英國石油 (BP) 2016 Q2 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 second-quarter 2016 results webcast and conference call. I am Jess Mitchell, BP's Head of Investor Relations and I am 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, Bernard Looney, and Tufan Erginbilgic, Chief Executive of our Downstream.

Before we start, I need to draw your attention to our cautionary statement. During today's presentation we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our UK and SEC filings.

Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. Thank you. And now over to Bob.

Thanks, Jess. So welcome everybody and thank you for joining us. It has been an eventful quarter. I think we can certainly say that. At the same time our sector has seen some strengthening in oil prices and at BP we have had a few significant events of our own.

In Norway we joined forces with Det norske to create Aker BP. In Baku last month we launched our new upstream strategy. And earlier this month you saw us draw a line under the remaining uncertainties around our Deepwater Horizon liabilities. So, while the environment has remained challenging we have continued to put our energies into shaping a much stronger future for the Group.

It's a future we feel very good about. We have established more efficient ways of working and move quickly to do so. Our track record of excellence, when it comes to execution, is getting stronger all the time. We are drawing on deep relationships built up over many years, many decades in some cases. That allows us to work really well with our partners to be innovative and to move fast and effectively where we see mutual advantage.

It also helps to have a long history. Our ability to learn and adapt to challenging circumstances has been proven many times over. It is part of what defines BP. And it is why we are confident in our ability to navigate a rapidly changing world, come out stronger, and carry on creating value for shareholders for decades to come. For today I will start by looking in more detail at the environment and our response. I will look at how we're not just demonstrating our resilience, but how we are making our business model more sustainable and how we have a new phase of growth within our sights.

As usual, Brian will take you through the detail of our second-quarter numbers and a reminder of our medium-term guidance. I will come back to update you on the ongoing progress and outlook for our Upstream and Downstream businesses. Then at the end, as always, there will be plenty of time for your questions.

Let's start then with how we see the macro environment. As we expected, growth in global oil demand remains strong and we have seen some slowing in global supply growth stemming from supply disruptions partially offset by the continued increase in Iranian production. In the United States, production continues to decline and we anticipate a further drop in the third quarter, but with producers slowly adding back rigs production should stabilize by year end.

While some of the factors that have recently supported oil prices may only be temporary, we see the overall fundamentals bringing the market into balance during the second half of this year. Over the last quarter we have seen oil prices strengthen in anticipation of this rebalancing with some weakening primarily due to the strong dollar in the last week or so.

The longer term fundamentals for the industry also remain robust. However, for the time being, oil inventories remain high, well above their five-year average shown in the green band and these inventories could still hold back further increases in oil prices for a while yet. So the forward curve is flattened although it still remains positive. Markets also remain cautious as they await more clarity around the impact of Brexit on oil demand.

Turning to BP, our primary objective, as you know, is one of growing value for shareholders over the long term. As we laid out to you last year, we have a set of enduring principles to guide us and we are holding firmly to those principles. First, it is always our relentless focus on safe and reliable operations. It is not only safer for people and the environment, but provides reliable cash flows. We're even more conscious of the need to improve this every day as we work to reset our business for the current circumstances.

We also continue to actively build and refine a strong, balanced portfolio which we manage for value over volume; in these tough times it is very clear how being an integrated group has enhanced our resilience. The environment today is also a strong reminder of the merits of having already reshaped our portfolio through around $75 billion of divestments since 2010 including our interest in TNK-BP and this mostly when prices were much higher.

Today, when you include our equity interest in Rosneft, we are a 3.3 million barrel per day Company. This means that we are focused on our strengths but can still operate at scale. Our Upstream has strong incumbent positions in many of the world's top basins with growth in the near term to 2020 and beyond that to 2030. That is without the need for a large acquisition as some have suggested.

In our Downstream we have a strong and focused footprint including advantaged manufacturing assets and an orientation to growth markets with high returns. So, we really like the portfolio we have, but we are also looking for opportunities to take advantage of the environment to deepen in assets we see as attractive. And we continue to look for creative repositioning opportunities. You have seen us do this in the lower 48 and in the partnership with Chevron in the Gulf of Mexico to advance the discoveries in the Paleogene.

More recently you have seen us do it with Det norske in Norway. At the same time, we have our selective ongoing divestments, which are continuously high grading the Group-wide portfolio. So, making the most of our strong portfolio is important, but we also know we must stay very focused on capital and cost discipline even as oil prices start to strengthen. It is about using our scarce capital wisely to preserve our growth objectives while making sure that all the changes we make now are sustainable for the future.

In the Upstream, you will have heard Bernard referring to this as making it stick. It is about changing the way we think about our business, adopting a manufacturing approach across all our businesses, so that we are always competing at the lower cost end of the supply curve. We have been on this path for some time and most of this will not be new with you.

What the last 18 months has proven is that these principles provide a consistent direction to our business. We continue to believe it is helping us set the right course for both the current environment and for the future. All of this works towards the most important of principles; that of growing sustainable free cash flow and shareholder distributions over the long term.

We have made a lot of progress so far in 2016. As predicted, the first half environment has been challenging. But as we look through the seasonal fluctuations and quarterly earnings, our business is proving resilient and this is even before we fully complete our cost rebasing, which will take us into 2017. At the same time, we're making strong progress towards some very important medium and long-term goals.

Significantly, following the substantial progress we have made in resolving outstanding claims arising from the Deepwater Horizon accident, our results today incorporate what we believe is a reliable estimate for all the remaining material liabilities to BP. This brings six years of managing the aftermath of the accident towards closure.

We can now draw a line under it. It has been a tough period for us, but it has reshaped how we think and how we operate and it has made us more disciplined. In short, it has made us a better Company. We will always be mindful of what we have learned but we are now able to give full attention to our future.

Our focus on safe, reliable and efficient operations is making us both safer and more competitive. We will not cover all the details today but it is showing up in our performance and it is making a difference to the bottom line. We have strong momentum in resetting our organic sources and uses of cash to balance in a $50 to $55 per barrel oil price range supporting our ongoing commitment to sustaining the dividend.

We are holding to our capital frame and now expect capital expenditure to be below our $17 billion guidance for this year and to be in a range of $15 billion to $17 billion in 2017, depending on where oil prices settle. This represents a 30% to 40% drop in capital expenditure by 2017 compared to our peak spend levels in 2013. The Group's controllable cash costs for the last four quarters are now some $5.6 billion below 2014 levels, putting us well on track to achieving our goal of a $7 billion reduction in 2017 cash costs compared to 2014.

Last month in Baku, as I mentioned, the Upstream team set out on a new vision. This showed our agenda for growth in the Upstream out to 2030. It also highlighted the 800,000 barrels per day of new net production expected by 2020, including 500,000 barrels of new capacity on stream by 2017 from new projects. Along with continued strong management of our base production, we expect this to drive a growing contribution to Group free cash flow over the medium term even in a $50 oil price world.

Similarly, in our Downstream, we are positioned to keep on delivering a strong and resilient contribution to Group free cash flow over the medium term at average historical refining margins. That comes from the real and material improvement in underlying performance that you will have seen in this business over recent quarters. We see more opportunity to grow through our access to growth markets.

We expect 2016 to remain challenging but we are starting to see a much stronger outlook for the Group. Near term our balance sheet remains robust to deal with uncertainties. Looking further out, as oil markets rebalance, we expect to see more support for oil prices but we are not relying on this. Our confidence comes from being firmly down the path of transforming our business to compete whatever the future holds.

I will come back to some of these points in more detail but for now let me hand it over to Brian to take you through the results.

Thanks, Bob. Starting with the price environment for the second quarter, Brent crude rose to an average of $46 per barrel in the second quarter compared to $34 per barrel in the first quarter and $62 per barrel a year ago. The quarter-on-quarter movement reflects the market's anticipation of global supply and demand rebalancing in the second half of the year.

Henry Hub gas prices, which have been on a downward trend since early 2014, showed some recovery towards the end of the quarter with spot prices averaging $2.10 per million British thermal units. Although prices remain weak the combination of declining production and increases in gas-fired power generation have helped to limit storage overhang and should continue to support some firming in price over the second half of the year.

The global refining marker margin averaged $13.80 per barrel in the second quarter, the lowest second quarter since 2010. It compares with $19.40 per barrel a year ago and $10.50 per barrel last quarter, reflecting some seasonal recovery. However, we expect high product stock levels to continue to keep industry refining margins under pressure. The steadily improving environment has had a positive impact on earnings and cash flow compared to the first quarter. While oil and gas prices have held up well so far in the third quarter, we still expect to see some volatility over the coming months.

Turning to the results for the Group. BP's second quarter underlying replacement cost profit was $720 million, down 45% on the same period a year ago and 35% higher than the first quarter of 2016. Compared to a year ago the result reflects lower Upstream realizations and a significantly weaker refining environment, partly offset by lower cash costs across the Group and lower expiration write-offs. Compared to the previous quarter the result reflects higher Upstream realizations, partly offset by higher levels of turnaround activity and a lower contribution from supply and trading.

Second-quarter underlying operating cash flow, which excludes pretax Gulf of Mexico oil spill payments, was $5.5 billion. This includes a working capital release of $1.3 billion in the quarter reversing out the $770 million build in the first quarter. This represents robust cash delivery given the onset of seasonal maintenance in both our main businesses. The second quarter dividend, payable in the third quarter of 2016, remains unchanged at $0.10 per ordinary share.

In Upstream, the underlying second-quarter replacement cost profit before interest and tax of $30 million compares with a profit of $500 million a year ago and a loss of $750 million in the first quarter of 2016. Compared to the second quarter of 2015, the result reflects lower liquids and gas realizations, partly offset by lower costs reflecting the benefits of simplification and efficiency activities and lower rig cancellation spend and lower exploration write-offs and DD&A.

Excluding Russia, second-quarter reported production versus a year ago was 1% lower. After adjusting for entitlement and portfolio impacts, underlying production increased by 1.5%. Compared to the first quarter, the result reflects higher liquids realizations partly offset by lower production in part due to seasonal maintenance activity and higher expiration write-offs. Looking ahead, we expect third-quarter reported production to be lower than the second quarter due to seasonal turnaround in maintenance activities and the impact of the plant outage at the Enterprise Pascagoula gas processing plant in the Gulf of Mexico.

Turning to Downstream, the second-quarter underlying replacement cost profit before interest and tax was $1.5 billion, compared with $1.9 billion a year ago and $1.8 billion in the first quarter. The fuels business reported an underlying replacement cost profit before interest and tax of $1 billion, compared with $1.4 billion in the same quarter last year and $1.3 billion in the first quarter of 2016. Compared to a year ago this reflects a significantly weaker refining environment partly offset by lower costs from simplification and efficiency programs and increased fuels marketing performance.

Refining operations in the second quarter were strong with Solomon availability at 95.7%, the highest since 2004. Compared to the first quarter, the result reflects a lower contribution from supply and trading after a strong first-quarter result, and a significantly high level of turnaround activity, partly offset by a stronger fuels marketing performance and higher refining marker margins, although these were largely offset by weaker crude oil differentials and product mix impacts specific to our refining portfolio.

The lubricants business reported an underlying replacement cost profit of $410 million in the second quarter, compared with $400 million a year ago and this brings the first-half pretax earnings to $800 million.

The petrochemicals business reported an underlying replacement cost profit of $90 million compared with $80 million a year ago. In the third quarter, we expect turnaround activity to remain high at a similar level to the second quarter and that industry refining margins will continue to be under pressure. Based on preliminary estimates, we have recognized $246 million as our estimate of BP's share of Rosneft's underlying net income for the second quarter, compared to $510 million a year ago and around $70 million in the first quarter of 2016.

Our estimates of BP's share of Rosneft's production for the second quarter is just over 1 million barrels of oil equivalent per day, an increase of 1.3% compared with a year ago and broadly flat compared with the previous quarter. Further details will be available when Rosneft report their second-quarter results.

Finally, the decision taken at Rosneft's general shareholders meeting in June, we are expecting to receive a dividend of around $335 million after tax based on current exchange rates by the end of July. The dividend represents 35% of our share of Rosneft's IFRS net income in 2015, an increase from a 25% payout ratio in prior years.

In other business and corporate we reported a pretax underlying replacement cost charge of $380 million for the second quarter, bringing the charge for the first half to $550 million. This is below guidance year to date, but we continue to expect the average underlying quarterly charge for the rest of the year to be around $300 million. The underlying effective tax rate for the second quarter is 21%, lower than a year ago mainly due to changes in the mix of earnings, partly offset by foreign exchange impacts on deferred tax balances.

Turning to the Gulf of Mexico oil spill costs and provisions. As Bob noted, following significant progress in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill, we announced on July 14, that we can now reliably estimate all of the remaining material liabilities in connection with the incident. This has resulted in a pretax charge for the second quarter of $5.2 billion.

The total cumulative pretax charge for the incident is $61.6 billion or $43.4 billion after tax. With a full $20 billion already paid out to the trust fund, BP is paying for the claims and other costs formally funded out of the trust as they arise. The pretax cash outflow on costs related to the oil spill for the second quarter was $1.6 billion.

Now this slide compares our sources and uses of cash in the first half of 2016 to the same period a year ago. Underlying operating cash flow, excluding pretax oil-spill related outgoings, was $8.5 billion for the first half, which included a working capital release of $520 million. First-half Gulf of Mexico oil-spill payments were $2.7 billion. Divestment proceeds amounted to $1.9 billion, including $300 million from the partial sale of the Group shareholding in Castrol India during the second quarter. Organic capital expenditure was $7.9 billion in the first half and $3.9 billion in the second quarter.

Now, turning to our financial frame. We continue to reset the capital and cash cost base of the Group. As already mentioned, we now expect capital expenditure to be below $17 billion this year and to be between $15 billion to $17 billion for 2017, depending on the prevailing oil price. Our plans to reduce 2017 controllable cash costs by $7 billion compared to 2014 are on track.

We're moving steadily towards rebalancing organic sources and uses of cash by 2017 at oil prices in the range of $50 to $55 per barrel. This currently defines the framework for our ongoing commitment to sustaining the dividend. Actual inflows and outflows will reflect ongoing recalibration to the environment including optimization of capital expenditure and any changes to the portfolio. Our ultimate aim over time is to sustain a position where operating cash flow from our business covers capital expenditure and the dividend.

Once rebalancing is achieved and based on our current portfolio, free cash flow is expected to start to grow at prices similar to where we are today. This is supported by the stronger cash flows expected from the next tranche of Upstream project startups and resilient performance from the Downstream.

If the price environment improves, we will look to ensure the right balance between disciplined investment for even stronger growth and growing distributions to shareholders over the longer term. We continue to expect $3 billion to $5 billion of investments in 2016 and around $2 billion to $3 billion per annum thereafter in line with our historical norms. The proceeds from these divestments provide additional flexibility and cover for our Deepwater Horizon payment commitments in the United States.

As a reminder, non-operating restructuring charges are expected to approach around $2.5 billion in total by the end of 2016, with around $1.9 billion incurred so far since the fourth quarter of 2014 and $70 million incurred in the second quarter. The impact on cash flow will reduce as we move through the second half of 2017. Lastly, looking at gearing. At the end of the second quarter net debt was $30.9 billion and gearing was 24.7% within our target gearing band.

With that I hand you back to Bob.

Thanks, Brian. Now, turning to the outlook for our businesses, let's start with a reminder of the new vision that our Upstream team laid out last month in Baku. Bernard told you about how the Upstream has been transformed over the last several years.

He and the team talked about how safety and reliability is job number one and how we continue to drive year-on-year improvement in this area, and about the balance in our portfolio and how we manage it for value over volume, as I described earlier. The team highlighted how our world-class organization and our functional model is making the Upstream more competitive in everything we do.

They also talked about our drive for efficiency and how both capital and cash costs are coming down with more still to come. Importantly, we talked about growth; growth that is imminent and which supports an aim to deliver $7 billion to $8 billion of pretax free cash flow to the Group in 2020 at a $50 oil price assumption. It does not stop there.

The Upstream team also demonstrated our capacity to continue to grow organically from 2020 to 2030 underpinned by our existing 45 billion barrels of resources and a strong focus on capital discipline and returns. So, we covered a lot of ground in Baku and you can find the materials on our website. I am going to only briefly touch on a few highlights today.

So, looking first at how we allocate our capital. In the Upstream, we currently estimate 2017 capital expenditure to be around $13 billion to $14 billion which is 35% lower than we forecasted back in 2014. We have a strict capital discipline process that is informing the choices we make and ensuring they are the right ones for resilience and growth. It starts with established hurdle rates and that means analyzing every pre-FID project, optimizing it and ensuring that its economics are robust.

We're seeing that in action today with the recycling of projects like Browse and Pike. We have also pared back exploration and are focusing our efforts on adding barrels with a short-cycle time. In the Lower 48, Iraq, and Alaska where we have vast resources, we have reduced our spend while retaining the flexibility to scale up activity should prices strengthen.

We are also adding new projects and activity. In Indonesia, for example, the recent sanctioning of the Tangguh Expansion Project will add a third LNG process train and 3.8 million tons per annum of production capacity. It is one of the lowest cost of supply additions in the world. And, in Egypt, the recently sanction development of Atoll will help provide much needed additional gas to the domestic market.

As we continue to lower our capital intensity and maintain discipline, we do not see a need for material growth in capital spend to meet our future growth plans. We are also very focused on performance improvement. We expect Upstream cash costs to reduce by $4 billion by 2017 compared to 2014 spend. This is a 30% drop and represents a major contribution to the Group's $7 billion target.

We have reset the organizational footprint making it one-third smaller than three years ago. We have focused on engaging our people in continuous improvement and eliminating waste and duplication. And we have hundreds of initiatives underway across the segment; these include increasing workforce productivity and interventions to standardize, simplify and optimize what we do every day.

These initiatives are being embedded into the organization to ensure we make efficiencies which will endure into the future. And we are also addressing our third-party spend as it represents a significant portion of our capital spending and around 50% of our cash costs. We have seen a big reduction in costs by working closely with our suppliers and through competitive bidding.

At the same time, we are focused on the efficiency of our projects and operations and we are seeing productivity increasing as we try new things and bring in new technology. Call it innovation. For example, by enhancing oil recovery and increasing the amount of drilling we do, we have reduced plan deferrals, increased plant reliability and established a four-year track record of base decline of less than 3%. For planning purposes, we expect our future base decline to be in the 3% to 5% range.

Our production costs are now top quartile and we estimate that 75% of these reductions can stick, no matter the oil price; the rest being market related. So, we have achieved a lot but we are deeply determined to do more. We have many more ideas to drive this level of performance further.

Now, turning to growth. As I mentioned earlier, we continue to expect 800,000 barrels of oil equivalent per day of new production by 2020. Of this, we expect 500,000 barrels of new capacity to be in place already by the end of 2017, and this is, on average, 70% complete and ahead of schedule and budget.

To date in 2016, we have started up four projects including, most recently, a major water injection project on our Thunder Horse platform in the Gulf of Mexico, which will increase reservoir pressure and enhance production. Around 90% of the 800,000 barrels relates to projects that have passed through the final investment decision, or FID, and which are well under construction.

For example, we have installed the remaining modules on Clair Ridge in the North Sea and the Glen Lyon FPSO is now on station in the Schiehallion field, west of Shetland. The remaining barrels are expected to move to the construction phase by 2017 or early 2018, and we have a long list of projects we could sanction in the next 18 months or so. That list includes the Mad Dog Phase 2 extension, further development of the Oman Khazzan field, Angelin in Trinidad, some India gas projects, the Trinidad Compression project, and Platina in Angola block 18.

We are continuing to optimize these projects, testing their costs and margins carefully against historical and competitive benchmarks. We will only proceed when we are ready and the projects are the best they can be. We can do that because we do not have to sanction all of them to deliver our growth objectives.

Last but not least, our pipeline of new projects is high quality. These projects deliver on average around 35% better margins than our base assets today at a flat oil-price environment. They also come with development costs around 20% lower on average than the existing portfolio.

Looking beyond 2020, we firmly believe we have the capacity to sustain long-term growth and this is much more than just an aspiration. Excluding Rosneft, we have 45 billion barrels of resources concentrated in 12 key regions. This is the equivalent of 50 years of production at today's level. Importantly, these resources are in fields we know well, with 70% of the non-proved resources in existing producing field areas and only 20% of the equivalent oil in place is being produced today.

We have reviewed each of these fields in detail, area by area, well by well, and can see material opportunity for growth in the next decade. We expect to deliver growth in four ways. First, from growth in and around our existing fields through continued infield drilling, the next phases of existing major projects and from new projects that progress to FID. This activity is very competitive versus our existing base.

Second, from the extension of licenses and contracts to fully exploit our existing positions. Third, from where we see an opportunity for greater value by either divesting or deepening the portfolio. For example, you have recently seen us deepen in the Culzean development in the North Sea. In Azerbaijan, we signed a memorandum of understanding to jointly explore block D230 with SOCAR in the North Absheron Basin. And we have also recently agreed to create a joint venture with Rosneft to explore in the vast onshore West Siberia and Yenisey-Khatanga basins.

Lastly, we will continue to explore in a more focused fashion, mindful that we are not relying on major exploration success for growth. A good example of this is our recently announced gas discovery in the Baltim South development lease in the East Nile Delta, which is building upon our incumbent position in this region.

Turning to our future investment strategy, this will continue to be balanced, targeting a mix of deepwater, conventional oil and gas and unconventionals. It will include a geographical, geopolitical and fiscal exposure aimed at diversifying risk and improving our resilience to a broad range of outcomes.

This slide takes you forward 15 years. It shows you just one scenario based on realistic assumptions. It has a base decline in the 3% to 5% range, a capital frame that does not have to materially expand, and no need to relax our investment hurdles. There is sufficient definition to our plans to give us confidence in our ability to deliver real growth and to focus selectively on the highest value options.

So, we now have a much clearer view of the future of the Upstream. We are driving performance and making it stick. We are reestablishing a business model that is sustainable in a $50 world and we are focused on growth both for this decade and the next.

Now in the Downstream, the execution of the strategy Tufan and the Downstream leadership team laid out in early 2015 is delivering results. We are focusing on improving the performance of an already strong portfolio of manufacturing assets to build a top-quartile refining business and increase the earnings potential of petrochemicals. We are continuing to grow our fuels marketing and lubricants businesses and are actively investing in high-return opportunities.

And, our simplification and efficiency programs are well on track to deliver $2.5 billion of cost efficiencies versus 2014. We aim to be the leading Downstream business as measured by a net income per barrel and, as you can see from the chart, we are competitive in our peer group. We will also deliver competitive returns; by this we mean delivering attractive pretax returns and doing this sustainably. From the chart you will see we have also made progress on this.

I would now like to spend a few minutes taking you through the key elements of this progress in the Downstream. This slide outlines the performance improvement we have seen in the Downstream over the last 18 months and how, as a result, the business is more resilient to refining margins. On the left you see pretax earnings; they have increased by $2.4 billion or more than 50% compared with 2014 in a similar refining margin environment.

Looking at this another way, the chart on the right shows the level of refining margin required to generate a Downstream pretax return of 15%. From the chart, we have reduced the refining margin required to deliver this level of returns by about half and we can now deliver attractive pretax returns, even at industry refining margin levels below the five-year historic range. Looking forward, we expect to sustain this underlying performance improvement and we have opportunities to improve it further.

Let me now show you where the performance improvement has come from starting with operating reliability and commercial performance in refining. You can see on the slide we are improving in our refining pretax earnings. We have more than doubled compared with 2014 at constant refining margins.

We have plans in place to continue to improve performance even further through site-by-site programs, which are focusing on operating reliability, efficiency improvements, advantaged feedstock, and optimizing our commercial terms. We are already seeing the benefits with refining utilization increasing from 88% in 2014 to 92% in the last 12 months, and our advantaged heavy crude processing increasing by 25% over the same period.

Looking to the future, we expect the earnings potential of our refining business to expand further as a result of these programs. Our fuels marketing and lubricants businesses are providing a material and reliable earnings stream with strong returns. These differentiated businesses together generate around 50% of the Downstream pretax earnings, or well in excess of $3 billion per year and they have a well-established track record of growth. They generate reliable profit and cash flows and have good exposure to growth markets, where we intend to expand further.

The retail business is the most material element of our fuels marketing operations. In our growth markets, we have seen first-half retail volumes increase by 5% year on year. We also continue to reinforce our position through strong convenience retail partnerships. Our lubricants business is underpinned by our own customer offers, strong brands, technology and customer relationships, which have consistently led to year-on-year pretax earnings growth.

Finally on the Downstream, our simplification and efficiency programs are on track to deliver around $2.5 billion of cost efficiencies compared with 2014. We estimate 2016 downstream cash costs to be more than 20% lower than 2014.

We continue to right-size the organization including all of our businesses and our head office to make it simpler and leaner. We expect more than 5,000 employee and agency contractor roles to be reduced by the end of next year compared to the end of 2014 with approximately 4,000 of those already occurring. We will drive efficiency in refining and petrochemicals through site-by-site improvement programs. At the same time, we will ensure that we do not compromise safety, quality, and reliability.

So, in the Downstream we have a business that is a very material part of BP's overall value proposition to shareholders. It is delivering strong competitive performance today and generating attractive returns. It has been reshaped to be much more resilient to a range of market conditions and we have further opportunities to grow the business in the future.

Now, that is a lot from me, but just to sum up. We're making steady headway in what remains a tough environment. We are sticking to our financial frame and this is putting us on track to rebalance organic sources and uses of cash by 2017 at $50 to $55 per barrel. This will allow us to sustain our dividend, while still maintaining the flexibility to grow.

We are also clear on the direction of our business. We believe it is a direction that can withstand the test of a $50 world and we can still grow sustainable free cash flow and distributions to shareholders over the long term. It is built on our long-held principles of portfolio strength and value over volume, but comes with much greater commitment to discipline in how we execute, how we allocate our capital and how we drive continuous improvement.

It is all about resilience, sustainability and growth. You can see this at work in the Upstream where the business is transforming itself to grow value. That growth is imminent and clearly visible out to 2020 and also strong to the end of the next decade. You can see it at work in the Downstream where our effort over the last few years has created a high-performing business with strong resilience to refining margin volatility and ongoing opportunities for growth.

We are feeling very good about BP and our future despite the challenges. We have adapted to some big changes and we have drawn a line under our Deepwater Horizon liabilities and we have a strong and clear plan to move forward.

But we know it is not only about having a plan but also about having a track record and we intend to continue to build on that and for you to see it show up in our underlying performance quarter by quarter, step by step.

Thank you for listening and we will open it up now for questions.

(Operator Instructions)

Hello everybody we will start the Q&A shortly, but before we do that I would just like to pass you to Bob to say a few words.

Yes, well thank you, Jess. I just want to let you all know on the call that Brian received a message from his family and he is not now on the call. So along with Jess, Tufan, Bernard and I, we'll take your questions. So should we turn it over?

Yes; thanks, Bob. And we'll take the first question from Jon Rigby at UBS.

I just want to explore the direction or travel, the speed at which you are moving down to that $50 to $55 per barrel cash neutrality level, if I can. The first is if I understand it, and maybe you can go through this in a bit more detail, I think you said that you got to $5.6 billion of cost benefits so far. So am I right in thinking you have about $1.4 billion to go? And I guess $1 billion asset CapEx. So, if I were to use your cash --I'm sorry your oil price sensitivity -- I guess we are looking at something of the order of $10 or so incremental improvement over the next 18 months or so. Is my arithmetic correct or is there additional stuff that is going on that I should be expected to be able to see?

And to the point on CapEx I wonder whether you could just talk a little bit around what you are seeing in the market. It was evident in the big cap oil-field service companies that were reporting last week, they started to indicate that they were looking to reverse some of the price concessions that they have made over the last 12 months or so, which is something of a concern because my expectation was there was still sort of cost deflation and cost benefits to extract. So, I wonder whether you could just talk about that relationship and how you see costs evolving. Thanks.

Yes. Jon, thank you. First off your numbers there are just about right. We intend to drive cash cost reductions by about $7 billion is our target in 2017 versus 2014. We have got $5.6 billion done; we have got another $1.4 billion that we can identify. We have said this year our CapEx target was $17 billion to $19 billion, it is going to come in under $17 billion and we are looking at next year anywhere from $15 billion to $17 billion on a CapEx.

We continue to see, and Bernard can comment on this, we continue to see reductions in contractor costs. So, while I have read those comments, that is not what we see going on today, and we think it is going to continue if these oil prices remain and we are going to rebase the business. We are confident we can rebase the business between $50 and $55 next year. Maybe, Bernard, you want to put a little color on what we're seeing and the cost reductions coming through in the Upstream.

Thanks, Bob, and thanks, Jon. We read those reports too. And I think as you have been speaking with us over the last while and listened in Baku we have been focusing very, very hard on the sustainable elements of our cost reduction program right across cost and capital, and we have been doing that for the reason that you just outlined.

We estimate that somewhere around three-quarters of the cost savings that we have had to date across the business are sustainable. We do think that about 25% are subject to market rates and we always said that we would expect to see some pressure on that 25% if and when prices recover. I think it is very early to be having that conversation about price recovery, quite frankly; I think we have got a lot more to do.

But, the real piece for us is that, on the sustainable element, which is the vast majority of our savings, not alone are we going to make those sustainable savings stick. But we actually believe and we talked with you in Baku about this, we actually believe there is a lot more to do. We are looking at how do we get cost back to the levels when they were last at this price range in 2005. That is opening up a lot of ideas. We talked about digitization and data. I think we've only begun to scratch the surface there.

So, there is a lot more that we can do in this space. Ideas are coming through each and every day, so I am not at all concerned with some of the commentary in that regard. I would say that I think the industry as a whole needs to continue to work together to lower the total cost of doing business in our industry, and rates is an element of that, an important element.

But a far more important element is looking at the entirety of the pie and seeing what we can do to drive the cost structure down for what I think one of those service company CEOs described as a medium for longer price environment; so a lot more to go, a lot more to do. We are very focused on the 75% and making it stick. And there will undoubtedly be some pressure but we will see how that emerges over the coming months and years.

And, Jon, as we talk about $7 billion, there is a big group of that in the Upstream and there is a big block of that in the Downstream as well. Maybe just a word from Tufan on some of the restructuring costs and how we see those as also sustainable and less subject to fluctuations with oil price.

Thanks, Bob. I think, Jon, what I would say is in addition to cost, obviously, we said at $2.5 billion we are on track but you need to think about some other underlying performance improvement in Downstream. So, in your equation you only look at cost and CapEx, actually it is more than that. That is the point I would like to make.

Jon, is that okay for you?

Yes, that works. Thank you.

That is great. Thanks, Jon. Just a reminder that of course we have restructuring charges at the moment and the cash impact of that should reduce as we go through 2017 as well. Moving on now we will take a question from Anish Kapadia at TPH. Go ahead, Anish.

Hi, good afternoon; a couple of questions, please. Firstly, just had some clarifications on slide 18 in terms of the cash balances and what is in that. So first of all I just wanted to know does it include investments into JVs? And, if not, what is the expected run rate for investments into JVs? Then, secondly on the 2017 and 2020 cash balances, what scrip take up does that assume? And finally on that I just wanted to clarify that the oil prices are real in 2017 and 2020.

The second question relates to some of the recent refining weakness that you are seeing. If I assume that refining margins remain around current levels, it seems like it is around $5 per barrel lower than your assumptions -- your planning assumptions for 2017 -- and you are looking at your sensitivities -- it seems like that is around a $10 per barrel lower -- sorry, higher breakeven for 2017.

So, just wondering if, firstly, are those calculations broadly correct, and in that kind of scenario of a very weak Downstream environment how would your strategy potentially change an investment outlook? Thank you.

Great, okay. Anish, thank you very much. In terms of investments into JVs, such as -- and the big ones that we would have would be Rosneft and Aker BP -- they are all self funding so we don't see money going into JVs like that other than projects that are the more traditional projects. So I think that is probably what you are looking at. The scrip uptake has averaged 19% since we started it. It has come up a bit. In the first quarter it was a higher number, 37%; I think it could be around that range this quarter.

We would expect that. We realize it dilutes over time. We plan to balance our operating cash flows to cover capital expenditure and the full dividend over time. A lot of our shareholders like the scrip, but I know it is not popular with everybody.

And then in terms of 2017 and beyond, our projections using the oil price, we are projecting on a nominal pricing basis. And then -- so let me turn it over to Tufan on the refining margin question.

On the refining margin, effectively against today's numbers, if you look at, first off, refining margins, actually our refining indicator margin is more like $12. And today it is more like $10, you are looking at. So, actually versus today, it is not as big difference as you are thinking because we are already experiencing, first off, those refining margins -- lower refining margins. One other thing I would say, we continue to increase the Downstream earnings capability.

It is in the charts that actually we more than doubled our refining profitability in a similar environment in 18 months. And if you look at Downstream underlying improvement in similar refining margin environment like last 12 months versus 2014, is $2.4 billion higher than actually 2014. And we believe we have more opportunities to continue to improve our performance plus the growth opportunities we have.

Anish, I will just add a footnote to that. I have read some reports; I think refining margins seem to be used as a proxy for a Downstream business. And our businesses in fuel retailing and lubricants was really strong in the first half of the year and the second quarter. So I think refining margins are just part of the picture on the Downstream.

Okay. Thanks, Anish. We will take a question now from the US, Blake Fernandez of Howard Weil. Are you there, Blake?

Yes, thanks, Jess. Good afternoon, folks. I guess continuing on the Downstream theme, Tufan, if you don't mind, it seems like the crude glut is beginning to shift into a bit of a product glut. And given your global footprint I was just curious if you could talk to maybe some of the regional aspects that you are seeing. In the US, in particular, we're seeing some increased gasoline imports. I did not know if you have a sense that the competitive advantage that the US has been enjoying is beginning to erode or if there's anything more macro oriented you could share?

Okay. Well, there is a lot in that question so I will try to be brief. But, I think US, so I will come back to refining margins but you talk about US advantage. Frankly, US advantage started to erode some time ago. It is not something new. When the US actually allowed the exports to take place, WTI Brent started to actually narrow and it is today, it is [$1 to $2] around that.

That plus the WTI production, because of the crude price, shale oil production going down, frankly, that differential almost got lost. So, US advantage is no longer on the crack advantage as US had to have, but more the energy costs. But energy costs, if you compare rest of the world refining versus US, even Europe, actually that advantage is offset by lower non-energy costs in Europe versus US. So overall, I would say once the exports were allowed that advantage, US advantage -- to a great extent, not fully, but to a great extent -- disappeared, but not fully because WTI probably will operate on an export parity basis.

Coming to sort of refining environment, overall, you are absolutely right, given the stock levels. Frankly, stock levels started to build second half last year so it is not new, but didn't affect the margins last year as much as it is affecting right now because 2014 finished with a very low stock levels globally. So, from that, if you look at OECD stocks, they have been building up almost second half 2015 every month, but didn't actually depress the margins as much as they are doing right now.

What was happening this year, first off anyway, and I can briefly talk about second half, but what was happening this year, that big stock there, especially, but gasoline, gasoline is the -- historically the highest OECD stocks we see. Distillate actually it is close to 2009 levels, which was historically the high level financial crisis.

So that stock level did not go down because, although demand actually is pretty robust, did not go down because utilization went up, not in Europe, not in US necessarily, but Chinese teapot refineries almost doubled their utilization this year versus last year. So as a result, stock level did not actually go up but did not go down significantly and that continues to put pressure on the refining margins.

Thank you for the comprehensive answer. If I could just follow up -- and I know Brian is not available so if this is too granular on the PSC side I can come back to you guys, but I'm just curious -- are you maintaining your flattish production for the year on an underlying basis excluding the PSCs? And is that the driver of the $30 increase in the rest of world price realizations quarter to quarter?

Well, as you will know in the PSCs, I thought you were asking about the plaintiffs' attorneys there for a second so -- the Plaintiff Steering Committee, so I am relieved. As you know, the way these PSCs, the production sharing contracts work, when the prices are lower there is more cost of oil coming to you and that is what we saw in the first quarter, which is why you have seen this -- primarily a big reduction in our production this quarter because the price is higher. I think it kind of depends on the price of oil having moved around a little bit.

Now, I think our underlying production guidance broadly flat versus 2015. I think in the third quarter we will see a reported production lower than 2Q but that is mainly due to the seasonal turnarounds and the maintenance, and as Brian said earlier, the impact of the outage at the Enterprise Pascagoula gas processing plant. But, as you know and rightly say, these PSCs move production levels around and we usually try to report them out separately so you can see.

Okay. Fair enough. Thank you, Bob.

Okay. Thanks, Blake.

Okay. We will take the next question from Oswald Clint at Bernstein.

Good afternoon. Yes, maybe two specific questions. I was interested in India. Feels like the price environment is right or the pricing that you wanted is there. The arbitration I think you have with the government might be lifted soon. I mean is that the case and could we see the lines getting back to work there in that country sooner or at least in the short term? That is my first question.

Then, maybe secondly more specifically on -- I know it's been two months or so since Thunder Horse water injection has started up. I'm curious if that is operating well or at least the performance from that asset post the start up of that project? Thank you.

Oswald, thanks. Yes, the change in the gas price which was done really in the first part of the year is quite -- quite a big step for India to move back in place market pricing. There is a formula there, but it generally makes these gas developments very, very attractive. India needs every molecule of gas it can get versus importing the LNG. So that is good.

We do have some arbitrations which are in place but I am optimistic that we are going to move through these things. And these India projects now are moving right up the list in terms of competing for the capital inside the group. In terms of timing and specifics, we will just wait but our relationship with Reliance, by the way, remains excellent through all of this. Let me turn over the Thunder Horse which is now pumping water into the ground.

Very much, Bob, as you said those India projects will end up being some of the best projects I think that we have. Looking forward to that. On Thunder Horse, Oswald, we have, we have just brought on a second well actually at Thunder Horse on the water injection side. It was ahead of schedule, we're getting the water into the ground and the injectivity that we wanted. So far so good. We are very pleased with the performance of that project thus far. So. Thanks.

Okay thank you, Oswald. We will take the next question from Jason Gammel at Jefferies.

Thank you very much Jess and hello everyone. I just want to ask two questions on the Upstream please. The first, and I am assuming this is Upstream actually, the first I wanted to talk about is the $15 billion to $17 billion CapEx range. Can you talk about what activity would be deferred if you went from the $17 billion to the $15 billion?

And then just on major capital projects obviously a lot of progress has been made very recently. And I just wondered if maybe Bernard could comment on whether there was still a possibility of further sanctions the rest of this year and thinking in Mad Dog 2 and perhaps Baltim in Egypt?

Thanks very much, Jason. I think on the capital side of things, I think Bob and Brian already said that capital for this year at a Group level it will probably be below $17 billion. I think we're continuing to see really, really good progress on that. Where would we flex the capital if we needed to? The flex as ever it tends to be in the onshore locations and I would look to places like the lower 48 where as you know I think we have created a really material flexible high quality option. So that is one that we can flex back and forth, Jason, quite a bit. We would also look at Alaska, we continue to look at Iraq. They're the sort of areas where the flexibility in the Upstream remains. And we continue to drive the productivity of the capital investment that we have.

And it's back to Jon's earlier question, we just continue to see ideas and solutions coming from the organization, working with our suppliers where we can do things simpler and more cost effectively. And, the list, quite frankly gets longer each and every day. We remain quite optimistic, very optimistic I would say in continuing to drive the capital productivity.

The major projects, I think in terms of sanctions for the rest of the year, we certainly see a number of options ahead of us. As you know we have sanctioned a total phase 1 in Egypt a fast-track development that we discovered in 2015. We just sanctioned the third train of LNG at Tangguh, which we are very excited about. The team has done a fantastic job there getting costs on a normalized level back to 2004 back to what we build trains one and two.

Mad Dog phase 2 always subject to partner approval but as we say, it is not just enough for us to hit the hurdle rates we want to make the projects be the best that we can be, or the best that they can be. And we're continuing to work Mad Dog, but I think you can see that one emerge towards the end of the year. We have of course, the next train at Khazzan where we will hopefully do 1.5 BCF a day for the price of what we originally thought a BCF a day would be done for. Bob's mentioned the India gas projects, which will move up the chain.

We have got onshore compression in Trinidad that may come into the picture. We have Angelin in Trinidad, we have Snadd in Norway, so a number of projects that are possible. All I would say that the expectation remains the same and that is twofold. Number one it has to hit, each has to hit the hurdle rates which is driven by value over volume. Mid-teens for Greenfield and greater than 20% for Brownfield and Infill.

And the project has got to be the best that it can be. And that is why we have continued to push Mad Dog phase 2 as an example. So that hopefully gives you a sense of what is out there. Does that help?

That is very helpful, Bernard. With a very quick follow-up, you did mention the discretionary spending in Iraq as being something you could ramp up and down fairly quickly. Given the fairly large movement in rest of world liquids production that we had from 1Q to 2Q, does that reflect lower activity levels or is this really all a pricing issue?

The reality Jason is that gross production in Iraq remains at about 1.4 million barrels a day. But as Bob says the way we calculate actual volume in Iraq is based on the volume that we lift in a quarter and we lifted 10 million barrels in the second quarter. But, it is also based on the change in value of the under lift position that we have.

When you have price changes between $34 and $46 between quarters it gives you wild swings in the actual reported production. So, we have reduced activity levels somewhat in Iraq but the team is doing a fantastic job of keeping production at a gross level where it needs to be. And hopefully you can see that the reported production swings are more an accounting artifact than they are a physical artifact on the ground.

Thanks very much. I appreciate the comments.

We will turn now to Asit Sen in the US from CLSA.

Thank you Jess, good afternoon. I have two unrelated questions. Bob, in your opening statement you alluded to rising Iranian production so just wondering if you could share your view on Iranian production trajectory this year and into next year and BPs growth aspiration in the country? That is number one. And number two, in the Upstream CapEx number of $15 billion to $17 billion, what would you say is the maintenance CapEx looking out?

Right, Asit. I think on Iran, it is better to just no comment on the future of the Company. We have a long history there from before, but the terms and what is happening there and how we allocate our capital, all of those things are not clear.

In terms of rising Iranian production, we have seen Spencer Dale, our economist, had projected Iranian increases of production around 0.5 million barrels a day. I think it came faster than we expected, but I am not sure we see it continuing at that sort of rise. So you will know from market data what is out there and what they are producing and can't really project much more on that.

On your question around maintenance CapEx. We project this year, the latest estimate in the second quarter, but for the year about $5.8 billion would be our maintenance CapEx across all of the businesses, Upstream and Downstream both. That number in 2015, by the way, was around $8 billion.

Okay, thank you, Asit. Back to the UK and we will take a question from Henry Tarr at Goldman Sachs.

Hi thanks, Jess. Just three quick questions. One was, when you're doing the FIDs and having sort of conversations with host governments, are you seeing flexibility around fiscal terms or other conditions? Are some of the governments being a little more open given the commodity price environment to attract investment?

The second in the quarter we saw falling production costs in the lower 48 and I do not know whether a comment around what is driving that would be helpful. Then, lastly I know there are obviously a wide range of inputs, et cetera, but any estimate for the phasing of the Macondo payments over the coming quarters and looking out to 2017 would be helpful. Thank you.

Right. Well first, Henry, a quick comment on the FIDs and I will just mention the one country and then Bernard may have other comments in other places we are working with it. Because we have not FIDed this yet, but I think India is a great example. Where a government has just look at the very fundamentals of lack of attractiveness into the sector and exploration and production and have made a big fundamental change. Bernard, there are a couple of other ones.

I think, Bob, India and I think the other great example where there is real alignment between ourselves and a host government would be in Egypt. I think the Egyptian government continues to be very flexible at how to make its country's resources economic. And remember this is a country that is importing LNG for the first time really in its history and at some stages at very high prices. So, the government there is working very well with us on ensuring that we have prices that obviously compete with what their alternative is. Which is to import, but also to help us get projects which are economic at the hurdle rates that we've talked about on the calls.

So the 50 plus years that we have in Egypt, the relationships that we built in country, the track record of performance and delivery that we have had in the country I think have given us a place where we are able to work very well with that government. And they have proved to be a very, very effective partner in moving that country's resources forward for the good of the nation and for the good of us as a Company.

The President and the Prime Minister and the Energy Minister all actually contact us and say what can we do to cut any red tape to move these forward. On your other question and I think it broadly around the world, I think it varies. Some governments are going through their own difficulties and some of them are interested in changing terms, wanting investments, some of them are not. I think it is the whole spectrum but overall these are two great important examples for us.

Now, on your payments and of course this is really complicated how we have moved through the Gulf of Mexico settlements. There is really four elements of payments going forward, let's see if I can describe them simply. The July 2015 settlement, that was the big one, the $18.8 billion settlement that was announced last year and signed into law in April of this year. The main payments in that are the second half of this year relate to the state and local governments.

The overall payment profile, the overall one is similar to that, that was disclosed at the time it goes out, a long time in time but the main payments in second half of 2016 are the state and local governments. Then there is the Department of Justice and the SEC settlement done some time ago. The final payments for that are due in 2017 for the DOJ and there is a piece in 2018 for the SEC.

There is a third element here, and this is what has led to really our ability now to make the estimates because on the 14th of July a judge in New Orleans really decided that a very large number of claims had no merit and moved out. But the claims from the individuals and businesses that opted out of the settlement with the business economic loss claims and the PSC settlement, those are mostly to be paid by the end of this year. They are part of the $5.2 billion provision.

And then something we call the BEL payments, business economic loss payments. We agreed in the first quarter with the PSC, different from the earlier PSC, the plaintiffs' steering committee and the facility to simplify and accelerate claims and to bring forward the completion and reduce the administrative costs of that facility. And the only guidance we could really get you now is we expect to complete all claims by 2019. That is also part of these provisions that we put out.

We have had 148,000 claims have been submitted, 114,000 have been finalized by that settlement procedure. Of that -- well probably 44,000 claims were issued. About 70,000 claims were closed with no payments, without merit. And we still have about 34,000 claims to move through this tail part of that. So, I have no idea whether that is going to be helpful because that is a very complicated set of layers there.

Henry, I think I will perhaps be able to help you with some of the detail at least around the settlement payments which we know of and that are upcoming. And then how the balance might play out. So perhaps we could catch up with you after the call on that.

Henry also asked, you also asked, I see my note here about the lower 48 costs. The efficiency and cost reduction initiatives have driven us now to have a 33% decrease in our production cost per barrel from 2012. That translates into a reduction of around $300 million per year annualized in cost savings. So, our unit production costs decreased to about $7.34 per barrel, 6% lower than the first quarter this year. So, this is all heading in the right direction.

Thank you.

Okay. We will take the next question from Brendan Warn of BMO.

Yes. Thanks for taking my question. I will just keep it to one. This question relates to the lower 48 onshore business and tying both back into the chart on page 25. I just, in terms of assumptions out to 2020, how much of that growth, lower 48 growth do you expect from the onshore business? And then if I can relate that to the slide on -- slide 18 and the chart on the left-hand side just in terms of the cash balance across the couple of different oil prices.

And referring also to that chart, can I just confirm too, the obviously you refer to your BP planning assumptions but just which refining margins -- is there a flex in refining margin across the range from $45 per barrel to $70 per barrel? Or is that at one static refining margin for the cash balance? Clarify those two points, please.

Okay, Brendan. Bernard on the lower 48 and I will make a comment about the refining margins and then Tufan if you want to add anything.

Great. Thanks, Bob. Brendan, not a huge amount. We see a little bit of volume growth very modest through to 2020. Thereafter we have real optionality. All I would do is say that it is not a huge contributor in a cash sense. But what you have seen in the reporting that we do is that we are actually driving production up while we are driving capital down, which of course is a very good thing.

We have improved, the team has done a fabulous job of improving the capital productivity in the lower 48 by over 52% here in the last couple of years. So, specifically there is a little bit of modest growth within that but not material, I would say.

On the refining margin we have assumed a $14 refining margin and that is static in those numbers. On that slide.

Just to add to that, I think $14 when we're sitting right now at $12, may look low. But actually if you look at the last 10 years, except the financial crisis in 2009 and 2010 and this year, the refining margins have either been around $14 or about that. Just to give you a perspective on that.

Okay. Thank you gentlemen.

Thanks, Brendan.

Next we will go to with Lydia Rainforth of Barclays.

Good afternoon. I am going to ask three questions if that is okay. The first one was coming back to the Deepwater Horizon liabilities and the comment, Bob, you made at the start about sort of drawing a line under and now giving full attention to the future. Can I ask what does that mean in practice for BP and is there anything that the latest provision allows BP to do that it could not do before?

The second one was for Tufan on the Downstream side and your take on the fuels marketing side and the impressive slide that you've shown in terms of growth, adds profitability in the fuels marketing side of that, 55% in the last 2 years, 2.5 years. Is that actually repeatable in the fuels marketing side over the next 3 years to 4 years? Then, the final one if I could just on the Upstream, and Bernard do you have an estimate for a base decline rate for 2016 so far and where that is running compared to expectations? Thank you.

Great Lydia, three varied questions there. I think -- good questions. So what does it practically mean to be able to identify a total pretax charge of $61.6 billion now, post tax $43.4 billion? What it does is, one, it allows us to plan. Certainly it reduces uncertainty now. So as we think about capital and projects it has always been in the back of our minds have we got this right, we were not able to quite identify all of the liabilities and provide a reliable estimate not only to you but to us as well.

So, we now have three quarters of the BEL claims have now been determined. We have had a significant increase in the claims process using some of these specialized frameworks of that. And we have had a lot of additional insight into undetermined claims including the various industry groupings, so we are confident that we have identified this. I think the options for us, and again, just in terms of being able to plan BP with a little bit more uncertainty, business does not like uncertainty.

I think it also gives some certainty to the ratings agencies as they look at BP and its future, there has always been a little bit of a question mark with the ratings agency. So, in that sense it gives me more confidence around credit rating and sustainability of dividends, for example. I realize those are a little bit intangible but I cannot underestimate for you the sense inside the Company of being able to plan the future with just that other element of certainty in front of us.

Okay. Fuels marketing, a couple of things, I think Bob mentioned earlier, first of all, to say marketing is a material part of our business. I will say right now sort of, if you look at how much we make last 12 months from fuels marketing plus lubricants is actually around $3.5 billion. So you know the lubricants numbers there, for you can come up with the fuels marketing number which is higher than lubricants number.

So one is actually it is material. The second thing is both of these businesses have return profile above 25%. These are pretax, by the way. And can we actually grow it? I would say yes, the reason is what we have been trying to do with fuels marketing really and with every business, but fuels marketing in this instance, create distinctive offers so that we actually deliver returns on growth higher than our competitors.

I will give you one example. This market, the UK, frankly in the UK last three years we have been achieving double digit [ARCO] growth. i.e., profit growth. It is a mature market but because of our offer we were able to do that. And then, we have exposure also to growth markets. Yes, this is one segment of Downstream we look to grow because we have good returns and exposure to growth.

Hi, Lydia. On the base decline for the first half, I think all I would say without giving a specific number our underlying production in the first half of the year is broadly flat. Second quarter it was up for the first half, it was broadly flat on an underlying basis. I think you will know that the projects that we have started up in the first half of the year are very, very modest. Angola LNG we have lifted four cargoes out of there, Thunder Horse water injection obviously no production, no immediate production contribution from that.

We have had Point Thomson in Alaska and In Salah Southern Fields, so you can get a sense on that base decline continues to be performing quite well for us. And as we said in Baku, we are going to do everything that we can to keep it to the lower end of the 3% to 5% range. And then obviously remind you what Bob said about reported production in the third quarter with the issues around Pascagoula in the Gulf as well. So hopefully that helps, Lydia.

Thank you.

Okay. Great. Next question from Pavel Molchanov of Raymond James in the US.

Thanks for taking my question. Going back to one of the earlier ones about your plans for Iran and I respect the fact that you do not want to get into detail. Can I ask the same type of question in relation to Mexico which is the other big geography that everybody wants to know who is going to go in and who is not? Anything that you can share on BPs plans for partnering with Pemex?

We have a very good relationship with Pemex and Mexico. We have worked there a long time, we have had people working there for a long time. It is a place we would like to work and we think that the skills that we bring from the Gulf of Mexico and the Deepwater can be helpful.

The country has made an unbelievable change and revision in its constitution and reforms that go beyond the energy industry. And it would be a natural place for us to work. Can't really comment yet on the terms because they are not out there yet and I don't know the details but it is a place that could be a natural fit with BP but let's see.

Okay. Thank you. Next question from Thomas Adolff of Credit Suisse, go ahead Thomas.

Hi Jess, thanks I have got a few questions. One for Tufan and again going back to refining. I can see your breakeven has improved significantly, but obviously as we all know in the refinery margin environment it is quite tough. I wondered whether any economic run cuts are yet evident in BPs portfolio? If not, at what marker margin would that be the case? And then I also have a more general question. Seizing the additional demand that we see, do you think, Tufan, that it will be met by higher runs globally or is next year drawing down the excess stocks.

And the second question maybe for Bernard or Bob, I believe you wanted to sell some assets in the UK at least according to the price of midstream assets. And in light of Brexit and who knows what will happen with Scotland, are discussions vis-a-vis are those assets on hold? And with that are you still confident you can deliver up to the $5 billion in disposals. My final question, on bolt-on deals, I wanted to know whether the bid/ask spreads are much narrower versus say six months ago?

Okay. Great. Thomas.

Should I start with refining? So I think refining, at this point, do we experience in our portfolio in the refining cuts, no. But I know in the industry I actually see some competitor refineries, less competitive refineries effectively starting to cut their runs in the current margins definitely. I am not going to give you, at this point, sort of a breakeven for us below which when do we cut because there are many factors, frankly.

We obviously look to also do commercial performance as well. So there are many factors playing into that even the crude price plays into that because secondary products are effected by that, which is not actually captured in our RMM, if you like. In terms of how I see going forward, at least in the second half, refining margins, these high stock levels as you can see right now, they are already putting pressure on the refining margins.

My expectation as I hinted already, utilization, some refineries already started to cut the runs therefore if this continues like that, it is logical to expect our utilization to go down in the industry. The demand level is still relatively strong. It is not as strong as last year. If demand continues at the current level you should expect stocks to go down in the second half, start to go down in the second half.

And Thomas on divestments, so far this year we have closed $1.9 billion of divestments, 90% of those have been in the Downstream. You will know that divestments are not a smooth quarter-on-quarter process, they come from different points. The one that you may have seen was a comment in the press about the sale possibly of storage terminals in the UK, so that may be what you have seen. I would say we are going to look at a lot of options. I am confident we will be in the $3 billion to $5 billion range this year.

We have got a lot of different talks going on. Not really going to identify where they all are the some of them may come up at the end of this year and some of them may move into the first quarter of next year. But we are very confident of the list here and we have got them all over the world, in fact, and some of the discussions that we have got going on. We are not going to overdo it with divestments after $75 billion now done. But we will always look for good options if there is value there.

And on bolt-ons?

On bolt-ons you raise a good point. I mean I think in many places around the world are now in the Upstream the bid/ask spread between sellers and buyers still feels too wide to us. So, we have done some bolt-ons that we like. We have deepened in the Culzean field in the UK, as one example. But there right now I think there are unrealistic expectations. I think there is a higher price built into what many people are asking for the sale of their assets and we are just not going to bite.

Perfect. Thanks very much.

Thank you Thomas. Going now to Irene Himona of Soc Gen, go ahead Irene.

Thank you, Jess. Good afternoon gentlemen. Two very quick questions. Firstly, at Downstream on slide 27, you show sort of changing earnings sensitivity effectively to the refining margin. My question is, is this captured in your published rule of thumb sensitivity to the Downstream which is, or was $500 million per dollar moving in the margin? If not should we be adjusting to something lower?

And secondly, in Q2 your Group adjusted tax rate was about 21.5%, I wanted to know if we stay at $45 the rest of the year, whether that is the right level to assume, which is obviously below the guidance? Thank you.

I will pick up the effective refining margin at Downstream question. If you look at the chart, what that chart is showing is effectively by improving our underlying performance by $2.4 billion, frankly we reduce -- and this is total Downstream, it is not refining, sometimes there is confusion.

We effectively reduced how much refining margin required to deliver, we took 15% return as a base here, saying this is sort of good returns. Obviously we look to improve the returns even beyond that. All this shows is we halved, literally halved the refining margins required to deliver 15% return in our Downstream. Downstream is getting more and more resilient. This is totally sort of in line with, in many ways, our rule of thumb assumptions which is also on an RMM basis as well.

Okay. Thank you.

Irene, on the tax rate, the underlying effective tax rate this quarter was 21%. And in our historic range has been in the 30% to 35% a year. But this is a good example, the first half, it has ranged around 20% and that is really due to the change in the mix of profits at the lower oil prices. There are parts in the world where of course profitability is down. We have had a mix.

There are lots of parts that move around on this. But I think the tax rate going forward will in part depend on the oil price, but you would expect us to be somewhere between the current levels of the 20% and getting up to the 30% to 35% that we had more historically. I think that going forward we would expect to be not at the historic rate. We will be lower than that.

Okay. Thank you, Irene. We will go next to Guy Baber of Simmons. Are you there, Guy?

Yes. Thank you very much. You have obviously made tremendous strides which you've highlighted previously in improving the competitiveness of your lower 48 portfolio.

Can you just remind us at what point in time you might be in a position to provide some more specific guidance around capital spending and activity levels for that business over the back half of this year? And how you think about that business within the confines of the $15 billion to $17 billion total budget next year?

Guy, it's Bernard. Just a few words on the lower 48. I think going very successfully for us. As we said earlier, capital productivity, so the efficiency of the capital improved by 52%. Operating cost down 28%, head count down over 50%. As a result, the break even of that business continues to be driven downwards. The returns of incremental investment in that business continue to improve. We actually took the capital quite a bit down in that business, for the full year in 2016. And we did that at the beginning of the year due to prevailing prices in gas, which were obviously very low.

Since then, we have actually allowed a little bit of capital to flow back into that business. Because the team there is able to generate rates of return sometimes well in excess of 20%, for incremental investments. So we think this is meeting our hurdle rates, it's good investments. So we have actually let a little bit of capital back into the business for the second half of the year which I think is a good thing. They had taken their rigs down actually to about one rig. I think they're running about three rigs to four rigs there at the moment that is on our operated business. We obviously also have the non-operated side of things.

So I think you can start to see a business that again, subject to investments that meet the hurdle rates that we said ourselves and we said the entire Company can sustain a capital rate around what we are seeing today maybe a little bit more. And an activity level that I think will be in the range of between 5 rigs and 10 rigs as you head into next year. So, really it is about productivity, it is about the returns, and it is about the hurdle rates. But so far, so good, we are very, very pleased with the performance of that business in Dave Lawler's hands.

That is very helpful. Thanks, Bernard.

Guy let me add a few things on that, I think this is a business that is not well understood. We are excited about it as Bernard said, we have got to 6 million net acres, we have 24,000 wells, we have 10,000 of them operated and we have a resource base of about 7.5 billion barrels of oil equivalent there with 37 TCF of gas and about 1.7 billion barrels of liquids.

And we have about 1,500 horizontal laterals identified that we can move on. About 40% of the resource yet to drill which is we can see that it is economic at less than $3 and less than $55. So this is a business, as Bernard said, that has a lot of potential. Go ahead, Guy.

With final certainty now around the Macondo liabilities and your ability to communicate that certainty to the market, understanding that you all have been very clear that you have a high degree of confidence in your existing resource space and the bid/ask spread still remains wide, does the appetite for M&A change at all here and the willingness or desire to capture some bottom of the cycle opportunities with that certainty now?

Guy, are you talking about the lower 48 or just globally?

Just in general, globally, lower 48 or elsewhere.

I think as we talked about bolt-ons earlier, those clearly where you have a competitive sort of logic to bolting on to what you are doing. I think our appetite is clear there when the opportunities come along. Bottom of the cycle we are certainly seeing it in cost structures. As Bernard said earlier, we are still seeing costs come down in Mad Dog for example. So is it now the bottom of the cycle, is it six months? I do not know.

But what we need to do, we have done such a good job of having discipline around our capital framework and our financial framework we do not want to drift out of that with enthusiasm. So we're going to keep the discipline on this. I think there will be opportunities around the world, there already have been some.

Thank you very much.

Okay. Thank you, Guy. We will now take a question from Alastair Syme of Citi.

Thanks, Jess, I had a very quick question just if you could help us quantify the restructuring [calc] charges as it flowed-through cash flow in first half 2016? And maybe how those compared to what happened in the first half of 2015?

Right, Alastair. We expect a total restructuring charge of $2.5 billion by the end of next year. So far we have had just under $2 billion, $1.9 billion since the first quarter of 2014. So we expect to see the full benefit by the second half of next year. So these related cash outgoings will continue into the first quarter of next year. Does that hit -- the first half of this year the cash impacts have been $600 million on that.

So $600 million out flow through first half of 2016.

And the first half of 2015 a year ago was $500 billion. And

Okay. Brilliant. Thank you very much.

Thanks, Alastair.

What happens Alastair is the cash impacts show up with a quarter to two quarters actually after the quarter in which we take the P&L charge. You would expect some cash impact still in 2017 even though we make it to the end of the P&L impact.

Okay. Thank you.

Next question now from Chris Kuplent of Bank of America Merrill Lynch.

Yes, thanks, Jess. Two very quick questions left. On your 2017 outlook I think originally, like Tufan confirmed, the $14 per barrel refining margin assumption I think originally you used a $3 Henry Hub assumption. Can you confirm if that is still the case?

And finally a question to Bob. I appreciate your offer Jess, I am sure I will be in touch to ask about the payment schedule around oil spill payments, but I wanted to ask should we perceive your $2 billion to $3 billion annual disposal target from next year onwards still as largely earmarked for oil spill payments? Thank you.

So, first, Chris. Thank you. On the refining marker margin it's $14.

Yes, it is $14.

The gas price?

We have not changed the planning assumptions in terms of what we have shown you here on the balancing at $50 to $55. Those planning assumptions are still the same as they were.

Which is [250].

Which is 250 Henry Hub that is the assumption on that.

That is pretty low, we think. That is okay. Then on the oil spill payments $2 billion to $3 billion per year is kind of been our corporate churn for many, many years. So it can be retail churn, it can be late life assets.

So you are right in our own thinking, that is $2 billion to $3 billion per year, year-by-year out in time will be used to fund what I would more or less think of, starting in 2018 and 2019 and beyond is a $1 billion dividend that will go out to 2033. For the charges with the Gulf of Mexico. So, it is just always part of our planning normally $2 billion to $3 billion. I think we will just keep that in there in our own mind that is what we think about it as earmarked for.

Okay. Thank you.

Chris we will follow up with you on that.

Let me to say that we do not expect the oil spill charges to be $2 billion to $3 billion going out to 2033 they are like $1 billion per year starting in 2019 on.

Yes. But certainly for the next few years we would expect that much of those divestment proceeds would be used up by the GOM payments.

Okay thank you.

Next, Nitin Sharma from JPMorgan.

Thanks, Jess, good afternoon everyone. Two questions for me. First one on project sanctions. Bob you flagged multiple times the falling cost curve in the benefits that probably hold for you, how does that falling cost weigh on your decision of [defining] the project now? Is it not better to wait and get more to make the project better?

And, staying with the project sanctions, maybe if you could talk about the commodity oil and gas price assumptions that you used for recent project sanctions at all. Second one on exploration budget of $1 billion, I am looking at write-offs, expense booked of around $600 million in [edge fund]. So is it right to assume that the run rate of exploration spend in [edge] will be lower subject to this volatility of exploration write-offs? Thank you.

Right. A couple of things. Project sanctions. We talked earlier about this being bottom of cycle, we have been really careful is Bernard said to really drive capital efficiency very, very carefully which is why we have deferred sanctioning multiple projects. Tangguh came along which we think was the lowest cost supply LNG addition in the world. We're going to keep it simple and design the third train like the first and the second ones.

And there were gas contracts into Japan associated with that project which we did not want those to go away so we went ahead and sanctioned it. We think it is the right time in the cycle. We will be really careful about whether we sanction these but right now, as Bernard said, the cost of a Mad Dog for example has come down and we continue to refine and simplify some of the engineering. We will pick this very carefully.

And we are making sure the breakeven cost or the cost that allows us to receive a reasonable return on our capital is coming down, down, down. And Mad Dog will be under $40 per barrel by the time we're done with that, for example. We need to think about future growth of the Company as well so getting this capital efficiency is a huge drive.

On the commodity prices that we have assumed. So talking about natural gas for a second, it is easy to follow Henry Hub but in reality a lot of the world does not work off of Henry Hub. So whether it is in Egypt or whether it is Oman, we are supplying gas into local markets and have contracts in place that provide a good rate of return. I think we can see that in India for example. So it is a little bit not so much to do with the commodity price but designing a project with a good return at a fixed gas price that we know. Then we will be careful about LNG. Tangguh makes sense, we have deferred Browse with our partners, for example, where it does not make sense. Now, in oil there are good projects out there. We would just be really careful of how we design them.

Now on exploration, there is always this lag between when you have spent exploration and when you turn them into projects or if they need to be eventually written off. So there is quite a lag in this. The first half exploration write-offs, for the first half of the year were around $420 million that is lower than the historical norm due to the drilling activity. Exploration expense was $600 million, including seismic work.

You should, in time, see lower exploration write-offs but we still have things in the portfolio that we have drilled, we are appraising them, that we have decisions to make so it is not that easy. This is always a line in your modeling that goes up and down for every company. But, lower in time should lead to lower exploration write-offs.

Fair enough, thank you.

Okay thank you, Nitin. Lucas Herrmann from Deutsche.

Thanks Jess so much, sorry to keep you so long. A couple of questions, Bob, if I might. The first one was just a point of clarity around breakeven $50, $55. And when you talk around cash coverage of dividend of operating breakeven $50 to $55 do you think about the dividend after a strip element or before it? In other words are you thinking about the full cash cost of the dividend or when you talk about breakeven are you thinking about the dividend posting average level of scrip of some kind?

Thanks, Lucas. The principal aim is reestablish a balance where the operating cash flows covers the capital expenditures and the full dividend over time. We are not there today. But, that is absolutely part of our aim and our financial framework.

All right. Thank you very much for that clarity. And Bob, further out, the Sunny Uplands. When oil does hopefully recover to a price we you are able to more than do that, how do we think about dividends -- how do we think about the allocation between dividends in the future or repatriating the stock that is being issued at scrip or issued at scrip through this period and perhaps into tomorrow as well? Ergo, can you see dividends improving or is your bias, or do you think the bias at the Board is going to be towards repatriating equity?

Good question, Lucas. We recognize that it dilutes shareholders, all of the companies that do this. There are shareholders again that really do like this program. But given that we intend to cover the full dividend, we would like to offset the scrip dilution at some point in the future.

We have done buybacks in the past, as you know it is a matter for the Board. But, there is no question in the Sunny Uplands or maybe even before we get to the Sunny Uplands that we would like to offset the scrip dilution.

One final quick one, Pascagoula, what is the impact on volume for you in Q3 assuming a continued outage?

I will turn this over to Bernard, he's on it almost every day now.

Hi Lucas. It is still complicated, the teams are working through it. It affects two facilities of our Gulf of Mexico system, Thunder Horse and Na Kika. They are producing or ramping up at the moment probably not to full rates. I would be thinking somewhere in the region of 30 MBD to 35 MBD in the quarter as an impact from Pascagoula; that is our current view of things.

That is crude as well? I appreciate that it's a gas processing plant but does it prevent you?

That is the impact on the GOM crude and gas production so the oil equivalent production impact in the quarter is about 30 to 35.

You do not want to split it for me do you, Bernard.

I prefer not to, Lucas.

I think the reason is because it also affects other -- if you split ours, it affects other companies as well. It is not just ours and we could mislead you there.

Gentlemen, thanks very much.

Thanks, Lucas.

Biraj Borkhataria of RBC.

Hi. Thanks for taking my question. Two quick ones if I could, First on Macondo, maybe I'll ask this in a slightly different way, but from the press release last week, could you give a split of the $5 billion charge between the BEL claims and the opt-out claims? That would be the first question. The second one probably one for Bernard, but could you just update us on the receivables balance in Egypt? Thanks.

Right. Biraj, of course the $5.2 billion charge is a most likely estimate of all of the liabilities. So many of the liabilities between the BEL and the opt-outs and excluded, those are people that have stepped out of the settlement, are very similar in their nature. So we brought it together in one overall charge. It is really hard to split that right down the middle or in two different buckets. But, what we think, it reflects the nature of claims in both of those categories broadly.

I am just trying to get to what is going to be paid out for the rest of this year and then what is to be spread over from now to 2019, so any info on that would be much appreciated.

Well, I think mostly it will be paid out by the end of this year. The large portion relates to the BEL and that $5.2 billion is a post-tax charge, there is a pre-tax number in there as well. I think there may be options here that we may have or the facility may have to accelerate. And I think I would probably just leave it at that. I think we're going to have some discussions with them about making the facility and the administrative costs more effective or not and I think I would just leave it at that. I know that is hard to model but that is the reality.

Okay. Thanks. And then the receivables balance in Egypt?

Thank you for the question. What I would say on that is that having been in Cairo earlier this year, this is a very, very high priority for the government. The Prime Minister when I met with him is very keen obviously to attract further investment into the country and recognizes that the issue of receivables is a concern on other investor's minds.

So, very high on their agenda, will not give you specifics numbers, as you might understand it is sensitive for the government. But, I would say that we are in a good position on our receivables and over dues in Egypt today. We have worked very closely with the government trying to find very innovative ways from how we spend Egyptian pounds to diverting some of our crude cargoes and so on.

So, the government has been very, very cooperative, very supportive. They know it is an issue for an investor as a result it is right up there priority list in terms of resolving. And we have worked very well with them. We will obviously keep a watchful eye on it in the months and years ahead as our investment levels continue there. But today I am actually quite comfortable with our position in the country in that regard. Hopefully that helps.

They are way down from the fourth quarter of 2012.

Okay thank you, Biraj. Next, Rob West of Redburn.

Thanks I have got a question for each of you. So starting with Tufan, I have noticed petrochemicals has done second quarter in a row now around $100 million a year of operating profits, So we're not quite back at the glory days of 2010 or 2011,but this is definitely the best quarterly run rate for about five years. Could you tell us what is the single biggest contributor of that improvement?

Then second question, for Bernard, can I ask about the decommissioning provisions that you are likely to report at the end of the year in your 2016 annual report? Just based on the trends you are seeing there. Apologies because I back this out so the sum might not be 100% accurate but it looks as though there's been a bit of a slowdown in decommissioning activity in terms of the number of P&A wells drilled in 2015 and maybe this year. So should that number, the decommissioning provision, be generally up or generally down?

Then one for Bob, which is in terms of the gearing. I know how you think about it in terms of that 20% to 30% band, if I make you think about it in the way that I think the rating agencies did that is more of an expanded net debt to that cash flow metric. Is there a fair cap you see on that expanded net debt to cash flow and where it should come in in addition to the 20% to 30% band you mentioned. Thank you.

Okay. Thanks, Rob.

I will start with petrochemicals, thanks for the question. Just to tell you, actually when we set our studies early 2015 what we said is, on petrochemicals we're not going to rely on the environment. We are going to create a business which is robust to environment. So what that meant is we were going to focus on expanding the earnings potential of the business. And on that, you're absolutely right, in a similar environment like last 18 months, if you look at the last 12 months versus 2014 we made more than $300 million more effectively in similar environment.

So second thing we said, actually cash breakeven, we will lower; at that time we said by 2018, 35%. By the end of this year, we believe we will have reduced that to 25% already. Now what we see is an opportunity we will be able to go beyond 35% and also bring forward 35% reduction in an earlier day. So what is driving all this is there is no one single answer unfortunately. But four things. We have stronger operations, we are retrofitting our new technology in PTA plants, and efficiency program we have and the portfolio restructuring. We are not done, frankly, with our program yet.

Can I ask one thing about that. I think you disposed of a facility in Alabama. Was that a loss-making facility at the EBIT level and that's a one-time gain from taking that out of the mix?

No, it was frankly more breakeven sort of level. Obviously it depends on which day you look at these things but the impact of that on this $300 million is almost nonexistent. So it is very, very small, that is how you should think about it.

Great. Thank you, Tufan.

Hi Rob, this is Bernard. Thanks for the question on decommissioning. If I just think about it in two lenses, one on activity and two on the provision itself, I think activity will be driven by regulatory requirements and any concerns that we have ourselves. Obviously, the majority of our activity today is in wells probably in Norway and a little bit in the North Sea and a splattering in the Gulf. But predominantly in Norway, so that activity will come and go as needs be.

In terms of the provision itself, we continue to look at the provision, we continue to make sure that we are coming up with innovative ways to do decommissioning. We're continuing to drive performance, the Valhall team decommissioning the wells in Norway and have turned in some stunning performance on what they have managed to be able to do. And we continue to look at the rates and make sure that the rates that we have got within our assumptions are consistent with what we are seeing in the world today and our view of the future.

So, you did see an adjustment in the second quarter, which was a positive change from a provisioning standpoint. But it is something that we continue to keep under a close eye. And I think in the long run it is an area of opportunity for the Company and for the industry if we can continue to find a different ways of doing this. And the performance that we have had on Valhall on the well side gives me a lot of hope in that space.

Could you just maybe say, rough guess, do you think it will be flat, up or down when you report at the end of the year?

I would prefer not to project it just yet Rob, I think it is too early to do that. But rest assured that we are continuing and will continue to work it to make sure that it is accurate and reflects our current performance.

Okay. Thanks.

Thanks Rob.

You raise a really good point about some of the ratios and cash cover of net debt. The agencies do look at the ratios of underlying operating cash flow. So they look at the underlying of our operations to the expanded debt, which also includes pensions and other liabilities and we watch these all very carefully. How these relate to different ratings are really a matter for the agencies.

But, we are comfortable right now. You are right, our gearing at 24.7 right in the middle of the band, but a few things around the cash. We had $23.5 billion of cash on the balance sheet at the end of the second quarter. The Group level has increased this quarter by $2.6 billion as we did issue some new debt, but that more than offset our repayment and we had of $1.3 billion of maturing debt. Give you a sense of what it means, a $1.6 billion movement in the net debt causes a 1% move in the gearing is a rule of thumb for us.

I think we have got a prudent level of liquidity. So, we are anticipating only moderate levels of new debt issuance during the remainder of the year. I think that we will have $1.9 billion will mature by the end of the year and then as we look into 2017 there is $6 billion of debt maturing. We think that all of this is quite manageable and we obviously have our reviews with the agencies periodically here. But, you are right, what you raise is a very important point.

All right. Thank you.

Okay. Martijn Rats of Morgan Stanley. Are you still there Martijn?

Hi. Yes. Frankly somewhat two sort of somewhat technical issues to assist to take off. If you look over the last couple of quarters and you take the deferred tax liabilities (inaudible) against the deferred tax assets, you see a continuing shrinkage of these net deferred tax liabilities. And of course a traditional interpretation is that actual tax payments catch up with the tax expense and that you are paying more than you have been expensing, which should weigh on cash flow.

So if over the last year net deferred tax liabilities have gone from about $10 billion to about $3 billion in this quarter, it sort of should suggest in terms of operating cash flow this in fact would have weighed on operating cash flow to the extent of about $7 billion. And I was wondering whether the traditional interpretation of these numbers was indeed correct or if there was some other effect going on? And also would you expect this to stop and start reversing at some point where instead of this becoming a cash flow headwind, this would become a cash flow tailwind?

The second question I wanted to ask you is regards to price realizations. I know the volumes in the quarter were quite low but price realizations of $55 a barrel in the category rest of the world seem quite high. Now I guess there are some technical issues here, quite often low volumes and higher prices go hand-in-hand. But given that you expect lower volumes to continue in the third quarter, would you also expect these higher price realizations to continue in the third quarter?

Well, on deferred taxes, I mean you have touched on now, I know you are trying to model this, this is probably one of the most complicated subjects as you will know. It really does change in the geographic mix of the profits towards a relatively high tax rate in the Upstream jurisdictions away from the relatively lower tax rate in the Downstream. And there is always foreign exchange impacts on deferred tax balances.

So, we just have never tried to give guidance on this because these numbers will move around. And I think that the best thing for you to do is model this with our effective tax rate guidance. We do have a very high Deepwater Horizon deferred tax asset that I think is something for you to think about there.

Okay.

It is probably the opposite of headwind I would say. And then the rest of world, on the oil realizations, I think excluding Iraq in the second quarter the rest of world oil realizations of $55.10 a barrel if you exclude Iraq, with Iraq. Excluding it is $44.32 per barrel.

Okay. So that is purely an Iraq effect.

Yes.

But if the volumes are lower in the third quarter because --

No, not the volumes because of the way the PSEs work. The cost of oil.

Okay. Thank you.

Thanks Martin. You have been very patient.

Okay. Thank you we will take the last question from Iain Reid of Macquarie. Go ahead.

Hi guys. Thanks very much for hanging on so long. Just two things, maybe for Bernard. Firstly, the $7 billion to $8 billion you talked about in terms of free cash flow delivery in 2020, Bernard, I wonder given the fact that crude prices are not that far away from your $50 that you were talking about then, could you give us a snapshot of where that number would be or has been in the second quarter of this year? And what the kind of direction of travel you see in the near term is on that?

And, then I have a couple of questions on your [post-two] 2020 major projects, the slide on page 25. Just an update if you can on where you are on the ACG PSC extension negotiations with the government. I know there has been for media stuff on that. And also an update on where you are on GOM Paleogene project because there's been a distinct lack of news on those as of recently.

Okay, Iain. I will take the first one and maybe the Paleogene and Bob says he will take the ACG one. On the $7 billion to $8 billion, yes, I think it is the projection we have made there, the pretax proxy projection that we have made is at prices that are similar to today.

We are quite a ways from that today but as you can tell we are very confident in that estimate. And that will come from three distinct areas, Iain, and no surprises on what they are. But we expect to continue to drive the cost base of the business down. We are top quartile in operating cost today. We intend to continue to push and to drive that further so you will see contribution from costs coming through to that $7 billion to $8 billion.

You will certainly see contribution from capital continue to come through. We believe and are seeing day to day that our capital continues to get more and more productive. That simple example from the lower 48 of 52% is one example, but we are seeing that right across the Company, driving costs and capital back to levels last seen when oil was $40 to $50 like in 2005.

And of course you are going to see it in production and in margin. We are going to bring on the 800,000 barrels per day of production between now and 2020. The projects are 70% on average complete, they are on average ahead of schedule and ahead of cost. And they bring with them margins that are on average 35% higher than today's equivalent or the 2015 equivalent at $50.

So, you will see where that is a breakdown of where it will come from, it will come from every aspect of the business. And obviously inside the business we're trying to do better than that and we will see where we turn out. So, that is the basis of the $7 billion to $8 billion. On the Paleogene and the Gulf of Mexico --

Any chance you give us a rough number of where you are on that and whether it is positive or not at the moment?

I think it is best really not to say, Iain, other than to say that the projection that we have out to 2020 is I think a robust one. And all I would say is that the momentum that we have today in the business, if you look at the physical things that are happening, what is happening to our cost base and what is happening to the productivity of the capital and the physical things that are happening with the projects, you would have to say that momentum is absolutely in the direction of supporting that $7 billion to $8 billion.

On the Paleogene, I think all I would say is that we're continuing to work it. We have the partnership with Chevron, they are bringing their experience from their developments, they're helping us. The partnership is working well, we are continuing to work Kaskida. So all I would say is that continues to be worked. We need to make the project, if it is going to happen there, economic. We're continuing to get results from the wells which generally are in line with what we are expecting and we're continuing to work development concepts.

Then, Iain, just a comment on ACG. I have seen some of the press reports which I think are not accurate. We are working with all of the partners in SOCAR now. We are looking again to look at some new life of field development options for ACG. That work is going pretty well.

So BP at all of the partners which are all great companies and SOCAR we're working together to see how we might implement this in an extension. We are pleased with the progress so far and everyone is looking forward to doing this. I think some reports intention I think do not really reflect what is happening.

Didn't get that one done quite soon then, Bob? Is that the general message?

We're finding even with Mad Dog, as you go through and look at new development options we are going to do this but we're also going to look at the development options here that might make sense in this current environment.

So let's see, I think the date of the contract was 2022 or 2024, it is a while. But I think everybody would like to move forward with this. And there are always contract extensions at the end of PSCs have to be done carefully and they take time. We are very optimistic.

Okay. Thank you a lot.

My goodness, we have been going for two hours and 10 minutes. It might be a record quarter for us, maybe not in terms of earnings but in terms of calls. For those of you who have been very, very patient, let me just take a minute because we have just talked about very many things here and I do want to just remind everybody what are the big principles of our financial framework.

We want to establish that balance where the operating cash flows will cover the capital in the full dividend over time. Assuming $50 to $55 per barrel we expect to do that next year and then we will have organic free cash flow growth after that we expect. The basis for this ongoing commitment we have got is really to sustain the dividend is the first priority in our financial framework. The inflows and the outflows, of course, they will be subject and we'll constantly recalibrate with the environment. That includes judgments we may make on how much CapEx we're going to spend and any changes to the portfolio.

CapEx below $17 billion this year I am sure that is going to happen and we will be between $15 billion and $17 billion next year depending on the oil price, but I think that is very likely. Cash cost reductions we are on track for $7 billion by 2017 versus 2014. We are well through that, $5.6 billion now down.

The $3 billion to $5 billion in this year, $2 billion to $3 billion in 2017 going forward. And just really rock solidly establishing ourselves in that 20% to 30% gearing band going forward, which we had for years and we took it down to 10% to 20% range after the Gulf spill

So I think those of you have been patient enough, I think I will leave it at that. Thank you all very much for, as always, your great questions. And if we do not see you, have a good summer. If not we will see you in another three months.