英國石油 (BP) 2015 Q4 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 fourth-quarter and full-year 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 you 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.

Thanks, Jess.

Welcome, everybody, and thank you for joining you us.

It already looks like another very turbulent year for our industry, so I'll start today by looking at that business environment.

Then I'll look at how we are responding and building resilience in these tough conditions.

I'll then give you the headlines from the full-year results.

As usual, Brian will take you through the detail of our fourth-quarter numbers, and provide an update on the medium-term guidance we laid out in October.

Then I'll come back to briefly update you on the ongoing work in our Upstream and Downstream businesses.

At the end, there will, as always, be time for your questions.

So let's start with the oil price environment.

Between September 2014 and the end of 2015, we saw the price of oil fall by over $60 per barrel.

And as we enter 2016, the fundamentals that caused this are still in play, which means prices are likely to remain very volatile in the near term.

However, the market is responding to these low oil prices.

Globally, supply is leveling out, especially in the United States, where output is declining.

Last year, low prices led to a steep increase in demand of approximately 1.8 million barrels per day, which is double the average annual demand growth of the past 10 years.

These trends suggest that supply may converge with levels of demand sometime in the second half of this year.

And as we move further out, we expect demand may well start to exceed supply, which is an increasingly consistent view across a number of industry commentators and data sources, including our own outlook.

Of course, inventories that have built up in the meantime would also need to work their way into the market.

As this all starts working together to improve the fundamentals, I might characterize the outlook as being lower for longer, but not lower forever.

There will be more detail on our view of the longer term in our updated Energy Outlook publication, which our chief economist, Spencer Dale, will launch next week.

The recent sharp fall in oil prices has had a big impact on our 2015 results, as it has for the whole industry.

The key in times is to adapt and compete to the new environment.

At BP, I believe we have a distinctive track record of understanding, responding, and adapting to change quickly and effectively.

I believe our swift response, the fundamental principles of our strategy, and the solid day-to-day delivery in our businesses are all serving us well in this environment.

This time last year, we predicted that the deteriorating environment would bring about a period of intense change for our industry.

We talked about a reset phase of two years or so, with outcomes defined by the level of oil and gas prices, the pace of deflation, the ability to achieve efficiencies, and possible M&A activity.

And we are seeing all of that playing out across the sector.

In BP, we recognized early on the need to focus on a set of clear priorities for the near term.

You may recall, we called these priorities the four D's: ongoing delivery in the business; a disciplined reset of our capital and cash costs; completing our planned divestments; and, most importantly, maintaining our dividend as the first priority in our financial framework.

In 2015, we did make good progress against these priorities.

As operators, we maintained a stronghold on safe and reliable delivery, while undertaking major business transformation.

In the Upstream, our focus on managing production in our base assets and driving down operating costs is showing up increasingly with competitive operating performance.

A strong year in the Downstream is a reminder of both the importance of our integrated model, and also the quality and performance of our Downstream portfolio.

And Rosneft, in which we have a 19.75% interest, is showing good operational and financial resilience in the current environment.

As last year began, we moved quickly to reset our capital expenditure plans.

Also, the reduction we've seen in our cash costs is substantial and also, we believe, largely sustainable for the long term.

And agreed divestments are within the range planned for the 2014 to 2015 period.

We'll come back to all these points in more detail as we go through today's presentation.

We also reached a milestone, a significant one, in July with the announcement of the agreements in principle with the United States government and five Gulf states to settle all federal and state claims arising from the Deepwater Horizon oil spill.

This leaves us able to focus more clearly on the future.

So we have achieved a lot, despite the challenges.

As we look forward in 2016, we continue to adapt to the changing circumstances.

I am convinced we are responding smartly, doing the right things, and that, as we adapt, we're also learning and enhancing our ability to adapt even further for what we expect to be a very tough year ahead.

We know how to do this in BP.

Our balance sheet was strengthened by divestments after 2010 to provide flexibility for Deepwater Horizon uncertainties, as well as this sort of price volatility.

And the rapid pace at which we are resetting the business is putting us well down a path of rebalancing our financial framework.

Brian will cover this more fully in a moment.

All of this is supporting our ongoing commitment to sustaining the dividend.

Of course, as we work through this reset phase, we have to think about more than just the near term.

Ours is a long-term business, and we need to respond to today's challenges in a very thoughtful way so as not to compromise safety or the growth plans that are essential for the future.

As we highlighted to you in October, we have not lost sight of the enduring principles that guide our business in any environment.

These principles embody what is needed to succeed in our business through the cycle, and they keep us focused on our primary objective of growing value for shareholders over the long term.

We talked a lot about this in October, so I will only touch on the main points again today.

Our approach starts with a relentless focus on safe and reliable operations.

It also recognizes the importance of a strong, balanced portfolio, with resilience to a wide range of operating conditions and opportunities for growth.

We've worked hard since 2010 to reshape our portfolio.

Through $75 billion of divestments, when you include our interest in TNK-BP, it leaves us with a high quality set of opportunities well aligned with what we do best.

With our interest in Rosneft, our portfolio retains the scale of a 3.3 million-barrel-per-day Company.

We manage this portfolio for value over volume, whether through inorganic activity such as our ongoing divestments or asset deepening, or through alternative ways to optimize our businesses, such as you have seen in the US Lower 48.

Capital and cost discipline are not only critical right now, but fundamental to our business model long term.

We must be efficient with our scarce capital.

We will continue to sanction projects, but only those we see as competitive, once they have been optimized for deflation.

And we continue to transform our cash cost base as we make the structural changes for a sustained business model for the future.

All of this works towards the most important shareholder-focused principle -- that of growing sustainable free cash flow and shareholder distributions over the long term.

Now, let me turn specifically to the full-year 2015 results for the Group.

Our underlying replacement cost profit was $5.9 billion for the year, a result significantly affected by the much weaker Upstream environment.

This was 51% lower than the full year in 2014.

At the same time, that result was supported by a strong environment and strong performance in the Downstream, and our efforts to reduce costs broadly across the Group.

These same factors impacted our underlying operating cash flow, which, excluding the oil spill payments, was $20.3 billion for the year.

This was 38% lower than last year.

Organic capital expenditure in 2015 was $18.7 billion, while proceeds during the year from divestments totaled $2.8 billion.

And gearing, at the end of the year, was 21.6%.

We distributed $6.7 billion in cash to shareholders through dividends.

And, finally, our reserve replacement ratio for 2015 is estimated at 61%, excluding the impact of acquisitions and divestments.

I'd like to take a moment now to look more closely at the outcome of our efforts to reset costs.

We continue to move quickly in lowering the costs we control across BP.

That means optimizing the scope of what we do every day and changing how we manage our internal costs, including extensive simplification of our organizational structures in every part of the business.

This is what makes a large part of these cost savings sustainable for the future.

And you can see the results to date.

The Group's controllable cash costs for the full-year 2015 are some $3.4 billion lower compared with 2014.

This is well down the track towards delivering the cash cost savings we outlined in October, which we now expect to be closer to $7 billion by 2017, compared to 2014.

Non-operating restructuring charges are expected to approach $2.5 billion in total by the end of 2016, relative to around $1.5 billion incurred in total since the fourth quarter of 2014.

As I just mentioned, organic capital expenditure for 2015 was $18.7 billion.

This compares to the guidance at the start of the year of around $20 billion, and 2014 actual spend of $22.9 billion.

As well as paring back some exploration and access spend, and prioritizing activity in our base operations, it reflects a very careful focus on balancing the timing of investments to capture the accelerating deflation in the supply chain, while ensuring we continue to invest sufficiently in our growth plans.

Based on past cycles, and the interventions we have in train, we expect continued deflation in 2016 in both capital spending and our operating cost base.

So you can see we are transforming the business to a sustainably lower cost base.

We must take full advantage of the changed environment while making the tough choices that ensure we establish a resilient cost structure for both the current environment and as a platform for future growth.

As we carefully manage the transformation to a lower cost base, we recognize it has never been more important to focus on safety.

This slide shows our progress at the Group level.

We see encouraging overall progress since 2011, which I believe reflects the disciplined approach we're taking to our operations around the globe.

Looking first at losses of primary containment, or LOPCs, which reflect even very small releases of any hazardous material, and we were pleased to see a decrease in 2015 with the overall downward trend clear on the chart.

We also track process safety events, which is the American Petroleum Institute, or API, industry metric.

We've seen a reduction in both tier 1 and tier 2 events, continuing the overall downward trend.

As regards personal safety, our recordable injury frequency rate has also reduced in 2015.

As I will never stop saying, safety is good business.

It remains the primary focus in our operations, and we are always striving to improve performance.

Good safety leads to a reliable operation of your assets, which leads to better financial results.

With the proper maintenance, it is a virtuous circle.

On that note, let me hand over to Brian.

Thanks, Bob.

Starting with the price environment for the fourth quarter.

Brent crude oil fell to an average of just under $44 per barrel, the lowest quarterly average since the second quarter of 2004.

This was mainly driven by sustained OPEC output pushing inventories higher, despite falling production in the United States.

Henry Hub gas prices averaged around $2.30 per million British thermal units in the fourth quarter, lower than the previous quarter due to unseasonably warm weather impacting demand.

Gas prices increased sharply towards the end of the year, as temperatures returned to more seasonal norms.

As expected, the overall refining environment deteriorated through the fourth quarter, as capacity returned after autumn maintenance and gasoline demand fell.

These lower trends had a significant impact on our fourth-quarter results in a quarter of otherwise strong operational delivery.

Turning now to results.

BP's fourth-quarter underlying replacement cost profit was $200 million, down 91% on the same period a year ago and 89% lower than the third quarter of 2015.

Compared to a year ago, the result reflects significantly lower Upstream realizations, and lower supply and trading, partly offset by lower costs.

Compared to the previous quarter, the results reflect lower Upstream realizations, a weaker refining environment, and lower supply and trading, partly offset by higher Upstream production.

Fourth-quarter operating cash flow was $5.8 billion.

The fourth quarter dividend, payable in the first quarter of 2015, remains unchanged at $0.10 per ordinary share.

Now turning to the highlights at a segment level.

In Upstream, the underlying fourth-quarter replacement cost loss before interest and tax of $730 million, compares with a profit of $2.2 billion a year ago and a profit of $820 million in the third quarter of 2015.

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

Excluding Russia, fourth-quarter reported production versus a year ago was 8% higher.

After adjusting for entitlement and portfolio impacts, underlying production increased by 2%.

Compared to the third quarter, the result reflects lower liquids and gas realizations, exploration write-offs that were $460 million higher, and lower gas marketing and trading results, partly offset by higher production.

Looking ahead, we expect first-quarter 2016 reported production to be broadly flat compared to the fourth quarter.

In the Downstream, the fourth-quarter underlying replacement cost profit before interest and tax was $1.2 billion, compared with $1.2 billion a year ago and $2.3 billion in the third quarter.

This brings the Downstream full-year underlying replacement cost profit to a record $7.5 billion.

The fuels business reported an underlying replacement cost profit before interest and tax of $890 million in the fourth quarter, compared with $930 million in the same quarter last year and $1.9 billion in the third quarter.

Compared to a year ago, this reflects cost benefits from simplification and efficiency programs, offset by weak supply and trading.

Compared to the third quarter, this reflects lower seasonal refining margins and weak supply and trading.

Refining operations in the fourth quarter were strong, with Solomon availability at 95.5%.

The lubricants business delivered an underlying replacement cost profit of $290 million in the fourth quarter, compared with $310 million in the same quarter last year and $350 million in the third quarter of 2015.

Compared to a year ago, this reflects continued strong margins, offset by adverse foreign exchange impacts.

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

Looking ahead, we expect refining margins in the first quarter to be lower than the fourth quarter.

Turning to Rosneft.

Based on preliminary information, we have recognized $235 million as our estimate of BP's share of Rosneft's underlying net income for the fourth quarter, compared to around $470 million a year ago and $380 million in the third quarter.

Our estimates of BP's share of Rosneft's production for the fourth quarter is just over 1 million barrels of oil equivalent per day.

Broadly flat compared with a year ago, and 2.5% higher than the previous quarter.

Further details will be made available by Rosneft with their results, which we expect to be issued later this quarter.

In Other Business and Corporate, the pre-tax underlying replacement cost charge was $300 million for the fourth quarter, an increase of $180 million on the same period a year ago, mainly due to a number of one-off credits in the fourth quarter of 2014.

The average quarterly charge during 2015 was lower than our guidance of $400 million per quarter, and reflects benefits from our simplification programs and profitability in our other corporate businesses.

The underlying effective tax rate for the fourth quarter was minus 20%, with tax credits in respect of the reported Upstream loss more than offsetting tax charges elsewhere in the business.

Excluding the one-off North Sea tax reduction in the first quarter of 2015, the underlying effective tax rate for 2015 was 31%.

This compares to 36% in 2014, and reflects a change in the mix of the Group's profits.

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

As previously announced, BP Exploration & Production reached agreements in principle with the United States government and five Gulf Coast states to settle all federal and state claims arising from the Deepwater Horizon oil spill, pending court approval of the proposed consent decree scheduled for the March 23, 2016.

The settlements do not include claims relating to the 2012 class action settlement with the Plaintiff Steering Committee, including business economic loss claims not provided for, private claims not included within the class action settlement, or private securities litigation in MDL2185.

The charge taken for the accident for the fourth quarter was $440 million, which takes the total cumulative pre-tax charge to $55.5 billion.

This reflects around $580 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.

The pre-tax cash outflow on costs related to the oil spill for the full-year 2015 was $1.1 billion, including $595 million relating to fines and penalties.

Of the $20 billion paid into the trust fund, $18.6 billion has now been paid out, with the remainder allocated to amounts already provided for.

As a reminder, we expect cash outflows in 2016 of $530 million in respect of the 2012 criminal settlement with the United States Department of Justice, and $1.1 billion in respect of the 2015 settlement agreements.

In addition, we also expect further payments relating to business economic loss claims and other costs not yet provided for.

We will continue to update you on these charges on a quarterly basis.

Now, looking at cash flow, this slide compares our sources and uses of cash in 2014 and 2015.

Operating cash flow for 2015 was $19.1 billion, of which $5.8 billion was generated in the fourth quarter.

This compares with $32.8 billion in 2014, and $7.2 billion in the fourth quarter of 2014.

Excluding oil spill related outgoings, underlying operating cash flow for the year was $20.3 billion, as noted by Bob.

This includes a working capital build of $300 million in the year.

Organic capital expenditure, for the full year, of $18.7 billion includes $5.5 billion for the fourth quarter.

Divestment proceeds totaled $2.8 billion in 2015, with $230 million in the fourth quarter.

Now, turning to our guidance for 2016.

We expect full-year underlying production in 2016 to be broadly flat compared with 2015.

The actual reported outcome will depend on divestments, OPEC quotas, and entitlement impacts.

Relative to October guidance of $17 billion to $19 billion per annum of capital expenditure through to 2017, we you now expect 2016 capital expenditure to be towards the lower end of this range.

This fine tuning of our guidance reflects the ongoing rebalancing of uses of cash in the lower price environment.

The reduction is largely driven by a better understanding of what to expect from deflation in the supply chain, rather than any material changes to planned activity.

Depending on where oil prices settle and how this continues to impact deflation, we will keep the capital frame under review as we move through 2016 and beyond.

In 2016, we expect DD&A to remain broadly flat relative to the 2015 charge of $15.2 billion.

In Other Business and Corporate, the average underlying quarterly charge is expected to be around $300 million, although this may fluctuate between individual quarters.

In the current environment and with our existing portfolio of assets, we expect the effective tax rate to be lower during 2016 due to the changes in the mix of Group profits.

Turning to our financial framework for the medium term.

As we laid out in October, our principal objective is to reestablish a balance in our financial framework by 2017, where operating cash flow covers capital expenditure and the current dividend at an average Brent oil price of around $60 per barrel.

We see this as consistent with sustaining the dividend at a level supported by the long-term through-cycle capability of our underlying businesses.

We continue to make strong progress on resetting both the capital and cash cost base of the Group.

As noted, we now expect 2016 capital expenditure to be towards the lower end of our $17 billion to $19 billion capital frame out to 2017.

Group controllable cash costs are now expected to reduce by close to $7 billion by 2017, compared to 2014.

As Bob highlighted, oil prices look very challenged in the near term, although our view of the medium term remains broadly unchanged.

With all the actions we are taking to reset the cost base, we expect to continue to recalibrate for the weaker environment, capturing more deflation with the deepening of the cycle.

We would, in turn, expect this to drive the balance point below $60 per barrel, should current conditions persist for longer than expected.

Once rebalancing is achieved, organic free cash flow is expected to start to grow at constant prices.

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

On divestments, having reached the $10 billion mark for 2014 and 2015, we continue to expect 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.

The proceeds from these divestments provide additional flexibility to manage oil price volatility and capacity to meet our Deepwater Horizon payment commitments in the United States.

We will also continue to manage gearing with some flexibility around the 20% level, although we expect gearing to run above 20% while the oil prices remain weak.

I'll now hand you back to Bob.

Thanks, Brian.

Turning to our businesses and looking first at the Upstream.

In a challenging external environment, we achieved a number of significant milestones in 2015.

In Exploration, we made a high-value discovery at the Atoll well offshore Egypt.

We were awarded new blocks in the Gulf of Mexico and Egypt, as well as achieving access in Mexico through our joint venture partner, Pan American Energy.

We saw three major project startups in 2015: The Kizomba Satellites Phase 2 and Greater Plutonio Phase 3 projects in Angola; and the Western Flank A project on the Australian northwest shelf.

The In Salah Southern Fields project in Algeria is expected to start up during the first quarter.

And we made final investment decisions, or FIDs, on four major projects, including our two West Nile Delta projects in Egypt.

In operations, 15 turnarounds were successfully completed, and the performance of our base assets continues to improve.

In its first year operating as a separate entity, our US Lower 48 onshore business delivered material improvements in competitiveness and performance.

Unit production costs in 2015 were around 7% lower year on year.

And by the fourth quarter, capital efficiency on BP-operated wells had improved by 15% compared to 2014, benefiting from some real innovation in well designs and improved execution by the team.

We continue to deliver on our Upstream cost agenda where we are rightsizing our organization, reducing our third-party spend, and influencing our partners where we are not the operator.

Our total Upstream workforce is now 20% smaller than it was in 2013, with 11% fewer employees and 48% fewer agency contractors.

We are aiming for a total Upstream employee and agency headcount below 20,000, compared to around 30,000 in 2013.

This will mean a further workforce reduction of around 4,000 people.

We have a significant focus on capturing deflation, and have achieved average cost reductions of around 15% in our third-party spend.

We've also accelerated competitive bidding programs across the Upstream.

We expect to have re-bid 40% of our third-party spend in our operations by the end of 2016, and around 60% of our well-services spend by the end of the first quarter of 2016.

We continue to challenge our teams and our partners to deliver as efficiently as possible, and our focus on cost in 2015 has resulted in unit production costs over 20% lower than 2013.

The next few slides come back to the most important points from our October presentation, starting with our base assets.

Here, performance remains resilient, with that focus on safety and reliability, maximizing production and resetting our cost base.

Our functional organizational model is executing this improving performance.

We've seen a significant reduction in process safety incidents, and our personal safety statistics continue to improve, with recordable injuries in the Upstream at their lowest level ever.

At the same time, BP-operated plant reliability in the Upstream has increased from 86% in 2011 to 95% in 2015, driven by big improvements in key regions including Angola, the North Sea, and the Gulf of Mexico.

Drilling efficiency is getting better, with nonproductive down time of more than 20% versus three years ago.

Thanks to these improvements, production from new wells and well work reached around 160,000 barrels of oil equivalent per day in 2015, with the vast majority of well programs delivering rates of return of over 20% at a $60 Brent oil price.

We expect all these efforts to keep our managed base decline at around 2% through 2016, compared with a 2014 baseline.

Our long-range view remains at 3% to 5%, as we have said before.

Moreover, these performance improvements have now positioned us in the top tier of our peer group on a cash flow per barrel equivalent basis.

Looking ahead, we expect over 800,000 barrels of oil equivalent per day of new production from projects starting up between 2015 and 2020.

Over half of that is anticipated to come from seven key projects, all of which are progressing well.

These projects are accretive to the existing portfolio, with operating cash margins around 35% better than the existing base business.

We have some significant new projects that will increase the share of gas production in our portfolio.

These include LNG projects, pipeline gas projects such as Shah Deniz 2, and domestic gas projects, such as those in Egypt and Oman.

Our domestic and pipeline gas investments offer the longevity of a typical LNG project, but cost less to develop.

We focus on cost of supply as much as the sale price.

We work to leverage our commercial, financial, and technical capability through the value chain to drive competitive returns on these projects.

Break-even prices for our major projects have fallen by around 15% in the past 12 months, meaning that the vast majority of our pre-FID projects now break even below $60 per barrel.

We continue to optimize project economics to drive to lower the cost of supply in this deflationary environment.

We're also rescoping and rephasing the spending appropriately.

In addition to the projects under construction, we have a deep hopper of around 50 pre-execute and appraisal opportunities around the world.

These include some very good new discoveries made in the last 18 months, such as Atoll in Egypt and Vorlich in the UK North Sea.

In October, we showed you a slide detailing the depth of our project portfolio, and this is available on our website.

You may want to have a look at this.

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

And while some of this may change as we optimize our portfolio, we believe this inventory of projects remains balanced across our asset themes, fiscal regimes, and geographies, and this will allow us to continue on our growth trajectory.

Lastly, looking beyond 2020 in the Upstream.

We have the options, discovered resources and acreages to sustain long-term growth.

To emphasize another chart you've seen before, we have a hopper of 44 billion barrels of oil equivalent, including 11 billion barrels of proved reserves from the existing base assets and sanctioned projects, and a further 33 billion barrels underpinning our growth beyond the end of the decade.

In addition, we have an exploration pipeline across a range of resource types.

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

And recent access to new regions and plays does create the potential for future production centers.

And also, we're building a material position through our relationship with Rosneft.

All of this gives us considerable flexibility to adapt to changes in the energy mix of world demand over the long term.

And we remain very excited about the future of our Upstream business.

Turning to the Downstream, also delivered strong safety and underlying financial performance in 2015, which puts us in a good position to meet our medium-term strategic targets.

Process safety metrics have improved again in 2015, seeing the lowest level on record for total tier 1 and 2 events.

This has been done, along with strong refining availability.

With the refineries running well, we have benefited from the favorable refining environment.

Record pre-tax earnings of $7.5 billion from the Downstream included $1.9 billion of underlying performance improvement relative to the environment in 2014, while pre-tax returns have doubled, to 18%.

Our simplification and efficiency programs in the Downstream contributed to a year-on-year cash cost reduction of by more than 15%.

We continue to focus on building an advantaged portfolio.

You may have seen this reflected in our recent announcement to divest our Alabama petrochemicals complex in the United States, and the agreement with our partner Rosneft to dissolve our refining joint operation in Germany.

Our Downstream strategy, as laid out last year, is delivering results.

In manufacturing, we continue to build a top-quartile refining business and are taking steps to significantly improve the cash break-even performance of the petrochemicals business.

In 2015, this delivered significant improvements versus 2014.

Our refining earnings more than doubled at a constant refining environment to 2014.

And, in petrochemicals, we grew earnings by over $200 million in a similar environment in 2014.

In fuels marketing and lubricants, we invest in high-returning businesses that generate operating cash flow growth.

In 2015, fuels marketing earnings grew by 11% at constant currencies, and lubricants earnings by 20% on the same basis, bringing the combined earnings of these two businesses to over $3 billion.

Across Downstream, we continue to divest non-core assets, but also selectively investing in growth opportunities.

The simplification and efficiency programs across the Company remain central to our strategy.

As the metrics in the charts show, we're moving towards our medium-term targets in the Downstream.

In addition to doubling returns, we delivered strong cash flow, driven by EBITDA growth.

We've reset the cost base, and taken a number of decisive portfolio actions.

Our competitiveness has also improved, as you can see on the bottom right chart.

Continued execution of this strategy is expected to lead to further growth in underlying performance and make the business even more resilient to environmental volatility.

Turning to simplification and efficiency in the Downstream.

Today, I can tell you we have increased our cost efficiencies target to $2.5 billion per year, compared to the $1.6 billion target we set this time last year.

We plan to achieve this annual target by the end of next year, 12 months earlier than originally planned.

We've made material progress in 2015, with cash costs more than 15% lower than in the same period in 2014.

This is from three broad activity streams.

Firstly, we continue to rightsize the organization.

For example, during 2015, we have simplified our fuels organization, reducing the number of businesses from nine to three.

We streamlined our lubricants business, and have started restructuring petrochemicals.

And we have taken actions in our head office, which have led to around a 40% reduction in costs through the streamlining and elimination of activities.

Secondly, through site-by-site improvement programs, we are driving manufacturing efficiency in refining and petrochemicals.

And, thirdly, our focus on third-party spend has resulted in significant cost reductions compared to last year, despite the ongoing inflationary pressures that are evident in Downstream markets.

Together, these programs are expected to result in more than 5,000 employee and agency contractor roles being removed in the Downstream by the end of next year, compared to the end of 2014, with more than 2,000 of these already occurring during 2015.

So 2015 has been a year of significant strategic progress, and some very material performance delivery for the Downstream segment.

This has reset our competitive position and established a strong underlying business.

The focus for Downstream going forward will be to continue delivering underlying performance improvement and growth and, in doing so, further improve the resilience of the business through the environmental volatility.

In summary -- and thank you for your patience -- we are moving rapidly down the path of resetting the Company for a sustained period of lower oil prices.

I am confident we are doing the right things.

We've made solid progress in 2015, and there is considerable momentum behind our work to transform BP for the current environment.

I know this Company has the focus and the grit to emerge from these current times smarter, more evolved, and better adapted than ever to successfully navigate the future, whatever it may bring.

We expect 2016 to be tough.

We do not expect oil prices to remain lower forever.

We have set a very clear course for the medium term.

It is based around a financial framework that rebalances organic sources and uses of cash by 2017 in a $60 world.

This is underpinned by disciplined management of our capital spending and continued rebasing of cash costs.

We will work to lower this balance point as we capture the impacts of deflation at the prevailing oil price.

But we're also clear that we will not compromise safety or the enduring principles that drive our business, nor will we compromise our platform for future growth.

Our aim is always to grow free cash flow and distributions over the long term, and this will continue to guide our decisions.

We believe we have the right portfolio, the right projects, and the right investment framework to do this.

And our resolve is strong.

While they are undoubtedly painful, tough times improve us.

They make us harder and leaner, sharper and more focused.

And, on that note, thank you for listening.

And we'll now turn it over to your questions.

(Operator Instructions)

Thank you all again for joining the call.

And we will take the first question from Oswald Clint of Bernstein.

Are you there, Oswald?

Yes, I am, Jess, thank you very much.

Two questions, please.

The first one really just coming on the back of Brian's comments about supply and trading, seemed to come up quite a lot this particular quarter.

I wonder, Brian, if you'd just remind us what happened in the quarter and maybe point to the magnitude of these supply and trading impacts in the fourth quarter, please.

And secondly, probably stepping back to the CapEx number.

The $17 billion number, whenever we think about your comments about keeping it under review, should we think of that as there's a portion or an element of that as potentially unsanctioned projects that could be deferred or pushed into next year if necessary?

Or is it really the results of the competitive bidding that you expect through the year that would actually allow you to change that number if required?

Thank you.

Oswald, so I'll just pick up on the first question.

I should really talk about 4Q in the context of the year for supply and trading.

It was a very good year, strong year for supply and trading, both in the oil business where we had the highest results we've seen for the year in quite some time, and a strong set of results in the Upstream business in terms of gas trading and marketing.

4Q discrete though was a weak quarter.

It was actually just below breakeven on the oil trading side.

And it was trading somewhere around about the plan on the Upstream side.

If you actually add 3Q and 4Q together in terms of the numbers, as you try and quantify what that looks like, the average of those two quarters is pretty typical for a plan.

So actually what's happened is 3Q particularly strong in both, 4Q more like a planned result for the gas side and just below breakeven on the oil side.

Maybe I could hit CapEx, Brian.

This is Lamar.

Hello, Oswald.

At least on the Upstream side on CapEx, there is some room for deferral if we really need to.

As you can imagine, it's relatively tight given where we are in the capital cycle.

And we do understand and will count on some additional deflation as we go forward into the year, and a part of that is already locked in, part of it is being negotiated.

And we have the ability to phase and scope things as we go through the year.

So there's some flexibility there if prices stay where they are today, for instance.

Perfect.

Thank you both again.

Thanks, Oswald.

We'll go now to Irene Himona of Soc Gen.

Thank you.

Yes, good afternoon.

I had two questions, please.

Firstly, in terms of the $3.4 billion controllable cash cost reduction in 2015, you've said before, I believe, that around half of these costs are in [first-party exteradine].

In which case, would you please clarify what proportion of that cost reduction was due to industry cost deflation, and what do you assume behind your $7 billion target for deflation?

And then the second question on the financial framework, the targeted 2017 organic cash flow at $60.

I think Brian you mentioned in the current environment that could be a lower number, but surely it won't be as low as [$30].

So my question is, in a worse case scenario of $30 into 2017, can you give us a sense of the cash flow deficit which you would face once you account for the increased cost cutting, lower CapEx, et cetera?

Thank you.

Irene, hello, this is Bob.

Lamar, comment on the Upstream and Tufan on the Downstream on the cash cost reductions.

Thanks, Bob.

Irene, you can imagine it's not an exact science here.

But we believe that the cost reductions that we've seen so far, and it probably will hold on the cash cost side, is about two-thirds of help and one-third deflation.

Just to give you a little context, in the Upstream the cash costs are about -- and it moves around a little bit, but around 30% internal costs, let's call that headcount, about 30% operated by others, and then about 40% third party.

Obviously, we're working on all those categories.

So, so far, most of it's been self help.

We do think some more deflation will come in as we affect more and more contracts and bid more and more services as they come out of contracts going forward.

But right now two-thirds, one-third is probably about as good as I can s say for the Upstream.

Irene, our of the $7 billion, a portion of that is in the Downstream.

All of that we think is sustainable cost reduction.

Thanks, Bob.

That's absolutely right.

So we actually raised, Irene, our cost reduction target to $2.5 billion from $1.6 billion.

And as Bob said, all of that is sustainable.

In fact, if anything, we are still working in an inflationary environment.

And out of that $2.5 billion it is -- we actually brought it forward by one year.

We are now saying not by 2018 but 2017, end of 2017.

It is very much front-end loaded.

In fact, we talk about $1.9 billion underlying performance improvement last year in Downstream, a significant part of it is cost efficiencies and they're all sustainable.

But our programs on efficiency is multi-year programs, so there is more to come this year and in 2017 as well.

Thanks, Irene.

And then, Irene, in terms of financial frame, I think what we can say from what we said in the third quarter is we are very confident now in terms of the balancing point for 2017, given that we've now seen the costs come out of the system this year.

So remember the $3.4 billion.

Within that number, we've already also taken a $600 million cancellation charge for some rigs early this year, so the actual -- if you look through that number, it's more like $4 billion.

We are confident we can get the capital towards the lower end of the range now for this year.

And we set ourselves a plan last year of around $50 -- it was actually at $50 a barrel, and we've actually reset for this year a plan that has oil prices in the first quarter roughly around where you see them trade today.

So I think we've set up a realistic set of assumptions for this year.

As Bob described, what we'll see around supply and demand, we do think there will be a point this year which that oversupply will start to be eroded going forward.

And in terms of balance point, I think to the degree that the oil prices stay lower this year and it takes more time for that oil price to recover, we will monitor the balance points as we go through this quarter by quarter.

Ultimately recognizing that it's our desire to get things back into balance.

So I think it's premature at this point to I say well what happens if it's $30 next year?

Clearly, we'll have a plan B, and potentially a plan C if we get to that point.

But for now we're confident in terms of the balance point at $60.

We are confident in terms of the plans we'd have to balance below that, given what we can now see on the costs, and we've raised the cost number up to something close to $7 billion.

So I think there's still an awful lot of flexibility in the financial frame to deal with pretty much all potential scenarios going forward.

Thank you very much.

Okay, thank you.

And turning now to the US, and we'll take a question from Doug Terreson of Evercore.

Are you there, Doug?

I am.

Good morning, everybody, and congratulations to Lamar.

Thanks, Doug.

Bob, on slides 27 and 28, you referred to the project portfolio when you talked about the outlook for growth over the longer term.

Simultaneously though when considering that growth has come somewhat at the expense of returns during the past cycle, not just for BP but for the other super majors too.

It makes me wonder whether emphasis should rebalance more towards value creation when considering that investors have responded with fairly low valuation for these companies in relation to the past couple of decades.

So but the question is whether or not you feel that the issues of structure and returns and growth need to be revisited in a more assertive fashion given this outcome, if they're not already during the downturn?

And why or why not?

Well, Doug, thanks, you're right.

Our industry has not done particularly well utilizing our capital in the last part of the cycle.

We're going to be very, very efficient and careful with our scarce capital.

We do see that with the projects we have either sanctioned today, which some of them are very large gas projects coming in with fixed prices that have already been negotiated.

Those are going to be -- increase the margins on the portfolio.

We have decisions to make this year.

We've seen some incredible costs come down, both by our own design work with partners on certain projects and also deflation, for example, the Mad Dog project in the Gulf of Mexico.

Which a few years ago, looked like it was economic at $100 a barrel and cost $20 billion.

We now look at that project, it's under $10 billion, and so we're going to be really careful about sanctioning these projects as long as we see the potential for improved returns if we defer them.

Which is what we're doing now, which is I think the discipline we need.

We do get the feedback from our shareholders, so the dividend is very important.

And it's always been a little bit different in the UK versus US, but we're hearing more and more from both sides of the Atlantic that the dividend is very important so we're going to manage the framework to do that.

I think what you described is in fact what we're doing with our capital.

We'll be really careful with it.

Okay.

Thanks a lot.

That's the right answer.

Having said that, Doug, when you look at the projects we have out to 2020, there's very much the potential there to increase production from our portfolio by 800,000 barrels a day of new projects.

The phasing may be a little bit different, and of course, the base production declines.

But I think we've got -- some people we don't have growth prospects.

I know we do.

Okay, great.

Thanks a lot.

Thanks, Doug.

Back in the UK now, we'll take a question from Martijn Rats of Morgan Stanley.

Good afternoon.

I wanted to ask you about the disposal program.

Because clearly, getting through this downturn requires the balance sheet to be managed.

And for the balance sheet to be managed, the gap between dividends and free cash flow need to be partly funded through disposals.

But it seems a very difficult time to do disposals.

So I wanted to ask you about how you see your plans to successfully pull off a robust level of disposals over the next couple of quarters.

I if you could provide some visibility on that, that would be helpful.

Thanks, Martijn, it's Brian.

I'll just pick up on that.

It's a very good point in terms of the current market, given there are so many assets up for sale out there, and more of quite low prices.

And just to be clear, we're not in a situation where we have to sell assets.

If the opportunities are there and the value's there, but we're not going to sell it selling below our whole value.

Just in terms of giving you some confidence around that.

We delivered the $10 billion that we said we would have announced over 2014 and 2015.

So that's good in terms of progress.

You'll also recall at the third quarter, we talked about the financial frame in terms of operating cash, balancing up dividends and capital.

And that disposal proceeds that now point forward be used in terms of the obligations around the long-term payments on the various Macondo settlements and other liabilities associated with Macondo.

So we've set in train a target for this year of [3%] to [5%].

I think that is well underpinned in the first half of this year.

It is -- and actually it's across a suite of assets.

If you recall that at $100 a barrel, we sold off close to $75 billion of assets if you include the TNK transaction at very high prices in the Upstream.

We're now looking more at midstream, Downstream assets.

So they're not as exposed to what's happening with the oil price right now.

But there's no question where we've had Upstream assets, they are challenged going forward in terms of sales.

We don't have to sell them.

But in terms of [3%] to [5%], I think that's pretty well underpinned for this year, and then we'll be back in this normal transition of [2%] to [3%] going forward.

Ultimately, those disposal proceeds are being linked to the long-term Macondo payments.

And what we're looking to do by 2017 is get operating cash back into balance with dividends and CapEx, which I think is something you've written about for quite some time, Martjin.

Yes.

All right.

Wonderful.

Thank you.

Thanks, Martin.

Another question from the US, Blake Fernandez of Howard Weil.

Thanks.

Maybe the other side of the M&A conversation.

You recently did a transaction in the lower 48, which is the first time in a while.

I was hoping maybe you can give an update on what opportunities you're seeing there in a depressed market, and maybe the opportunity to do some bolt-on going forward.

Blake, hello, Lamar.

Yes, we did do a relatively small acquisition in 4Q in lower 48, and it was a bolt-on as some of Devon's assets.

And we do see opportunities like that.

But some of the valuations in certain basins, and Permian would be one that I would highlight, were really still pretty high.

And so where it makes sense and we can show an investment case where it's competitive with the other capital we're spending, we'll do that.

But we are starting to see opportunities like that as people re-juggle their capital, and some of those may fit us and we look at those opportunistically, obviously.

Okay, thanks, Lamar.

The second question, Brian, this may be for you.

But the DD&A guidance is fairly flat.

I'm just curious, as you begin to sanction more and more projects and maybe do some M&A in this depressed environment.

At what point do you think we can maybe begin to see a rollover in that DD&A, and do you have any sense of order of magnitude?

Yes, it's a great question.

Where we actually looked at that in terms of giving you forward guidance going forward.

We've still got capital rolling off in terms of depreciation.

We still have projects coming onstream.

But I think flat for this year is a reasonable assumption, and then we'll see where the capital gets you going forward in terms of the trajectory.

But we do have number of projects still coming on, and therefore, the DD&A schedule kicks in.

But I don't see any major uptick from here.

It may start to drift off a little bit depending on where we get to around deflation this year and next.

Thanks, much.

Next we'll take a question from Jon Rigby of UBS.

Go ahead, John.

Thank you.

Two questions.

The first is, just on about the CapEx and disposals.

Is it, because of you've given us a long-term guidance to disposal levels, is it perhaps worth thinking about your actual CapEx as being a net number, i.e.

less the $2 billion to $3 billion as a level of net investment into the business that can sustain the business going forward, rather than the gross figure that you talk about?

And the second question is really a query actually.

Could you go a little bit more into detail on the tax charges?

Both to disaggregate how 4Q came about, and perhaps how that relates to 2016 assuming that 2016's operating environment looks quite like the fourth quarter of 2015?

Thanks.

Jon, let me start and then Brian.

It's interesting you say that, because that's exactly how we managed 2015 was CapEx and disposals, and set our own framework around just that.

So we will do that going forward.

It's kind of hard to set the CapEx number now because it actually is drifting downward further with deflation.

But, Brian, you comment on that and the tax.

On the tax, Jon, there's a lot of moving parts in 2015.

You had the North Sea tax changes in the second quarter that affected the tax charge that quarter.

Not for cash, but in terms of the overall charge we took.

You also had the deferred taxes, which are a benefit for us in terms of where the dollar movements on the deferred tax balances that we have.

And then, of course, you've got the mix of the earnings now coming through from very different looking portfolios in the Upstream than we had before.

And then the loss in the Upstream in the fourth quarter, which triggered the credit.

So an awful lot of moving parts through this year.

What we've tried to do is cut through that, and actually get you to an underlying effective tax rate if you take out the big North Sea change.

But keep the deferred tax movements in of around 31% for the year.

And looking forward into 2016, we would expect that effective tax rate to be lower, which is the guidance that we've given you.

How low it is compared to where we are today is very much a function of the portfolio mix of assets that we have, particularly in the Upstream and what those earnings look like.

In the Downstream, it's far more stable in terms of predictability going forward.

But it will really be about the various points of the tax regimes in which we operate inside the Upstream, and the balance of those.

But we're confident it will be lower than the 31% we have for this year.

Thank you.

Okay.

Turning now to Rob West of Redburn.

Thanks for taking my question.

I'm going to have another one on tax rates if you can bear it.

My question is, if you strip out tax credits, if you assume you couldn't book any tax credit at all, what would be the cash tax rate relative to that 31%?

Can you help me think about that as a metric potentially come apart in a low price environment?

And then secondly on the gearing, you always talk about it in terms of balance sheet gearing.

But I wonder, do you ever think about it in terms of net debt to cash flow or any other metrics?

And how should we see the ceiling there if you broaden the gearing metrics you think about for where you're comfortable going up to?

Thank you.

Rob, thank you.

So the first answer is, the long run average, if you look at our cash tax paid versus charged, typically runs a at 5% to 7% below the effective tax rate.

That's just a good rule of thumb if you look over the last five or seven years as we've looked at it in terms of the actual tax paid.

We're now into all sorts of other movements that have kicked in this low oil price.

But I think that's a pretty good estimate going forward if you're looking for what the actual cash tax looks like, taking into account those deferred tax credits that you have rolled in.

In terms of metrics, it's actually a very good point on the gearing point.

It's one that we've just shown over a long, long time, because it's been part of the financial frame.

The metric that we use internally that we look at very closely and monitor and performance management is really funds from operations.

So free cash flow or cash flow from operations over our extended debt book, which is something the rating agencies look at as well.

So we take on of board the debt we're carrying plus all of the leases for rigs and other activities, and then we look at that metric in terms of the actual cash we're generating over that extended piece, and we like to manage that in a certain range.

But the gearing is more of a -- it gives you an indicator.

Actually right now, in terms of debt, we have a lot of capacity.

But we're not about to try and start to use that, other than to be able to manage through this transition we've got into the new low price environment.

Okay.

Can I just make sure I heard you correctly.

So you're saying in a 30% to 40% tax environment, your cash tax rate will with lower than the P&L tax rate?

Correct.

Okay.

Thank you.

Right.

I have a question from Jason Kenney come in via the web.

What needs to happen for the US Upstream to return to a quarterly profit?

Is this possible in 2016?

Let me take that one.

Jason, this is Lamar.

A couple things need to happen.

One is, we need to of course continue to run the assets well.

Which, by the way, the Gulf of Mexico has been running exceptionally well the last couple of years.

That's got to continue.

If I just take 4Q, which is sitting right in front of me, exploration write-offs were pretty high in the Gulf of Mexico with the Gila write-off.

If I could put exploration write-offs to the side for a second, and we run things pretty well, we need a little bit of price help and the entire US would return to profitability.

So at $40 a barrel, it's very difficult and you know 4Q the gas price for lower 48 or anywhere in the US was exceptionally low.

So we do need a bit of price help if that's going to happen in 2016, which Brian I think has outlaid our view and how terms or prices could increase towards the back end of the year, yes, I think you could see it.

But again, we had quite high exploration write-offs this year.

So the US overall was negative $850 million.

Okay.

Thanks, Lamar.

We'll take the next question from Asit Sen in the US from CLSA.

Thank you, and good morning.

Two questions.

One on Upstream CapEx, and a quick one for Tufan on Downstream.

In this capital constrained environment, Bob, just wondering if you could talk to two specific areas, Eagle Ford shale and exploration.

Eagle Ford Shale is material for BP.

You have about 200,000 net acres there.

Could you frame the thought process with respect to projected activity, volume trajectory this year in 2016 versus last year?

And secondly, your comment on paring exploration spend, totally understandable in this environment.

Could you quantify how you're thinking about calibrating this?

Because historically, you have been fairly active in reloading exploration pipeline.

Asit, thanks.

I'll comment on exploration, and Lamar on the Eagle Ford.

On our exploration, obviously, we've got discretion in exploration.

We have commitments out there.

We'll meet those commitments, but our exploration spending is down from roughly $3.5 billion in 2013, down to about $1 billion now.

Now that's still a lot of activity, but that's a significant reduction.

That's the one thing I think that we can phase, and we'll just be very cautious and careful around that.

This is about the exploration and drilling spend.

Lamar, on the lower 48, Eagle Ford.

In the Eagle Ford, you're quite right.

We have a sizable position in the Eagle Ford in partnership with Lewis.

Activity has been slower in 2015 than prior years.

We are on a bit of the gassy side in the Eagle Ford, a fantastic asset with lots of well locations to go.

But the activity has been a attenuated.

I don't have -- I see it right at the top of my head whether they -- I think thinking flat production probably is about right for that, rather than any major growth going forward for the next year or two.

But obviously, we have to work to plans with Lewis and see where those investments and Dave Lawler's portfolio fit.

But I think the Eagle Ford will be, at least our Eagle Ford, will be attenuated a little bit here a little bit for the next couple years.

And a footnote on the exploration costs.

Actually, our deferral of exploration is a little bit like some of the major projects.

The drilling costs are coming down really fast.

So it's, I think, in our best interest to slow down a bit.

And can I -- just maybe one point on renewal versus organic exploration.

We are also working pretty hard to add unconventional resources into the hopper, and Oman is a great example which is renewal but it's not inside the exploration expenses or typical organic exploration.

So when we think about renewal, it's organic exploration.

It's unconventional access.

It's Russia, and it's potentially bolt-on acquisitions, if they're valuable to us.

Thanks.

Very helpful.

And a quick one on Downstream, and thanks for the details on Downstream cash flow and EBITDA.

Was wondering if Tufan could speak to 2016 CapEx outlook, should we consider roughly $2 billion as a good run rate?

I'm trying to get to a free cash flow outlook here.

I'm not sure -- we actually give sort of segment CapEx numbers here.

But I think -- I will say, we said $2 billion to $3 billion range, I think, in 3Q, and that is what you should expect, somewhere in that range.

Obviously, we will continue to calibrate that CapEx as we calibrate Group CapEx in the context of the environment.

Thank you.

Right.

Back in the UK, Theepan Jothilingam of Nomura.

Thanks, Jess.

Good afternoon, gentlemen.

Two questions, please.

Could you maybe talk about how important the credit rating is to BP?

If there was a downgrade, what that would cost you both operationally and financially?

And then secondly, just on business economic losses, I know you're not providing estimates going forward.

But I was just wondering if you'd give us an update in terms of the number of claims that were processed, what's been rejected and what remains in terms of just claims and numbers there?

And maybe a profile there?

Theepan, it's Brian.

In terms of firstly credit rating.

Obviously, the whole sector has been on watch, and you saw the note last night around one of the agencies.

We're currently sitting at a rating of A with both major agencies, one on negative outlook, one on positive outlook, but now announcing a likely downgrade.

So from our perspective, right now the average cost of borrowing for BP of our debt book is just over 2%.

So I don't think a downgrade, per se, on that would have a significant impact, probably 10 or 15 basis points on the portfolio.

But also remember that we are carrying very high cash balances, which have served us well over the last four or five years.

And those balances will naturally roll down.

So we wouldn't be expecting to renew all of our debt on a roll-forward basis.

So I would say it would not have a significant impact from a financial frame perspective, if that were to occur.

And then in terms of bell claims, right now where we are is, of the 146,000 total claims that have come into the PSC in terms of the Court Supervised Settlement Fund, we have 56% have been processed and 44% are still in progress.

That is 64,000 claims.

82,000 have been processed, where 30,000 offers have been made and 52,000 cases have been rejected with no payment.

So that gives you a summary of where we are with that process.

And we are working closely with the Court Supervised Settlement Fund in terms of a number of opportunities to try and progress issues with them and the plaintiffs steering committee in terms of moving that process forward.

Thanks, Brian.

Okay.

Next question from Fred Lucas of JPMorgan.

Good afternoon, guys.

Question for Brian.

Could you clarify the oil price deck that you're now running for your ceiling test, impairment test?

I think last year, it was a strip that run up to $97 Brent in 2020.

So if you could talk us through that deck, both for oil and Henry Hub.

And a follow-up question on the dividend for Bob.

Bob, your stock's now yielding 8%.

I hear everything you say about your resolve to sustain the dividend, but I just wondered if the market continues to bet against you and price your dividend very differently to how you think they should, does that affect your resolve in any way to sustain your dividend?

And if I may, a question for, Tufan, please.

Could you give some color on the outlook for gasoline margins please?

So, Fred, if I just pick up the first one, probably the easiest one, which is around the forward strip.

We use, for our impairment tests, the five-year forward strip.

This year, we did some -- we ran calculations around the middle of December.

We then reran those, given the whole curve moved in early January.

So we ran them in the early part of January.

So based on that assumption, 2020 would have had an oil price of about $56 a barrel on the forward curve, because we use the five-year forward curve.

And that's a policy we've had in place for a long time.

And that's basically the answer where we are.

What do you use after the five years, Brian?

We then use our long-term assumptions.

So by the time you get out to 2021, it would be whatever the $80 value is on a real basis from 2015.

$80 Brent.

Correct.

And Henry Hub?

It would be -- so in terms of the five-year strip of what we've used, we'd use a figure of $3.18 is what we'd be using in 2020.

Although that's certainly on the conservative side.

But it's what the five-year strip gave us.

And long, long term, we assumption of $5 real, and whatever that would translate to out in 2021.

Great, thanks.

And, Fred, on the dividend, I think it's worth putting some of the numbers in perspective.

Last year, we paid a dividend tend of $6.6 billion.

We had $18.7 billion of CapEx, which is a lever there.

We've got cash costs of $24 billion, those are coming down.

So we've got lots of things to work on here, as well as keeping the growth going.

And then our gearing levels.

So as we look at the supply and demand going forward, this is a cycle.

We think it will tighten up here.

So it's not -- I think it's -- obviously, we're not going to do something crazy here.

But right now we think it's the right thing is to maintain what we hear and the feedback from our shareholders around the dividend resolve.

Maybe, Fred, just to supplement that.

We came into the start of last year with what I believe is a realistic price assumption of $50 a barrel for our plans this year, and the imbalance we ended up running this year was $4.5 billion.

Which is, in my view, an incredibly strong result in terms of the imbalance given we went from $100 a barrel down to $50 in pretty rapid order.

We've now seen $3.5 billion of costs come out.

We think we can take out $7 billion.

We've moved the capital range from [$24 billion] to [$26 billion] down to [$17 billion].

I think what we're trying to say is we have a huge amount of flexibility within the existing frame, and we'll monitor it quarter by quarter.

But we're not going to hold the position that hell or high water we're going hold this position.

It's in the round of all the other parts of the financial frame.

Okay.

So from that, do I hear you say that it doesn't matter therefore how the market prices your dividend in terms of how you view it?

I think what we focus on, Fred, is the things that we control internally, and we let the market set the yield.

Okay.

And I would just add, as we look at the results that we put out in the fourth quarter.

The operating cash flow of $5.8 billion, I think people seem to be looking past that, because there's a very healthy cash generation in the fourth quarter for us.

And given your confidence around that your ability to get to that cash flow balance, could you not commit to pay $0.40 this year and at least that next, as indeed some other companies have done with their dividends?

Fred, I think that's really a matter for the Board, and I think it would be rather imprudent without talking with our investors about that first.

So I think that's the sort of thing we'd talk about on a call, but it's really a matter for the Board.

Okay.

Fred, on the gasoline margins, or just refining margins probably you're after there, here's how I see it.

So last year, actually refining surplus, capacity surplus, was the lowest among if you look at last five years.

So therefore, we actually experienced slightly -- relatively better margins last year.

What you should expect in 2016, we expect 1.3 million barrels refining capacity coming into the market this year, and the demand expectation is 1.5 million barrels.

But 0.3 of that will be NGL and biofuels.

Therefore you should take 1.2 for refining.

And also going into this year, we have high gasoline and diesel stocks.

So what you will see refining capacity surplus will go up this year.

But actually given the strong demand, because 1.5 is still very strong demand, given the strong demand, you should expect that refining margins will be lower than last year but still well supported.

And between gasoline and diesel, as was the case last year, given that low crude price environment is driving gasoline demand, you should expect better gasoline cracks than diesel cracks.

But one thing I would say, this is [an environment].

So what we do, really, we have a very quality portfolio in refining.

But actually we have a strategy to expand the earnings potential of that portfolio.

And last year in 2015, we more than doubled the refining earnings at constant environment to 2014, and we have more performance improvement opportunity going forward.

So that should tell you, we are actually increasing the earnings at a constant environment in refining.

Thanks, Tufan.

Okay.

Thank you, Fred.

And we'll go to Pavel Molchanov at Raymond James in the US.

Thanks for taking the question.

You referenced the fact that Downstream would be the likely focus of your asset disposals this year.

Are you concerned at all about be becoming too much of an E&P Company if you continue to monetize your refining assets?

Yes, Pavel, that was really a backward-looking statement.

But actually during 2015, a lot of the disposals that we got away were in the Downstream.

And looking forward, there are still some parts of the Downstream inside there, but also some midstream assets in terms of pipeline and so on and terminals.

So it's a mix going forward.

In terms of the balance of the portfolio, that's something that we look at in terms of long-term strategy and where the Company is heading.

And it actually feels pretty good right now, it gets back to the whole point of integration of having a Downstream business.

Having divested $75 billion or so, which 80% of it is Upstream, we do like the portfolio.

We think it has a good balance, it's working well.

We've got -- I'll say it's a good thing we divested 13 refineries in the last decade, because what we have now are very high quality refineries and markets that are growing and emerging markets, Tufan.

Just one thing to that.

We are not actually divesting any assets we would like to keep in the portfolio.

So these are non-core assets and totally in line with our strategy, totally in line with the strategy that I outlined, not beyond that really.

So these are strategic divestments, rather than chasing the cash.

And then just quickly on the balance sheet.

20% is your medium-term target for gearing.

What is the absolute highest level that you would possibly be able to accept?

Pavel, so we don't have a target of 20%.

We just simply said we'd manage it around 20%.

It's likely to stay above 20% while the oil price stays what it is, just to be absolutely clear.

We don't look at it in terms of gearing as a target.

I could take you back during the crisis of Macondo in 2010, and our net debt rose to a figure of $35 billion, $36 billion.

We are a long way away from that today.

So we wouldn't really have gearing as the absolute metric.

It's things like the amount of operating cash we generate and of the extended debt book is one of the more key measures that we'd look at in terms of where we'd manage that.

And historically, before the accident, Pavel, we ran the Company with a financial framework with gearings between 20% and 30% for many years.

We took it down of 10% to 20% following the accident to move through the uncertainties around that, and most of those are fortunately resolved now.

So we're at 21% at a time when you can compare that I think to historically we're very comfortable with that level.

Thank you.

Okay.

Thanks, Pavel.

Now a question from Aneek Haq of Exane.

Thank you very much, guys.

I just wanted to ask -- I guess one of the questions that's been asked a couple of times, but maybe just in terms of laying out your priorities, you've mentioned the dividend being important for shareholders.

But if you were to prioritize the dividend, balance sheet, and sustaining your production in this weak environment, can you maybe just put that, Bob, in terms of how you would see it?

And then also a question for Lamar.

It's the same question I asked last quarter as well.

But just wanted an update on where you're seeing, from a regional perspective, the most success coming through from a deflationary perspective on operating and CapEx deflation.

Aneek, thanks.

Well, the dividend, the balance sheet and sustaining production, we have really focused on getting off the production treadmill.

So it's really value over volume, and the new projects coming on, some of them have much higher margins than our current portfolio.

So we'll focus on that.

We certainly are and expect to see out to the end of the decade increase in production, but that's actually not what we want to focus on.

It is that cash flow that comes from all of our assets.

So I look at the balance sheet today.

It's a strong balance sheet, and the dividend works well within it.

I know it's all in the headline, so about all of, particularly the European oil companies, can they maintain these dividends.

It's very important to our shareholders.

But we're not going to drive the Company off of a cliff.

We'll be wise about this, and the Board will be wise as we go forward.

It's just the balance sheet is strong, and as long as it stays strong, it's a priority.

Aneek, this is Lamar.

The areas that have responded quickest and most aggressively to the environment, similar to what we said last time, the lower 48 moved first and hardest I think in terms of excess capacity.

And that was matched in terms of percentages, and the percentages, I'm talking 30% to 50% in lots of different services, it was matched globally with deepwater rigs and globally with some mini seismic services.

Now what we're seeing around the world, people are responding to what looks like a lower for longer set of circumstances.

So it is adjusting pretty materially everywhere.

The Middle East was the slowest and has been the slowest to react, but it's even reacting there.

So I think this is what we've seen in past cycles, where it takes a couple years before things start really stabilizing and you can understand exactly where the deflationary curves are going.

So folks are catching up to the lower 48, I guess, is the way to think about it.

And as you go, each year more and more of the operators' portfolios are exposed to new contracts to negotiate.

And so that helps in terms of resetting the price curve.

Thank you very much, guys.

Okay.

And next Lydia Rainforth of Barclays.

Go ahead, Lydia.

Thanks, Jess.

Good afternoon.

Two questions if I could.

The first one, just going backing to that chart or map that you had on the long-term growth options.

I think clearly there is a lot of different options in a number of geographies.

And I think it's just [out past] 2020.

But what sort of growth rate do you think the portfolio is capable of supporting at that level?

And I know told Pavel in there value as volume.

If I look at what sort of level would you want BP to go up, at if at all, on that longer-term number?

And then the second point, just to come back to the cash flow from operations.

Is there anything unusual in terms of the working cap move that we should be aware of going into 2016?

Thank you.

Lydia, thanks.

Both good questions.

I'll start on the Upstream one, and then Lamar and then Brian on the working capital.

Long-term growth, when you look at the -- there are a lot of projects out there, and some of these projects are well under way.

We do see a portfolio capable of seeing 800,000 barrels a day additional production from those projects by 2020.

There may be, depending on phasing, there may be better economics to delay some of them.

We'll talk about that -- we talked about the Mad Dog project as an example earlier.

Right now looks, it like we're being -- we're able to keep the underlying decline of our assets at around a 2% level which is very, very good.

And it's because of the reliability of how we're running things, and longer term, 3% to 5% would be more likely.

But I think we're very capable of growing around those figures.

Lamar.

Yes, I'll just build on that.

I think the 800,000 barrels a day out to 2020 is solid, and it's built, as you say Bob, correctly on a base that's performing well.

Those projects for the vast majority of them are in execute.

So the bigger deferral decisions or phasing decisions that we're making affect the period post 2020.

And we have -- you ask a kind of a theoretical question, what's the portfolio capable of growing, and I don't think we'd want to put a number on it, because I do think if you -- I know we wear out Mad Dog as an example.

But it is going to happen, and it is going to be from one case to the other, super value accretive, yet it may attenuate growth in the year 2020 from what it could have been.

So we're looking at every single investment decision to make sure that we're optimizing value, hitting the market at the right time, making sure scope, scale, phasing is correct to optimize each investment.

So I think we've signaled growth through 2020 and beyond, and we've called it different words, moderate, gentle, and I think we'll stick with that.

Lydia, on the last question in terms of working capital.

We actually had, all in by the end of the year, a $300 million working capital build for the full year.

So we might expect some of that to be released through next year, but just a lot of moving parts.

And in the fourth quarter, we had $1.5 billion release coming through those numbers, the $5.8 billion that Bob talked about.

But for the year, in terms of the $19.1 billion or $20.3 billion excluding the Macondo payments, overall, it was a $300 million build this year.

Nothing particularly that we'd expect that will move things around next year, other than the oil price itself and the flat price.

And that obviously has an impact on the way up, and on the way down in terms of where we go from here.

Before you take the next question, we are aware that there's a conference call with another big oil company that starts in about two minutes.

So we recognize that some of you have to get off, and those that do, thank you for joining us.

But keep going, Jess.

Okay.

So Guy Baber of Simmons, are you still there, Guy?

I am, thanks very much for taking the question.

I wanted to start with the macro question here, and then I had a follow-up.

But obviously, you've highlighted previously balancing sources and uses of cash at $60 a barrel in 2017.

In stating the obvious, but forward curve right now is about 30% below that price.

So we understand the forward curve is far from a perfect indicator of price, but it's still a disconcerting gap.

So can you just help us reconcile that gap, perhaps by highlighting in some more detail what fundamentally gives you the greatest confidence in a return to $60 in the next couple of years?

And along with that, with your global perspective, can you update us on what you are seeing from a global demand growth perspective for oil that underpins your expectation that you highlight on slide 6 for inventory draws by the end of this year?

Maybe I'll start on the global one, and then we'll get back to the balance point, Guy.

Thank you for the question.

We do see, last year, increasing global demand for oil was up 1.8 million barrels.

Put that in perspective, and that was one of the highest growth rates in about 10 years.

Put that in perspective today, the world produces around 93 million barrels.

Right now, today, it looks like there's about 1 million barrels surplus.

We do see growth continuing in North America and China, in particular, for petroleum products.

So we're estimating demand growth at around [1.5 million].

So we see production falling in the US, there's other sources coming on, but we think that on a daily basis, it will come into balance third and fourth quarter.

Then you have a lot of stocks out there that need to be drawn, but I think the plug on all those stock tanks and ships and swimming pool filled with oil will start to drain, and at some point after that sentiment will change.

And that makes some assumptions about Chinese growth rate, US growth rates.

We're not negative on those growth rates.

At these low prices, we're seeing increases in demand in many places around the world.

So that's our global reason why we think we're going to get back into balance this year as we have so often in these cycles.

In terms of forward curve, you're quite right, the forward curve is somewhat lower than that figure.

But of course, when we set the plan at $50 last year, the forward curve would have told us $75, which I think would have been an incredibly imprudent thing to do back then a year ago.

Equally I would say if you try and go and trade that forward curve, you'll find very low liquidity a year out from now.

And I think what you'll find even if you go two or three years out, any of you that have followed those markets, there is very little liquidity out there.

So I think the market itself doesn't have any clear direction one or two years out.

And I think given geopolitics don't appear to have any sort of impact in terms of the macro picture, it will be, as Bob has described it, supply and demand will ultimately derive where the price goes from here.

We are not banking on it being $60 next year, just to be absolutely clear.

In fact, we don't have a plan set at that level for next year.

We will look and monitor through this year, just as we did last year.

But I think it would be imprudent to start to use the forward curve in either direction from where we are right now, given the liquidity that far out.

What I would say is in terms of plans for this year, we've set our first quarter plan not far away in the [$30]s from where the oil price is trading today.

So actually, year to date, we are pretty much tacking where we've set the plan for this year.

For the first quarter, we have a trajectory that sees it rising through the back end of the year.

But overall, the average oil price we're assuming for this year will be below what we assumed last year.

So I think we've still set a pretty prudent set of assumptions for this year in the transition.

And with the oil price, Guy, I think it's important to remember.

This industry has a remarkable track record for readjusting its cost structures, and of course it did go up to the $100 per barrel world there for a while, and people thought maybe that's the new normal.

But these are cycles.

And back when it was $25 a barrel, the industry made money, at $40 a barrel, at $50 a barrel.

So this industry moves fast.

That's why you see the costs coming down in the deflation.

So even if it's not $60 next year, and it's below $60, somewhere in the $50s I think we can still balance things in 2017.

Thanks very much for that very comprehensive answer.

And then on the final point that you made about the cost structure readjusting, you've highlighted that pre-FID major project breakevens are down 15% from a year ago.

Do you have a target for incremental improvement on that front if low oil prices persist consistent with your plan through the balance of this year?

Just trying to get a sense of the incremental opportunity for ongoing major project improvement, what you might be saying a year from now against the collapse in the commodity.

Guy, hello, this is Lamar.

I do think there will be more deflation to come this year, and it will affect that aggregate 15% reduction that we've talked about and we're seeing that flow through.

So we don't have necessarily a target, but each project, project by project, we are trying to optimize with our contractors, with our partners, to optimize when and how we go to the market.

And try to evaluate what is the price, what is the cost, what is the benefit of doing it now versus trying to do something a little later.

So I do think there will be more to come, but we're not targeting a particular number and then pressing the green light.

So each project is different.

Fair enough.

Thanks, Lamar.

Moving now to Biraj Borkhataria from RBC.

Hello, thanks for taking my question.

Two, if I may.

First one on the lower 48.

You've talked a lot about cost deflation, but when I look at the additional disclosure you have, the production cost per barrel was actually up Q on Q as was CapEx.

So I was wondering if you could provide any color on that, whether it was a timing issue or anything else?

And then second question is following up on the credit rating.

Do you foresee any second derivative effects from having a credit rating downgrade such as an impact on your LNG trading arm or anything like that?

Any color there would also be appreciated, thanks.

Biraj, hello, this is Lamar.

Yes, on lower 48, 4Q was up on CapEx and costs a bit.

A couple things to say there.

One, some of those rises are seasonal.

Secondly, we did have the acquisition of the piece that I talked about in 4Q.

And an interesting thing throughout this year, actually, as we look year on year over the last three years, our costs, our Company operated costs, have come down over 20%, whereas as our operated by others costs have gone up by something on the order of 5% or 6% over that period.

And they are still sigher in 2015 than they were in 2014.

So I suspect those will drop.

So I think when I've been talking about the lower 48 in recent quarterly discussions, I've been talking mostly about what we've been doing in self help in our own business which has come down, as I say, about 20%.

The aggregate for 4Q for this year was 7%.

So I think the team is on track, and we're now, just to give you a piece of context, we're now in terms of cost equivalent or below our average costs of the operated by others portfolio.

Biraj, I think you had a second part of your question was on related to credit ratings.

Would you mind just to repeat that?

Sure.

Just following on from Theepan's question.

So if there was to be a credit rating downgrade of one or two notches, would there be any impact on any other part of the business outside of increased borrowing costs such as your LNG contracts?

No, there would be no impact.

Okay.

Thank you.

Thank you.

And turning now to David Gamboa of Tudor, Pickering, Holt.

Hello, good afternoon.

Thanks for taking my questions.

I just had one, for me if you could give a bit more detail on the Upstream spend for 2016.

You've talked about $1 billion on the exploration side of things.

I was thinking about if you could probably give us a bit more detail on what you expect to spend on base expenditure and what on development?

Just trying to get a sense on what do you need to spend in order to maintain that 3% to 5% decline in the long term.

Thank you.

Thanks, David.

This is Lamar.

The exploration spend, as Bob said, will be probably just over $1 billion in 2016, similar to this year.

The remainder of the spend roughly, roughly is half projects and half base and what we call wedge or in-fill.

Within that basin and wedge, within the base and the wedge categories, we haven't given exact breakdowns.

But I think you could say about 40% of that is probably base, what we call base spend, and then the rest would be various in-fill programs and programs of -- in and around the base field.

So think of it as half projects, half base and wedge, with maybe about 40% in terms of maintaining the base underlying.

Thank you very much.

Moving next to Gordon Gray of HSBC.

Go ahead, Gordon.

Thanks, good afternoon.

Two quick ones if I could.

One was, in the past, you've been talking pretty optimistically about your Gila discovery in the Gulf of Mexico, and obviously that's now the subject of a write-down in the charges today.

Maybe talk us through a little bit what's changed there, and what you're seeing now that you didn't before.

Secondly, in the impairment charge, I see there was something of $1 billion out of impairment reversals.

I know you've run us through what your pricing assumptions are in here.

Could you run us through that comment on the change in the discount rate, how you set that, if you can, and roughly what impact that might have had on the impairments?

Thanks.

Good question, Gordon.

Lamar and then Brian?

So we have written off Gila.

We have not relinquished the leases, so let me be clear there.

But we have had well results that I think led us to that conclusion that it was prudent to do this at this time.

We're still looking at that area with our Partners to understand which and how pieces could be developed, and how we retain some of those assets.

So it's a mix of environment and well results I would say.

Okay.

Thanks.

Then in terms of discount rates, we moved our discount rate back to the pre-Macondo level that we held.

It moved up by 1% over the last five years.

We do a calculation each year to look at what the weighted average cost of capital is in terms of using it for those impairment tests, and it moved back down to where it was pre-Macondo, back down by 1%.

Is it possible to say what sort of impact that had on the impairments overall or not?

That was part of the impact in terms of the write-backs on the mostly North Sea, it was part of it.

There was also some pieces around assumptions going forward around decommissioning and so on.

But effectively, it was around the discount rate.

Great.

Thank you.

So we have our last couple of questions still.

Thank you all for your patience.

We'll go next to Lucas Herrmann of Deutsche Bank.

Jess, thanks.

Gentlemen, this afternoon, thanks for all the time.

Couple of quick ones.

First, Brian, very simply, if I look at cash flow through the final quarter, the oil price was an average of $44.

It's not dissimilar to that we're assuming anyway for the current year.

The $5.8 billion of cash included about $1.5 billion working capital benefit.

If I think about 2016 and an oil price that isn't dissimilar, what's wrong with my just flat multiplying [$4.3 billion] by 4 and adding a bit for incremental operating cost savings that you should see through the course of the current year?

That's question one.

Question two, just trying to understand what's happening with some of the pension movements on the balance sheet in the context of both the long-term liability falling and the short-term surplus rising.

Is there anything we should be aware of in terms of changes, or really the valuation whatever the plan?

No, not on pension, pension is actually incredibly well funded.

And remember you've got all the moving parts now.

You have the unfunded and the funded pensions inside there.

And of course, having closed the DAB scheme some years ago, that is actually more in a runoff position now in terms of where we are with that.

So, no, nothing you need to be aware of or concerned about other than the requirements around IS19 that makes us actually look at this on an IS19 basis, which would be different than the way we look actuarial-wise with the pension trustees.

In terms if the first part, Lucas, because you and I have talked about this on many occasion.

Never take a quarter and times its by four.

Because if you took the first quarter of last year which was all of $1.8 billion and times that by four, that would be equally wrong as taking your $4.3 billion now and timesing that by four.

I think in terms of as you try to balance up 2015 into 2016 what it looks like, and let's just assume $44 or $45 a barrel for this year, the $44 that you just mentioned.

You've got the balance of all the severance payments that were going out last year that don't hit us this year, the new severance payments coming in this year, the full-year effects of all the cash costs coming out of last year which would $4 billion, if you add back the rig cancellation costs, and the new costs going out this year.

So there's an awful lot of moving parts inside that calculation.

What I would say is I believe we'll make good progress again this year like last year, in terms of reducing the deficit in terms of the rebalancing the books.

I'm confident that we'll get things back into balance, as Bob described, provided we still have to see the upward move in the oil price.

And I'm not talking about a big upward move, relatively modest from where we are today in terms of balancing the book for next year.

How much of that $4 billion benefit this year or cost reduction this year did you actually see this year in cash?

A lot of that came through in the -- well actually, you saw it in the third quarter is when we started to see it come through.

But then of course, you also have the severance payments going out, the [Rat-Ex] cash going out in the fourth quarter.

And you'll continue to see that trend.

So it's very difficult now to model until you see all the moving parts, in terms of as people leave and severance and cash payments go with them.

And costs come out of the system.

So it will take about, from start to finish, about two and-a-half years to see the full benefits coming through, so middle 2017 you should probably see the full benefits.

Brian,, Bob, everyone, thank you.

I'll leave it there.

Thanks for your time.

Thanks you, Lucas.

Okay.

Brendan Warn of BMO.

I'll withdraw my question in consideration of time.

Thanks, guys.

Thanks, Brendan.

Next, Thomas Adolff of Credit Suisse.

Are you still there, Thomas?

Yes, I actually do have two questions.

Thanks, Brendan.

One for Bob, and one for Lamar.

So the first one I guess for Bob.

Governments are short of cash and the industry is suffering, we know that.

So I wonder what sort of discussions you're having with governments on fiscal terms, local content and whether anything has actually also changed as far as receivables positions are concerned, especially linked to Angola, Egypt, Azerbaijan, Iraq?

Second question for Lamar, and actually going to slide 22 of your presentation.

You're showing the cash flow breakeven analysis to 2017 and 2020.

And I always wondered whether that actually assumes a CapEx profile that sees your reserve life shrink.

Obviously, Lamar, we had this discussion in December of last year where you said the $17 billion to $19 billion assumes a reserve shrinkage.

And that kind of ties in pretty well with the chart you also showed at the Upstream day in December 2014.

So what I wanted to know is if you were to assume a reserve life to be preserved, what sort of a through cycle cash flow breakeven do you see?

And are you willing to let your reserve life shrink, because your reserve life looks for favorably versus your peers?

Thank you.

Thomas, thank you.

Good questions.

There are dynamics all over the world now with oil producing countries under some stress, probably the biggest examples around out there, Nigeria, Venezuela, there is stress out there.

Some of the countries you mentioned, you mentioned four of them, and it's a mix.

So for example, Egypt, it's the opposite.

It's an oil importing country, the country's actually doing better and our receivables have come down in Egypt to about the lowest level they've been in decades right now.

You've got Angola, which is clearly under some stress, devaluations of currency there, not that much sovereign debts.

We do have our investments are governed by PSAs.

They're good legal and commercial foundations for us and the other IOCs, and yes it's stressful and we've got to be really thoughtful there about our workforce, how we reduce the workforce, do we add stress in the country or not.

So we're working through that very carefully.

Azerbaijan, it's a history of a great relationship in Azerbaijan over 20 years or so.

Again, it's a PSA.

The Azeri government has provided a strong commitment to us in the past with our existing projects, stability of the PSAs, and of course we're investing a lot in the Shah Deniz project.

It's a massive project to develop the gas to take it into Europe.

That project is ahead of schedule and under budget right now.

So we're working with them.

They are a country that has sovereign credit outlook that is not bad, but they're very progressive.

They're starting to work with the IMF, and they devalued their currency.

So working through that as a partner with the government.

Iraq, I think Iraq is clearly a country stressed.

Their production is up.

I think they're going to be thoughtful and careful about the amount they want us to spend there, because it's a -- basically the capital we invest comes back to us pretty quickly with a per barrel fee and the liftings where we get paid sometimes they're ahead, sometimes they're behind.

But I think Iraq is dealing with their problems carefully.

But this is one of the things, as we sit in Europe and or North America, and think the world is all stable, there's a lot of regions around the world that do have these stresses including inside the UK and including regions inside the US.

So we're very, very mindful of it.

But I think we're managing that well.

Thomas, let me hit reserve replacement and capital and things like that.

At these levels that Brian has outlined and going forward of course, so many things depend on what the price is going to be and what deflation is going to be and how we lock all that in.

But let's just use $17 billion to $19 billion going forward at constant prices, might be a way to think about it.

We do think we can grow the segment.

As you know, and we have talked before, there is a period of time -- this is lumpy, these reserve replacement periods, and we are fortunate to have a relatively high R to P. And if you look at total proved reserves, those have been relatively weak over the last couple years, including this year, or 2015.

Proved undeveloped into proved has been relatively stronger.

And we do have FIDs and extensions to existing PSAs that we think will be coming, and it will be lumpy.

And the proved developed reserves, sorry, total proved reserves, I believe will improve in the relatively near future and we still have some work to do to pull on that R to P.

So I think it's kind of all of the above.

But we've modeled this over and over and over looking at what we think we can do, and it points to the ability to grow 2020 and beyond.

Okay.

Thank you very much.

Okay.

Thanks, Thomas.

And Chris Kuplent of Bank of America.

Are you with us still, Chris?

Yes, I am.

I'm sorry about that.

I'll keep it very short hopefully.

Quick first question, could you talk to us about how much of your $17 billion, $19 billion CapEx budget for 2016?

And then for 2017, is actually today already committed and how much room there still is for FIDs that are yet to be signed?

And maybe if you could just give us the three most I think FIDs as you see it that you are looking forward to announcing over that time frame?

And thirdly, I just wondered, I remember, just put me in my place here, please.

I remember after Q3, you had said you had sold $7.8 billion of assets.

So I'm just wondering how you have closed the $10 billion to reconcile those two numbers.

Thank you.

So maybe I'll just pick up the last point, Chris.

We had announced that $7.8 billion at the end of 3Q, we've now announce $9.8 billion, so the 410 billion is covered.

You may not have seen all the announcements around each of the individual assets, but they are pretty much complete now as close in terms of $9.8 billion versus the $10 billion.

In terms of CapEx committed, it depends on where we are.

Each year there's a number of projects in phase.

Typically coming into a year, we'd have about 80% of the capital will typically be committed.

It's a function of where deflation ends up being this year.

So I think it's too soon to say, and there's some flexibility with the overall program in terms of the ranges we set in place.

I would just note, Chris, that once we FID a project, the cost of that project is not locked in.

We're seeing some remarkable cost reductions in projects that are FID.

The drilling costs in Egypt come way down, fast drilling, pipe spending all around the world.

Steel costs are coming down even inside projects that have been FID.

Chris, Lamar.

It's not all for our own, there are many things you can do with phasing of project, phasing of spend to try to optimize the system that you've got.

And there are discretionary programs that we can choose to -- we may not want to, but we can choose to defer or delay if we need to.

The other thing is you asked about FIDs and which ones are we looking forward to.

We're not necessarily putting any time frame on these FIDs of any sort.

But we're [tangu] train 3 potentially in the next little bit, Mad Dog phase 2, other projects in Trinidad.

We've got a whole list that we're working.

And we're trying, as I said earlier, to optimize to make sure that those -- effectively we build structural cost advantage into those if we possibly can when it's time to authorize them.

That's great.

Thank you very much.

Thanks, Chris.

And lastly, Fred Lucas has been waiting with a follow-up question which I think will be our last question if Fred is still with us.

Yes, indeed.

Thanks, Jess.

It will be brief.

Brian, could you just tell us what the size of your base production is in KBOPD, and what the average cash margin of that base was in 2015.

And if I may, what your reserve replacement ratio was in 2015, 61%, if you strip out Rosneft?

Thank you.

That latter part you'll find when we file the 20F in the annual report [recants] when we finalize that.

So we don't typically give explicit at this point in the process that will come round early March when we file the 20F and annual reporting account.

And I couldn't give you the cash margin for 2015, Lamar, unless there's --

No, not the cash margin.

But, Fred, we only had, in terms of the volume, we only had I think 12 NBD of major projects come on in 2015.

So the base is pretty much everything.

That's pretty much the whole thing.

So we can therefore work out at $55 roughly where it was last year what your reference base cash margin is, and then add that 35% or more out to 2020.

Is that right?

$52, Fred.

Yes, that's correct.

Holding the price constant.

Correct.

Great.

Thanks, guys.

Okay.

Thank you very much everybody.

I'll just hand over to Bob to close the call.

Great.

Thanks, Jess.

I have this visual image out there that everyone has two microphones, one in the right ear and one in the left ear, listening to two conference calls.

So those of you who are doing that, thank you.

I will be brief.

No one asked about organizational change, and I think I'm going to comment on it.

Because there's been some speculation in the press here in London, and it's all about succession.

Actually, we had on of our senior executives, a very good executive, who has wanted to retire for some time.

Due to that, we decided to do as a team what we're asking our teams to do all around which is redistribute roles, not fill that role.

And so therefore, we've got lots to do with a small, very tight, capable management team.

So Lamar's going to fill the role of Deputy CEO, which we've had before in BP.

And take on some of the things I'm doing, some of the things that other people are doing.

Supply and trading will move to Brian.

Alternative Energies will move out and go to Dev Sanyel.

So this is just going to make us all work more focused, and make sure we in the headquarters don't generate work that doesn't need to be done by rationing our time.

It's going to be a big help to me.

So this is not a succession point.

A couple of things.

My reaction to the reaction to our earnings.

Everyone today is part of the red club everywhere on the screens.

While we've been talking, the price of oil has been down over 5%, no it's down about 3.5%.

We're down 8%, amazing to me.

And what surprises me is, people haven't seen the operating cash flow number which is the metric that we're driving the business for.

And I think in terms of expectations when numbers get down around zero, as is happening with a number of the oil companies now, percentages become wildly extreme of misses.

And I think really I think we missed expectations, primarily due to greater exploration write-offs, just a couple there, and a little bit on trading.

So I'm a little surprised at the market reaction to it, and again, I know you've got lots to do.

There's still quite a number of people, we've got as many as 500 people on still.

Thank you very much for joining us.

I think we're in for quite a year, but I'm absolutely clear we've got a plan.

We know exactly what we need to execute on, the cost reductions coming through in Downstream and Upstream are going to make us a much stronger Company, and the balance sheet is strong.

So thank you all.

Have a good earnings season, everybody.