Welcome to the BP Presentation for the Financial Community Webcast and Conference Call. I now hand over to Jessica Mitchell, Head of Investor Relations.
Hello and welcome. This is BP's Q2 2015 results webcast and conference call. I'm Jess Mitchell, BP's Head of Investor Relations and I'm here with our Group Chief Executive, Bob Dudley and our Chief Financial Officer, Brian Gilvari. 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 U. K. And SEC filings. Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website.
Thank you. And now over to Bob.
Thanks, Jess, and hello, everyone. Thanks for joining us. It has been a very important quarter for BP. We reached agreements in principle in the United States to resolve the largest remaining liabilities in relation to the Deepwater Horizon oil spill. This has been recognized as a landmark step forward by all parties and leaves us all able to chart a much clear course for the future.
The 2nd quarter environment has also continued to test us. As you've seen, our upstream earnings for the Q2 remained under pressure, reflecting continued oil price weakness and the large maintenance program we have underway this summer. The result also includes some large non cash write offs. At the same time, there is clear evidence of the underlying strength and resilience of our businesses. Our downstream continues to perform strongly and there are clear signs of efficiencies, sustainable efficiencies and cost reductions right across the group.
Underlying cash flow for the quarter also improved. So I will start with an overview including our thoughts on the future. In a moment, Bryant will go through the results in detail. Then I want to come back and give you an update on our interest in Russia and take a brief look at progress in our businesses. After summarizing, there'll be time for Q and A.
I'd like to start with a reminder of the near term priorities we laid out in February. As you know, we have held the view for some time that oil prices will be lower for longer. But whatever the oil price charts look like, we are clear on what we need to do. To describe this simply, we focus on the 4 Ds of delivery, divestments, discipline and the dividend. On delivery, we've had a strong first half of the year.
Group safety performance has improved across a number of metrics compared with 2014. In the upstream, we have started up 2 new projects this quarter, both in Angola, while making strong progress on the milestones that support our next wave of startups. We've also completed 6 turnarounds as part of our major program for the year. And in the downstream, as you've seen, the business continues to perform strongly. We are seeing continued safe, reliable and efficient execution right across the group, downstream and upstream, which is maintaining operational momentum at the same time as we reset for the new environment.
Turning to our divestments. We continue to strike agreements toward our $10,000,000,000 program with $7,400,000,000 agreed to date. The total since 2010 is now roughly $45,000,000,000 not including the TNKBP divestment of 26,000,000,000 dollars On discipline, our work to reset capital and cash costs is now moving fast and I will show you in a moment. This all works towards our focus on rebalancing our financial framework to manage through a period of low oil prices, while sustaining our dividend as the first priority within that framework. We are confident these remain the right priorities for the near term.
Now turning to our ongoing work to reset capital and cost across the group. We now expect our organic capital expenditure to be below $20,000,000,000 for 20.15 compared to our guidance back in a $100 world of $24,000,000,000 to 26,000,000,000 This is being achieved for this year largely through rephrasing and pairing back of marginal activity. But we are also seeing benefits from deflation. Industry commentary suggests offshore costs are reducing rapidly and this is consistent with what we are seeing in our supply chain. This gives us confidence in sustaining a lower level of capital spend over the medium term, while maintaining the same growth aspirations.
We are also starting to see results from the many programs we have in place to reset our controllable cash cost base. We are realizing benefits from the investments we've made over the past few years in improving reliability and the simplification that followed the reshaping of our portfolio. As well, our intensified efforts to reset costs in response to the environment is gaining momentum. Total group cash costs year to date are around $1,700,000,000 lower than the same period last year. This is despite the inclusion of around $400,000,000 of rig cancellation costs taken as an operating item.
This is an encouraging early indicator of progress, especially given there is usually a lag before cost reductions fully reflect in results. What we are seeing is an organization that is adapting rapidly to a new environment by adopting a more cost conscious business model. And we will continue to identify more opportunities for simplification and efficiency. Non operating restructuring charges are currently expected to be closer to $1,500,000,000 by the end of 2015 relative to the $1,000,000,000 we announced back in December and reflects the faster pace. So we are in action on all fronts related to cost.
We are optimizing the scope of our activity, leveraging deflation in the supply chain and changing how we manage our own internal cost including extensive simplification of our organizational structures in every part of the business. We have by necessity become too complicated. We believe the benefits from the changes we're making are largely structural and will be sustainable over the long term. Let me turn now to a brief look at the longer term. Back in February, we anticipated a reset phase lasting around 2 years, during which our aim is to rebalance the group sources and uses of cash to underpin our dividend.
So our work on cost is a strong focus right now, but we are mindful to achieve this without compromising our longer term goals. This involves testing and getting even clear on the fundamental drivers of our business model in the new environment. We are taking the time and importantly, the opportunity to understand what deflation can deliver and how our portfolio might respond in a range of price scenarios. What I can tell you now is that we have some strongly held principles that will not change. Our focus on value over volume will remain.
It is central to our strategy and a guiding principle in any price environment. In practice, it means we constantly look to create value by optimizing and high grading our portfolio, whether through divestments, farming out early life assets, selective acquisition or simply finding smarter ways to work our portfolio harder as with the U. S. Lower 48. Our commitment to capital discipline is also unchanged.
As already noted, in the upstream, we expect to see an impact from deflation resulting in a structurally lower level of capital spend for a given level of activity over time. Our aim remains to define a disciplined level of capital spend to grow our portfolio in terms of both operating cash flow and production. To be clear, our strategy still aims to grow production, while seeing growth in operating cash flow as a better measure of value. It has become a lot harder to plan activity in the current environment, but we remain focused on 3 areas. First, it's about sustaining activity in our pipeline of core projects, ensuring every dollar of capital is optimally invested and leverages any deflationary opportunity.
We believe that the strong pipeline of projects and appraisal options we showed you at our Upstream Day in December extending well beyond 2020 are of sufficient quantity and quality to be a key driver of growth. As a reminder, over half of our production from new major projects to 2020 is already under construction and these projects remain on track. 2nd, we see management of our base oil and gas production as a significant lever. We continue to make excellent progress. Our producing assets are becoming safer and more reliable.
We are improving operating efficiency and working to maximize recovery from our reservoirs. This is enabling us to maintain historical levels decline within the boundaries of a lower capital budget. And third, we are constantly looking for new high value options to add to our portfolio near term. This can come, for example, through inorganic deepening in strategic areas or through a shift in exploration to more near field high value prospects allowing faster pull through. In the Downstream, we expect continued strong performance from a combination of our advantaged assets and our growth and efficiency programs.
Group wide, we believe that our balanced high quality portfolio and our ongoing focus on capital and cost discipline gives us a strong platform from which to define a model to grow shareholder value. This all works towards a final fundamental principle that of returning value to shareholders through distributions over the longer term. We will, of course, share more detail with you as the environment firms and our plans take stronger shape. The key point for today is that we have made a head start on resetting our capital and cost and believe we are well positioned for the challenges ahead. I'll now hand over to Brian to take you through the quarter.
Thanks, Bob, and hello, everyone. Starting with the environment. Brent oil averaged $62 per barrel in the 2nd quarter, up from $54 per barrel in the 1st quarter, but still significantly below the average of $110 per barrel in the same period last year. Oil prices have fallen back again over the last few weeks in response to persistent weakness in market fundamentals. Although demand has been stronger, OPEC production is running higher than the 2014 average and production in the United States has remained resilient.
The recent agreement to lift certain Iranian sanctions has also raised the prospect of additional production coming onto the market. Henry Hub gas prices averaged $2.65 per 1,000,000 British thermal units in the 2nd quarter, over 40% lower than the same period in 2014 and slightly lower than the Q1 average. Continued strong growth in gas production has left the market oversupplied pushing gas prices down to levels that compete with coal for power generation. Our global refining marker margin averaged $19.40 per barrel in 0.40 dollars per barrel in the Q2, the highest level since the Q3 of 2012. Margins have been supported by strong gasoline demand, tight supplies on the U.
S. West Coast and low product stocks outside of the United States. At the same time, U. S.-Canadian crude differentials were at their narrowest since the Q2 of 2,009. We expect oil prices to remain soft over the short to medium term, while we expect refining margins to respond to changes in regional supply demand as we see out the summer driving season in the United States.
So turning to the results. BP's 2nd quarter underlying replacement cost profit was $1,300,000,000 down 64% on the same period a year ago and 49% lower than the Q1 of 2015. Compared to a year ago, the result reflects significantly lower upstream realizations, higher exploration write offs including additional one off charges associated with Libya and the reduced contribution from Rosneft, partly offset by a strong downstream performance and lower cash costs across the group. 2nd quarter operating cash flow was 6.3 $1,000,000,000 And we've taken a further $270,000,000 non operating restructuring charge in today's results, bringing the cumulative charge to $920,000,000 against the near $1,500,000,000 charge we now expect to see before the year end. The 2nd quarter dividend payable in the 3rd quarter has been announced as $0.10 per ordinary share.
Turning to highlights at a segment level. In upstream, the underlying 2nd quarter replacement cost profit before interest and tax of $490,000,000 compares with $4,700,000,000 a year ago and $600,000,000 in the Q1 of 2015. Notably, upstream earnings were impacted by around $600,000,000 in Libya, including exploration write offs and other costs, primarily due to circumstances in the country. Compared to the Q2 last year, the result reflects significantly lower liquids and gas realizations and higher exploration write offs, partly offset by lower cash costs, including the benefits from simplification and efficiency programs. Excluding Russia, 2nd quarter reported production versus a year ago was 0.3% higher.
After adjusting for entitlement and portfolio impacts, underlying production decreased by 1.7% mainly due to increased turnaround activity, partly offset by the ramp up of major projects, which started up in 2014. Compared to the Q1, the result reflects exploration write offs of $800,000,000 relative to a charge of less than $100,000,000 in the first quarter and the impact of our seasonal turnaround program, largely offset by higher liquids realizations and the absence of cancellation charges relating to 2 deepwater rigs. Looking ahead, we expect 3rd quarter reported production to be broadly flat compared to the 2nd quarter, primarily reflecting levels of maintenance activity comparable to the Q2. In the Downstream, the 2nd quarter underlying replacement cost profit before interest and tax was $1,900,000,000 compared with $730,000,000 in the Q2 last year and $2,200,000,000 in the Q1. This result contributed to strong first half earnings delivery for Downstream.
The fuels business reported an underlying replacement cost profit before interest and tax of $1,400,000,000 compared with $520,000,000 in the same quarter last year and $1,800,000,000 in the Q1 of 2015. Compared to a year ago, this reflects an improved refining environment and production mix, partially offset by weakened North American crude differentials, a higher oil supply and trading contribution returning to average levels for the quarter and cost benefits from simplification and efficiency programs. Compared to the Q1, the result reflects a lower oil supply and trading contribution relative to a strong first quarter and higher seasonal turnarounds, partially offset by improved refining margins and fuels marketing volume growth. The lubricants business delivered an underlying replacement cost profit of $400,000,000 in the 2nd quarter, compared with $310,000,000 in the same quarter last year and $350,000,000 in the Q1 of 2015. This strong quarterly performance reflects continued momentum in growth markets, premium brand performance and benefits from our simplification and efficiency programs leading to lower costs.
These benefits were partially offset by adverse foreign exchange The petrochemicals business reported an underlying replacement cost profit of $80,000,000 in the 2nd quarter. Looking forward to the Q3, we expect reduced refining margins and lower levels of turnaround activity. Turning to Rosneft. Based on preliminary information, we have recognized $510,000,000 as our estimate of BP's share of Rosneft's underlying net income for the Q2 compared to around $1,000,000,000 a year ago and $180,000,000 in the Q1. Our estimate of BP's share of Rosneft's production for the Q1 is just over 1,000,000 barrels of oil equivalent per day, an increase of 1.8% compared with a year ago and 1% lower than the previous quarter.
Further details will be made available by Rosneft with their results. Earlier in July, we received our share of the Rosneft dividend in respect of 2014, which amounted to $271,000,000 after tax. In other business and corporate, we reported a pretax underlying replacement cost charge of $400,000,000 for the 2nd quarter in line with guidance. The underlying effective tax rate for the 2nd quarter was 35%. Excluding the 1 off North Sea deferred tax benefit report in the Q1, we continue to expect the full year effective tax rate to be lower than the full year 2014 figure of 36%.
Turning to Gulf of Mexico oil spill costs and provisions. As we described on the 2nd July, BP Exploration and Production reached agreements in principle with the United States government and 5 Gulf Coast states to settle all federal and state claims arising from the Deepwater Horizon oil spill. The agreement with the states also provides the settlement of claims made by over 400 local government entities. The settlement provides for total payments of up to $18,700,000,000 over a period of 18 years. These agreements are subject to finalizing definitive agreements, which will include a consent decree with the federal and state governments, all of which will be subject to final court approval.
Yesterday, we signed releases from the vast majority of local government entities and we'll be making the payments required within the next few weeks. Turning to other Gulf of Mexico legal matters. The settlements do not include claims relating to 2012 class action settlement with the plaintiff steering committee including business economic loss claims not provisioned for private claims not included within the class action settlements or private securities litigation in MDL-two thousand one hundred and eighty five. The charge taken for the incident for the Q2 was $10,800,000,000 which takes the total cumulative pre tax charge to $54,600,000,000 This reflects around $10,000,000,000 associated with the government settlements just mentioned around $460,000,000 related to business economic loss claims not provided for, adjustments to other provisions and the ongoing costs of the Gulf Coast Restoration Organization. It is still not possible to reliably estimate the remaining liability for business economic loss claims and we continue to review this each quarter.
The pre tax cash outflow on costs related to the ore spill for the 2nd quarter was $110,000,000 This slide compares our sources and uses of cash in the first half of twenty fifteen to the same period a year ago. Operating cash flow in the first half was $8,100,000,000 of which $6,300,000,000 was generated in the 2nd quarter. This compares with $16,100,000,000 in the first half of twenty fourteen $7,900,000,000 in the Q2 of 2014. Excluding oil spill related outgoings, first half underlying cash flow was $8,900,000,000 This reflects the impact of lower oil prices on earnings as well as a build of $1,400,000,000 in working capital in the first half of 2015, which we expect to unwind as the year progresses. Our organic capital expenditure was $8,900,000,000 in the first half and $4,500,000,000 in the second quarter.
We received divestment proceeds of $2,300,000,000 in the first half of twenty fifteen, including $530,000,000 in the second quarter. Now turning to financial framework and the approach we laid out to you in February. We now expect organic capital expenditure to be below $20,000,000,000 in 20.15 and have agreed $7,400,000,000 of our $10,000,000,000 divestment program. We are taking advantage of sector deflation to continue to optimize our capital costs, while actively resetting our cash costs to deliver sustainable efficiency. These changes are largely structural and they support our principal objective of rebalancing sources and uses of cash, so that underlying operating cash flow covers capital expenditure and dividends.
We are working to reestablish this balance for a sustained weaker environment. And lastly, just a few words on gearing. Our policy since the Deepwater Horizon incident has been to maintain gearing within a band of 10% to 20%, while uncertainties remain. At the end of last year, our balance sheet reflected gearing at 16.7% well within this band against the backdrop of the near $100 per barrel average oil price environment in 2014. Gearing at the 2nd quarter stands at 18.8%.
This reflects average oil prices of $58 per barrel over the first half of this year and an impact of around 1% due to our recent agreements in principle to settle with the United States government and Gulf States. Once these agreements are finalized, a considerable uncertainty in relation to our financial framework will be removed, placing our gearing band in a much stronger context. Now let me hand you back to Bob.
Thanks, Brian. First, the recent developments in Russia. In June, Rosneft held their Annual General Meeting in St. Petersburg. Amongst other matters, shareholders approved the once a year dividend payable for 2014, as Brian mentioned and voted for the new Ross Neff Board.
In addition to my own reelection, we now have a second VP Executive on the 9 person Board, Guillermo Quintero. Guillermo is currently VP's Regional President in Brazil and is a highly experienced oil and gas executive. Beyond our shareholding in Rosneft, we recently signed agreements to purchase a 20% equity share in Rosneft's TAS project. This project is an existing conventional oilfield in Eastern Siberia, which currently produces around 20,000 barrels of oil per day. The full field development plan for TAS ramps up production to 100,000 barrels a day by the end of the decade with further potential for gas production.
Along with the TASS equity, we also agreed 3 conventional exploration areas of mutual interest with Rossnout. 1 in Eastern Siberia located around the Tas interest in a relatively unexplored region and 2, in the already prolific Western Siberian Hydrocarbon Basin. We are pleased with the progress both through our shareholding and also in partnership with Rosneft. As always, we remain mindful of the geopolitical situation, but look forward to continuing to pursue these and other potential opportunities where not prohibited by sanctions. Turning to the upstream and starting with exploration.
We made a high value discovery with the Atoll well offshore Egypt in the Q1. In the Q2, we've had a further gas discovery at the Nowruz prospect in the Abu Madi West lease. We expect production from this well later this year and we see follow on opportunities in neighboring BP operated blocks. In projects, we successfully started up Greater Plutonium Phase 3 in June, our 2nd major project startup in Angola this year. 2 further startups are planned for 2015.
The Insula Southern Fields project in Algeria and the Western Flank A project on the Australian Northwest shelf. We continue to make progress on a number of projects set to start up over the next few years, including in Oman and Shaddanese II projects among others. In our operations, we remain focused on the optimization of our base assets. We have completed 6 turnarounds this year with 3 currently underway and a further six yet to start. We are seeing the results of investment in our producing assets with BP operated plant reliability up from around 85% in 2011 to 94% in the first half of twenty fifteen.
Our asset specific plans in the U. K. North Sea have helped to improve BP operated plant reliability from 67% to 82% over the last 6 quarters. And in our drilling activities, we have decreased non productive time by over 20% since 2012. All of these efforts have allowed us to increase operating efficiency and support underlying production growth, while maintaining strict capital discipline.
As I highlighted earlier, we are resetting our cost base and capital frame and driving deflation and efficiency into the way we work across the upstream. Since the beginning of the year, we have been working with our suppliers to rebase our cost in some of our biggest areas of upstream spending and you can see a range of rate reductions we've achieved to date on the chart. We expect the benefits to show up in both capital expenditure and cash costs and examples include a 33% savings against the sub C installation budget on one of our Gulf of Mexico expansion projects. Another is negotiating a rate reduction of over 30 percent for drilling our latest development well on the Mungo asset in the U. K.
North Sea and around 10% rate reduction from major well service suppliers globally, including a 20% rate reduction on tubulars. We've also delivered additional through optimizing activities and processes. For example, an 18% reduction in logistics costs through more efficient use of boats and helicopters in our operated Gulf of Mexico assets, a savings of 19% from optimization of our repair and maintenance program in Angola and an 8% savings on well placement costs through improved monitoring utilization of components in Trinidad. At the same time, we are rightsizing our organization to reduce costs further. Since 2013, upstream staff headcount is down 8%, while agency headcount is down 37%.
Expatriate employee numbers are at their lowest level since 2011. And as we have said before, we are exercising strict capital discipline across the upstream. We are testing the resilience of project economics in a low price environment and progressing only the highest quality options in the portfolio. We are retaining optionality on remaining resources and recycling projects where we see potential for optimization. On our Mad Dog 2 project in the Gulf of Mexico, standardization, scope optimization and industry deflation is enabling us to develop around 90% of the resources using half the capital, whilst retaining optionality for future expansion.
Our global project team are now driving this agenda systematically across all of our projects worldwide. In the Lower forty 8 of the U. S, we have empowered our new business units to implement their own capital and operating efficiency improvements. We are beginning to see the benefits of these efforts. Operating costs are trending lower.
And in our Woodford and Haynesville assets, we have halved the cost of bringing new wells on stream. In the downstream, our strong first half performance demonstrates clear progress against the strategic goals we outlined in February this year. In fuels, our focus on advantaged manufacturing and marketing growth is beginning to deliver additional gross margin benefits with year on year pre tax earnings growth of $2,000,000,000 in the first half. We continued to upgrade our portfolio during the quarter and we ceased refining operations at our Bulwark Island facility in Australia. In addition, we recently announced together with our partner Rossneft, a planned reorganization of our German refining joint operation, which will further simplify our fuels organization and operations.
Our fuels marketing business is also experiencing growth with volumes up by around 2% year to date. In lubricants, our sustained focus on growth markets and premium products has contributed to strong first half pre tax operating profits, over 15% higher than 2014. And in petrochemicals, our new world scale PTA plant in Zhuhai, China is now fully commissioned and operational. This plant with its advanced technology is expected to operate with industry leading operating cost efficiency creating a higher earnings potential business more resilient to bottom up cycle conditions. Across the Downstream, we are also seeing significant year on year benefits from our simplification and efficiency programs.
Cash costs were 15% lower at the half year than the same period in 2014. This year to date reduction includes the benefits from a comprehensive simplification and efficiency program comprising some 30 initiatives that are currently underway. In addition to the announced proposal to restructure the German refining joint operation, we have simplified our fuels organization, reducing the number of businesses from 9 to 3 and are also simplifying our lubricants business structure. Together, these changes will eliminate duplication, reduce interfaces and simplify our route to the market. We're also streamlining our head office functions, eliminating activity, which does not directly support our strategy and simplifying the way we operate.
And these changes have reduced the number of downstream head office functions by over 50%. And in manufacturing, we're delivering efficiencies through the application of technology and implementing plans refinery by refinery to further improve our competitiveness. As well, we are maintaining strict cost discipline in our daily operations, including a focus on 3rd party costs. Taken together, these programs underpin the accelerated delivery of the $1,600,000,000 per we highlighted in February. So let me leave you with just a few thoughts in summary.
It is a challenging time for our industry, but I remain confident that moving quickly to simplify and reset the company for a sustained weaker environment is the right thing to do for all seasons. I believe we've made a good start. We are staying very focused on operational delivery. We're working steadily to complete our planned divestments and we are resetting capital and cash cost in a way that drives sustainable efficiencies. This supports our efforts to rebalance our sources and uses of cash and ensure we can sustain our dividend.
This is the clear priority within our financial framework right now. While the amount is very large, we also recognize that we have found a realistic path to closure on the largest remaining legal exposures in the Gulf of Mexico. Removing this legal overhang and uncertainty allows us to focus on our future. Looking further out, we see the strength of our portfolio and our strong commitment to capital and cost discipline, giving us a strong base from which to define the right model to grow shareholder value in a new environment. And I think on that note, I'd like to thank you for listening.
And now let's take your questions.
Thank you for waiting on the line everybody. We'll take the first question today from Jason Gammel of Jefferies. Are you there Jason?
Yes, I am Jess. Thanks very much and thank you for the presentation. My question is around the cost efficiencies that have been gained, the $1,700,000,000 year to date. You've made reference to having to absorb the rig cancellations within that. I would assume that this is a process that was ramping up for the beginning of the year.
So can you give us any color Bob and Brian around how sustainable this is in the back half of the year? Is there are there further gains to be made?
Jason, hi. Thank you. Well, there are further gains. We're sort of well into restructuring of cost in the
upstream and
we'll continue on later this year. Most certainly it will be in some of our big and we'll continue on later this year. Most certainly it will be in some of our big centers around the world Houston some more in Aberdeen. You're right the rig cancellation costs had we not done that when used it as capital we would have been seeing a higher cost reduction.
Yes. And actually also to point out that we've taken a higher restructuring charge as well this quarter just to flag that in December we'd said that we'd set aside $1,000,000,000 for restructuring. It looks now more like $1,500,000,000 for this year. And if you recall this program started on the corporate side post the big disposal program. Around about 2.5 years ago, we started talking to you about the restructuring of our corporate overheads.
That's really what led us down the path of $1,000,000,000 restructuring. We're now into the deflationary period in terms of deflation coming through now and the results in the cash costs. So I think you'll see more as the year progresses. And the additional restructuring charge we've taken this quarter I think is a signal of the small cost that come out of the system.
So can I just take
it from that that the controllable costs could be down by more than €3,400,000,000 on an annual basis?
No. I would never I think I've always said on these calls and I'd never, never go for multiples of what you see in the first half of the year. There's lots of moving parts to the numbers. The general trajectory though is still down.
Okay, great. Thanks.
Thanks, Jason. Over in the U. S, Blake Fernandez of Howard Weil.
Hi. Thanks, Jess. Brian, I wanted to clarify. You made some comments on the gearing band of 10% to 20% and obviously you're at 18.8% at the end of the quarter. With more clarity on the legal front, I just want to make sure were you kind of insinuating that that band could retrench higher back to the 20% to 30% level that we've seen in the past?
Yes. Thanks, Blake. I mean, I think it's really just putting it in the context of where we are. We moved to 10% to 20% band post 2010 as we refinanced the balance sheet. And I think it was just right with the degree of uncertainties both in terms of Macondo litigation, but also the general environment that we moved into that band.
I think the only point I'm making is that where we now sit in that band is a much stronger context now that we know the scale and scope of the liabilities pretty much the majority of liabilities associated with Macondo going forward. And the way in which that deal has been negotiated over 18 years creates the space to say actually within the current context that's a much stronger place to be. In terms of where we sit into the future, there are so many moving parts. We're not signaling at this point that we're moving out of that 10% to 20% band, but it's a far more comfortable place to be knowing what the liabilities are going forward.
Okay. Thanks. If I could just ask one follow-up too maybe of Bob. Bob, you've had a thesis of lower for longer on oil, which has proved correct so far. You've also come out recently in support of a carbon pricing system.
And project sanctions, the only project you really move forward on is a natural gas project. I'm just curious if you can elaborate a little bit if we could potentially have a strategic shift underway here in preference of gas over oil? Thanks.
Yes. Like we have just moved past the 50%. We're roughly right now at 50 percent of our portfolio in terms of production is now gas versus oil. Part of that is because we had oil projects coming on. And in the last 2 years, we have sanctioned significant large gas projects.
So down the road by the end of the decade, we'll be between 55% 60% gas when the Oman projects and the Chardanese projects come on. Strategic shift, I mean, it's clear that carbon pricing and carbon emissions are going to be a focus of the world. We think having that reduced carbon sense
that the world is
coming together in December the sense that the world is coming together in December. We think that the world really does need a framework to work within. Number 1 should be energy efficiency because that is the biggest single lever in terms of reduced emissions. And after that a carbon pricing that can be used by the world where the proceeds from that don't just go into the general funds of the world, but actually move to solving the transition to lower carbon energy over many decades. And we've taken a position on that with now 11 other companies in an oil and gas climate initiative.
It's going to be part of the focus. Strategic shift? I think so. I think it's a natural one with our portfolio and the projects we see ahead.
I appreciate the color. Thank you. Thanks, Blake.
Next question from Jon Rigby at UBS.
Yes. Thanks. Two questions actually.
The first just a point
of clarification on these cash cost reductions. Can you say is the EUR 1,700,000,000 the savings that you made over the first half of the year or where you're running ratably at the end of the second quarter, just so I can get a handle on that? And then secondly, just picking up on the high exploration charge that you've taken this time around, which a large portion is write off. So I understand that it's not cash. But I can see from your accounts that your intangible drilling costs, the stuff that you've got on the balance sheet, has been rising very significantly over the last 3 or 4 years.
Is the process of looking at your portfolio rescheduling when you go ahead with projects deciding whether those projects are appropriate or not going to have implications for what you're carrying on the balance sheet? And therefore, should we be expecting larger non cash costs over the balance of this year and maybe into 2016 running through the exploration charge? Thanks.
So, John, on the first question, it's a straight simple delta. It's just not run rate. It's the absolute quantum. It's €1,700,000,000 lower first half versus first half. On the intangibles, you're right.
I think last time I looked, it's tracking just below $20,000,000,000 in terms of exploration intangibles. And we'll continue simply to process each of those prospects. It's increased over the last 4 or 5 years given the amount of ramp up we've had in the exploration activity. So it's not surprising. The typical exploration write offs have been running at an average over the last 4 or 5 years around $400,000,000 a quarter.
You've seen more this quarter and even last year, but I don't think it's an indication of a trend that you should expect more and that continues to ramp up going forward. It's just a reflection as we look at specific projects. And Libya was a bit of a one off this quarter given where we got to with the process and what was happening in the country itself. So I wouldn't take that as a leading indicator for future.
Sort of filtering process ongoing?
Yeah. Yes. I mean, we're going through all the prospects right now. It's a good place to be in terms of the prospects that we have going forward. And some of those we'll choose to progress and some we won't.
Right. Okay. Thank you.
Moving on to Irene Himona of SocGen. Go ahead Irene.
Thank you, Jess. Good afternoon. Just two questions, please. Firstly, on lubes. In Q2, obviously, profit rose very substantially.
I think we were up 26% year on year. And for a long time, the average sort of quarterly run rate was around about EUR 20,000,000. In Q2, we are close to EUR 400,000,000. Given that you don't disclose anything other than profit, is there some guidance you can give us on whether the Q2 lubes profit is sort of sustainable going forward? And then my second question concerns dividend payout.
As you reset sort of costs and CapEx, do you look at the payout ratio at all? Is it part of your financial framework? Thank you.
Thanks, Irene. I'll take the lubes and then Brian on the dividend. I think we are seeing some things that are we don't give out the details of lubricants, but strong factor is the growth of some of our power brand sales and some of our lube brands like Edge and Magnetek and GTX, especially when the Americas and China. So I think we are seeing sustainable sales increases and volume increases in those markets which are growing.
And then on the question around payout ratios, absolutely, Irene, of course we look at those. It's important that we make sure that we can underpin the balancing of sources and uses of cash. And I think as Bob laid out in his comments, we could see the oil price getting soft at the middle part of last year. So we'd already laid in plans for this year at lower prices. Obviously, we saw the big drop off in the 4th quarter and we've adjusted things accordingly through this year.
And it will take a couple of years as we get things back into balance in terms of sources and use of cash. But yes, we do look at payout ratios. Thank you.
Thanks, Irene. Back in the U. S. Guy Baber of Simmons and Co.
Thanks for taking my question. Bob, I believe you mentioned that growth through the cycle was still a key objective for the company. So I was hoping you could just elaborate on that comment, particularly in light of the phasing of projects and the significant reduction to capital spending you all are achieving relative to the view just 12 months ago. So the question is, at sub $20,000,000,000 of CapEx annually, do you believe that that is enough capital to organically grow the business longer term and replenish the portfolio? Or would that level of CapEx need to be supplemented by some amount of inorganic activity?
Just hoping for some more thoughts there. And then I have a more specific follow-up as well.
Yes, Guy. We do think that we can see underlying production growth with the projects we have in these levels of capital out through the end of the decade. I think we can see with deflation, we can continue to develop these projects and move them forward and we'll just get more activity out of less CapEx going forward. So I think we can. And the deflation, I mean to give you some extent of the deflation across the various geographies and sectors, I mean rig rates have come down very quickly with drops of about 30% in some places and more already seen in some places.
You've got the real impact of oversupplied market there. Our development costs for new projects, we're projecting to deflate by as much as 20% to 30% depending on the project. So we think there is absolutely scope here for having growth through the cycle with lower capital.
Okay. Very helpful. And then I wanted to discuss also just the U. S. Lower forty eight business a bit more.
But you have a half year under your belt now that business operating as a separate entity. The macro environment has also changed tremendously from the time when you announced the separation there. So I was just hoping at this juncture you could give us an update as to how that business has performed relative to expectations, the extent to which perhaps you've been able to improve the cost structure and how that performance of that business is influencing strategy and your thoughts around capital allocation as you move into next year? And also how do you assess at this point the size of your position in the Lower forty eight relative to what you would view as strategically optimal?
Okay, Guy. That sounds like a half hour answer to a question.
It's a
good one though. So there's no question we feel like the we've improved the competitiveness of the business. We've done all kinds of structural things organized it into 5 sort of accountability based business units that can move very quickly in implementing sort of capital changes and cost reductions. So far the kinds of things we're doing is managing the producing wells better, new artificial lift. We're reducing our some of our costs to drill wells.
We've actually increased the number of rigs running from around 2 up to 10 now across the business units. At the end of 2014, we only had 2 in fact. We've got 7 in the Mid Continent area, 2 rigs in the East Texas and 1 rig in Wyoming. So we've also seen an increase from the drilling and the activity and the percentage of liquids, which is up it's up pushing 20%, about 18% now. So our production across the Lower 48 is about 280,000 barrels per day equivalent.
So we're pleased with it. Obviously, it's challenged with the lower prices right now, costs coming down. The team the executive team has come into that business. We have reduced the size of it in terms of the number of people. I think it's much more efficient and it's moved out of our Houston campus into lower overhead activity.
So I think it's we continue with the desire for it to be a market visible high return onshore operator in the U. S. It's got about 1200 employees today across 5 states. And we think this I wouldn't call it an experiment. I think it's a real restructuring activity we've taken on to be competitive.
We knew we weren't and they're doing a great job. So it gives you some sense of a guy without too much cost structures are coming down.
Thank you.
Okay, Guy.
Thanks, Guy. Back in the U. K, Tipan Joffilingam of Nomura. Go ahead, Tipan.
Yeah. Hi. Good afternoon. Thanks, Jeff. Just a few questions actually, please.
Firstly, just coming back to the PSC settlement. I just wanted to understand how you thought the admin charges would progress through this year. I mean is it right to think that now with the BEL claims and that deadline passed that charge starts to drop away? Secondly, just coming back to oil projects and FID, you talked about the reengineering on Mad Dog. Is that still a 2015 event in terms of sanctioning?
And what type of price do you test down to? What's your low case now in terms of oil prices for sanctioning? And then thirdly, Bob, I guess a concern for investors has been that you discussed selective acquisitions. So can you just sort of elaborate on what you think is the right type of strategic deal for BP scale type? And if you are in the lower for longer camp, is it right for BP to do a deal sort of in the next 6 to 12 months?
So maybe to be I'll just pick up that first question on the PSC settlement where we've taken additional administration charges this quarter, T Pen. We've now provisioned out to the end of 2018. If you look at the total number of claims still yet to process, there's still just about over 50% of the total claims still yet to be processed. We saw a big, big uptick in the last 10 days before the June 8 deadline. It's not clear what the quality of those claims will look like as the administrator works his way through that.
But we are working with the administration in terms of the administration of the costs of the PSC settlement. And of course, we do expect that to taper down by the end of 2018. But we've now fully provided what we believe to be the right level of administration costs going forward. And now it's simply a matter of what the business economic loss claims look like. And it will probably be another couple of quarters before we actually have sufficient actuarial data to make assessments on that in terms of forward provision.
But we'll continue to review that each quarter.
And on TPAN, Mad Dog as you know is a second phase of the Mad Dog field in Gulf of Mexico is a very prospective project that we've been working now with the settlement. I think it's clear about our investment plans in the United States. We're working with our partners there. As we've retooled and reengineered that project, the costs have come down substantially. We said at one time we may FID it before the end of the year.
I mean I think where we are now could be this could be towards the end of the year, it could be early next year. What we're finding is we see the deflation costs coming down. What we have to decide is at what point do we say they're going to continue to come down. We're just going to try to optimize the economic point of the FID. But it's still very much on the cards.
And in terms of acquisitions, it's never a good idea to talk about acquisitions or scale of acquisitions. I think what we will continually do is scan and screen for deepening in existing projects as a starter. I think that simplifies our activities without adding the overhead. That's an obvious one. And I think commenting on acquisitions, I think probably the bigger point for us is thinking about value over volume.
And so we're going to pursue the value. And I think we'll just see. I think the landscape is quite uncertain in the industry and it will be for some time and that will throw up all kinds of challenges and opportunities for companies that are well positioned for it. That's probably all I should say, T Pen.
Fair enough. And just I mean can you give any sort of parameters on what you're testing down to get in terms of project economics?
Yes. We yes sorry I forgot.
Sorry.
Are testing our projects believe it or not. We're certainly testing them right now and looking at decisions around the $60 mark. We're of course running and looking at it at $80 We even do a little stress test down at $40 but we think that they probably don't accurately reflect the cost structure today. So right now we're looking at these around the $60 mark.
Thanks, Scott. Very helpful.
We'll take the next question from Oswald Clint of Bernstein.
Thank you very much, Jess. Yeah. Bob, I had a question really on Russia and this kind of strategic move into East Siberia. I guess it wasn't it's not a big part of Rosnett or I guess TNK previously. So what's changed to make you kind of move over to that region where Corus, the geology is a little bit different?
Or is there can you talk about maybe how big you think this becomes? Does it could it become a new hub? And does it really fit into that category you were mentioning about near field exploration kind of pulling volumes through much faster? And then maybe secondly, maybe a question for Brian. In terms of the Lower 48 again, terms of your separate disclosure, I think you're saying $8 or $9 a barrel production costs, which I guess when I compare that to $4,000,000 to $0.50 other E and Ps looks pretty good already at least versus the average $2,000,000 or $3 less.
So I guess the question is have you really pushed it looks like you've done quite a bit already. Or is there kind of significant further movement on that number?
Thank you.
Oswald, I'll take Russia and then Brian. Actually, Oswald, if you look at East Siberian oil basins around in that area, there is significant activity by Rosneft out in that area. TNKBP had a very large field out there called the Virkna Chonskoy field and now is of course part of Rosneft. And it is an area where the East Siberian pipeline goes through. So there's quite a bit of discovered fields out there and an additional exploration AMI seems very appropriate given the basin geology.
And of course the Heartland a very, very large Western Siberian Basin which is sort of where everybody's big production in Russia is of all the companies. We have signed two areas of mutual interest there which is about 265,000 square kilometers. 2 very large areas there and we're conventional oil exploration out there as well. So we see both of those as sort of key to the activities of Rosneft and for BP not wanting to just be a financial investor in Rosneft to partner with them.
Oswald in terms of Lower forty 8, you're right to highlight it from the disclosures. It's down 6 percent in terms of production costs. And we will continue to expect that trend to continue to decline with the new team that we've got in place the new approach that we have to Lower 48%. So I think there's more to follow on this and you'll see that as the next 4 or 5 quarters progresses. But we are now running that business in a very, very different way to the way we were before.
Okay. Very good. Thank you.
Right. Doug Terreson at Evercore. Are you there Doug?
I am. Good afternoon everybody.
I have a couple
of questions. First because rightsizing the cost base is obviously becoming a pretty important objective, especially based on Bob's tone and comments today. I just wanted to see if there were any metrics or different markers that you guys have related to the different divisions that could provide a little bit more specificity? Meaning, we talked about group cash cost earlier, but is there any color that could be provided on the different divisions to just give us some insight going forward?
Yes. Doug, it's Brian. Maybe just pick it. I mean, probably the biggest indicators, which is one of the sort of tough areas for us is around headcount. As I said earlier, we started this in the corporate restructuring place where we're seeing significant headcount reductions both in terms of our own employees, but also contractors where we tend to run a bigger contractor workforce in places like IT and S.
But then if you look at the 2 divisions, you're also seeing significant headcount reductions both in upstream and downstream as we progress through the year. And I think you'll see more of before we get to the end of the year hence the larger restructuring charge. Then if you look at various metrics in terms of benchmarking, we are also seeing improvements. Lower 48 was one example, but across the piece looking in terms of how we drive deflation through the system.
Okay. And I have one more question one more question rather. An important theme for the company over the past several years has been value over volume and I think it served you guys well. And I think Bob mentioned a few minutes ago that that would remain the relevant thing for strategic activity as well that is if they were to materialize. So when you guys think about this phrase value over volume, what specific criteria are you referring to meaning what's most important for the company when it thinks about capital allocation today and also strategic activity if it materializes?
Yes. Good point. And it Doug, hello. And it doesn't mean that volume growth isn't something that we will strive to do. We actually believe that we can see the potential for production growth between now and the end of the decade out there.
But what it really means is that we're going to strive for every additional marginal barrel of production that have a higher margin than our existing portfolio, so that we bring up the margin of the entire portfolio with the decisions that we make. We have by necessity had to divest $45,000,000,000 of our assets. But actually what that has done is allowed us to focus a portfolio and increase the average margin of the portfolio. And then the 15 major projects that were brought on from 2011 through 2014 had twice the margin of the existing portfolio. So I think that's how we'll think about strategic steps or other strategic steps or other things or deepening in projects, I think that's a good for all seasons philosophy.
I think we got in the cred mill of driving production rather than keeping our eye on the margins. Now we are a believer that there is value and I think the world has played itself out since 2010, 2011 that vertically integrated companies have a role here. So we're seeing the group benefiting from strong downstream margins, a very focused downstream portfolio as well that moves through the cycles. And we think that not only is that a countercyclical benefit, but we really do see the linkage between our upstream and our downstream and what I think is a very skilled trading organization as well.
Thanks for the elaboration, Bob.
Okay, Doug.
Next, we'll take a question from Thomas Adolff of Credit Suisse. Go ahead, Thomas.
Thanks, Jess. Two questions, please. 1 on decline rate and one on your 4Ds divestments. But firstly, on the portfolio decline rate, back in December at one of your breakout sessions at the Upstream Day, you said that the portfolio decline rate is around 4% to 5%. Presumably, that was based on a higher spend on brownfields.
And obviously, you never gave an exact split of how where the CapEx was cut. So I wonder whether that 4% to 5% is still the case or whether that's still too early to say I. E. The effects from a lower spend? Or are you just successful in maintaining that range as you say you're getting more from existing assets from a lower spend?
Secondly, one of your 4Ds divestments and feel free to correct me if I'm misquoting you. I believe beyond 2015, you used to say the disposal plan should be around $3,000,000,000 per annum, a normal portfolio optimization approach, which obviously would also then come with acquisition unless organically you're successful in adding resources. But if you look at this €3,000,000,000 per annum figure in this environment in the context of a leaner portfolio since Macondo? Is that something you're still confident you can achieve?
Thomas, maybe I'll just take that last question. In terms of €3,000,000,000 I think the number we've always used before is €2,000,000,000 to €3,000,000,000 of natural churn, which is what we've done historically and see no reason why we wouldn't do that on a point forward basis. So it still gives you indications of around €2,000,000,000 to €3,000,000,000 in a portfolio of our size. I think all you're seeing is it's a different mix of assets now than those late life assets that were high returning highly depreciated assets that you saw in the $45,000,000,000 program. We're now seeing some early life assets that actually aren't in production things like the Paleogene we did at the start of this year.
So it will be a different mix going forward, but we'll continue to look to churn $2,000,000,000 to $3,000,000,000 of the portfolio each year.
And Thomas on the decline rate, I think I'm going to take your point which is a good one all the way back to reminding the obvious that safety is good business. And all the turnarounds that we did in the company from really 2010 up through 2014 which was an enormous program has led to some of the best operating efficiency we've had in the company. The months of May June were 95% operating efficiency of our upstream assets. And the North Sea in particular has come up in its efficiency as and the Gulf of Mexico has been working well, though we have the turnarounds the normal turnarounds down. What that has done is allowed us and I just went through this, the base management, base production management those decline rates now look actually a little better in the sense that we are sort of seeing 3% to 5%.
We said 4% to 5% in December. We're actually seeing them around 3% to 5% possibly as well. So all of that leads to the good operating cash flow. It's sort of a virtuous search of safety, reliability, uptime, efficiency, more operating cash flow and then maintaining the base.
Perfect. Thank you very much.
Next question from Rob West at Redburn.
Thanks, Jess. Hi, Bob. Hi, Brian. I've got a question on some of your greenfield projects, the 3 in particular. I guess there's a spectrum at the moment of things that were designed and contracted and locked in, in say 20122013 and can't really flex that much in terms of development plan or the contracts.
And things like Mad Dog Phase 2, it looks like even since December further costs have come out from renegotiating contracts and redesigning the world. How should we think about the 3 big greenfields Kazan, East and then West Nile Delta in that context? Do they since they're effectively sanctioned in the last year in a category of things that can move in terms of cost, can move in terms of design? Or should we think about those as the budgets just totally locked in as what was announced? And then my second question is on gasoline where the cracks have been strengthening relative to diesel.
I think you're one of the more gasoline heavy of the majors. Is there any change in the configuration of your refineries? Can you get more yield out on the gasoline side? And have you taken any steps to do that already? Or do you see the margins just normalizing in the second half of the year?
Thanks very much.
Yes. Okay, Rob. A couple of things. Well, a couple of things. One thing we've learned over time is what we don't want to do is in the middle of a project change the scope.
So when you look at projects that are essentially pretty early here West Nile Delta, we reengineered that for several years. And we are in fact we FID that in the Q1. It's a big project 5 Tcf of gas. We think it will be on stream 2017, 2018. We are in the use existing transportation process infrastructure there.
We are seeing deflation come through. We just went out and spudded the first well on the developments side of it and the rig rates are very attractive. So I do expect to see that coming through in projects like West Nile Delta, Chardanese. We sanctioned that project at the very end of 2013, so it was during 2014. We have seen deflation come through on a variety of things from even the steel and the pipelines to it's a little bit harder for drilling in the Caspian because it's sort of a landlocked sea to an extent.
But right now that project is under budget and ahead of schedule which is good. And in Oman which is a nearly 300 wells over 15 years, we're certainly seeing the deflation coming through in the cost of the wells and in the processing plant there. So the ones that we have in train those big three ones that you talked about to varying degrees West Nile Delta will see a lot. Chardanese a reasonable amount. And because it's onshore in Oman and not offshore in the yard somewhere, it's definitely going to see cost deflation as well.
And then in terms of refining and our ability to switch yields, I mean, there is some degree of yields which we can sort of flip between sort of 4% to 5%. I'm not sure we're that much more gasoline heavy than the rest of the industry. We have got a much smaller footprint in terms of refining portfolio. I mean, got out of somewhere close to 13 or 14 refineries over the last 13 or 14 years. We're down down to portfolio of assets.
We've got some inside that portfolio like Cherry Point which is heavily linked towards diesel jet fuel. But in terms of the ability to move some of the yield, it's sort of at the margin. I would also say that these 2Q refining margins that we've seen have been very strong supported by strong gasoline demand and tight product supplies on the West Coast. But actually if we see some of those correcting as we get through 3Q and 4Q.
That's really useful. Thanks. Thank you.
Okay. We'll take a question now from Chris Coupland of Bank of America.
Thank you and good afternoon. First question is on CapEx. I just wanted to understand a little bit more about your comments Bob, where the savings have come from. You've got a range there I guess somewhere between 10% 20% on average. Can you translate that maybe to your current CapEx budget, which you set out at €20,000,000,000 for this year.
Now you're seeing it already lower. How much of that CapEx budget as you look forward into 20 sixteen-twenty 17 has now been you would say satisfactorily renegotiated and is committed? That would be helpful to get an idea around remaining flexibility as we look out? And I guess the second question is simply a boring question. Sorry, Brian.
Just wanted to come back and ask you halfway through the year whether you can comment on your full year guidance on things like production, which was meant to be flat year on year, D and A and all those other lovely items you had in your full year results presentation? Thank you. Okay.
I'll take the more colorful one CapEx deflation. Thanks, Chris. Well, we don't think we've seen by any means the deflation that's yet to occur. I mean, as the world sort of moves into what I think does look lower for a period of time here, typically if you go back in some of the other cycles in time, the 86 and then the late 90s, deflation impact typically occurs with a lag of 1 to 3 years depending on the market maturity of the local market regional market. I think our historical analysis shows that our cash costs should be able to come down 13%, 14% and 20% deflation for capital cost by 2017.
We think the development costs for new projects which have the rigs in there, we think they'll deflate by as much as 20% to 30%. Of course, it's much less for projects where we've negotiated the prices during the term. But with these things like Mad Dog coming up and these sort of just started projects, I don't think we've seen the end of the CapEx. I know you're trying to look for what is the CapEx level to model 2016 2017 for the same level of activity. I think we're not quite sure there ourselves, but we are seeing this deflation come through.
We're going to continue to drive it. I can give you some color so far. We have seen about a third savings on subsea installations at Thunder Horse in the Gulf of Mexico expansion project for example. We've seen 30% rate reductions for the North Sea Mungo field drilling. We've seen 20% reductions from Sumitomo and pipes and pipelines, but back to 2,009 pricing levels about a 20% savings on the subsea hardware for Egypt and the West Nile Delta project we talked about before.
So I've got a number of other examples here 10% rate reductions on well services 20% down on tubulars. And these are still moving and some of them were locked in before, but these are the new ones. And as time goes forward, we're going to see these come through. I think we're seeing a big cost rebasing of the entire oil and gas industry now. And we used to make money at 60.
We used to make money at 40. We used to make money at 25. But it's going to require this rebasing of costs, which I think is now firmly in the whole industry's sights Chris.
Okay. Thank you.
Chris. And then in terms of guidance, no major changes from what we laid out for you at the start of the year other than the capital piece we gave you which is that before we'd said around $20,000,000,000 as we are sizing the program for this year. We've seen the deflation come through. As Bob just described, we're still in the middle of that process. So we're now confident to say it will be below $20,000,000,000 for this year.
In terms of production guidance, it still remains broadly flat with 2014 is probably still appropriate. That said, I think the 2Q turnarounds went extremely well in terms of bringing that production back on stream, especially in the Gulf of Mexico. Reliability has been running well. Again, that gives us some confidence in terms of the piece Bob talked about around the turnaround program historically. But then we also have the hurricane season, which we know 3Q last year was not that heavier downturn in terms of volumes as a result of hurricanes.
I have no idea what will happen through the Q3. And really that probably determine where we end up in terms of this year versus last year. But I'd say broadly flat is still a good recommendation. There may be some upside, but it largely depends on the hurricane season.
Okay. Thanks. And you would say all the other items as is?
Yes. No other changes are than what we've already flagged on capital.
Okay. And just on that point, would you be advising us against strongly advising us against annualizing your first half €9,000,000,000 plus?
I always try and strongly advise everyone never to take a quarter or a half year and multiply it by the remainder of the years. But I think below 20% is now a confident is I can confidently sit here and say we believe it will be below 20%.
Okay. Thank you.
Turning next to Lydia Raimeforth of Barclays.
Thanks, Jeff. Good afternoon. A question just following up on Chris' actually. So on the cash cost, Rob, when you're talking about those being able to come down 13% to 14%, if I look at the chart that you showed, it does have 2015 first half being similar to first half twenty ten and yet the production base is close to 30% lower than it was at that point. So is that 13% to 14% on a unit cash cost basis that we're looking at?
And then secondly, on the chart of the renegotiations that you've had so far, what percentage of contracts does that actually cover that you've renegotiated? And the final one is just on the dividend and so you pay dividend and focus on rebalancing the financial framework. Is there anything on a 2 to 3 year view that you think will stop BP from being able to rebalance that financial framework to be able to support the current dividend? Thank you.
Yes. Lydie on the unit on the cash cost question what I was referring to sort of our historical review of the deflationary cycle that if you look over time, the unit costs come down 13%. So that's a little bit of a theoretical point of looking at history of what we've seen in the past during downturns. To be honest, our company became overly complicated by necessity after the accident. We put in place multiple safety operational risk organizations parallel review processes decision making that I think we have our confidence back now.
And I think we have even greater potential to reduce our cash costs going forward. So one was theoretical based on history of the industry. And I think ours you'll continue to see them come down on the dividend.
Yes. But in terms of dividend, I mean, it really is a base of as Bob said, this industry works at 25 dollars 40 dollars 45 dollars 50 dollars 60 dollars a barrel. It's a question of how fast you can get deflation back into sync. We've got a very strong downstream business that's very cash generative right now. The Upstream is cash generative, very cash generative in the Q2.
We were actually surplus cash in the Q2 with the and actually our net debt came down as a consequence. That's no indication for the next two quarters. We continue to look at the trend is on deflation. But one of our primary goals going forward is getting everything back into balance and ensuring we can support the dividend that we have in place today.
And Lydia just to clarify the cash cost chart is absolute cash cost and it looked flat in 2014 because it's only the first half of the year. In fact, we did see a reduction in cash costs in 2014 which was weighted to the second half of the year. Moving on now to Fred Lucas of JPMorgan.
Thanks, Geoff. Good afternoon. Bob, a question around the potential for further structural change to your upstream portfolio? And as you look through your lenses into a lower for longer price setting, where within your upstream portfolio do you think BP is either over or underexposed either by geography or asset type?
Well, Fred, I think it's a little easier to answer after the $45,000,000,000 of divestments. So we have a lot of it that's moved away. I think where we can always add to, I'm going to say we're underway, but we can focus on and should focus on is near field opportunities around our existing hubs and infrastructure. That's clearly a real opportunity for us to focus on. Mad Dog is an example of that.
In fact some of the Russian projects there near infrastructure is another example of it. I think the portfolio we built over the last 3 years in terms of shrinking it down and compacting it is actually pretty balanced. I don't see an area that I feel like we obviously need to move away from because it's high cost. I would feel differently if you were asking me that question with a portfolio 3 years ago. And right now again it's the value.
If we see the value in all parts of the world around something that fits the portfolio, we won't stop there. But you won't hear me say something like, well, I think we need more LNG or I think we need more conventional or unconventional gas. I think it's really just how the opportunities put themselves up. And if we've got a strong balance sheet, we've got certainty now in the payments in the Gulf, We can rebase the cost structure of the company. I think we'll be well suited for opportunities when they come along and I think there will be some.
Okay. Thanks. Second question for Brian please around cost inflation. It feels like were you to represent the chart you've shown us today in 6 months' time, those bars are going to get broader and move deeper. Deflation is still building, I think you said so yourself.
I mean, if we just draw a line through the middle of those deflationary numbers today around 20% and assume not too much of that is getting caught in the CapEx budget for 2015. I mean, why wouldn't the CapEx budget of €15,000,000,000 be appropriate and realistic for 2016?
That's for the group is that for the group Fred or for upstream?
That's for the group.
Yes. That I don't think you'll see that levered deflation coming in. On the cost base, I think we still got more to flow in the second half of the year hence why the bigger restructuring charge is taken. So I think there are more costs on the RevEx side to come out. I think on Just
CapEx, yes.
Yes. No, no. I'm just thinking yes, but on the capital side, I think it's now into the tough decisions about I think over the next 2016, 2017, 2018 and even 2019 those projects are baked in. Bob talked about some deflation even we're seeing in those existing projects like Shaktadis Phase 2 in Mankozan and West Nile Delta in terms of Egypt. But then we're going to some hard decisions about the growth of the company beyond 2019 and making some of those tough choices around capital versus rebalancing books.
And I think around 60 around whether the market today around $60 a barrel, I think we can comfortably do both. I think $15 would be way too low, not that I want to give you guidance now for next year. But we'll need to see whether inflation comes out this year and then give you some further guidance as we get into the Q1 of next year Fred. But I think 15% would be way over cooking it in terms of what we're seeing in the market.
Fair enough. And just finally tactically, do you can you do you have a line of sight to see or say when you think deflation might peak? I'm just wondering tactically when we might start to see you get closer to more project sanctions around the bottom of the deflation cost curve?
Yes. It's a great question Fred. And I think you'll see more of that as we go through the Q3 results in terms of the bottoming out of deflation. But I think it's just too soon to say.
Do you think we might bottom out before year end?
Couldn't tell you Fred. It depends tell me what the oil price is going to be.
Current oil price?
I think you won't see it bottom out until next year.
Yes. It's probably right.
I agree with that.
Okay. Thanks very much guys.
Thanks Fred. Next question from Biraj Borkhataria of RBC.
Hi. Thanks for taking my question. Most of them have been answered, but I had one on your comments on a strategic shift to gas. Maybe you could just give us your outlook on LNG and how you see that fitting in your portfolio? And in particular, how you're assessing potential new projects in LNG?
Thanks.
Yeah. Biraj, LNG Economics have been challenged, but there's real deflation coming down now in some of the LNG projects. We haven't just started the front end engineering to decide whether or not down the road here to FID the Browse project in Australia is 1. But we've already seen indications of significant drop in CapEx projects. The other ones that we have and we have also been waiting before we take the step.
But for example, the expansion of the Canggu project in Indonesia, the 3rd train on that, I think by delaying and not moving forward so fast, we are going to see deflation come through in that and we'll consider that as an expansion sometime next year. But these are exactly the kinds of projects that are going to allow us to fine tune and make decisions and have options for the future. I mean, I do believe that gas demand, we're going to see by 2,035, we're going to continue to see growth in both gas and oil. There's no question there's going to be demand that will be out there in Asia in particular for these LNG projects. It's just a matter I think of getting the timing right and getting the costs right.
And I'm hopeful that next year we get on the Angolan LNG project which has essentially been built. It just needs to be refined and get that on as well.
Thanks. Very helpful.
Thank you. And thanks to all those that are still waiting patiently. We will try and get to you all. Alastair Syme from Citi. Are you still there Alastair?
Yes. Thanks, Jess. Can I ask you a couple of short questions on dividends and returns?
I think in an earlier answer on dividends that they were put in the context of the cash balance. I'm wondering if you could put them in the context of through cycle returns. And so put another way, what return on assets do you think are needed to be delivered in the investment cycle to support and grow real dividends? And then the second question, given your framing on oil prices, probably the more conservative end of the industry, where you joint venture with other companies. Do you think your approach or criteria is making you move forward at a different place than some of your peers?
So Alastair on the first question, I mean, I think long run returns can only head in one direction from where we are given what's happening with costs. And having gone from $100 a barrel down to $50 obviously you've got the big chunk of revenues missing. But as we now start to focus on the projects that Bob was talking about, they're naturally going to be biased towards high returning assets versus where the portfolio are. So that will be a big focus. And that is what will give us confidence to ensure that we can continue to underpin the dividend going forward.
So returns is a big part of what we're looking at in terms of the current portfolio of projects and those things that we'll pursue over the sort of near term and medium term with a very key eye on the long term future and long term growth of the company.
Yes. Alastair your point about oil prices, I mean, we may have been bearish. I sort of feel that we're not alone now for sure. What we're finding in our joint ventures and even consideration of new projects and concepts and working with the engineering teams whether it's Mad Dog with BHP and Chevron for example great partners. I think everybody is now looking at costs very, very hard driving it through in the capital costs.
The suppliers are moderating. So I don't feel that we're having a difficult time sort of slowing things down or moderating pace other than the fact that we were driving very hard in our joint venture projects to make sure the cost structures are changing. So I don't feel like we're out there on our own now Alistair. And I would say that the approach of rebasing the cost structure and for us simplifying BP which is something we really need to do and have been working at very hard. It's a good for all seasons thing in any case.
And I think Can I
come back to the first question just briefly? I mean, if you look across BP, the sort of the dividend payout, I guess, as you sort of measure it against operating cash flows sort of higher than it used to be. Is it the implication that your hurdle rate on new investment is also higher than it used to be?
I think in terms of how we look at the hurdle rates going forward, we're still working on the same range that we had historically. It's more about how the cost base now catches up with the oil prices. I'd actually argue Alisa that you could say that certainly for the sector and for BPA it's for different reasons because we sold off a big chunk of high returning assets But the sector has trended to 10% returns at $100 a barrel which tells you that the cost base was above $100 a barrel or more capital was being layered in to future investment that wasn't in service. And I think as we start to correct the portfolio going forward with the focus on the lower capital appetite being driven by deflation some activity you'll start to see those returns drift back up again. But that is one of the main drivers that we see over the near to short term.
Thank you.
In the U. S. Now, Asset Sen of Cowen and Co.
Thanks, Jess. Good afternoon. Two quick ones. First on Lower 48. Brian, thanks for providing all the information on the financial data, particularly the production cost for BOE.
Just wondering if you could provide us with the DD and A per BOE for the Q1 and Q2 if possible? And second, doing quick math on downstream free cash flow for the first half of this year and using sort of a historical downstream DD and A and a tax rate of 35%, looks like around $3,000,000,000 in free cash flow, fairly impressive. Thinking about potential upside outside of the macro, could you talk about where we are in the multiyear $1,600,000,000 cash cost efficiency program? And also any thoughts on the impact of the China PTA plan that just about started?
So on the first question on low-forty eight, we don't provide the DD and A data, hence why it's not in the updates. So that isn't something that we include in the disclosures right now. On free cash flow that's your I'm guessing that they that's certainly not our figures because we don't give you free cash flow figures by sub segment. We look at those at the segment level. But you're right the Downstream is a very strong free cash flow accretive part of our company and has been through the cycle.
It's one of the parts of the business that we run for cash and therefore is free cash accretive. And then in terms of the GBP 1,600,000,000 efficiencies Bob laid out I think in his presentation different components of how that's now starting to flow through And we have seen that flow through the first half of this year.
Yes, Asit. And I'll add on the $1,600,000,000 restructuring in the downstream annual cash cost efficiencies by 2018 versus the 20 14 baseline. And where we are in that I will I'll just note that these restructuring programs a lot of them have to do with labor flexibility and geographies. And labor flexibility and ability to restructure sort of quickly is faster in the U. S.
It's faster in the U. K. It takes longer in Europe. So I think we've got primarily. On the PTC, Germany primarily.
On the PTA plant Zhuhai, it's an incredibly efficient project. It's probably one of the most energy efficient projects. It's got a capacity of about 1,250,000 tons a year and we use one of our proprietary technologies that are there.
It's called
ISOCS. It's going to it's probably going to have the industry leading manufacturing costs. PTA has been overbuilt. It's an industry that's been somewhat stressed. But I think this is a really nice addition to the industry and should be probably the most efficient unit possibly in Asia in the world.
I hope that helps. Asit?
Yes. Thank you so much. Okay.
Thanks, Asit. Next, Lukas Hermann of Deutsche.
Jess, thanks very much. And gentlemen, thanks for all the comments this afternoon. Just a couple of quick ones if I might. Firstly, Bob, going back to Mad Dog, did I hear correctly that you mentioned costs have fallen by I think 50% from the original costing? And from memory, the original costing I thought was CHF 14,000,000,000 So you're suggesting that that project now is trending around CHF 7,000,000,000.
Secondly, could you just talk a little bit more about the Gulf and your production kind of expectations, aspirations this year going into next? I guess I'm just glancing back at the sundry presentation 2 years ago when I think you intimated the Gulf including the or after removing the disposals you've made would be doing somewhere around EUR260,000,000 EUR 270,000,000 this year. And just whether that's a realistic number or ambitious now? And maybe contrast it a little bit with what's going on in the U. K.
Where the performance appears to have improved fairly markedly over the course of the last 6 months? We're seeing good volume growth. And sorry, finally, just since you mentioned Zhuhai, does it make a profit at current PTA prices? Or will we just be looking at a cash contribution at this stage?
Right. Okay. That's a wide spectrum there.
Yes. Let me pick up the last one, because that's probably the easiest one. We don't give you profitability by asset, but it would certainly be cash accretive.
Sorry about that. Thank you.
That's right. It's really just come on in the Q1, but yes. Now Mad Dog, depends on the point in time the $14,000,000,000 but at one point in time sometime probably 2010, 2011, the Mad Dog cost estimates were as high as $22,000,000,000 for the project. It's been recycled now. And I think all I'll say, because we're still talking about it with partners, but it's $14,000,000,000 down in December 2014 and we now believe we can get that project done for under $10,000,000,000 And in the Gulf of Mexico, we I don't know if we gave it out exactly what the full year was last year, but the Q4 $260,000,000 or so going into this year the Q1 above $250,000,000 We've got the turnarounds going on right now.
I think the growth will come through the Thunder Horse South expansion down the road, the Thunder Horse water injections. We've got the Ursa Med Dog recoveries out there. I think being able to keep this running and getting up to 270 by 2018 is very much in our sights. And the Gulf of Mexico sorry the North Sea, which was as many people said the problem child of the offshore oil and gas industry globally because of the efficiencies which were running around 65% a few years ago as an industry. For us, we've taken our plant reliability up from 75% in 2012 up to around 82% now.
And on the Norwegian side in 2012, we were running about just under 70%. Now we're up to 92% so far year to date. So the North Sea is a very challenged mature basin that is responding very, very quickly to the challenges here. And I think reliability for the industry is going up.
Okay. Both of you. Thank you very much.
Next question from Gordon Gray of HSBC.
Hi, gentlemen. Just one thing left to ask actually. If we take aside the strength that we've seen in refining margins, you have a refining business which is top quartile which is running at 94% utilization. Is this as good as it gets I. E.
What other levers do you have for when margins inevitably do come back for improving the underlying performance of that business further?
So you're right to flag that actually it is running at very high utilization. There may be still some more road to travel in terms of across the whole portfolio. Some of those assets are operating at 98%, 99%, so right at the top end. So there's still so right at the top end. So there's still some room for improvement.
But there's other things around commercial performance inside those
refineries, how we set
them up to run, the commercial side of it and then how we interact with the trading business. So I think there is still road to travel in the downstream, if you look at what 2 funds done with the business both in terms of cost but also on the revenue side. So I think you're right to flag it's at the sort of top end, but there are some assets performing significantly above that and therefore there is some more room to travel.
Okay. Thanks.
And the fuels marketing outside of that the networks, the retail networks there's efficiencies still to come from that part of it because we sort of think of it as a fuels value chain. But it's great to have these assets running 94%. This is really this is what we want.
Yeah, absolutely.
And the next question comes from Anish Kapadia of Tudor, Pickering, Holt.
Hi. Good afternoon. Thank you. I was wondering if on
the cash flow side of things you saw underlying cash flow lower in 2015 than 2014. And I guess kind of looking back at your 2014 targets, I saw that your underlying earnings were 14% below your target, but your cash flow was 9% above. So I was just wondering if you can explain that. And were there some one off positives on the cash flow side last year that won't be repeated this year?
Secondly, just on Angola, I was wondering if you could confirm
that the 2015 pre sold well that you were drilling were unsuccessful. I haven't seen anything around that. Just wondering how the outlook for Angola looks now given some disappointing exploration and probably kind of having moved through the infill drilling and tieback program? And then just the final question was on you mentioned moving up to 10 rigs in the U. S.
Just struggling a bit with the rationale over there when you're seeing just over $25 per barrel liquid realizations and $2 gas realizations. Thank you.
So maybe on the first question around the operating cash. You may recall that in 2014, we did have a $2,200,000,000 working capital release, which underpinned the operating cash flows for last year. This year so far in the first half of the year we've had a $1,400,000,000 build. So that's a swing of somewhere from 3 point $5,000,000,000 to $4,000,000,000 just on working capital. I'd expect the $1,400,000,000 build to be released through the second half of the year.
On underlying operating cash flows, if you adjust the environment and the price, actually they are coming through year on year stronger in terms of if I go back and look at base revenues across the businesses, correcting for the environment in the oil price. So actually we are seeing a strong set of operating cash flows coming through this year. That will get stronger as we see the costs flow directly through to the bottom line and through to cash in the second half of the year.
Yes. And Anisho in Angola, we've drilled 2 years here 2 wells in Angola this year, Catambi and Pandora. They're both still under evaluation. So I think best not to comment on that. We're working with partners on that.
And on the rigs in the Gulf of Mexico, we have 8 running now. In the Gulf of Mexico, they are we've got a couple of them working on the Mad Dog. We've got a drillship working on Atlantis. We've got another working on Atlantis. I mean these are high performance wells for us.
We've had one exploration rig that's been working on Gila sidetracks there. And we've got 3 of them working on Thunder Horse. So I'm talking about in the Gulf of Mexico which is your question.
Did you ask a question about low 48 as well?
Yes. So I was actually referring to I think you mentioned you're up to 10 rigs on the low 48. I was just wondering given the where the realization seemed extremely low at $25 per barrel liquid realizations. I'm just wondering how it makes sense
to do that. I think the big change that we're seeing there in terms of Lower 48 is a 50% reduction in the drilling costs. So as we brought those drilling costs down, Dave and his team have been able to ramp up the number of rigs we've actually got working down there. And if you then look at the basins that we're in, that actually changed the profitability of the portfolio that we now have in the lower 48%. So it's absolutely being driven by the fact we've reduced the drilling cost by 50%.
And I think a big focus on the Anadarko and Arkoma Basins which where we get nearly 20% liquids from it.
Okay. Thank you. Stephen Simcoe of Morningstar in the U. S. Are you there Stephen?
Hi. Good afternoon, everyone. Just one quick question, as it's getting pretty late. When we look at or thinking about downstream CapEx and where it's going to trend with the wetting commissioning done and the recent spend levels that have happened over the last 6, 9, 12 months, what would be the right way to think about past 2015 as far as what the kind of base case spending level would be as well as any adjustments you might make depending on commodity price movements from here?
We don't typically publish CapEx by sub segment, but you're right to flag the fact that downstream's capital is significantly lower than the most recent run rate with now the Whiting Refinery Commission fully commissioned. The capital has come down quite significantly. And I think you'll expect to run at roundabout the levels that we see today. We'll look at strategic opportunities in terms of infill as Bob described around the fuels marketing business. As opportunities arise we'll look to do that.
But I don't think you should assume any more big projects on the refining side in terms of downstream over the sort of short to medium term. We're pretty comfortable with the portfolio that we have. So you're right to say CapEx will be trending lower is lower this year, but we'll continue to look at opportunities going forward.
And in addition to Zuhai, project is also completed. So there's a couple of big projects that are now on stream.
Thank you. Richard Griffith of Canaccord.
Good afternoon. Sorry to drag you back to the cost issue. But I was just wondering you've talked a lot about the deflationary environment. But I was wondering to what extent are you going to be able to lock in any structural changes from simplification, standardization, etcetera, that a lot of players have talked about in the industry as opposed to us just going through a more cyclical questions
we ask as that we're making to that we're making to simplify the structure that we think will be sustainable most certainly in the upstream. And so that again is good for all seasons here. We've become very complicated. So reduction in terms of decision making, how we do it, numbers of people to get things done. We think we have a lot to run.
That's absolutely sustainable. I think the deflation once we move this in there are elements of it that may not be sustainable because that's what history shows in a commodity with a cycle. But we're working to change our company to make sure we're not so complicated. And standardization is a very good point. I mean, we've as an industry have wanted to design serial number 1 for many things on many platforms for some time now.
I mean, we're driving now a single kind of wellhead that we can use in different places around the world, standardization of equipment, standardization of activity and that's starting to link up between the companies as well. So there's a period of time where everyone had their own way of doing it. I think people are moving very, very quickly now. And we're part of an industry group now working on standardization of some of the big pieces of equipment that to try to do just that.
And sorry to come back. Just if you took Mad Dog Phase 2 as an example, I mean what proportion of that 50% capital reduction you've talked about be equivalent to the standardization simplification as opposed to some of the more cyclical factors?
Well, some of it is the big scope of the project itself. I mean, what we were trying to do. We've looked at simplifying the design, the requirements, the wellheads, even the phasing of the project, looking at Far East fabrication options. I mean, I think one of it is a big change in scope. And the second part of it is just agreement of what we've learned over the last few years on standardizing wellheads equipment drilling completion designs that sort of thing.
Okay. All right. Thank you.
Thanks, Richard. Jason Kenney of Santander, are you there Jason?
Good afternoon. Thank you and appreciate your time. I'm going to ask my quarterly question on Russia, if I can. So I can understand the year on year downshift by about 50% for the Russia division. But the Q2 versus the Q1 is up 2.8 times.
And if I remember correctly in the Q1 you said there was already big FX support in the Q1. So I'm still struggling to get how that Russia divisional number comes in. And I appreciate that you still got sensitivities because Rosneft hasn't reported. Yes. So the second question if I just ask you that as well.
On the U. S. Gulf of Mexico settlement, I mean you mentioned you're going to be paying something in coming weeks. Should we be thinking of that kind of annual number that was defined in the settlement press release? Should we be thinking of it as an annual payment, a one off annual payment each Q3 or each Q4?
Or is it something that is paid quarter to quarter to quarter for the next 18 years?
So let me pick up the Russia question, which is probably the easy one of those Jason, in that we can't really provide any detail. But the components that would make up the mix of our estimates of what we can see and of course it's really for Rosneft to sort of come back with the actual breakdown. The different components 1Q versus 2Q will be around. 1, we know the euros price improved. So that's out there.
You can catch that. You know that there'll be a positive duty lag given what happens to the oil price through the quarter versus previous quarters. You'll then we've made estimates of what we think the ForEx hedging piece will be around their debt book in terms of what they laid in place around ForEx accounting. And then there'll be other movements around provisions. So really it's a question for the Rosneft results, but they're the big components that we can see moving around that would explain the result quarter to quarter based on our estimates.
That would be the sort of first point. On the second Are you ever going to be
able to get a rule of thumb for that?
That's really a question for Rosneft and I think that's highly unlikely given the amount of moving parts that you've got. It's
really not always easy to model. We had
exactly the is really not always easy to model. We had exactly the same problem or not problem with TNKBP. But what happens is in Russia the duty lag means that the tax preference price is set a quarter or a period of time before the period measured. So when production falls, it often gets hit with a higher duty percentage. And then when production rises or oil price rises, the tax payments of the duties are essentially lower per barrel.
So as we've seen in the Q2 versus the Q1, we've had a rise in the price, which has led to a lower duty than what you would use as your rule of thumb. So it's a rule of thumb, but it's also sort of having to watch the delta in the oil price. And it is tricky. It is tricky. We had the same problem always projecting TNKBP.
Okay. Thanks.
And then in terms of the settlement Jason, there's 4 big components to the piece. The first one is around Clean Water Act fines and penalties, which has the 15 year payment schedule starting 12 months from when the consent decree becomes final. So if the consent decree were to become final in February next year, the first payment would be due 12 months from that date. So that would take you to February 2017. So that's kind of how the Clean Water Act piece works.
The same thing is with the natural resource damage assessment, exactly the same breakdown. It will be 12 months from the consent decree becoming final and that will then set the trend for future payments. In terms of the state, it's a little bit more complicated, so I'll come back to that. And then in terms of the locals, the various local government entities, as we was announced in today's results and was announced by the court yesterday, we did issue to the court yesterday via a phone call that we were happy with the and satisfied with the various releases we've been given by the vast majority of local municipalities. And those payments will now start to progress over the next few weeks and those payments will be made directly from the trust fund that was put in place.
In terms of the state settlements of $4,900,000,000 structured slightly differently where $1,000,000,000 will flow when the consent decree becomes final. Again that will flow from the trust fund and that will be paid to each individual state along an explicit formula. And then there is a series of payments that take you out to from memory 2,031 or 2,032 over 18 years from where we are today in terms of future payments on a yearly basis that effectively become an annuity in terms of cash flowing into those 5 Gulf states around these state benefit claims.
Okay. Thanks.
Thanks, Jason. And now Neil Morton of Investec. Go ahead Neil.
Thank you, Jess. Good afternoon, everybody. Just two questions left, please. I guess both for Brian. Firstly, you mentioned about the sort of removal of uncertainties post the settlement having changed your perspective of the gearing band.
How does it change your view of the 30 $3,000,000,000 of cash on the balance sheet? And then just secondly, in terms of tracking your cash costs. In the dim and distant past, you used to flag a couple of lines in the income statement the production expenses and the distribution admin expenses. Can we still use those as reasonable proxies for your evolution of cash costs?
No. And I'll come back to why. Because there are so many moving parts in those costs. What we try I'll take that one first. We use a subset of what one is you'll still see those reports in the annual reporting accounts.
I can't remember where they are, but it's way deep inside the document you'll find them reported. There are so many moving parts and variable costs inside those. We take a subset of those costs which are the ones that we performance management and they're the ones that you see where we see the $1,700,000,000 reduction. That is actually consistent with what we said historically in previous when we set targets around cash cost reductions. It's the same subset of those.
But you will be able to track the high level numbers. If they come down or up, it will be coincidental with the programs we're doing. It shouldn't be an indicator of whether we're driving costs in either direction because of the variable nature of a big chunk of those costs. And then in terms of uncertainties, our average cost of borrowing is tracking just above 2%. But it's fair to say that you should assume that we would see our cash balances would trend downwards over time as this consent decree becomes final and the need to hold cash will be less of a concern going forward than it has been historically with the overhang of the potential requirement to post bonds against fines, which is which will now lapse as a result of this settlement.
Do you think there's a
no term level for cash balances across the company?
Yes, there is. And we run that within the financial frame, but we don't disclose what that number is. But certainly since 2010, we now run with a cash buffer going forward, but it would be significantly below where the cash buffer is today.
Great. Thank you.
All right. Thank you, everybody. That was the last question. It's been a long call. Thank you for your engagement and your patience.
I'll just hand over to Bob to make a few final remarks.
Right. Well, thank you everybody. You have shown remarkable endurance, persistence and patience which means you are kindred spirits with all of us here at BP. I think the set of results, which came out this morning, were below expectations. But I think if you step back from it, it's really the Libyan exploration write offs and you're probably about where most of you expected us to be.
We're not pessimistic about where we're going. We think we have got programs going across the company both not only in the upstream where it's obvious necessity, but the downstream and in our corporate simplifications and overhead reductions. We think this is going to serve us well as we go forward. I think operability, we don't often get the chance to talk to you about our assets operating reliably and safely consistently through the quarter. And this has been a remarkable quarter for us.
We're never going to be complacent about that, but also we didn't talk about safety. But our safety statistics this past quarter at least have been as good as they have ever been across the metrics that we measure. So again, we're not going to be complacent on that as well. And thank you all very much. As we sit here, I see the oil price is still in the got a 52 in front of it for Brent and a 47 in the U.
S. So we're just going to continue to march on. Thanks for your patience.