I now hand over to Jessica Mitchell, Head of Investor Relations. Hello, and welcome. This is BP's Q2 2017 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.
Thank you, Jess. Good morning, everyone, and thank you for joining us. Today, we are here to report on our results for the Q2. The environment continues to challenge us. At the same time, it's been another quarter of solid operational delivery in all of our businesses.
In the upstream, we are safely and efficiently executing on our suite of major project startups for the year and the downstream is showing resilient performance while also bringing on growth. Most notably, it has been another quarter of solid underlying operating cash delivery for the group of $6,900,000,000 despite the weaker environment. On an organic basis, we were able to balance our sources and uses of cash this quarter. For today, I'll start by looking in more detail at the environment and we'll also look at how the plans we have in place are fit and flexible to respond to the continuing uncertainty. As usual, Brian will take you through the detail of our 2nd quarter numbers and a reminder of our financial frame and guidance.
I'll come back to update you on our upstream and downstream businesses before we take your questions. So starting with the macro, after a stronger start of the year, Brent oil prices declined in the 2nd quarter, Continuing high inventories and recovering production in the United States and Libya put pressure on prices, despite the extension of the OPEC production cuts for the Q1 of 2018 announced in May. Looking over the course of the year, demand for oil is expected to remain robust and increase by an above average 1,500,000 barrels per day this year, supported by continued recovery in GDP growth and supported by sustained lower oil prices. At the same time, non OPEC supply after declining last year is expected to increase by 700,000 barrels per day this year, driven largely by the recovery in U. S.
Tight oil production. Compliance among the OPEC and non OPEC countries participating in production cuts remains strong and we expect this to continue at least through the period of agreement to March 2018. Putting this all together, OECD inventories appear to be declining, moving us towards a more balanced position, although there remains a lot of uncertainties around the timing of that and around the longer term outlook. It is a tough environment and it could remain that way for some time, but we're building a business that is resilient to these changing conditions, we're operating effectively and we are advancing the strategic plans we laid out to you in February. That means we're getting back to growth and securing our future over the longer term.
The foundation for everything we do is a relentless focus on safe and reliable operations. You will always hear us talk about that. Keeping our people and operations safe remains our top priority and number one value. It also underpins our growth plans and supports the delivery of reliable and sustainable cash flow. Across the group, we expect strong growth over the next 5 years.
In the upstream, we are on track to add more than 1,000,000 barrels per day of new oil equivalent production by 2021 from 2016. Around 800,000 barrels per day net to BP is expected to come from our major projects by the end of the decade with an additional 200,000 barrels a day coming from our recent portfolio additions. Our new projects should deliver on average 35% better operating cash margins compared to the base portfolio in 2015 and around 20% on average lower development costs. This makes us increasingly resilient the environment as we look to move the portfolio even lower down the cost curve. In the Downstream, we expect to see more than $3,000,000,000 in sustainable underlying earnings growth by 2021, in addition to the $3,000,000,000 improvement delivered since 2014.
We laid out our strategies for marketing and advantage manufacturing in some detail at our recent Downstream Day in June, where we illustrated the differentiated and very competitive drivers of future value in this business. So I am confident in the plans we have set out to deliver disciplined growth. Before Brian takes you through a reminder of our financial frame, I want to briefly emphasize a few key points. First is that we continue to maintain a strict focus on capital and cost discipline That is essential in everything we do. 2nd, we're changing the way we think about how we operate.
We've come a long way over the last few years to become simpler and more streamlined and we continue to learn from others, including outside our industry. And third, we are making big strides in modernization, implementing digital and cutting edge technology across our businesses. We need to do all of these things well to ensure we remain competitive in any price environment and I'm confident that the steps we are taking will be enduring into the future. So with that, let me hand it over to Brian to take you through the results.
Thanks, Bob. Turning to the environment. Brent crude averaged $50 per barrel in the 2nd quarter compared to $54 per barrel in the Q1 of 2017 and $46 per barrel a year ago. The recent price movements reflect increased production from Libya, Nigeria and the United States moderated by the extended OPEC production cuts. Henry Hub gas prices averaged $3.20 per 1,000,000 British thermal units in the 2nd quarter compared to $3.30 in the 1st quarter and $2 a year ago.
The global refining marker margin showed seasonal improvements. The 2nd quarter averaged $13.80 per barrel compared to $11.70 per barrel in the Q1 and $13.80 per barrel last year. Turning now to the results for the group. BP's 2nd quarter underlying replacement cost profit was AUD680,000,000 around 5% lower than the same period a year ago and 55% lower than the Q1 of 2017. Compared to a year ago, the result reflects higher exploration write offs and a lower contribution from oil supply and trading, partly offset by higher upstream liquids and gas realizations and higher upstream production.
Compared to the previous quarter, the result reflects lower upstream liquids realizations, higher exploration write offs and a weaker contribution from oil supply and trading. 2nd quarter underlying operating cash flow, which excludes Gulf of Mexico oil spill payments was CAD6.9 billion The 2nd quarter dividend payable in the Q3 of 2017 remains unchanged at €0.10 per ordinary share. In Upstream, the underlying 2nd quarter replacement cost profit before interest and tax of CAD710 1,000,000,000 compares with CAD 30 1,000,000 a year ago and CAD 1,400,000,000 in the Q1 of 2017. Compared to the Q2 of 2016, the result reflects higher liquids and gas realizations, the impact of the Abu Dhabi concession renewal and higher production from major project start ups, partly offset by higher non cash exploration write offs largely in Angola and higher depreciation depletion and amortization. Total production for the group was 3,600,000 barrels of oil equivalent per day for the quarter.
Excluding Rosneft, 2nd quarter reported production was 2,400,000 barrels per day 10% higher than a year ago. After adjusting for entitlement and portfolio impacts, underlying production increased by 7% with the ramp up of major projects. Compared to the Q1, the result reflects higher exploration write offs and lower liquids realizations. Looking ahead, we expect Q3 2017 reported production to be broadly flat with the Q2 with the continued ramp up of major projects offset by seasonal turnaround and maintenance activities. Turning to Downstream.
The 2nd quarter underlying replacement cost profit before interest and tax was CAD1.4 billion compared with CAD1.5 billion a year ago and $1,700,000,000 in the 1st quarter. The fuels business reported an underlying replacement cost profit before interest and tax of CAD910 1,000,000,000 in the 2nd quarter, compared with CAD 1,000,000,000 in the same quarter last year and CAD 1,200,000,000 in the 1st quarter. Compared to a year ago, the result reflects continued fuels marketing growth bringing the half year result to around 20% above the same period last year and increased refining commercial optimization. This was more than offset by a significantly lower contribution from supply and trading and higher level of turnaround activity. Compared to the Q1, the result reflects higher fuels marketing earnings and improved industry refining margins largely offset by narrow North American heavy crude oil differentials and product mix impact.
This, however, was more than offset by a weaker supply and trading contribution and a higher level of turnaround activity. The lubricants business reported an underlying replacement cost profit of CAD360 1,000,000 in the 2nd quarter compared with CAD410 1,000,000 a year ago and CAD390 1,000,000 in the 1st quarter. The Petrochemicals business reported an underlying replacement cost profit of CAD150,000,000 in the 2nd quarter compared with CAD90 1,000,000 a year ago and CAD150 1,000,000 in the 1st quarter. In the 3rd quarter, we expect a similar level of industry refining margins and that North American heavy crude oil differentials will remain under pressure. Turning to Rosneft.
Based on preliminary estimates, we have recognized CAD280 1,000,000 as BP's share of Rosneft's underlying net income for the 2nd quarter compared to CAD 245,000,000 a year ago and CAD100 1,000,000 in the Q1 of 2017. Compared with a year ago, the estimate reflects a high euros price partially offset by lower duty lag benefit. Our estimate of BP's share of Rosneft's production for the Q2 is 1,100,000 barrels of oil equivalent per day, an increase of 9% compared with a year ago and roughly flat compared with the previous quarter. The increase compared with last year reflects the completion of recent acquisitions and new fields coming online. In July, we received our share of the Rosneft dividend, which amounted to CAD190 1,000,000 after all taxes.
This dividend represents 35 percent of Rosneft's IFRS net income for 2016. Further details will be available when Rosneft report their 2nd quarter results. In other business and corporate, we reported a pretax underlying replacement cost charge of CAD370 1,000,000 for the Q2. We continue to expect the average underlying quarterly charge for the year to be around AUD350,000,000 although this may fluctuate between individual quarters due to foreign exchange impacts. A non operating pre tax charge of CAD350 1,000,000 was also taken in the quarter reflecting the latest estimate for Gulf of Mexico oil spill claims and associated administration costs.
This is in addition to the ongoing unwind of discounting effects on the provision, which have no impact on cash. The adjusted effective tax rate for the Q2 was 60% and is higher than a year ago, mainly due to the Angola exploration write off, which receives no tax relief and the Abu Dhabi concession renewal. In the current environment, we now expect the full year underlying effective tax rate to be tracking above 40% due to exploration write offs in the first half of the year. Looking next at cash flow. This slide compares our sources and uses of cash in the first half of twenty seventeen compared to the same period a year ago.
As Bob said, we balance our sources and uses of cash organically as shown on the top right chart. Excluding pretax oil spill related outgoings, underlying operating cash flow was $11,300,000,000 for the first half, of which CAD6.9 billion was generated in the 2nd quarter. This includes a modest net working capital release of CAD110 1,000,000,000 in the first half with CAD1.4 billion in the 2nd quarter. Organic capital expenditure was CAD7.9 billion in the first half and $4,300,000,000 in the second quarter. Net debt at the end of the quarter was $39,800,000,000 and gearing was at 28.8 percent within our 20% to 30% target band.
The increase was primarily due to Gulf of Mexico oil spill payments, but we expect an improvement over the second half as payments decline and divestment proceeds come in towards the end of the year. Now turning to a reminder of the key elements of our financial frame and our overall objective of growing sustainable free cash flow. Starting with organic cash flows. As we have seen this quarter, underlying operating cash flow is robust despite the lower trend in oil prices relative to the previous quarter. This reflects the steady operational progress within our businesses and reversal of the Q1 working capital build.
With 3 of the 7 project start ups planned for this year already online, we expect the ongoing execution and ramp up of our project pipeline along with ongoing underlying performance improvements in the Downstream to continue to drive operating cash delivery for the group into 2018 and beyond. Operating cash flow will also continue to reflect the focus on continuous efficiency improvement and transformation taking place across the group. Non operating restructuring charges have continued into 2017, although we expect the cash flow impact to be lower than last year. Looking out to 2021, our overall capital investment plan remains unchanged from those we laid out in February. We expect organic capital expenditure for the group to fall within a CAD 15,000,000,000 to CAD 17,000,000,000 per annum frame.
At the upper end, we expect not to exceed CAD 17,000,000,000 in any one year and we will be very disciplined about that. The lower end represents the ready flexibility we have to tighten capital expenditure in periods of lower oil prices without materially impacting our growth objectives. So we would expect our capital expenditure for 2018 to be at the low end of the range should oil prices remain around $50 per barrel. However, and I do want this point to be clear, this is not a flaw. To the degree that oil prices remain structurally lower, we will continue to drive capital efficiency towards a sustainably lower investment frame for the overall portfolio going forward.
Over the medium term, the underlying momentum in our businesses coupled with the discipline in our capital frame supports growing free cash flow for the group at oil prices well below where they are today. And I will come back to that in a moment. For inorganic cash flow, 2017 was always going to be a year with Deepwater Horizon payments heavily loaded to the first half and divestment proceeds to the back end of the year. Deepwater Horizon cash payments were $4,300,000,000 in the first half and are expected to be between CAD 4,500,000,000 to CAD 5,500,000,000 for the full year. Total Deepwater Horizon cash payments are then estimated to fall to around $2,000,000,000 in 2018 and to step down to a little over $1,000,000,000 per annum from 2019 onwards.
Divestments are expected to be in the range of CAD4.5 billion to CAD5.5 billion for this year with disposal proceeds weighted towards the second half. Longer term, we expect divestments to reduce to a more typical CAD 2,000,000,000 to CAD 3,000,000,000 per annum, while also remaining a lever for optimizing our portfolio and creating additional flexibility within the financial frame if required. Turning now to our progress in balancing the cash flows of the group. Our aim has been to reestablish a balance in our financial framework where operating cash flow covers capital expenditure and the current dividend at the prevailing oil price. In the first half of twenty seventeen, we made good progress in balancing organic cash flows.
Underlying operating cash flow after organic CapEx and cash dividends was CAD600 1,000,000 in surplus at an average Brent price of CAD52 per barrel with broadly neutral working capital. So we were balanced comfortably below CAD50 per barrel. So despite oil prices remaining unsettled, we have made strong progress in rebalancing our financial frame, allowing us to maintain our dividend with confidence. Our balance sheet is resilient. For the time being, we retain the option of scrip as an undiscounted alternative to our cash dividend, while continuing to target gearing within a 20% to 30% band.
At Brent oil prices below $50 per barrel, as already discussed, we would look to further optimize capital expenditure. We have confidence in the group's near term ability to recalibrate to sustained sub-fifty dollars oil prices as we bring on strong growth in both our businesses. Looking out to 2021, we expect our organic cash balance point to reduce steadily to around $35 to $40 per barrel, reflecting the material improvements in free cash flow expected in both the upstream and the downstream. Beyond 2018, we expect organic free cash flow to start to grow in a constant price environment, supported by the further ramp up of our new slate of upstream project start ups and underlying performance coupled with strong margin growth in the downstream. Once surplus free cash flow is being generated, we would look in the first instance to address the dilution that arises from the scrip dividend alternative.
We will then aim to ensure the right balance between disciplined investments and distributions growth depending on the context and outlook at the time. Let me now hand you back to Bob.
Thanks, Brian. Let me briefly now update you on progress across our 2 main segments as it has been a very eventful quarter with more to come as we get into the second half of the year. I'll start with the upstream and you will have heard us talk before about 2017 as a very significant year for BP. This is proving to be the case. We have already started up 3 of our 7 major projects for the year, 2 more are imminent.
We've made a lot of progress in resetting our cost base over the last few years and we expect that trend to continue. This year, we expect unit production costs to be more than 40% lower than in 2013. Around 75% of these cost reductions are from efficiency. So these should be sustainable in the longer term. Beyond this, we're pushing ahead with some really transformational changes as we digitize the business at pace.
This stretches from subsurface modeling to wells construction, to plant operations and all the way to electronic procurement. We expect to deliver $13,000,000,000 to $14,000,000,000 of pre tax free cash flow in 2021 based on our February assumption of $55 per barrel. This is underpinned by 5% per annum average production growth, continued decline in unit production costs and improved capital efficiency. Looking beyond 2021, we have improved both our capacity for growth as well as the quality of that growth. We believe in the strength of our portfolio, which is balanced, increasingly competitive and positioned to reflect changing energy trends.
We always look to grow value and returns, not just volume, and we will deliver this through continued optimization of our resources through our area development planning process, the recent acquisitions, as well as our modernization and transformation agenda. Looking specifically at performance so far this year, we have maintained our discipline and operations while delivering effectively on the program of new projects. As I just mentioned, 3 of our 7 major projects are already online. In March, West Nile Delta, the Taurus Libre projects in Egypt started up 8 months ahead of schedule and with production 20% above plan. In April, Trinidad Onshore Compression was delivered under budget.
And in May, we started Quad 204 in the North Sea. This is a significant oil project, included the construction and installation of the world's largest harsh water FPSO, the Glen Lyon. Persephone off the coast of Western Australia is in the final stages of commissioning and is on track to come online in 3Q. In Trinidad, the Juniper facility is progressing through final commissioning activities and startup is expected in the coming weeks. That leaves 2 more for 2017 and we remain on track to have Kazan Phase 1 in Oman and Zohr in Egypt online by the end of the year.
We continue to see strong operating performance on our operated assets this quarter. We completed 1 turnaround in the first half and preparations are underway to start 4 turnarounds in the 3rd quarter. As for production, excluding Russia, this quarter it was 10% higher than the Q2 of 2016, driven by the extension of the ATCO concession in 4Q 2016, as well as the start up of our major projects and good underlying performance of our assets. And our unit production costs were 18% lower in the first half of twenty seventeen compared with the same period in 2016. This year, we've also had 4 significant discoveries, which support the strategic shift we are making.
Results from the Savannah and Macadamia exploration wells offshore Trinidad indicate an estimated 2,000,000,000,000 cubic feet of gas in place to underpin new developments in these areas. Also in offshore Senegal, BP along with joint venture partner Kosmos Energy announced in May a major gas discovery at the Yaqar well. This well further confirms our belief that offshore Mauritania in Senegal is a world class hydrocarbon basin and marks an important step in building BP's new business in this important region. Out to 2020, our major projects are a significant part of our growth wedge to the end of this decade and beyond. The 800,000 barrels per day of new projects production by 2020 is firmly on track with the portfolio under construction ahead of schedule and around 15% under budget.
You will see the impact of our 2017 major projects towards the back end of the year with production ramping up as we go into 2018. During the Q2, we sanctioned the R series deepwater gas project in block KGD-six off the East Coast of India. This is the first of 3 planned projects in the block that are expected to be developed in an integrated manner. We've also sanctioned the Angeline Offshore Gas Project in Trinidad. Looking further ahead, we have a strong portfolio that we continue to optimize and test against our hurdle rates.
And that gives us a lot of options with only the best and the most competitive going forward to FID within the discipline of our capital frame. So we've made a lot of progress already this year in the upstream. We're right on course with where we want to be with the execution of our current set of projects. And we're progressing in a very disciplined way with our plans for future growth. Now turning to the Downstream, I'll start with a reminder of some key messages Tufan set out as part of the recent Downstream Investor Day.
The disciplined execution of our strategy is delivering results. Dollars 3,000,000,000 of underlying earnings growth has already been delivered in the 2 years since 2014 and plans are in place for more than $3,000,000,000 of further growth by 2021. Growth is expected to continue to come from our marketing businesses, which are differentiated and high returning and our strategy is to grow these businesses in important global markets. We also expect further growth from manufacturing, where we continue to build a top quartile refining business and improve the cash breakeven performance of our petrochemicals business. Efficiency and simplification remains central to earnings delivery.
Cash costs in 2016 were some $3,000,000,000 lower than in 2014 and at their lowest level in more than 10 years. And we continue to focus rigorously on cost management and efficiencies. Taking all of this together, we expect to deliver between $9,000,000,000 $10,000,000,000 of pre tax free cash flow with returns of around 20% in the downstream in 2021. The chart on the left side shows the detail of where we plan to deliver more than $3,000,000,000 of future earnings growth. And you can see it is expected to come from all businesses.
Each of our downstream businesses are differentiated and it is their sources of competitive differentiation which underpin our detailed growth plans. And by expanding our earnings potential, we will also further improve the resilience of the business. You can see from the right hand chart how we have already made significant progress, materially reducing the refining margin required to deliver downstream pre tax returns of 15% over the last 2 years and how our plans will improve this even further. In a changing world, our strategy is building a downstream business which is fit for now and the future. Now turning to progress so far this year, we continue to grow underlying earnings in both marketing manufacturing with continued strong delivery against the strategy.
In fuels marketing, earnings have grown by around 20% in the first half of twenty seventeen compared to 2016. We've continued the rollout of our convenience partnerships model with around 90 sites added so far this year. And premium fuels volumes have grown by 7% year on year. In Mexico, we were the 1st international oil company to enter the fuel retail market since deregulation and volumes across our sites have more than doubled during the 1st months of trading. And in India, we signed a memorandum of understanding with Reliance Industries to jointly explore options to develop differentiated retail and aviation fuels, mobility and advanced low carbon energy businesses.
In lubricants, we secured a new agreement to become the exclusive premium lubricants brand retailed by Kroger, the largest supermarket chain in the United States. We also successfully renewed our strategic partnership and supply agreements with a number of major vehicle manufacturers. And in manufacturing, underlying earnings have grown in both refining and petrochemicals during the first half of the year. In refining, we grew the value of commercial optimization compared with last year and increased the level of advantaged feedstock processed in the U. S.
In petrochemicals, following the upgrade at our Cooper River plant in the U. S, our industry leading technology is now operational at all our key PTA sites. And we also delivered record production levels at our plant in Zhuhai, China during the first half of the year. So in downstream, we have a clear strategy, which we're executing well. You can see this in the results across our marketing in February, we laid out a very clear strategy for building resilience and competitiveness today, along with growth plans that are highly responsive to the changes that are taking place in the longer term picture for global energy.
These plans are in action and we've seen this in the solid operational delivery in the first half of twenty seventeen. We're building a track record of strong and reliable operational performance. We are right on track with a really busy program of projects in the upstream and we have real momentum in all of our downstream businesses. And we are maintaining our capital discipline as well as the focus on bringing our costs down in a long term sustainable way. So we believe we have an investment proposition that works in the near term and over the longer term horizons.
All of this supports our principal aim of growing sustainable free cash flow and distributions to shareholders over the longer term. On that note, thank you for listening and we'll now open it up for questions.
Thank you and good morning again everybody. We do have a long list of callers this morning. So in the interest of time and to be fair to those at the back of the queue, we'd like to ask you today to please adhere to our usual convention of 2 questions only. And of course, IR will be available for follow-up after the call. We'll take the first question from Irene Himona of SocGen.
Are you there Irene? Yes.
Good morning. Thank you, Jess. I had two quick questions, please. Firstly, on asset disposals. Brian, you reiterate the EUR 4,500,000,000 to EUR 5,500,000,000 by year end.
I wonder if that refers to sales to be announced or actual cash receipts. And have you announced some disposals that have yet to close this year? Secondly, just very quickly on DD and A, it's up about 11% in the first half. I wonder if the EUR 8,600,000,000 is representative of the annualized charge. Thank you.
Hi, Irina. So on disposal, it's proceeds. So it will be cash in. This year, we've already announced over $2,000,000,000 if you take into account SECO. It's probably up $2,500,000,000 in terms of announced deals.
And then there's a whole suite of other small medium sized transactions that will close in the second half of the year. So the actual range you've laid out there of the 4.5% to 5.5% is still well underpinned. On DD and A, I'll have to come back to you on that specific question. But in terms of effectively what we've got coming through so far this year is the new projects coming on stream and therefore we start to activate DD and A around those assets. It will pretty much flat line from where we are.
If you look on a DD and A per barrel basis for this year, it will probably flat line over the next 2 or 3 years as we look at the growth projects coming on stream and assets coming off the books as we go through some disposals. But we'll come back to you on the specifics of DD and A and what the track looks like for the rest of the year with IR later.
Okay. Thanks so much.
Thanks, Irene. And turning next to Christian Malek of JPMorgan. Go ahead, Christian.
Thank you, Jessica, and good morning, Brian and Bob. Two questions just very quickly. First, you previously mentioned the floor remains low, sort of in the low 40s, that your CapEx can be as low as $14,000,000,000 In light of your cautious view that oil is likely to trade within the range of 45,000,000 to 55,000,000 next year, your continued efficiency drives an improved cash margin on new projects, do you think there's more scope to reduce group CapEx without necessarily sacrificing sustained CFFO beyond 2020? And the second question, sort of coming back to oil prices, to Bob, you've outlined an oil price for you for next year. Is it fair saying that's your view in the long term too?
Or do you see things reverting higher? Just interested to know how you think the trend sort of continues through the back end of the decade.
Maybe just on the capital frame. What we've laid out is the 15% to 17% range. I think for next year, I mean, Bob will come on to the oil prices, but I think we'll probably see oil prices firming through this quarter as we see demand continuing to grow. That will probably taper off in the back end of this year. So I think a range for next year around €45,000,000 to €55,000,000 seems like a reasonable assumption today, but a lot could change between now and the end of the year around supply and the demand side of the equation.
But in terms of capital, assuming we're around $50 a barrel for next year, then we'd be at the low end of our capital range. And if we saw a prolonged period down to $45 a barrel, we could go below that $15 which is what we've laid out in today's results and we continue to believe that. We're seeing more capital efficiency come through. You've seen a strong set of cash flows in the first half of the year. If you take out or then basically it's pretty neutral working capital for the first half of the year if you add the 2 quarters together.
That gives you a pretty good indication of the strength of the cash coming through and therefore more flexibility as we go forward. And we'll continue to see capital efficiency and focus on costs and productivity throughout the organization.
And Christian, when you look at the supply and demand and the projections out there, I think Brian used the term 45 to 55 for the next year. In our thinking, that's pretty good fairway for us going forward, thinking about $50 oil for the next 5 years is the numbers we're going to use right now and keep the discipline about it. That will bring down the cost structures even further in the industry. The U. S.
Shales are a swing producer. There's always geopolitical events that could be create spikes in the other direction. But in terms of our thinking, getting PEP to work, getting our breakevens well into the 30s and thinking there's a rough $50 over the next 5 years is right now our thinking.
Great. We'll move next to Lydia Rainforth of Barclays. Are you there, Lydia?
Thanks, Jess. And yes, good morning, everyone. Two questions, if I could. Just going back to Brian on chart on Slide 17 around the free cash flow cover of the dividend. If I remember rightly, at the 1Q stage that was shown at $55 real and it's now shown at $50 to $55 Is the interpretation of that chart just sounds clear that the business will be breakeven sub $50 a barrel next year?
And then the second one was just in terms of the confidence in the numbers and the projections going forward. When I sort of add up all the projects and things like that, it does look like the numbers are very much risked and that there is potential upside within that. Can you just comment on sort of how much confidence or kind of how much risking there is actually in that process? Thank you.
Lydia, so I mean the second part of the question, we risk all of those projects. And I think as Bernard laid out when we laid out the strategy at the end of February, it implies 5% growth. And of course those projects are risked across the piece. And similarly with the Downstream as you saw from the Downstream Investor Day. And they're risked for a reason to sort of say that if you sort of take the middle of the fairway that Bob described and that's what we think the outcomes will be and there's lots of things can move up and down around that range.
On the move from €55,000,000 to €50,000,000 to €55,000,000 so well spotted. And you saw that in the first half of the year, we came in cash breakeven was actually below €50 a barrel. We still have to offset the script going forward. So that's still important for us in terms of next year. And then in terms of where we're targeting cash breakeven next year will be a choice as to where we set the capital.
We'll continue to see more come through I think in the way of costs and capital efficiency that Bob laid out. And as we land our plans for next year at the end of this year, we'll ensure that we set things up to make sure that we are balanced next year, ensuring that we also cover the script going forward and make sure that we can offset that on a go forward basis. But there's a lot of moving parts between now and the end of the year. But you're right to pick up directionally our breakeven price is moving down quicker than we may have anticipated at the start of the year. And first half year is good progress, but there's still an awful lot more to do in the second half.
Perfect. Thank you very much.
Thank you. We'll take a question now from Anish Kapadia of TPH.
Good morning. First question is on Macondo. When I look at the balance sheet, you've got a current liability on the balance sheet of about $3,000,000,000 So I just wanted to check, does that mean you'll have around $3,000,000,000 of cash out over the next 12 months from the condo? Or are there other offsets or further charges to think about? And I suppose how the kind of PSC settlement works into that?
The second question is relating to your U. S. Midstream. I know you're limited in terms of what you can say on that, but I just wanted to kind of think about the bigger picture strategy on examining the potential IPO. Why are you looking at kind of going down that route rather than outright asset sale as I believe the majority of your assets are non operated?
Thank you.
Okay, Nish. On the Macanliabilities, that would be the current liabilities, which would be typically 12 to 18 months out. So you're right to say that that's the right order of magnitude, which we've laid out for you already, which actually can also imply from the ranges we've given you CHF 4,500,000 to CHF 5,500,000,000 for this year. We continue to expect to stay in that range and around CHF 2,000,000,000 for next year. So I think that also box balances.
And we took a small increase in the provision as we start to see the wind down now in terms of final suite of claims in the facility. And we expect the bulk of those claims to be dealt with in terms of determinations through to the end of this year and into next year and the sort of final payments to go out next year by the end of 2018. And then we'll be left with a suite of things on appeal. In terms of midstream MLP, Bob, do you want to just pick up where we are in the MLP?
Yes. Anish, like you say, we can't say very much about it. But I think fundamentally versus a sale versus an MLP, these are assets are important to BP to optimize our operations around the U. S, the pipelines, refining. And so by maintaining management interest in it, it's a lot better than just an outright sale, which could damage our optimizations.
Thank you.
Okay. We'll move next to Tapan Joffeelingham of Exane.
Yes. Thanks, Jess. Good morning, gents. Two questions on upstream hubs. Just could you talk about Kazan and what's on the critical path in terms of commissioning and then ramp up?
What's the sort of speed of the production increase we should expect from Oman, please? Second question, just on the U. S. Lehr 48 gas business. Could you perhaps talk about where you are in terms of cash generation?
Are you cash flow neutral at these positions and the progress you're making there in terms of taking out costs? Thank you.
Yes, Tipan, the Kazan project is moving along very well. You'll know we've got a 60% working interest in there with the Oman Oil Company. Our latest estimate for start ups should be by October. Overall progress in the project is up around 99.8%. We've got gas that is filling the plant now.
It should be about 7 Tcf of unconventional gas. We've got another agreement that to expand it by 50% takes it up to another 3 point 5 Tcf. First gas, we can't really give the date today, but we've notified the government that we expect it to be in 3rd quarter. Our forecast for production this year are up around 17,000 barrels a day this year and will be up well over 100,000 barrels a day next year. Plateaued production will be a Bcf a day gross.
So we're feeling very good about the progress of the project and just stay tuned on that.
Tidpan, then on Lower 48, for last year we were cash breakeven below $3 and for the first half of this year we're cash breakeven below $3 So therefore $3 an MMBT would be generating cash.
Great. Thank you.
Thanks, Thi Pan. Turning next to Alastair Syme of Citi.
Thanks very much, Jess. Brian, you've historically shied away from talking around divisional tax rates. And we get some disclosure on the upstream from the ENGA filings. But can you talk around what the portfolio activity will do to that upstream tax rate when we see the full year accounts this year? And secondly, you've highlighted the WTI, WCS spread in the quarter.
Can you give us some sort of ballpark sensitivity on how that spread impacts on your Downstream earnings? Thank you.
Yes. So on tax rates, I mean, it is there is a whole suite of inputs that come into that depending on where oil price is, depending whether it's PSA, PSC, particularly from a corporate perspective in terms of deferred tax losses that we carry forward, what's happening with foreign exchange rates. So therefore, it's actually not that easy or straightforward to try and give you an indication of what's happening in terms of overall rate. But I think guidance for the year for the corporation this year, we're probably tracking now above 40%. And remember, we moved from around 30% the range previously was around 25% to 35%.
With the ADNA concession, we moved the effective rate up to €40,000,000 because of high tax barrels that come through with that. On that basis for this year, we're now tracking above €40,000,000 given the expiration write offs that didn't attract any tax relief this year. So we're now tracking above 40%. Cash tax rate, Alastair, would typically track around 6% to 10% below that historically. So and actually for the first half, it's about 8% below.
But other than that, I'm afraid I can't give you any much more information. In terms of WCI, WCS, as you'd expect, as prices come down, that differential narrows in. Also with some of the disruptions up in Canada and producer outages, we've seen that effectively that spread has come in. We've talked historically about wanting something around the mid teens is where the white the big white investment around the upgraders came. If the level gets too low, you start to run more WTI than heavy.
But I think you'll start to see the spread open up a little bit, which we've seen recently, but we're not expecting a major recovery as we come through this year. And it will really be driven by pure supply and demand economics coming out of Canada in terms of heavy crude. We don't actually give an indication in terms of what that means and on a rule of thumb basis. And so really that's all I can say about WTI and WCS.
Okay. Thank you.
Thanks Alastair. Next up, Jason Gammel of Jefferies.
I wanted to ask, first of all, about how you think about leverage relative to the relief of the script dividend, just recognizing that we're now getting pretty close to your 30% ceiling on the end of the quarter and recognizing that divestiture proceeds will pull that down. But is there any level of leverage that you would want to reach before the release of the script dividend once you get into a position where you're generating significant free cash flow? And then my second question is a fairly quick one, I hope. I've lost my decoder ring, Brian. I was hoping you could tell me the absolute magnitude that is associated with significantly lower supply and trading contribution.
Jason, thank you. And I'm sure if somebody can do an algorithm with machine learning, you'll probably be able to work out these results from all the various things we've said over the last 10 years. On the first piece, gearing net debt, that's not really doesn't cause us any issues in terms of offsetting scrip. So that wouldn't be a determining factor in our decision to offset scrip. And we're only talking something at today's levels offsetting scrip is around $1,000,000,000 to $1,500,000,000 So it's not a huge amount in the overall scheme of things.
And certainly the balance sheet could more than absorb that. So that the balance sheet will not form a determining step in offsetting scrip. It will be about being back into cash surplus on an organic basis will be the biggest driver of that. So that is not a cause for concern and certainly would not come into the equation. Even if 30%, there's still quite a lot of flexibility we've got in the balance sheet and 30% is in the ceiling for that range.
It's more about long term financial frame and guidance. So it's always possible to go through it, although I don't anticipate that will happen given the strong cash flows we've seen in the first half of the year. Supply and trading overall, gas and oil is tracking to plan so far this year. Oil trading had a stronger Q1 than Q2, but actually if you add up the first half, it's tracking just at around about plan and is bang on the historical 5 year average. So there's no major issues with 2Q other than the fact it was weaker than 1Q and it was weaker than what was a strong 2Q last year in comparison.
So that's the decoding for you. And other than that, I can't give you any more specifics.
Thank you, Jason. We'll go now to Gordon Gray of HSBC.
Thanks. Two quick ones, please. Firstly, on Deepwater Horizon payments. If I recall, the non fine portion of it, the majority of it is tax deductible. But although you're generating profits at the moment in the U.
S, the pre and post cash tax cash outflows are the same. Can you talk about how much of a tax shield, let's say, is still outstanding from Deepwater Horizon payments and how that may work its way through? And the second one was just one about the R Series fields in India. Just if you can give us a feel for the clarity you have and if possible some more detail on the pricing of the gas that gives you confidence in the long term returns from that project?
Yes. So in terms of the tax credits off of Acadique will arise, and the majority of those have been booked. A number of them have already cleared their way through the system. If you think now we're sort of year 7 beyond where we were in terms of the original provisions that were taken. And the only increase, the only credit for the tax charge will be what's been taken for this quarter associated with business economic loss claims that we laid out for you in the results.
So that continues to work its way through our annual results. And as you say, as we start to see the U. S. Come back into profit, you'll see those credits start to work their way through. But a number of those credits have already worked their way through the system over the last 6, 7 years.
And as India has said that they want to increase their share of gas 20% domestically, we're in a with the new contracts market rates that put us probably the price will vary a little bit quarter to quarter, but the $6 to $7 area for the pricing. With the FIDs that we put in place and the reengineering and retooling of the cost of the developments come way down, they move way up in our prioritization. We're starting out with the first phase. We've got 2 more behind it after the R series. 1 is a D55 field, which is deep below the KGD 6 platform itself.
So these projects are looking very good right now and there's a lot of government support for these things to come on.
That's great. Thanks.
Thanks, Gordon. Turning next to Thomas Adolff of Credit Suisse.
Good morning. I've got two questions as well and going back to CapEx, if you don't mind. Firstly, in terms of capital efficiency and productivity, the levels you have reached today, do you think it is harder to go much further at a steady oil price? And what I'm interested in is further capital efficiency, including as well as excluding the benefits from automation, big data, etcetera, things like where we are where are we on the standardization process? And in the context of that, what is assumed in your 2021 targets?
And secondly, perhaps also indirectly linked to the first question, you said your CapEx guidance represents a hard seeding and a soft floor. But in the context of the soft floor, how long can you go before you start to start the business of capital? And how does it compare at a steady
With that Thomas, I think if Bernard were here, he'd tell you in terms of longer term, he's looking to position that division and business to ensure that it's robust at $45 a barrel. And no doubt we may well see those levels again over the next 12 months. So I think there is more capital productivity to come through from all the areas you've just laid out. And I think you remember at the end of February, Bernard talked about all of the modernization and technology advancements that we're making. You will have seen some announcements in the press around things that we're doing.
They will inevitably lead to more capital productivity, which we're seeing right across other sectors. And a number of things we've been early adopters of, we're now starting to bring into fruition, which saw some of the things Bernard talked about at the end of February. So there is more to come in that space. In terms of the short term, because really we're only talking the next 12 months out in terms of the flexibility in the frame to the downside. There's probably about $1,000,000,000 of capital to the downside if we saw a prolonged period of $45 a barrel over the next 18 months.
I suspect that will not be the case, but nevertheless we will have plans in place to make sure that
we can deal with that and ensure
that after effectively giving ourselves 3 years to get the company back into balance after that 4 year period of $100 a barrel, then I think it's right that next year we will be back in balance.
And Thomas, I'll just add on the upstream, the technologies that are not fully built into our cost estimates that will transform new developments will be the transformation we'll see in drilling, automated drilling will come in, the use of sensors and automation and all across these developments will undoubtedly lead to productivity increases that we haven't yet fully built in. In terms of starving the business for capital, I think it's always going to be the discipline. We have more opportunities that we can actually pursue going forward. So we'll just try to get that balance right and make sure we continue the growth without starving the business of capital, but really driving that efficiency into it.
Thank you.
Thank you. And we'll turn next to Rob West of Redburn. Go ahead, Rob.
Hi, Bob. Hi, Brian. Hi, Jess. Thanks for taking my question. The first one is just a bit of clarification on Page 21, where you talk about major projects ahead of schedule, which I think is the title of the slide.
I was wondering, is that referring to some of the start ups this year where the ahead of schedule has already been announced in press releases? Or looking down that list, are there any in 'eighteen or 'nineteen, 'twenty that are coming in ahead of the milestones you've set out for them along the way? So that was the first question. And the second one was just going back to what Anish asked you about the extra provisioning for Macondo. I just like to understand a little bit better what is mechanically happening where those extra charges need to be taken?
I don't know if you can give us more detail on what actually changes quarter to quarter, where you have to take those extra charges, so we can get a sense of whether any future charges might be sensible for us to kind of put into our numbers as well. Thank you.
Rob, a couple of things in terms of major projects ahead of schedule. These are some of these schedules we laid out quite some time ago. Thunder Horse South, which came on last year was far ahead of schedule and under budget. Of course, we've seen West Nile Delta come on this year. Zohr, which was originally a 2018 project, now will come on in 2017, of course, operating with ENI.
Kazan at one point was an 2018 startup. It's now getting close, so we've narrowed it back down. If you look ahead to 2018, I'll just pick a couple of projects. I think Atoll, the first phase in Egypt has potential to be ahead of schedule. It's not inconceivable it could come on before the end of this year, but probably Q1 next year.
That's moved fast very, very quickly. Phase 1 of Chardanese, the delivery of gas into Turkey, that's moved up sort of targeting I think probably October next year. And then Maersk is operating Killeen, which is we've seen that move up as well. So those are just a few on those lists. And of course, these our schedules change all the time, of course, as we get further into the engineering, we can see it and be more precise.
But I think the execution of our major projects team over the last 4 years has been quite remarkable and a transformation from the phase that we were in before.
And then
in terms of will arise. It's really around the runoff of the final piece of the claims facility. There was a recent ruling in the court which has led to if you remember at the very start of this process we had about 149,000 claims in that facility. We're down to 5,000. There's been a recent court ruling which majority wise underpinned a number of other rulings we have which has helped in terms of proceeding going forward.
But it's also effectively resulted in the recycle of about 2,000 of the 5,000 remaining claims to go back through the process which is deferring things out which means admin costs are slightly higher and a redetermination around some of those claims as a result. So hence that's why we put you through this extra charge. Effectively, we're expecting everything to be done by the end of next year. There's a slight 12 month delay to the runoff and the final piece of the claim. But we don't believe it will have a cash impact this year, and it will have a minimal cash impact next year.
That's very clear. Thank you.
Thank you. And we'll take a question now from Jon Rigby of UBS.
Thank you. Can I ask you about the Downstream? I mean, you invested a lot of time and effort in presenting to the market on the Downstream about a month ago with quite a differentiated bit of disclosure and discussion around the separate businesses that go into the downstream. And you talked about some of the progress today, but the disclosures that you're giving are very traditional, one might say, somewhat old fashioned. And I think as you acknowledge, the trading result this quarter sort of emphasizes the volatility in that business.
So wouldn't it be better or have some thought been given to expanding disclosures to talk about some of the progress in the underlying sub segments around the conversion of sites and other progress that you're making to emphasize progress made in the Downstreams, what are quite ambitious earnings and cash flow targets? That's the first question. The second is, Brian, you talked about the use of cash as and when you move to cash surplus and you talked about the balance between the anti dilution of the script and CapEx. You didn't mention debt. And I wondered whether over the longer term, given what's happening in the market, given obviously volatility in oil prices, the impact of shale, etcetera, whether there's been any consideration taken around sort of lowering through cycle net debt as and when you can.
Thanks.
So maybe John, on the second part of the question, Our average cost of borrowing is just over 2%. So I mean just to put that into context that it's not that expensive to carry that level of debt. And you'll recall during the Macondo period of uncertainty, we moved the range down to 10% to 20%. But now that's if anything the push from investors is actually 30% is pretty comfortable couldn't you go higher. So net debt is not one of the issues that sort of on the agenda in terms of now it will naturally decline over time as we go forward and debt rolls off.
We'll have choices as to whether we want to renew that debt depending on where the prevailing rates are. But right now economically, it's actually it's not a bad place to be in terms of where we are. So that doesn't cause any cause for concern. On Downstream, I think over the last 4 years, we've done a lot of disclosure. You've got sub segmentation of the fuels business.
We show you lubricants, we show you chemicals. So you've got access to those. I think the downstream Investor Day, Tufan, laid out a lot of information, which again you'll see in the disclosures. We talk about the number of new sites that we've added so far this year. I think it was something around the order of 90 new sites.
We have the Woolworths transaction, which is in the sort of regulatory phase in terms of approvals going through and what we're doing on the Convenience Partnership side. We also give you some indication around trading inside the fuels business as you alluded to in terms of volatility. But we'll take on board your comments and we'll sort of talk with Tufan about whether we can give you more disclosures going forward. But you will start to see the underlying improvements come through that we saw over the last 2 or 3 years. And what we've laid out for 2021, you'll get a lot more information around that going forward.
Thanks.
Thanks, John. And the next question will be from Martin Ratz of Morgan Stanley.
Yes. Good morning. Thanks for taking my questions. I have 2. I also have a question on Slide 21, which is the exhibit that shows your major projects over the next couple of years.
Altogether, it adds up to 800,000 barrels a day of oil equivalent production. But if you focus on the projects that are oil, as far as I can see, they add up to about 85 1,000 barrels a day of that total, so a smidgen above 10%, suggesting that the other 90% is gas. Now I know the mix is shifting and that the strategy is sort of moving. But is that really the strategic intent of BP to have the oil gas mix shift so much towards gas over the next couple of years? And the second question is relates to the Russia Sanctions Review Act.
I have to say, I struggle to really understand how much this means or what it could mean. But perhaps could you give us your view of what it would mean for BP if this was passed in its current form?
Right. Thanks, Martin. Both good questions. There is a shift in the portfolio to gas. It's not a 90% shift.
We do have the oil projects in there. If you look at the Thunder Horse expansion projects, you've got the Mad Dog project, which is a significant oil project coming down the track. Clare Ridge next year in the U. K. Quad 204 this past year.
And then with a fair number of these gas projects, there's a lot of liquids and condensate with it. So I think the number isn't 90%. These projects we look at as advantaged gas projects. They're not like Lower 48 type projects. They tend to be in markets that are short gas, where we have contractual gas pricing so that the economics are clear.
The Egypt projects fit into that, the Oman projects fit into that. So there's gas and there's gas. And so these are quite selective gas projects for us. And Mauritania Senegal which has will have a significant amount of gas. I'd also add that there's a lot of oil prospectivity there as well which wouldn't be on the charts.
But it is. You've seen our strategic shift. We will low cost oil, advantaged oil will still remain a very important part of the portfolio, but a shift higher to gas. On the Russia sanctions, we've noticed that there were the language in the version that went into the house was full of unintended consequences. For example, that might have affected the Chardanese project, even the some of the Egyptian projects.
As I understand, The sanctions themselves The sanctions themselves as they're written and we'll carefully monitor this and of course we have to work very carefully within the sanctions, But we're not aware of any material adverse effect on our current income and investment in Russia or elsewhere or our ability to work with Rosneft itself. We stay away from targeted individuals, of course, and don't get involved in any of their personal business. But we've been able to work well within the guidelines for the last 3 years. And these new ones don't appear to change that.
All right. Thank you.
Thanks, Martin. And we'll go now to Macquarie Della Vigna of Goldman Sachs.
Thank you for taking my question. I was wondering over the next 12, 24 months, which projects you felt comfortable enough to FID and where you think that more work could still further lower the costs from here? Thank you.
Well, we deferred a couple of FIDs, you'll know in Pike and in Browse for good reasons. We could see ourselves with an additional FID in Atlantis Phase 3, a very significant oil development in the Gulf of Mexico, the costs are coming down. That's clearly got great prospectivity there. That's one I would think about. We've got another one in the Gulf of Mexico we may consider.
We need to work with our partners on that. You might see us with additional FIDs down the road here with in India. We've said we've sanctioned the first one with the R series, but there's others in India. And we've just recently sanctioned Angeline in Trinidad. So we'll pace these out, we'll be very selective about them, but we've got some good projects there that you don't see on the list on Slide 21, which and I'd also add some of those are oil.
Thank you.
Thank you, Michele. Next question from Ian Reid of Macquarie.
Yes. Hi, guys. Thank you very much. A couple of questions, please. 1 on Senegal Mauritania.
Just wondered how the recent discovery of Yakar has changed in any way the planning you've got for developments there? Is this going to kind of change the focus from the Tortue discovery? I wonder if you can give us an update on what you're planning at the moment in terms of FID on that project? And second question, Bob, just coming back on this Russia issue and just perhaps a bit more philosophically, the dividend from Rosnet has now fallen below $200,000,000 per annum. And it looks like it's not going to move very much from that given the outlook for oil prices.
I'm just wondering how you feel about the return on the investment from the significant amount of money you've got invested in Rosneft following the dissolution of 10 ks BP and whether that really whether the strategic upside, which you keep talking about, really compensates for the very low return you're getting from that investment?
Yes. Ian, thanks. On Mauritania Senegal, we had that significant discovery south of Tortue in Senegal, whereas Tortue is on the line between Mauritania and Senegal. We're drill stem testing a well right now in Tortue. I think this is such a prospective region now.
We see resources there. If we look at it, I think there's probably 50 Tcf of gas out there in Mauritania and Senegal. The development concepts, I think will be modular in a way that we'll be able to we need to appraise this and then we'll optimize it. We have a development concept now for Tortue, but we can alter this depending on discovery of other resources out there. We'll be drilling some wells in Mauritania, the Hippocamp project in Requin Tigua this year, all of those things could change our thinking in terms of what could be a fairly complex resource area and maybe even further in the north in Mauritania there's some oil.
But I think what that discovery essentially does, it just demonstrates the high potential of the basin itself. So I would stay tuned with that. It's all good news. We'll see what happens on the DST and these other wells that we're planning to drill this year. On the Rosneft dividend, by the way, there'll be an extraordinary general meeting of Rosneft in September where they'll begin to declare dividends twice a year.
So it's always been 1 year dividend once a year. We'll see another dividend payment in the 4th quarter. I'm reasonably sure that's the outcome from the voting. Rosneft is 5,500,000 barrel a day company. It has lots that it's doing to make itself more efficient.
The Russian government is reviewing their tax system, because it was basically put in place $100 oil. I still believe it has lots of upside potential. It like BP is working to get its breakeven cost down. And so I think it's doing exactly that strategically the things any company should be doing at these oil prices and I still remain hopeful that we'll see improved profitability from them. But I think this step of going to a dividend twice a year based on half year earnings, and then looking at the portfolio, the tail of the portfolio is all positive.
Okay. Can I just ask any update on the timing of FID for Tortue?
Well, no, not with the DST going on now. I think that's part of it is just to appraise it further. But we've done a lot of engineering work with Kosmos and we'll be able to move pretty fast on it. But no, I can't give you a date right now.
Okay. Thanks, Bob.
Thank you. We'll take a question now from Chris Kupland of Bank of America.
Thank you. My two questions are as follows. Firstly, Brian, you once again refer to the €2,000,000,000 to €3,000,000,000 annual disposal rate that we should expect from 2018 onwards. Is that a net number? Or should we assume that, that proceeds generated will partly cover ongoing oil spill payment costs and at the same time be reinvested in external growth, the likes of ZOAR and Mauritania that we've seen over the last two quarters?
And my second question would purely be for a clarification. You said you've announced EUR 2,500,000,000 of disposals so far this year. Can you already tell us how much cash flow you those assets have generated in the first half so far? Thank you.
So on the second question, Chris, the difference, it's $800,000,000 of proceeds have come in, in the first two quarters and the difference is, of course, SECO, which is due to close by the end of this year. It will be the delta between those two pieces. And then on the €2,000,000,000 to €3,000,000,000 that I mean it's not that they will cover in any 1 year. But so effectively over time what we've said disposal proceeds will cover deepwater rise and payments and inorganics. And for next year, actually, that will be the case.
So something around $2,000,000,000 to $3,000,000,000 will cover, euros 2,000,000,000 of deepwater rising payments that currently forecast for next year, if we look at the schedule of payments to come out and where we think the claims facility is and the balance of inorganics in terms of cash payments in 2018. So that's correct.
And sorry, Brian, for SECO in the first half in terms of cash flow that you've still consolidated in terms of run rate?
In terms of proceeds or in terms of the earnings and the asset?
Underlying earnings. No.
So the cash, that is still consolidated inside the numbers in the first half of the year. And that will only be deconsolidated when the transaction closes once it goes through regulatory improvements in China.
And in the first half, there would have been a few couple of 100?
We don't do cash numbers by sub assets, which I don't think you'd expect, Chris. But there is a significant amount of proceeds to come with the closing of that transaction in the second half of the year, around $1,700,000,000 is the full consideration.
Yes. Okay. Thank you.
Thank you, Chris. And we'll take the last question now from Biraj Bakhataria of RBC.
Hi. Thanks for taking my question. I had a couple. So firstly, in the lower 48, the data you provided shows that the costs of or the operating costs have gone up for the last couple of quarters. I was wondering if you could talk a little bit about the underlying trends you're seeing there.
And then secondly, back on FIDs, I just want to get a sense of how you're thinking about this going forward. One of your peers has talked about 2017 being a window to lock in your part of month of cycle service costs. You don't seem to be in as much of a rush. I was wondering if you could talk a bit about what you're seeing maybe on the offshore market or any commentary there? Thank you.
On Lower forty eight, it's nothing more than phasing of where we are in terms of the various programs. We obviously have a choice in terms of what we do in the drilling space each quarter. So it's quarterly noise that you can see coming through those numbers. But the long term focus continues to remain on making sure that we continue to drive efficiencies and costs through into that business and what we're learning from the various activities that we've done that we laid out for you last year.
And Biraj, on the FIDs, you're right. Well, some of the competitors are saying 2017 is a year to lock it in. We have been locking in some of the low yard spaces and contracts for the FIDs we've done in 2016 and 2017, not convinced that this is the low point, particularly in the offshore and offshore drilling. For example, where I think there's such a big oversupply that you can expect to see drilling costs come down. So it's not clear yet that we have to rush to lock these in.
That's very helpful. Thank you.
Thank you, Biraj. And I think that's the last of our questions. So thank you very much everybody for helping us run a more efficient call today. And I'll just hand back to Bob for closing remarks. Thank you.
Thank you, Jess, and thank you everyone for listening today. It is quite a bit shorter. It may not feel like it, but it's been quite a bit shorter this quarter than the other quarters, which is absolutely based on your feedback. I'll just say in February, we laid out a strategy for where we're heading, getting our business readjusted for the new price environment and we need to build a track record. This is only the Q2 out of the 20 quarters that we laid out then.
So we'll just keep coming back, snapshots as we move forward on this. I think we've delivered pretty well on this quarter. And particularly, as you know, we really drive our business for cash and that's the most important number that I think comes through on this quarter. So thank you all very much.