at the right point in time, be a major projects as well.

So we have several places that oil could come from, and those will be worked into the project schedule as they compete and get developed.

And in Angola, where would you expect production to fall to, by the end of the decade?

Yes, Anish, I'm not -- I don't have any direct prediction on where Angola is, production is going to be.

We don't normally talk about a piece of our portfolio like that, nor an individual country.

So I don't have a production prediction for you there.

Thank you.

And we now have a couple of questions from Fadel Gheit at Oppenheimer.

The first one is, do you expect the recent gas discovery by ENI to have any impact on BP West Nile Delta gas development?

Fadel, no, I do not.

That project is underway, and the terms are clear, and I don't see that having any effect on West Nile Delta.

And also from Fadel, does BP need to keep $32 billion cash balance, while having $50 billion [update]?

Yes.

Thank you, Fadel.

Of course, that $32 billion includes various standby lines that we put in place after Macondo, of the tune to $6 billion to $7 billion.

So, no, we would expect to see some of that debt roll off over its natural course over this year, which it has already this year, and through to next year.

But we certainly, don't need to keep that level of cash balance going forward.

Turning now Jean-Pierre Dmirdjian of Liberum.

He's referring to slide 23, and 45% of the expected Upstream CapEx from 2015 relating to projects?

And can we please let him know how much of this is committed in 2015?

Jean-Pierre, obviously all of the 2015 spending is committed, and then, 2016 I would say most of it, and then it starts tapering from there.

So it's -- there are more options and flexibility as you get further out in time.

I don't have an exact profile to give you today, but it frees up, as you go along in terms of time.

And we will take the last question from Dennis Coleman of Bank of America.

Can you please update how BP's positioned with the credit rating agencies, given the updated financial framework?

If you will, in terms of the current financial framework, we are both single-A with both rating agencies.

In terms of outlook, like the sector -- I think the whole sector is on negative outlook, as a result of the oil price across the whole piece, but we are today single-A is our credit rating.

And in terms of what we have laid out today for 2017, I think it is premature to see what impact that may have from ratings perspective.

And a second part to the question --

Sorry, to be clear, I wouldn't expect it to have -- I think it, in terms of where we've got to now, in terms of rebalancing at this lower oil price, I would not expect that to have any impact.

And a second part of the question is, whether the Macondo payments are included as a payment debt obligation in the gearing calculation?

I think we laid this out on July 2, with the agreements in principle, but effectively it is a long-term contractual agreement, is the way it's treated.

It's an overall impact of 1% on the gearing of the company.

Well, thank you, everybody.

I am sorry that the telephone lines let us down today, but thank you for keeping the web questions coming.

And I will now just hand back to Bob to close the call.

Well, thank you, Jess, and thank you everyone for on the line.

It has been about 2 hours and 20 minutes, so thank you very much for your patience.

Sometimes when you are caught, and something isn't working, it is good to let you know we did receive word that the external telecommunications carrier's bridge that supported this telecom has crashed.

It sounds all very dramatic.

I don't think anyone was hurt.

I do know those of you who dialed in, could listen, you just could not speak.

And so, thank you all -- for those many people who shifted over to the web, and we could see the numbers.

It was probably the largest call we have had.

So thank you for that.

The length of this call is actually in response to shareholders.

Many of you on the line, in fact who we know well, who had given us the feedback to go into a little bit more detail on this quarter.

I think you will see, a consistent quarter of operational delivery now, the operational reliability.

It is that virtuous circle of safety, reliability, feeding through to financial results, that we have been working so hard on.

I think they do come through, again this quarter.

It allows us to compete well.

Probably the big thing that we are starting to see now, is that we can again now, plan the company for the longer-term.

Having progressed the Deepwater Horizon spill agreements in principle is actually a big thing for shareholders.

Again that, reestablishing the financial framework, get the operating cash flow to be able to cover the capital expenditures, and the dividends is our objective.

Our dividend is going to be set at a level that is consistent with the long-term cash generation, that we see the underlying businesses have that capability.

We have gone through all the numbers there.

And supporting all of that, and we are trying to make very sustainable changes in our cost structure, we want to support that commitment we have made, to sustaining the dividend.

And that remains strong priority for us right now, without sacrificing the future growth of the firm.

And I think with that, thank you all very much for your patience.

And we will be out and around, seeing many of you.

Thanks.