BP Plc (BP) Bernard Looney on Q2 2016 Results - Earnings Call Transcript

| About: BP p.l.c. (BP)

BP Plc (NYSE:BP)

Q2 2016 Earnings Call

July 26, 2016 9:00 am ET

Executives

Jessica Mitchell - Head-Group Investor Relations

Robert W. Dudley - Group Chief Executive

Brian Gilvary - Group Chief Financial Officer & Executive Director

Bernard Looney - Chief Executive Officer-Upstream Division

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

Analysts

Jon Rigby - UBS Ltd. (Broker)

Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP

Blake Fernandez - Howard Weil

Oswald Clint - Sanford C. Bernstein Ltd.

Jason Gammel - Jefferies International Ltd.

Asit Sen - CLSA Americas LLC

Henry M. Tarr - Goldman Sachs International

Brendan Warn - BMO Capital Markets Ltd.

Lydia R. Rainforth - Barclays Capital Securities Ltd.

Pavel S. Molchanov - Raymond James & Associates, Inc.

Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.

Irene Himona - Société Générale SA (Broker)

Guy A. Baber IV - Simmons & Company

Alastair R. Syme - Citigroup Global Markets Ltd.

Christopher Kuplent - Bank of America Merrill Lynch

Nitin Sharma - JPMorgan Securities Plc

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

Biraj Borkhataria - RBC Europe Ltd. (Broker)

Robert West - Redburn (Europe) Ltd.

Martijn P. Rats - Morgan Stanley & Co. International Plc

Iain Reid - Macquarie Capital (Europe) Ltd.

Operator

Welcome to the BP presentation to the financial community webcast and conference call. I now hand over to Jessica Mitchell, Head of Investor Relations.

Jessica Mitchell - Head-Group Investor Relations

Hello and welcome. This is BP's second quarter 2016 results webcast and conference call. I'm Jess Mitchell, BP's Head of Investor Relations. And I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary. Also with us for the Q&A is the Chief Executive of our Upstream, 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.

Robert W. Dudley - Group Chief Executive

Thanks, Jess. So welcome, everybody, and thank you for joining us.

It's 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've 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've continued to put our energies into shaping a much stronger future for the group. It's a future we feel very good about. We've established more efficient ways of working and moved quickly to do so. Our track record of excellence when it comes to execution is getting stronger all the time. And 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's part of what defines BP, and it's 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'll start by looking in more detail at the environment and our response. And I'll 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. And I'll 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 continued 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 has 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 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 are even more conscious of the need to improve this every day as we work to reset our business to 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's 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're 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. And that's 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're 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've 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's 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 Bern referring to this as making it stick. It's about changing the way we think about our business, adopting a manufacturing approach across all our businesses so that we're always competing at the lower cost end of the supply curve.

We've 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 toward the most important of principles, that of growing sustainable free cash flow and shareholder distributions over the long term.

We've 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 in 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's 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've 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 won't 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 over 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, and we see more opportunity to grow through our access to growth markets.

So 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'll 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.

Brian Gilvary - Group Chief Financial Officer & Executive Director

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.

Our 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 exploration 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 pre-tax 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 exploration write-offs. Looking ahead, we expect third quarter reported production to be lower than the second quarter due to seasonal turnaround and maintenance activities and the impact of the plant outage at the Enterprise Pascagoula [Mississippi] 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 pre-tax 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.

Following 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 pre-tax 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 was 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 pre-tax charge for the second quarter of $5.2 billion. The total cumulative pre-tax charge for the incident is $61.6 billion, or $43.4 billion after tax. With a full $20 billion already paid out of the trust fund, BP is paying for the claims and other costs formerly funded out of the trust as they arise. The pre-tax 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 pre-tax 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's 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 are 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 divestments 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.

Robert W. Dudley - Group Chief Executive

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 pre-tax free cash flow to the group in 2020 at a $50 oil price assumption. It doesn't 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 prefeed 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've 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're 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 sanctioned 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're 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've reset the organizational footprint, making it one-third smaller than three years ago. We've focused on engaging our people and 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're also addressing our third-party spend, as it represents a significant portion of our capital spending and around 50% of our cash costs. And we've seen a big reduction in cost 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're seeing productivity increasing as we try new things and bring in new technology, called innovation. For example, by enhancing oil recovery and increasing the amount of drilling we do, we have reduced planned 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've achieved a lot, but we're deeply determined to do more. We have many more ideas to drive this the 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're continuing to optimize these projects, testing their costs and margins carefully against historical and competitor benchmarks. We will only proceed when we are ready and the projects are the best they can be. We can do that because we don't 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. And 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've 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. And 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're 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 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 pre-tax returns and doing this sustainably. From the chart, you will see we have also made progress on this.

I'd 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've 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 pre-tax earnings. They've 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 pre-tax 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 pre-tax 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 this slide we are improving in our refining pre-tax earnings. We've more than doubled compared with 2014 at constant refining margins. And 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 pre-tax 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 pre-tax 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's a lot from me. But just to sum up, we're making steady headway in what remains a tough environment. We're 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're 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's 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 through the end of the next decade. And 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.

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

Question-and-Answer Session

Operator

Jessica Mitchell - Head-Group Investor Relations

Okay, hello, everybody. We'll start the Q&A shortly. But before we do that, I'd just like to pass you to Bob to say a few words.

Robert W. Dudley - Group Chief Executive

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

Jessica Mitchell - Head-Group Investor Relations

Yes. Thanks, Bob, and we'll take the first question from Jon Rigby at UBS. Are you there, Jon?

Jon Rigby - UBS Ltd. (Broker)

I am. Thank you, Jess. I just wanted to explore the direction of travel, the speed at which you're 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're at 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're 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's going on that I should be expected to be able to see?

And to the point on CapEx, I wonder whether you can just talk a little bit around what you're 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've made over the last 12 months or so, which is something of a concern because my expectation was there was still some 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.

Robert W. Dudley - Group Chief Executive

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

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

Bernard Looney - Chief Executive Officer-Upstream Division

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've been focusing very, very hard on the sustainable elements of our cost reduction program right across cost and capital. And we've been doing that for the reason that you just outlined. We estimate that somewhere around three-quarters of the cost savings that we've 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's very early to be having that conversation about price recovery. Quite frankly, I think we've 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's a lot more to do. We're looking at how do we get costs back to the levels when they were last at this price range in 2005. That's 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's a lot more that we can do in this space. Ideas are coming through each and every day. So I'm 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 saying what we can do to drive the cost structure down for what I think one of those service company's CEOs described as a medium-for-longer price environment. So a lot more to go, a lot more to do. We're very focused on the 75% and making it stick. And there will undoubtedly be some pressure, but we'll see how that emerges over the coming months and years.

Robert W. Dudley - Group Chief Executive

Jon, as we talk about $7 billion, there's a big group of that in the upstream and there's a big block of that in the downstream as well, and 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 in oil price.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

Thanks, Bob. I think, Jon, what I would say is in addition to cost, obviously we said it, $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's the point I would like to make.

Robert W. Dudley - Group Chief Executive

Jon, is that okay for you?

Jon Rigby - UBS Ltd. (Broker)

Yes, that works. Thank you.

Robert W. Dudley - Group Chief Executive

Okay, thank you.

Jessica Mitchell - Head-Group Investor Relations

That's great. Thanks, Jon. And 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.

Okay, moving on now, we'll take a question from Anish Kapadia at TPH. Go ahead, Anish.

Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP

Hi, good afternoon. I have a couple questions, please. Firstly, I just had some clarifications on slide 18 in terms of the cash balances and what's in there. So first of all, I just wanted to know. Does it include investments into JVs? And if not, what's the expected run rate for investments into JVs? And 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're seeing. If I assume that refining margins remain around current levels, it seems like it's around $5 per barrel lower than your assumptions, your planning assumptions for 2017. And you're looking at your sensitivities, it seems like that's around a $10 per barrel lower – sorry, higher breakeven for 2017. And so I'm just wondering. Firstly, are those calculations broadly correct? And in that scenario of a very weak downstream environment, how would your strategy potentially change and investment outlook? Thank you.

Robert W. Dudley - Group Chief Executive

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're 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's probably what you're looking at.

The scrip uptake has averaged 19% since we started it. It's 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. So 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's not popular with everybody.

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

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

I think on the refining margin, effectively against today's numbers, if you look at first half 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 half 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.

Robert W. Dudley - Group Chief Executive

Anish, I'll just add a footnote to that. I've 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.

Jessica Mitchell - Head-Group Investor Relations

Okay, thanks, Anish. We'll take a question now from the U.S., Blake Fernandez of Howard Weil. Are you there, Blake?

Blake Fernandez - Howard Weil

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're seeing. In the U.S. in particular, we're seeing some increased gasoline imports. I didn't know if you have a sense of the competitive advantage that the U.S. has been enjoying, if it's beginning to erode, or if there is anything more macro oriented you could share.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

Okay, there's a lot in that question, so I'll try to be brief. But I think U.S. – so I'll come back to refining margins. But you talk about U.S. advantage. Frankly, U.S. advantage started to erode some time ago. It's not something new. When the U.S. actually allowed exports to take place, WTI Brent started to actually narrow, and today it is $1 – $2 around that. That plus the WTI production because of the crude price share of production going down, frankly that differential almost got lost. So U.S. advantage is no longer on the crack advantage as U.S. had to have but more the energy cost. But energy cost, if you compare rest of the world refining versus U.S., even Europe, actually that advantage is offset by lower non-energy costs in Europe versus U.S. So overall, I would say once the exports were allowed, that U.S. 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 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 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 half anyway, and I can briefly talk about second half. But what was happening this year, that big stock there, especially both gasoline – gasoline is the historical high as OECD stocks we see. Distillate actually, it is close to 2009 levels, which was historically the high level, financial crisis. So that stock level didn't go down because although demand actually is pretty robust, it didn't go down because utilization went up, not in Europe, not in the U.S. necessarily, but Chinese teapot refineries almost doubled their utilization this year versus last year. So as a result, stock level didn't actually go up but didn't go down significantly, and that continues to put pressure on the refining margins.

Blake Fernandez - Howard Weil

Thank you for the comprehensive answer, one – just if I could just follow up. I know Brian isn't 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?

Robert W. Dudley - Group Chief Executive

Well, as you'll know in the PSCs – I thought you were asking about the plaintiffs' attorneys there for a second, Plaintiff Steering Committee, so I'm relieved. As you know, the way these PSCs, these production sharing contracts work, when the prices are lower, there's more costs that are (58:12) coming to you, and that's what we saw in the first quarter, which is why you've seen this – primarily, a big reduction in our production this quarter because the price is higher. I think it 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'll see reported production lower than 2Q. But that's 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.

Blake Fernandez - Howard Weil

Okay, fair enough. Thank you, Bob.

Robert W. Dudley - Group Chief Executive

Okay, thanks, Blake.

Jessica Mitchell - Head-Group Investor Relations

Okay, we'll take the next question from Oswald Clint at Bernstein.

Oswald Clint - Sanford C. Bernstein Ltd.

Yes, hi. Good afternoon, maybe two specific questions. I was interested in India. It 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. Is that the case? And could we see you and Reliance getting back to work there in that country sooner or at least in the short term? That's my first question.

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

Robert W. Dudley - Group Chief Executive

Oswald, thanks. Yes, the change in the gas price, which was done really in the first part of the year, is quite a big step for India, to move back in place market pricing. There's 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's good. We do have some arbitrations which are in place. But I am optimistic that we're going to move through these things, and these India projects now are moving right up the list in terms of competing for capital inside the group. And in terms of timing and specifics, we'll 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.

Bernard Looney - Chief Executive Officer-Upstream Division

Very much, Bob. And as you said, those India projects will end up being some of the best projects I think that we have, so looking forward to that.

On Thunder Horse, Oswald, we've 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 in the ground and the injectivity that we wanted. So, so far, so good, we're very pleased with the performance of that project thus far. So thanks.

Jessica Mitchell - Head-Group Investor Relations

Okay, thank you, Oswald. We'll take our next question from Jason Gammel at Jefferies.

Jason Gammel - Jefferies International Ltd.

Thanks very much, Jess, and hello, everyone. I just wanted to ask two questions on the upstream, please. The first, and I'm 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. I just wondered if maybe Bernard could comment on whether there was still a possibility of further sanctions the rest of this year. I'm thinking Mad Dog 2 and perhaps even Bakim (61:59) in Egypt.

Bernard Looney - Chief Executive Officer-Upstream Division

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 be 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, tends to be in the onshore locations. And I would look to places like the Lower 48 where, as you know, I think we've created a really material flexible high-quality option. So that's one that we can flex back and forth, Jason, quite a bit. We'd also look at Alaska. We continue to look at Iraq. So they're the sorts of areas where the flexibility in the upstream remains, and we continue to drive the productivity of the capital investment that we have.

And 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, more cost effectively, and the list quite frankly gets longer each and every day. So 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've sanctioned Atoll 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're very excited about. The team has done a fantastic job there getting costs on a normalized level back to 2004, back to what we built Train 1 and Train 2. Mad Dog Phase 2 always subject to partner approval, but as we say, it's 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 could see that one emerge towards the end of the year. We have, of course, the next train at Khazzan, where we'll hopefully do 1.5 Bcf a day for the price of what we originally thought a Bcf a day would be done for.

Bob has mentioned the India gas projects, which will move up the chain. We've got onshore compression in Trinidad that may come into the picture. We've got Angelin in Trinidad. We've got Snadd in Norway, so a number of projects that are possible. All I would say is 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's why we've 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?

Jason Gammel - Jefferies International Ltd.

That's very helpful, Bernard. If I can just with a very quick follow-up, you did mention the discretionary spending in Iraq as being something that 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?

Bernard Looney - Chief Executive Officer-Upstream Division

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's also based on the change in value of the under-lift position that we have. And 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.

Jason Gammel - Jefferies International Ltd.

Thanks very much, I appreciate the comments.

Jessica Mitchell - Head-Group Investor Relations

We'll turn now to Asit Sen in the U.S. from CLSA.

Asit Sen - CLSA Americas LLC

Thank you, Jess. Good afternoon. I have two unrelated questions. Bob, in your opening statement, you alluded to rising Iranian production. So I'm just wondering if you could share your view on Iranian production trajectory this year and next year and BP's growth aspiration in the country. That's 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?

Robert W. Dudley - Group Chief Executive

Right, Asit. I think on Iran, it's probably better just to no comment on the future of the company. We have a long history there from before, but the terms and what's happening there and how we allocate our capital, all those things are not clear. And 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'm not sure we see it continuing at that sort of rise. So you'll know from market data what's out there and what they're producing and can't really project much more on that.

On your question around maintenance CapEx, we project this year, this is 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.

Asit Sen - CLSA Americas LLC

Thank you, Bob.

Robert W. Dudley - Group Chief Executive

And that number in 2015, by the way, was around $8 billion.

Asit Sen - CLSA Americas LLC

Thanks lot.

Jessica Mitchell - Head-Group Investor Relations

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

Henry M. Tarr - Goldman Sachs International

Hi. Thanks, Jess, just three quick questions. One was when you're doing the FIDs and having 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 don't know whether a comment around what's driving that would be helpful.

And 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.

Robert W. Dudley - Group Chief Executive

Right. First, Henry, a quick comment on the FIDs, and I'll just mention the one country and then Bernard, he's going to have some other comments on other places where we're working. Because we have not FID-ed this yet, but I think India is a great example where a government has just looked at the very fundamentals of lack of attractiveness into the sector in exploration and production and have made a big fundamental change. Bernard, there are a couple of other ones I think you...

Bernard Looney - Chief Executive Officer-Upstream Division

I think, Bob, I think India and I think the other great example where there's 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 help us get projects which are economic at the hurdle rates that we've talked about on the call.

So the 50-plus years that we have in Egypt, the relationships that we've built in country, the track record of performance and delivery that we've had in the country I think have given us a place where we're able to work very well with that government. And they've 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.

Robert W. Dudley - Group Chief Executive

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.

Bernard Looney - Chief Executive Officer-Upstream Division

Right.

Robert W. Dudley - Group Chief Executive

On your other question, and I think 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 investment, some of them are not. I think it's a 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've moved through the Gulf of Mexico settlements. And there are 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 this year. The main payments in that the second half of this year relate to the state and the 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 to state and local governments.

Then there's 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's a piece in 2018 for the SEC. There's a third element here, and this is what's led to really our ability now to make the estimates because on July 14, 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're part of that $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 Plaintiff 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 give to you now is we expect to complete all claims by 2019. That's also part of these provisions that we've put out. We've had – 148,000 claims have been submitted, 114,000 have been finalized by that settlement procedure. Of that, probably 44,000 claims were issued, about 70,000 claims were closed with no payments without merit, and we've still got about 34,000 claims to move through it, through this tail part of that. So I have no idea whether that's going to be helpful because that's a very complicated set of layers there.

Jessica Mitchell - Head-Group Investor Relations

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

Robert W. Dudley - Group Chief Executive

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

Henry M. Tarr - Goldman Sachs International

Thank you.

Jessica Mitchell - Head-Group Investor Relations

Okay, we'll take the next question from Brendan Warn of BMO.

Brendan Warn - BMO Capital Markets Ltd.

Yes, thanks for taking my question. I'll just keep it to one, just a question I guess related to the Lower 48 onshore business and tying both back into the chart on page 25. Just in terms of the 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're busy with planning assumptions, but just which refining margins, is there a flex in refining margins across the range from $45 a barrel to $70 a barrel, or is it one static refining margin for that cash balance? If you can, clarify those two points, please.

Robert W. Dudley - Group Chief Executive

Okay, Brendan. Bernard, on the Lower 48, I'll make a comment about the refining margins. And then, Tufan, if you want to, add anything.

Bernard Looney - Chief Executive Officer-Upstream Division

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

Robert W. Dudley - Group Chief Executive

And on the refining margin, we've assumed a $14 refining margin, and it's static in those numbers on that slide.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

Just to add to that, I think $14 when we are sitting right now, $12 – $8 may look low. But actually if you look at last 10 years, except the financial crisis of 2009 and 2010 and this year, refining margins have been either around $14 or above that, just to give you a perspective on that.

Brendan Warn - BMO Capital Markets Ltd.

Okay, thanks, gentlemen.

Robert W. Dudley - Group Chief Executive

Thanks, Brendan.

Jessica Mitchell - Head-Group Investor Relations

We'll go next to Lydia Rainforth of Barclays.

Lydia R. Rainforth - Barclays Capital Securities Ltd.

Good afternoon. I'm going to ask three questions, if that's okay. The first one was coming back to the Deepwater Horizon liabilities and the comment, Bob, you made to us about drawing a line under it 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 couldn't do before?

The second one was just for Tufan on the downstream side and particularly on the fuels marketing side and the impressive side you've shown in terms of growth of profitability in the fuels marketing side of about 55% in the last two – 2.5 years. Is that actually repeatable on the fuels marketing side over the next three to four years?

And then just final one, if I could, just on the upstream, Bernard, do you have an estimate for the base decline rate for 2016 so far and where that is running compared to expectations? Thank you.

Robert W. Dudley - Group Chief Executive

Great, Lydia, three varied questions there, I think good questions. So what does it practically mean to be able to identify a total pre-tax 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's always been in the back of our minds. Have we got this right? We weren't able to quite identify all 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've had a significant increase in the claims process using some of these specialized frameworks of that. And we've 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 of certainty because business doesn't like uncertainty. I think it also gives some certainty to the ratings agencies as they look and they look at BP and its future. There's always been a little bit of a question mark with the ratings agencies. 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 can't 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.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

Okay, fuels marketing, a couple of things. I think Bob mentioned earlier, first of all, to say actually marketing is a material part of our business. I'll say right now if you look at how much we make last 12 months from fuels marketing plus lubricants, it's actually around $3.5 billion. So you know the lubricants number, therefore you can come up with the fuels marketing number, which is higher than the lubricants number. So one actually it is material. Second thing is both of these businesses have return profile above 25%. These are pre-tax, 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'll give you one example. This market, the UK, frankly in the UK, the last three years we have been achieving double-digit ARCO (1:21:56) growth, I mean 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.

Bernard Looney - Chief Executive Officer-Upstream Division

Hi, Lydia. On the base decline for the first half, I think all I would say is without giving a specific number, our underlying production in the first half of the year is broadly flat. The second quarter it was up. For the first half, it was broadly flat on an underlying basis.

I think you'll know that the projects that we've started up in the first half of the year are very, very modest. Angola LNG, we've lifted four cargos out of there. Thunder Horse water injection, obviously no production, no immediate production contribution from that. We've had Point Thomson in Alaska and In Salah Southern Fields. So I think you can get a sense from that base decline continues to be performing quite well for us. And as we said in Baku, we're 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 of 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.

Lydia R. Rainforth - Barclays Capital Securities Ltd.

It does, thank you.

Jessica Mitchell - Head-Group Investor Relations

Okay, great. Next question from Pavel Molchanov of Raymond James in the U.S.

Pavel S. Molchanov - Raymond James & Associates, Inc.

Thanks for taking the question. Going back to one of the earlier ones about your plans for Iran, and I respect the fact that you don't 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's going to go in and who's not? Anything you can share on BP's plans for partnering with PEMEX?

Robert W. Dudley - Group Chief Executive

We have a very good relationship with PEMEX and Mexico. We've worked there a long time. We've had people working there for a long time. It's a place we would like to work, and we think that the skills 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. I can't really comment yet on the terms because they're not out there yet and I don't know the details, but it's a place that could be a natural fit with BP. But let's see.

Jessica Mitchell - Head-Group Investor Relations

Okay, thank you. Next question from Thomas Adolff of Credit Suisse. Go ahead, Thomas.

Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.

Hi, Jess. Thanks. I've got a few questions, please, one for Tufan and again going back to refining. I can see your breakeven has improved significantly. But obviously, as we all know, the refinery margin environment is quite tough. So I wondered whether any economic run cuts are yet evident in BP's portfolio. If not, at what market margin would that be the case? And then I also had a more general question. Seasonally, the additional demand that we see, do you think, Tufan, they will be met by higher runs globally or from actually drawing down the extra 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 press, some midstream assets. And in light of Brexit and who knows what will happen with Scotland, are discussions vis-à-vis those assets on hold? And with that, are you still confident you can deliver up to the $5 billion in disposals?

And my final question on bolt-on deals, I wanted to know whether the bid/ask spreads are much narrower versus, say, six months ago. Thank you.

Robert W. Dudley - Group Chief Executive

Great, Thomas. Go ahead, Tufan.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

Should I start with refining?

Robert W. Dudley - Group Chief Executive

Yes, absolutely.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

So I think refining at this point, do we experience in our portfolio any refining cuts? No, but I know in the industry I actually see some competitors, competitor refineries, less competitive refineries effectively starting to cut their runs and the current margins definitely. I'm not going to give you at this point 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 affected by that, which is not actually captured in our RMM [Refining Marker Margin], 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 runs. Therefore, if this continues like that, it is logical to expect our utilization to go down in the industry. And the demand level is still relatively strong. It's 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.

Robert W. Dudley - Group Chief Executive

And, Thomas, on divestments, so far this year we closed $1.9 billion of divestments. Ninety percent of those have been in the downstream. You'll know that divestments are not a smooth quarter-on-quarter process. They come from the different points. The one 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've seen.

I would say we're going to look at a lot of options. I'm confident we'll be in the $3 billion to $5 billion range this year. We've got a lot of different talks going on. I'm not really going to identify where they all are. Some of them may come up at the end of this year. Some of them may move into the first quarter of next year. But we're very confident of the list here, and we've got them all over the world in fact. And some of the discussions we've got going on, we're not going to overdo it with divestments after $75 billion now done. But we'll always look for good options if there's value there.

Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.

Great, and on bolt-ons?

Robert W. Dudley - Group Chief Executive

On bolt-ons, you raise a good point. I think in many places around the world right 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've deepened in the Culzean field in the UK, as one example. But there right now, I think there are unrealistic expectations. I think there's a higher price built into what many people are asking for the sale of their assets, and we're just not going to bite.

Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.

Perfect, thank you very much.

Jessica Mitchell - Head-Group Investor Relations

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

Irene Himona - Société Générale SA (Broker)

Thank you, Jess. Good afternoon, gentlemen, two very quick questions. Firstly, downstream on slide 27, you show a change in earnings sensitivity effectively to the refining margin. My question is, is this captured in your published rule of thumb sensitivity to the downstream, which I think or was $500 million per dollar movement 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.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

I'll pick up the effective refining margin and downstream question. If you look at that chart, what that chart is showing is effectively by improving our underlying performance by $2.4 billion, frankly, we reduced – and this is total downstream. It is not refining. Sometimes there's confusion. We effectively reduced how much refining margin required to deliver – we took 15% returns as a base here, saying this is good returns. Obviously, we will look to improve 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 in line with in many ways our rule of thumb assumptions, which is also on an RMM basis as well.

Irene Himona - Société Générale SA (Broker)

Okay, thank you.

Robert W. Dudley - Group Chief Executive

Okay, Irene. On the tax rate, the underlying effective tax rate this quarter was 21%. And our historic range has been in the 30% to 35% a year. But this is a good example first half. It's a range around 20%, and that's really due to the change in the mix of profits at the lower oil prices. There are parts around the world where of course profitability is down. So we've 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 20% and getting up to the 30% – 35% that we've had more historically. I think going forward, we would expect to be not at the historic rate. We'll be lower than that.

Irene Himona - Société Générale SA (Broker)

Okay, thank you very much.

Jessica Mitchell - Head-Group Investor Relations

Okay, thanks, Irene. And we'll go next to Guy Baber of Simmons. Are you there, Guy?

Guy A. Baber IV - Simmons & Company

Yes, thank you very much. You've 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?

Bernard Looney - Chief Executive Officer-Upstream Division

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 costs down 28%, head count down over 50%. As a result, the breakeven 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've 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 investment. So we think this is meeting our hurdle rates. It's a good investment. So we've actually let a little bit of capital 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 to four rigs there at the moment. That's 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 set ourselves and we set the entire company and sustain a capital rate around what we're seeing today, maybe a little bit more, and an activity level that I think will be in the range of between five and 10 rigs as we 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're very, very pleased with the performance of that business in Dave Lawler's hands.

Guy A. Baber IV - Simmons & Company

That's very helpful. Thanks, Bernard.

Robert W. Dudley - Group Chief Executive

Guy, let me just add a few things on that. I think this is a business that isn't well understood. We're excited about it, as Bernard said. We've got 6 million net acres. We've got 24,000 wells. 10,000 of them are operated, and we've got a resource base of about 7.5 billion barrels of oil equivalent there. So there's 37 Tcf of gas and about 1.2 billion barrels of liquids. And we've got about 1,500 horizontal laterals identified that we can move on, about 40% of the resource yet to drill, which is we can see it's economic at less than $3 gas and less than $55 oil. So this is a business, as Bernard said, that's got a lot of potential. Go ahead, Guy, sorry.

Guy A. Baber IV - Simmons & Company

You bet. With final certainty now around 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 base and the bid/ask spreads still remain wide, does the appetite for M&A change at all here, and the willingness or desire to capture some of bottom of the cycle opportunities with that certainty now?

Robert W. Dudley - Group Chief Executive

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

Guy A. Baber IV - Simmons & Company

Just in general globally, Lower 48 or elsewhere.

Robert W. Dudley - Group Chief Executive

I think as we talked about bolt-ons earlier, those clearly where you have a competitive logic to bolting onto what you're doing, I think our appetite is clear there when the opportunities come along. Bottom of cycle, we're certainly seeing it in the cost structures. As Bernard said earlier, we're still seeing costs come down in Mad Dog, for example. So is it now the bottom of the cycle? Is it six months? I don't know. But what we need to do, we've done such a good job of having discipline around our capital framework and our financial framework. We don't want to drift out of that with enthusiasm, so we're going to keep the discipline on this. And I think there will be opportunities around the world. There already have been some.

Guy A. Baber IV - Simmons & Company

Great, thank you very much.

Jessica Mitchell - Head-Group Investor Relations

Okay, thank you, Guy. We'll take a question now from Alastair Syme of Citi.

Alastair R. Syme - Citigroup Global Markets Ltd.

Thanks, Jess. I had a very quick question. Just if you could, quantify or help us quantify the restructuring cash charges as a flow-through cash flow in first half 2016 and maybe how those compare to what happened in first half 2015.

Robert W. Dudley - Group Chief Executive

Right, Alastair. We expect a total restructuring charge of $2.5 billion by the end of next year. So far, we've had just under $2 billion, $1.9 billion since the fourth 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 – first half this year, the cash impacts have been $600 million on that.

Alastair R. Syme - Citigroup Global Markets Ltd.

So $600 million outflow through first half of 2016?

Robert W. Dudley - Group Chief Executive

Right, and the first half of 2015, a year ago, was $500 billion.

Alastair R. Syme - Citigroup Global Markets Ltd.

Okay, brilliant. Thank you very much.

Robert W. Dudley - Group Chief Executive

Thanks, Alastair.

Jessica Mitchell - Head-Group Investor Relations

So what happens, Alastair, is that the cash impacts show up a quarter to two quarters actually after the quarter in which we take the P&L charge. And so you would expect some cash impact still in 2017 even though we may get to the end of the P&L impact.

Alastair R. Syme - Citigroup Global Markets Ltd.

Okay, great. Thank you.

Jessica Mitchell - Head-Group Investor Relations

Okay, next question now from Chris Kuplent of Bank of America Merrill Lynch.

Christopher Kuplent - Bank of America Merrill Lynch

Thanks, Jess, just two very quick questions left. On your 2017 outlook, I think originally, Tufan confirmed the $14 a barrel refining margin assumption. I think originally you used a $3 Henry Hub assumption. Can you confirm that that's still the case?

And finally a question to Bob. I appreciate your offer, Jess, but I'm sure I will be in touch to ask about the payment schedule around oil spill payments. But I just 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.

Robert W. Dudley - Group Chief Executive

So first, Chris, thank you. On the refining marker margin, it is $14?

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

It is $14, yes.

Robert W. Dudley - Group Chief Executive

And the gas price...

Jessica Mitchell - Head-Group Investor Relations

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

Robert W. Dudley - Group Chief Executive

Which is $2.50, $2.50 Henry Hub.

Jessica Mitchell - Head-Group Investor Relations

Yes, $2.50 Henry Hub is the assumption on that.

Robert W. Dudley - Group Chief Executive

Pretty low, I think.

Jessica Mitchell - Head-Group Investor Relations

Yes.

Robert W. Dudley - Group Chief Executive

That's okay. And then on the oil spill payments, $2 billion to $3 billion a year has been our corporate churn for many, many years. And so it can be retail churn, it can be late life assets. So you're right. In our own thinking, that $2 billion to $3 billion a 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, as a $1 billion dividend that will go out to 2033 for the charges with the Gulf of Mexico. So it's just always part of our planning normally, $2 billion to $3 billion. And I think we'll just keep that in there. In our own mind, that's what we think about it as earmarked for.

Christopher Kuplent - Bank of America Merrill Lynch

Okay, thank you.

Jessica Mitchell - Head-Group Investor Relations

Okay. And, Chris, we'll follow up with you on that.

Robert W. Dudley - Group Chief Executive

Let me just say that we don't expect the oil spill charges to be $2 billion to $3 billion going out to 2033. They're like $1 billion a year starting I think in 2019 on.

Jessica Mitchell - Head-Group Investor Relations

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

Christopher Kuplent - Bank of America Merrill Lynch

Okay, thank you.

Jessica Mitchell - Head-Group Investor Relations

Okay. Next, Nitin Sharma from JPMorgan.

Nitin Sharma - JPMorgan Securities Plc

Thanks, Jess. Good afternoon, everyone, two questions for me, first one on project sanctions. Bob, you flagged multiple times the falling cost curve and the benefits that probably that holds for you. How does that falling cost weigh on your decision of FID-ing the projects now? Is it not better to wait and get more – make the project better?

And staying with project sanctions, maybe if you can talk about the commodity oil and gas price assumptions that you used for recent project sanctions, Tangguh, Atoll.

Second one on exploration budget of $1 billion, I'm looking at write-off expense build (1:43:33) of around $600 million in H1. So is it right to assume that run rate of exploration spend in H2 will be lower subject to obvious volatility of exploration write-offs? Thank you.

Robert W. Dudley - Group Chief Executive

Right, okay, a couple things, Nitin. Thank you. Project sanctions, we talked earlier about this being bottom of cycle. We've been really careful, as Bernard said, to really drive capital efficiency very, very carefully, which is why we have deferred sanctioning multiple projects. Tangguh came along, which was we think 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 didn't want those to go away. So we went ahead and sanctioned it. We think it's the right time in the cycle.

We'll be really careful about whether we sanction these. But right now, as Bernard said, the costs of Mad Dog, for example, have come down and we just continue to refine and simplify some of the engineering. And we'll pick this very, 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. Mad Dog will be under $40 a barrel by the time we're done on that, for example. So 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've assumed, so talking about natural gas for a second, it's easy to follow Henry Hub. But in reality, a lot of the world doesn't work off of Henry Hub. And so whether it's in Egypt or whether it's in Oman, we are supplying gas into local markets and have contracts in place that provide a good rate of return, and I think we can see that in India, for example. So it's 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. And then we'll be careful about LNG. Tangguh makes sense. We've deferred Browse with our partners, for example, where it doesn't make sense. And now in oil, there are good projects out there. We'll just be really careful how we design them.

Now on exploration, there's always this lag between when you've spent exploration and when you turn them into projects or if they need to be eventually written off, so there's quite a lag in this. The first half exploration write-offs for the first half of the year were around $420 million. That's 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've drilled, we're appraising them, that we have decisions to make. So it's 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.

Nitin Sharma - JPMorgan Securities Plc

Fair enough, thank you.

Jessica Mitchell - Head-Group Investor Relations

Okay, thank you, Nitin. Lucas Herrmann now from Deutsche.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

Jess, thanks very 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. When you talk around cash coverage of dividend or operating breakeven, $50 – $55, do you think about the dividend after a scrip element or before it? In other words, are you thinking about the full cash cost of the dividend, or when you talk around breakeven, are you thinking about the dividend post an average level of scrip of some kind?

Robert W. Dudley - Group Chief Executive

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

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

All right, thank you very much for that clarity. And, Bob, further out, the sunny uplands when your oil does hopefully recover to a price where you're 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's being issued at scrip or issued as 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 of the board is going to be towards actually repatriating equity?

Robert W. Dudley - Group Chief Executive

Good question, Lucas. We recognize it dilutes shareholders, all 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'd like to offset the scrip dilution at some point in the future. We have done buybacks in the past. As you know, it's a matter for the board. But there's 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.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

Okay. Bob, thanks, and one final quick one. Pascagoula, what's the impact on volume for you in Q3, assuming a continued outage?

Robert W. Dudley - Group Chief Executive

I'm going to turn that one over to Bernard. He's on it almost every day now.

Bernard Looney - Chief Executive Officer-Upstream Division

Hi, Lucas.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

Hi, Bernard.

Bernard Looney - Chief Executive Officer-Upstream Division

Yes, it's 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 to 35 MBD in the quarter as an impact from Pascagoula. That's our current view of things.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

And that's crude as well, or is that just – I appreciate it's a gas processing plant, but does it prevent you...

Bernard Looney - Chief Executive Officer-Upstream Division

Yes, that's the impact on the GoM crude and gas production. So the oil equivalent production impacting the quarter is about 30 to 35 MBD.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

Okay, you don't want to split it for me, do you, Bernard?

Bernard Looney - Chief Executive Officer-Upstream Division

I'd prefer not to, Lucas, but thank you.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

All right.

Robert W. Dudley - Group Chief Executive

I think the reason is because it also affects other – you split ours, it affects other companies as well. It's not just ours, and we can mislead you I think there.

Lucas O. Herrmann - Deutsche Bank AG (Broker UK)

Lovely. Gentlemen, thanks very much.

Robert W. Dudley - Group Chief Executive

Thanks, Lucas.

Jessica Mitchell - Head-Group Investor Relations

Okay, Biraj Borkhataria of RBC.

Biraj Borkhataria - RBC Europe Ltd. (Broker)

Hi, thanks for taking my questions, two quick ones, if I could. First one 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.

And the second one, probably one for Bernard, but could you just update us on the receivables balance in Egypt? Thanks.

Robert W. Dudley - Group Chief Executive

Right, Biraj. Of course, the $5.2 billion charge is a most likely estimate of all the liabilities. And so many of the liabilities between the BEL and the opt-outs are excluded. Those are people that 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.

Biraj Borkhataria - RBC Europe Ltd. (Broker)

I'm just trying to get to what's going to be paid out for the rest of this year and then what's to be spread over from now to 2019. So any info on that would be much appreciated.

Robert W. Dudley - Group Chief Executive

I think it will mostly be paid out by the end of this year. The large portion relates to the BEL. And the $5.2 billion is a post-tax charge. There's 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'd 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. I think I'd just leave it at that. I know that's hard to model, but it's the reality.

Biraj Borkhataria - RBC Europe Ltd. (Broker)

Many thanks. And then the receivables balance in Egypt?

Bernard Looney - Chief Executive Officer-Upstream Division

Yes, Biraj, 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 investors' minds, so very high on their agenda.

I won't give you specific numbers. As you might understand, it's sensitive for the government, but I would say that we're in a good position on our receivables and overdues in Egypt today. We've worked very closely with the government in trying to find very innovative ways from how we spend Egyptian pounds to diverting some of our crude cargos and so on. So the government has been very, very cooperative, very supportive. They know it's an issue for foreign investors. And as a result, it's right up their priority list in terms of resolving, and we work very well with them. And we will obviously keep a watchful eye on it in the months and years ahead as our investment levels continue there. But today I'm actually quite comfortable with our position in the country in that regard. Hopefully that helps.

Robert W. Dudley - Group Chief Executive

They're way down from the fourth quarter of 2012.

Bernard Looney - Chief Executive Officer-Upstream Division

Very much, yes.

Jessica Mitchell - Head-Group Investor Relations

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

Robert West - Redburn (Europe) Ltd.

Hi there, thanks. I've got a question for each of you. Starting with Tufan, I noticed petrochemicals is the second quarter in a row now around $100 million a year of operating profit. So we're not quite back at the glory days of 2010 or 2011, but it's definitely the best quarterly run rate for about five years. Could you just tell us? What is the single biggest contributor of that improvement?

Then second question for Bernard, can I ask you about the decommissioning provisions that you're likely to report at the end of the year in your 2016 Annual Report, just based on the trends you're seeing there? Apologies because I backed this out, so the system 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?

And 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. But if I make you think about it in the way that I think the rating agencies do, that's more of an expanded net debt to 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.

Robert W. Dudley - Group Chief Executive

Okay, thanks, Rob. Okay, go ahead.

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

I'll start with petrochemicals, Rob. Thanks for the question. Just to tell you, actually when we set our strategy early 2015, what we said is on petrochemicals, we are not going to rely on the environment. We are going to create a business which is a robust environment. So what that meant is we were going to focus on expanding the earnings potential of the business. And on that you are absolutely right. In a similar environment, like last 18 months, if you look at 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 as an opportunity, we will be able to go beyond 35% and also bring forward 35% reduction to an earlier day. So what is driving all this is there's 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. And we are not done, frankly, with our program yet.

Robert West - Redburn (Europe) Ltd.

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?

Tufan Erginbilgic - Chief Executive Officer-Downstream Operations

No., it was more, frankly, more breakeven level. Obviously, it depends on which day you look at these things. But the impact of that on this $300 million is almost non-existent. So it is very, very small. That's how you should think about it.

Robert West - Redburn (Europe) Ltd.

Great, thank you. Thank you, Tufan.

Bernard Looney - Chief Executive Officer-Upstream Division

Hi, Rob. It's 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, 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 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 we've got within our assumptions are consistent with what we're 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's something that we continue to keep under a close eye. And I think in the long run, it's an area of opportunity for the company and for the industry if we can continue to find different ways of doing this. And the performance that we've had on Valhall on the well side gives me a lot of hope in that space.

Robert West - Redburn (Europe) Ltd.

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

Bernard Looney - Chief Executive Officer-Upstream Division

I'd prefer not to project it just yet, Rob.

Robert West - Redburn (Europe) Ltd.

Okay, no worries. That's fine.

Bernard Looney - Chief Executive Officer-Upstream Division

I think it's too early to do that. But rest assured that we're continuing and will continue to work it to make sure that it's accurate and reflects our current performance.

Robert West - Redburn (Europe) Ltd.

Okay, thank you.

Bernard Looney - Chief Executive Officer-Upstream Division

Thanks, Rob.

Robert W. Dudley - Group Chief Executive

And, Rob, you raised 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're comfortable right now.

You're 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 levels increased this quarter by $2.6 billion because we did issue some new debt., but that more than offset a repayment of – we had about $1.3 billion of maturing debt.

To give you a sense of what it means, a $1.6 billion movement in the net debt causes a 1% move in the gearing as a rule of thumb for us. I think we've got a prudent level of liquidity, so we're anticipating only moderate levels of new debt issuance during the remainder of the year. I think we will have – $1.9 billion will mature by the end of the year. And then as we look into 2017, there's $6 billion of debt maturing. We think all this is quite manageable, and we obviously have our reviews with the agencies periodically here. But you're right, what you raise is a very important point.

Robert West - Redburn (Europe) Ltd.

Great. Thank you. Thanks.

Robert W. Dudley - Group Chief Executive

Thanks, Rob.

Jessica Mitchell - Head-Group Investor Relations

Okay. Martijn Rats of Morgan Stanley, are you still there, Martijn?

Martijn P. Rats - Morgan Stanley & Co. International Plc

Hi. Hello, yes. Frankly, there are two somewhat technical issues to pick off. If you look over the last couple of quarters and you take the deferred tax liabilities and you net them off against the deferred tax assets, you see a continuing shrinkage of these net deferred tax liabilities. And of course, the traditional interpretation is of course that the actual tax payments catch up with the tax expense and that you're paying more than you've 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 should suggest that in terms of operating cash flow, this effect 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 is indeed correct or whether there is 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 becomes a cash flow tailwind?

The second question, one that I wanted to ask you, is regards to price realizations. I know that volumes in the quarter were quite low, but price realizations of $55 a barrel in the category rest of the world seemed 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?

Robert W. Dudley - Group Chief Executive

On deferred taxes, you've touched on that one. I know you're trying to model this. This is probably one of the most complicated subjects. As you'll 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 are 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 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.

Martijn P. Rats - Morgan Stanley & Co. International Plc

Okay.

Robert W. Dudley - Group Chief Executive

And it's probably just the opposite of headwind, I would say.

Martijn P. Rats - Morgan Stanley & Co. International Plc

Okay.

Jessica Mitchell - Head-Group Investor Relations

Okay.

Robert W. Dudley - Group Chief Executive

And then on the rest of the – on the oil realizations, I think excluding Iraq in the second quarter, rest-of-world oil realizations were $55.10 a barrel with Iraq. And excluding it is $44.32 a barrel.

Martijn P. Rats - Morgan Stanley & Co. International Plc

Okay. Okay. So that is purely an Iraq effect?

Robert W. Dudley - Group Chief Executive

Yes.

Martijn P. Rats - Morgan Stanley & Co. International Plc

So if the volumes are lower in the third quarter because of the region...

Robert W. Dudley - Group Chief Executive

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

Martijn P. Rats - Morgan Stanley & Co. International Plc

Okay. Okay, thank you.

Robert W. Dudley - Group Chief Executive

Okay, thanks, Martin. You've been very patient.

Jessica Mitchell - Head-Group Investor Relations

Okay, thank you. We'll take the last question from Iain Reid of Macquarie. Go ahead, Iain.

Iain Reid - Macquarie Capital (Europe) Ltd.

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 aren't that far away from the $50 you had talked about there, 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 direction of travel you see in the near term is on that?

And then I've got a couple of questions on your post-2020 major projects as far as on page 25. Just an update, if you can, on where you are on the ACG PSA extension negotiations with the government. I know there's been some media stuff on that. And also an update on where you are on GoM Paleogene projects because there's been a distinct lack of news on those recently.

Bernard Looney - Chief Executive Officer-Upstream Division

Okay. Iain, I'll 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've made there, the pre-tax proxy projection that we've made is at prices that are similar to today. We're quite a ways from that today. But as you can tell, we're 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're top quartile in operating costs today. We intend to continue to push and to drive that further. So you'll see more coming – you'll see contribution from cost coming through to that $7 billion to $8 billion. You'll 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're seeing that right across the company, driving cost and capital back to levels last seen when oil was $40 to $50 like in 2005.

And of course, you're going to see it in production and in margin. And we're going to bring on the 800,000 barrels a 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'll see where the – that's a breakdown of where it will come from. It'll come from every aspect of the business, and obviously inside the business we're trying to do better than that, and we'll see where we turn out. So that's the basis of the $7 billion to $8 billion. On the Paleogene and the Gulf...

Iain Reid - Macquarie Capital (Europe) Ltd.

Any chance you give us a rough number where you are on that, whether it's positive or not at the moment?

Bernard Looney - Chief Executive Officer-Upstream Division

I think it's 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. 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's happening to our cost base, what's happening to the productivity of the capital and the physical things that are happening with the projects, you'd 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 we're continuing to work it. We've got the partnership with Chevron. They're bringing their experience from their developments. They're helping us. The partnership is working well. We're continuing to work Kaskida. So all I would say is that continues to be worked. We need to make a project if it's going to happen there economic. We're continuing to get results from the wells, which generally are in line with what we're expecting. And we're continuing to work development concepts.

Robert W. Dudley - Group Chief Executive

And then, Iain, just to comment on ACG, I've seen some of the press reports, which I think are not accurate. We're working with all the partners and SOCAR now. We're looking again to look at some new life-of-field development options for ACG. That work is going pretty well. So BP and all the partners, which are all great companies and SOCAR we're working together to see how we might implement this in an extension. We're pleased with the progress so far, and everybody is looking forward to doing this. And I think some reports of tension I think don't really reflect what's happening. I could leave it...

Iain Reid - Macquarie Capital (Europe) Ltd.

You're going to get that one done quite soon then, Bob? Is that the general message?

Robert W. Dudley - Group Chief Executive

What we're finding even with Mad Dog, as we go through and you look at new development options, we're 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 day-to-day contract was through 2022 or 2024. It's a while. But I think everybody would like to move forward with this. And these always contract extensions at the end of PSCs have to be done carefully and they take time. We're very optimistic.

Iain Reid - Macquarie Capital (Europe) Ltd.

Okay, thanks. Thanks a lot.

Robert W. Dudley - Group Chief Executive

My goodness, we've been going for two hours and ten 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've 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 and the full dividend over time assuming $50 to $55 a barrel. We expect to do that next year. Then we'll have organic free cash flow growth after that, we expect. The basis for this ongoing commitment we've got is really to sustain the dividend. That's the first priority in our financial framework. The inflows and the outflows, of course they'll 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'm sure that's going to happen, and we'll be between $15 billion and $17 billion next year depending on the oil price, but I think that's very likely.

Cash cost reductions, we're on track for $7 billion by 2017 versus 2014. And we're well through that, $5.6 billion now down. The divestments, $3 billion to $5 billion in this year, $2 billion to $3 billion in 2017 going forward, and just really rock solidly establish ourselves in that 20% to 30% gearing band going forward, which we had for years and we took it down to the 10% to 20% range after the Gulf spill.

So I think those of you who 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 don't see you, have a good summer. If not, we'll see you in another three months.

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