Hello and welcome. This is BP's 4th Quarter and Full Year 2016 Results Webcast and Conference Call. I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley and our Chief Financial Officer, Brian 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. Welcome everybody and thank you for joining us. We're reporting on another challenging quarter today and another challenging year for the industry. But for BP, it's been a very eventful quarter and one where we've continued to make good progress on many fronts. We certainly had a busy end of 2016, and I'll spend some time in a moment on that and our other actions to get back to growth.
As usual, Brian will take you through the detail of our 4th quarter numbers and provide an update on our guidance for 2017. I'll come back to briefly update you on the progress in our upstream and downstream businesses. And at the end, Brian, Jess and I will take any questions you have. But first, I'd like to take a look at the environment. By the end of last year, we were seeing Brent oil prices around where they are today in the mid-50s.
But in 2016, the average oil price was $44 per barrel, the lowest for 12 years. Henry Hub gas prices were also weak in 2016, averaging $2.50 per MMBtu for the year and the refining marker margin at $11.80 per barrel was the lowest since 2010. As we stand today, Brent oil prices have risen by around $10 per barrel since the OPEC deal was announced. We still expect oil demand growth to be strong this year at 1,300,000 barrels per day with modest growth in non OPEC supply, which means the timing and extent of market rebalancing depends heavily on OPEC behavior. The physical market has begun to tighten with inventories falling a little faster than seasonal norms.
However, OECD inventories at the end of 2016 were still close to 3,000,000,000 barrels, significantly higher than their recent historic average. We expect much of the historical inventory overhang to be eroded by the end of 2017 if OPEC and non OPEC producers deliver on their promised production cuts. Any shortfall could delay this process and does still pose some downside risk to prices in the near term. So while we remain optimistic about the market continuing to rebalance in 2017, we recognize that this can take some time. In short, the road to a more balanced position still has uncertainties.
We are very aware of these uncertainties, but as you'll hear today, we are confident in our resilience to the environment and we're continuing to build momentum in our businesses. Turning to our results. The slide you are seeing now is a summary of our full year 2016 results for the group as a whole. Our underlying replacement cost profit was 2 point $6,000,000,000 for the year. Our underlying operating cash flow, excluding oil spill related payments, was $17,800,000,000 for the year.
This was 12% lower than last year, but represents strong performance in these tough market conditions. Organic capital expenditure in 2016 was $16,000,000,000 excluding the consideration for our recently announced renewal of 10% of the Abu Dhabi ADCO concession. Proceeds during the year from divestments totaled $3,200,000,000 Gearing at the end of the year was just under 27%. We distributed $4,600,000,000 in cash to shareholders through dividends. And finally, our reserve replacement ratio for 2016 is estimated at 109%, including the impact of the Abu Dhabi concession renewal.
Putting these numbers in perspective, we finished the year ahead of where we expected to be at this point in rebalancing our organic financial frame, supported by the significant and rapid structural changes we've made to our cost base. Our organic capital of $16,000,000,000 was well below our original guidance of $17,000,000,000 to $19,000,000,000 for the year. As well, we reached our controllable cash cost reduction target of $7,000,000,000 versus 20.14 a year early. So looking over the course of the year, we're pleased with our underlying financial progress despite the very weak environment. And Brian will give you some more details on this in a minute.
More broadly, we've had a very busy and eventful year. We've clarified the remaining material uncertainties around our Deepwater Horizon liabilities. This has allowed us to put more of our energies into shaping a strong future for the group. In the upstream, progress is visible with 6 major project startups completed in 2016, including the early startup of the Thunder Horse South expansion in the Gulf of Mexico. This supports our aim to drive material growth and free cash flow from this business over the medium term.
In the downstream, we rolled out our biggest fuels launch in a decade. The new ultimate fuels range is just one example of the differentiated customer offers helping to underpin material and reliable earnings growth in our marketing businesses. And most significantly, we have made big strides in creating a stronger platform for growth. We've moved forward a number of the high quality development options you are already familiar with, and we have deepened our incumbent interest in some specific areas we consider to be very strategic. And we've added to our portfolio with some creative new partnerships and some exciting new opportunities.
This slide pulls together some of our key activities last year, many of which came in a busy final quarter for announcements. Earlier in the year, we completed the merger of our Norwegian North Sea portfolio with Detnorsk to form Aker BP. The new company is now well established and we believe it has a potential to grow its production to around a250,000 barrels a day by the early 2020s. More recently, we were awarded a 10% interest in Abu Dhabi's EDCO concession, which provides us with material long term onshore oil reserves, low cost oil production and cash flows. These are resources that we already understand well, which will add resilience and production to our upstream portfolio out to 2,055.
You may have also seen that we agreed to acquire world class working interest in discoveries in Mauritania and Senegal, giving us a And in the Gulf of Mexico, we gave Mad Dog 2, the go ahead after 3 years of work to bring costs down to $9,000,000,000 which is around 60% lower than the original figure. We expect this to add around 140,000 barrels a day gross of oil equivalent capacity, supporting our post-twenty 20 returns focused growth. We're also expanding other incumbent positions where we see opportunities for greater growth. Our purchase of a 10% share in the giant offshore gas field Zohr is an example of this as it complements our existing large gas portfolio in Egypt. We also reached agreement with the government of Oman for Phase 2 of the Kazan gas project.
And in Azerbaijan, we will continue to build on the success of the Azeri Sharag Gunesli oil field following the signing of a letter of intent to extend development out to 2,050. In the downstream, we announced a new strategic partnership with Woolworths, one of Australia's largest supermarket retailers. Subject to regulatory approvals, this will see us acquiring and operating over 500 fuel and convenience sites as well as establishing a new convenience retail partnership. You may have also seen the partnership we entered into with Fulcrum Bioenergy, a pioneer in the development of low carbon jet fuel. Taken together, all of these opportunities are building the resilience, competitiveness and balance of our global portfolio.
They are helping shape the future of the group and getting us back to growth. So we've been busy, but our commitment to keeping our people and operations safe has remained our top priority. This slide shows our progress at the group level. Overall, the data suggests we have maintained the progress made in previous years and are seeing improvements in some key measures. Tier 1 and Tier 2 process safety events are industry standard process safety metrics.
In 2016, we had 20% fewer Tier 1 events than in 2015, while the total number of Tier 2 events was broadly flat with 2015. Turning to losses of primary containment or LOPCs. These refer to releases of any hazardous material from primary containment, including very small ones. LOPCs increased in our Lower forty eight business, partly due to difficult winter operating conditions, but were broadly flat elsewhere. Looking at personal safety, our recordable injury frequency rate has reduced in 2016.
This continues a pattern of improvement in this area over a number of years. As I will never tire of saying, safety is at the heart of all we do. We're not going to be satisfied while we're having accidents or harming our people. We know there's always more to do. With that, I'll hand over to Brian to take you through the numbers.
Thanks, Bob. Looking more specifically at the oil price for the Q4, Brent crude averaged $49 per barrel in the 4th quarter, up from $46 per barrel in the 3rd quarter. Following the production cut announced by OPEC and non OPEC producers at the end of November, the oil price showed strong momentum and is now comfortably above $50 per barrel. United States gas prices rallied in the 4th quarter due to sustained falls in production and continued growth in demand. Henry Hub averaged $3 per 1,000,000 British thermal units, up from $2.30 a year ago and $2.80 in the 3rd quarter.
The 4th quarter global refining marker margin remained weak at $11.40 per barrel compared to $11.60 per barrel in the 3rd quarter and $13.20 a barrel a year ago. Looking ahead, we expect the stronger outlook for both oil and gas prices to support improved realizations in our upstream business this year. Although refinery utilization is likely to remain weak, we expect margins to recover slightly in 2017 due to lower product stocks, but to still be well below the very high margins of 2015. Turning now to the results. BP's 4th quarter underlying replacement cost profit was CAD400 1,000,000 compared with CAD200 1,000,000 a year ago and $930,000,000 in the Q3 of 2016.
Compared to a year ago, the result reflects lower cash and non cash costs across the group and higher upstream liquids realizations, partly offset by weaker refining margins and a higher level of turnaround activity. Compared to the previous quarter, the result reflects the absence of the one off UK tax benefit reported in the 3rd quarter, a weaker supply and trading result and higher turnaround activity, partly offset by higher upstream oil and gas realizations. 4th quarter underlying operating cash flow, which excludes Gulf of Mexico oil payments was CAD 4,500,000,000 The 4th quarter dividend payable in the Q1 of 2017 remains unchanged at CAD 0.10 per ordinary share. In Upstream, the 4th quarter underlying replacement cost profit before interest and tax of CAD 400,000,000 compares with a loss of CAD730 1,000,000 a year ago and a loss of CAD220 1,000,000 in the Q3 of 2016. Compared to the Q4 of 2015, the result mainly reflects lower costs including the benefits of simplification and efficiency activities, lower exploration write offs and higher liquids realizations.
Excluding Rosneft, 4th quarter reported production versus a year ago was 5.5% lower. After adjusting for entitlement and portfolio impacts, underlying production increased by 1.8%, largely reflecting major project ramp ups. Compared to the Q3, the result mainly reflects higher liquids and gas realizations and lower rig cancellation and one off charges. Looking ahead, we expect Q1 2017 reported production to be higher than the Q4 of 2016, reflecting the impact of the Abu Dhabi concession renewal. Now turning to downstream.
The 4th quarter underlying replacement cost profit before interest and tax was CAD880 1,000,000 compared with CAD1.2 billion a year ago and CAD1.4 billion in the 3rd quarter. The fuels business reported an underlying replacement cost profit before interest and tax of $420,000,000 in the 4th quarter compared with CAD 890,000,000 in the same quarter last year and CAD 980,000,000 in the 3rd quarter. Compared to a year ago, this reflects a significantly weaker refining environment and a particularly large turnaround at our Whiting Refinery, which had a significant impact in the quarter. These adverse effects were partly offset by higher refining margin capture in our operations, increased fuels marketing performance driven by retail growth and lower costs reflecting the benefits from our simplification and efficiency programs. Compared to the Q3, the result reflects a significantly weaker supply and trading performance and the impact of the Whiting turnaround, which I previously mentioned.
The lubricants business reported an underlying replacement cost profit of $360,000,000 in the 4th quarter compared with CAD290 1,000,000 a year ago and CAD370 1,000,000 in the 3rd quarter. This result brings our full year pretax earnings to a record $1,500,000,000 The petrochemicals business reported an underlying replacement cost profit of $100,000,000 in the 4th quarter. This brings our full year pre tax earnings to CAD380,000,000 compared with CAD170,000,000 in 2015. Looking to the Q1 of 2017, we expect a similar level of refining margins and lower turnaround activity compared with the 4th quarter. Based on preliminary estimates, we have recognized CAD135,000,000 as BP's share of Rosneft's underlying net income for the 4th quarter compared with CAD 120,000,000 last quarter.
This reflects higher euros prices and duty lag benefits partially offset by higher expected tax impacts. Our estimate of BP's share of Rosneft production for the Q4 was 1,200,000 barrels of oil equivalent per day, an increase of 12% compared with a year ago and an increase of 12% compared with the previous quarter. The increase reflects the completion of the acquisition of Basneft and Rosneft's increased stake in Petromenogas joint venture. Further details will be available when Rosneft report their 4th quarter results. In Other Business and Corporate, the pretax underlying replacement cost charge was CAD 420,000,000 for the 4th quarter, an increase of CAD 120,000,000 on the same period a year ago, reflecting adverse foreign exchange impacts.
The average quarterly charge during 2016 was $310,000,000 in line with guidance. The adjusted effective tax rate for the 4th quarter was 10% compared with 37% last quarter. This mainly reflects the reassessment of deferred tax asset positions, partly offset by foreign exchange impacts. The adjusted effective tax rate for 2016 was 23% compared to 31% for 2015 excluding the impact of the North Sea tax changes in both years. Turning to the Gulf of Mexico oil spill costs and provisions.
The total cumulative pre tax charge for the incident is CAD 62,600,000,000 or CAD 44,100,000,000 after tax. The charge taken for 4th quarter was CAD 800,000,000 pretax or CAD 530,000,000 after tax. This reflects our latest estimate for claims including business economic loss claims and other costs and the ongoing unwind of discounting effects on the provision which have no impact on cash. Significant progress has been made in the Q4 and we are moving towards completion of the process for resolving business economic loss claims. Amounts to resolve the remaining claims are expected to be substantially paid this year.
We have revised our provision for these claims to reflect our best estimate of the cost of the remaining claims. The pre tax cash outflow on costs related to the ore spill for the full year 2016 was $7,100,000,000 Looking next to cash flow. This slide compares our sources and uses of cash in 2015 2016. Underlying operating cash flow, which excludes pretax oil spill related outgoings was CAD 17,800,000,000 in 2016, of which CAD 4,500,000,000 was generated in the 4th quarter. This includes a working capital release of $3,200,000,000 for the year with $2,000,000,000 in the 4th quarter.
Organic capital expenditure for the full year of $16,000,000,000 included $4,500,000,000 for the 4th quarter. Divestment proceeds totaled $470,000,000 in the 4th quarter and $3,200,000,000 for the year, including $570,000,000 from the partial sale of the group's shareholding in Castrol India. Gulf of Mexico oil spill payments were $2,000,000,000 in the 4th quarter, bringing full year 2016 cash payments to $7,100,000,000 We estimate that the cash impact of non operating restructuring charges was around $1,000,000,000 in 2016 with around CAD 2,000,000,000 since the Q4 of 2014. As Bob noted, cash flow delivery from our operations was robust despite the much weaker environment, supported by delivering our CAD7 billion cash cost reduction target a year ahead of plan. As well, organic capital expenditure for the year was well below our original guidance.
So we ended the year ahead of where we expected to be on rebalancing organic sources and uses of cash. This helped mitigate the net inorganic outflow that rose due to rephasing of divestment proceeds previously expected in 2016 into 2017 and Deepwater Horizon cash payments that were higher than we anticipated for 2016 mainly due to faster resolution of claims. Net debt at year end was CAD 35,500,000,000 and gearing was at 27% comfortably within our 20% to 30% target band. In 2017, we see a number of factors impacting our financial framework. In addition to what we anticipate will be a stronger environment compared to 2016, we expect group operating cash flow to reflect the full cumulative effect of having already reached our $7,000,000,000 cash cost reduction target.
It will also reflect the ongoing focus on continuous efficiency improvement across the group. With our portfolio now growing, this will show up in future mostly in the unit cost matrix of our businesses. Non operating restructuring charges are expected to continue into 2017, although we expect the cash flow impact to be lower than last year. We now expect 2017 organic capital expenditure to be between CAD 16,000,000,000 to CAD 17,000,000,000 including the estimated operational capital spend for our portfolio additions. This compares to previous guidance towards the lower half of CAD15 1,000,000,000 to CAD 17,000,000,000 range for the old portfolio.
In addition, we expect some CAD 700,000,000 of inorganic cash outflow in 2017 related to these already announced transactions. Compared to 2016, we expect divestment proceeds to be higher in 2017 in the range of CAD4.5 billion to CAD5.5 billion for a year and then reducing from 2018 to more typical CAD2 billion to CAD3 billion per annum. At the same time, we estimate Deepwater Horizon cash payments to be lower than last year also in the range of CAD 4,500,000,000 to CAD 5,500,000,000 As already noted, we expect the remaining business economic loss claims to be substantially paid this year. We therefore expect the total deepwater rising cash payments to fall sharply to around $2,000,000,000 in 2018 and to then step down to a little over $1,000,000,000 per annum from 2019 onwards. So putting all of this into context, we remain firmly focused on reestablishing a balance in our financial framework where operating cash flow covers capital expenditure and the current dividend at the prevailing oil price.
The strong progress we have made to date in structurally rebalancing our financial frame is allowing us to maintain our dividend and underpins our confidence in pursuing the inorganic transactions already noted by Bob. This is consistent with our aim to retain the dividend at a level we believe is supported by the long term cash generating potential of our businesses, while balancing investments to ensure we can grow free cash flow over the longer term. As already discussed, we expect the environment to remain uncertain for a while yet and we have the usual seasonal trends in our business to navigate. Our recently announced portfolio additions are accretive to cash flow over the longer term, but create additional cash outflow in the early years. So current oil prices notwithstanding, we anticipate rebalancing at the prevailing oil price towards the back end of the year.
This also coincides with the mostly second half start up of our extensive program of new upstream major projects. Including the impacts of our announced portfolio additions, this translates to balancing organically by the end of the year at a Brent oil price of around $60 per barrel. Our balance sheet has the flexibility to deal with near term fluctuations. For this year, we will retain the option of a scrip as an undiscounted alternative to our cash dividend. We continue to target gearing within a 20% to 30% band going forward, monitoring our cash inflows and outflows closely.
Over the near term, we will explore further funding mechanisms or divestments if required to enhance cover and retain flexibility to take further advantage of growth enhancing opportunities. Looking further out and based on our new portfolio, we expect organic free cash flow to start to grow at around this same price level. We expect this to be supported strongly over the medium term by the ramp up of our new slate of upstream project start ups, strong marketing growth and from the accretive effects of our enhanced portfolio. As noted in October, once rebalancing is achieved, we would look to address the dilution that arises from the scrip dividend alternative. We will then aim to ensure the right balance between disciplined investment for even stronger growth and growing distributions to shareholders over the longer term.
This slide summarizes our remaining guidance for 2017. We expect full year underlying production in 2017 to be higher than 2016, primarily due to our major project start ups. We also expect actual reported production to be materially higher as this will include the renewal of the Abu Dhabi concession, although the actual outcome will also depend on divestments, OPEC quotas and entitlement impacts. In 2017, we expect DD and A to be higher than the 2016 charge of CAD14.5 billion mainly reflecting the impact of the Abu Dhabi concession renewal. In other business and corporate, the average underlying quarterly charge is expected to be around CAD 350,000,000 dollars although this may fluctuate between individual quarters.
From the Q1 of 2017, we will recognize our 10% share of the Abu Dhabi concession on a pre tax basis within the Upstream. We expect this will have a material impact on Upstream pre tax underlying replacement cost profit, but will also reflect a higher effective tax rate for the group. In the current environment, we expect the effective tax rate to be in the region of 40% in 2017, mainly reflecting the inclusion of the Abu Dhabi concession. We will publish our updated rules of thumb on our website later this quarter. I'll now hand you back to Bob.
Thanks, Brian. I'd now like to take a closer look at how our upstream and downstream businesses are contributing to the picture of growing resilience that Brian has set out. Looking first at the upstream, we achieved a lot in 2016 in a challenging price environment and continue to become a more resilient business. You can see this in improvements in our operating performance, the actions we've taken to reduce cost and capital spend through our active portfolio management. We continued to see strong operating performance in 2016 with plant reliability for operated assets at around 95%.
All 11 turnarounds in 2016 were completed on or ahead of schedule. This was accompanied by strong drilling performance with drilling and completion non productive time reduced to around 20% compared to 26% in 2015. I've already mentioned we had 6 start ups last year, which makes 2016 a big year for major projects with another big year to come. The first of the 2016 startups was in February with the startup of the Insala Southern Fields in Algeria. Then came Point Thompson in Alaska in April, the recent restart of Angolan LNG and Thunder Horse water injection in the Gulf of Mexico, both in May.
And in December, the Enamidis compression project in Algeria. Last on the list is the Thunder Horse South expansion in the Gulf, which started 11 months ahead of schedule and $150,000,000 under budget. We also made final investment decisions or FIDs on 5 major projects this year, including most recently the Mad Dog 2 expansion in the U. S. Gulf.
Last month, we completed installation of the jacket and topsides for the Juniper project in Trinidad, marking a significant milestone for the project. This organic growth keeps us on track for the planned 800,000 barrels of oil equivalent per day of new production from major projects by 2020 and contributes to growth beyond this. In addition to the 2016 exploration discoveries previously announced in Egypt and Angola, we've made significant progress in enhancing our portfolio with significant new access through our agreements with Kosmos Energy in Mauritania and Senegal, again the 10% share of the Zohr field in Egypt, 2 new deepwater exploration blocks in the Salina Basin in Mexico and our previously announced new access in China and Newfoundland, Canada. So 2016 was a busy year for the upstream. With our recent announcements, we now have a stronger and more diversified upstream portfolio that lays the foundations for future growth.
In the Downstream, the execution of strategy has delivered another year of material underlying performance improvement. Full year pretax earnings of $5,600,000,000 are more than 25% higher than 2014, despite the refining environment being significantly weaker than 2014 and one of the weakest in the last 10 years. This includes $3,000,000,000 of underlying performance improvement at constant margins since 2014, dollars 1,200,000,000 of which was delivered in 2016. This demonstrates that we continue to expand the earnings potential of our business. Our refining operational performance was strong with Solomon availability increasing to 95.3% for the full year.
In the Q4, we also completed the dissolution of our German joint operation with Rosneft. This will greatly simplify and refocus our refining business in the heart of Europe. In our fuels, marketing and lubricants businesses, we saw continued growth in pre tax earnings of more than 15% versus last year, reflecting underlying performance improvement and benefits from continued investment. Across our retail business, which is the most material element of our fuels marketing operations, volumes increased by 3%, supported by the success of our new ultimate fuels with active technology and the expansion of our convenience partnerships with leading retailers. As I mentioned earlier, our recently announced strategic partnership with Woolworths in Australia demonstrates our strategy of growing our advantage marketing businesses in important global markets.
Once completed, it will provide additional earnings and operating cash flows to the downstream. In lubricants, this year we had a record pre tax earnings. We had good growth across all of our growth markets and premium brands such as Castrol. And through technology, we continue to develop new offers and lower carbon products for our customers. In addition to Ultimate Fuels, we also launched new products in lubricants and petrochemicals.
Finally, total cash costs in the Downstream are now $3,000,000,000 lower than in 2014, their lowest level in more than 10 years. This reflects the benefits mainly from our simplification and efficiency programs along with some foreign exchange impacts. In summary, 2016 has been another year of delivery from our downstream business. It has continued to grow underlying earnings, is more resilient to the environment and has built a great platform for further exciting growth opportunities. Now it's time we moved on to take some questions, but let me briefly sum up what you've heard from us.
1st and foremost, our strong focus on safety and reliability is underpinning a track record of continually improving operational performance. 2nd, we've been working systematically to a plan to rebase our capital and cash spend. As Brian laid out, the group is moving steadily towards rebalancing our financial framework organically by the end of 2017 at around $60 per barrel oil prices, which includes the operational impacts of our many recent portfolio announcements. Our balance sheet is sufficiently strong to deal with near term volatility, while also being flexible. That's why we have been able to be creative with our portfolio to step in and capture a set of strategic opportunities that will add value and enhance future earnings and cash flow for many, many years to come.
3rd, we are increasingly resilient to all conditions, with that resilience coming from the progress we're making in focusing and simplifying both our upstream and downstream businesses. 4th, both upstream and downstream have been building capacity to deliver material and growing free cash flow for the group over the medium term, even if the environment stays much of where it is today. Our confidence in this outlook allows us to continue to sustain our dividend. Looking further out, our primary objective remains to grow sustainable free cash flow and distributions to shareholders. We are looking forward to showing you more of the detail in our strategy update on the 28th February.
We aim to show you how we are building an even stronger platform for growth, how we are retaining a focus on returns and how we are shaping our longer term future and what we all know is a rapidly changing world. So thank you very much for listening.
We'll take the first question today from Alastair Syme of Citi.
Good morning, everyone. Brian, can you just clarify on Q4 on the cash flow statement around the timing of dividends received from associates? It seems to be quite a big swing from previous quarters. And I have a follow-up question on Egypt as well, please.
Thanks, Alastair. Sorry, specifically, what is it in terms of related company income?
Exactly.
I think there would have been a cash inflow off the back of a bond in Argentina would have come through in the Q4. And I can't remember the exact amount, but that would have been part of the delta.
Okay. So it's not an unusual mismatch on dividends received this quarter?
No.
From associates? Okay. No. My follow-up question is on Egypt. Can you strategically, can you talk about the overall exposure to Egypt on a risk adjusted basis?
And are there any synergies on being in Zohr versus your existing Western Nile Delta business?
Well, I think I'll let Bob talk about the activity in terms of the ZOAR and how it sits within the portfolio. In terms of risk exposure, if anything with Egypt, I think the risk is significantly reduced from where we were 4 or 5 years ago in terms of both the portfolio we have because now being part of the SOR, of course, balances out some of that risk. It also enables us to deploy and we have deployed over the last 3 or 4 years Egyptian pounds paid locally into local contracts. And therefore, if you think about the the receivable that was coming under some stress post the various changes 3 years ago after the Arab Spring, That is now vastly reduced from where we are. And so from a risk perspective, Egypt is actually now in terms of our radar screen is much reduced from where we were.
Of course, as you pointed out, ZOOR helps in terms of further investments across our portfolio. But from a risk perspective financially, Egypt is reduced from where we were.
Yes, Alastair, the Zohr purchase for BP, of course BP and he and I work together all across Egypt in many places and we've got our own very large projects in Egypt, very large one, the West Nile Delta project, which come on towards the summer here. For us, Egypt is very strategic. As Brian said, we've worked there for 50 years without an interruption at all. We think it's got great potential as a gas market and as the West Nile Delta and Zohr come on this year, we think Egypt as a country's position potentially moving to a gas exporting country is in very good shape. So I know it's overlooked by a lot of people, but we're very pleased with that project and as well as the other ones we've got.
We've got other discoveries there that we're moving towards development as well.
We'll take the next question from Thomas Adolff of Credit Suisse.
Good morning. I've got two questions around the CapEx, please. The easy one, I guess, is I wonder what the share of CapEx today is that can generate cash flow within the next 2 years. Just wanted to better understand the cash flow cycle and financial risk associated to your CapEx. And the other question on CapEx I have is the longer term sustaining CapEx.
And last year in Baku, when you hosted the field trip, you talked about the portfolio quality and that you were very happy with what you had and that the sustaining CapEx will be at around $15,000,000,000 to $17,000,000,000 for the company as a whole. Obviously, since then, you've made a number of acquisitions presumably to strengthen your portfolio as you've highlighted, and that is also leading to a slightly higher CapEx range in the near term to $16,000,000,000 to $17,000,000,000 per annum. But I wondered whether this enhanced portfolio also now allows you to sell more in 2017 because I'm assuming that so the question I really have around that is, can the longer term CapEx range in the say world of $60,000,000 to $65,000,000 revert back to the $15,000,000,000 to $17,000,000,000 range or is the disposal plan merely a function of matching Macondo liabilities? Thank you.
So Thomas, let me just pick up the first part of the question, which I think is about capital in service and capital not in service. I don't have the precise figures for you. But obviously, given the number of big projects we've got coming on stream this year, there is a significant amount of upstream capital will be in projects. So I'm guessing somewhere close to 40%, 45% of the CapEx we're spending in the upstream this year will be in the major project wedge for 'seventeen. And we can come back to you with the specifics around that, but we don't normally give guidance around what's in service and what's not in service in terms of build.
In terms of the disposal program, I mean, as we've said many times, we've sold off close to 50, actually over $55,000,000,000 of upstream assets over the last 2 or 3 years at $100 a barrel of those higher prices. The next phase of divestments, and if you look at the divestments that we slated through 2016, the majority of those are midstream, downstream. Actually, quite a few corporate assets we had around the place have been sold off. The target we've set for next year has some upstream in there, but none of it that's going to have a significant impact in terms of the future capital program. So I think we gave you guidance at 3Q around €15,000,000,000 to €17,000,000,000 of capital for this year.
We've closed those extra transactions that Bob talked about in terms of creating optionality for the future. And therefore, we've moved the capital frame up to €16,000,000,000 to as you through into 20 and we'll see as you through into 2018. And then we'll see whether other opportunities arise this year. The ones that we talked about, they all came together at same time. You wouldn't normally have that many converge in that shorter space of time, but there may be other opportunities for us this year as well.
So I think the key is everything has to come back to the balance of the financial frame and making sure that we can cover organic CapEx and the full dividend with the operating cash flow. That gets more sustainable from here as we start to see the ramp up in projects and the new builds coming on.
Can I just follow-up on the last point you made? You said that there may be more opportunities this year and next. Presumably, you're referring to further acquisitions. And obviously, the focus also has to be on balance sheet. So would you fund further acquisition via the balance sheet or further equity issuance or more disposals?
Thank you.
Well, I think what we'll continue to stay focused on for our shareholders is deals which are accretive. And anything which is accretive, we will look at. But please don't let me send a signal out that we're out there on a shopping spree right now because we're not. But if opportunities arise, take Aker BP as an example for last year, which is great example of a late life asset that now has a huge growth opportunity through a creative innovative structure that we put in place. I could argue the same thing about Abu Dhabi, about Mauritania Senegal.
Each time you see a step into the marketplace, it's really about creating optionality for the future. But everything comes back to what are we trying to do for our shareholders. So I think if you see if accretive opportunities arise, then they're ones that we'll look at. But of course, it will all be bounded within the financial frame.
Perfect. Thank you.
Thanks, Thomas. Turning now to Martin Ratz of Morgan Stanley. Go ahead, Martin.
Yes. Good morning. I wanted to ask you two questions. So the CapEx has, of course, come down a fair amount during the course of this year, but the CapEx commitments you've entered into are quite significant and stand out relative to some of your peers. So I guess that reflects how you see this cycle unfolding as in it suggests that you think this is the right time to do projects.
And I was wondering if that is indeed sort of the right interpretation of that observation. The second thing I wanted to ask you about is the following. So on the 3Q conference call, there was a comment and I'll read it out. It said, in Upstream, growth is imminent and visible until the end of the next decade. And on this call, we're talking about the large number of transactions you've done over the last 2 months.
And the comment in the press release is that we've laid the foundations for BP to be back to growth. And I have to say, I struggle a little bit to make these things consistent with each other. Can you talk about that?
Well, Martin, a couple of things. One, I don't think our CapEx has ramped up very much. And we said 'seventeen to 'nineteen this year. We came in at 'sixteen. We're probably looking at a $1,000,000,000 more roughly this year.
So I don't see that as a massive boost. In terms of the growth going out, we've got 6 big projects coming on in 2017. In addition to the 6 that came on in 2016, the ones in Algeria, the Thunder Horse West Water Injection, Point Thompson, Angola LNG, Inaminas and Thunder Horse South expansions came on in 'sixteen. We've got the big Quad 204 project coming on in the North Sea. We've got Trinidad onshore.
We've got the compression project. We've got Juniper in Trinidad. We've got the giant Oman, Kazan Phase 1, Persephone coming on in Australia, West Nile Delta, very large project coming on in 'seventeen. You keep going on into 'eighteen. You see the big Claire Ridge projects in the UK, Killeen in the North Sea, the big Shaddanese project coming out of Azerbaijan and Atoll in Egypt.
The list goes on and on. We see guidance out there with some other FIDs this year as well to for that 800 1,000 barrels a day additional production from new projects. And I haven't mentioned them all. Mad Dog Phase 2 is another one. So I think if you lay out the upstream major project summary, the ones that we brought on, the ones that have come on this year, the ones planned in 2018 2019 and the FIDs you'll see, that's what is meant by the future growth.
Okay. Thank you.
Thanks, Martin. Next question from Oswald Clint at Sanford Bernstein.
Hi, good morning. And sorry to labor a point, but I had a similar question to the last few. It's really going back to the Baku trip when we hear about the 45,000,000,000 barrel resource base and 8,000,000,000 barrels that would have to be extracted over the next 13, 14, 15 years to continue growth. Maybe another question. Is there anything in that 8,000,000,000 barrel number that was supposed to be the development hopper that just isn't looking so attractive today that you had to make these deals in the last 2 months of last year?
Or these deals were just so attractive you had to move on them? The first question. And then maybe one, Brian, I'm just want to look at the cash flow numbers again, the kind of $18,000,000,000 last year and we have to step up, I guess, to $24,000,000 $25,000,000 this year to cover that CapEx and dividend. So, I can see getting half of that kind of $6,000,000,000 delta uplift from the commodity price, but is the other half coming from upstream volumes or is there a decent contribution from Whiting or I guess some of these Australian the acquisition in Australian retail in December? Thank you.
Oswald, I'm actually going to pick up the first part of the question first, then Bob might want to kind of sweep on it. But just to say, just from the financial frame perspective, I think Bob's just laid out a list of projects that I think underpins Martin's question that says call me old fashioned, but with that level of projects coming through and the nature of the gas and oil mix, that gives us significant growth. So actually, we didn't need to do any of the deals in terms of the future health of the company last year. And one of the things that actually really gave us confidence to execute on those, there are 2 things. 1 was being able to bound the liabilities around Macondo in terms of understanding now that we're in the final stages of that process around liabilities and understanding what the future commitments are.
But the second piece was also around recognizing that by the end of last year, we've managed to get the portfolio back at balanced at around $55 a barrel in terms of the portfolio we had at the end of last year. And we've given ourselves 8 quarters to do that. And if you remember back in February 2015, the lower someone reminded me on a call this morning about the lower for longer tag that we had that at the time people pushed back and said no, no oil prices will come back. We were very bearish and ensured that we got after a series of things around costs and capital to get the portfolio back to balance of 55. The great thing about being able to do that is that creates optionality.
And these deals are deals that my dear friends on my left, Bob, have been working for a number over a long period of time, and they came together at the right time. And I'll come back to the cash flow number. But I don't know if, Bob, you want to add anything around the deal structure we put through again in 4Q.
Well, I think as you said, those deals were not essential for us. We've been working on them for a while. They had to be accretive, some obvious ones in Abu Dhabi. The terms there came together and they're very attractive and they lengthened the company's life out 2,055. Azerbaijan, another natural one that you see us doing is looking for an extension there on the ACG concession, which will go out to 2,050.
The Zohr project strategically just works really well for us and with our partnerships there with E and I. The little bolt on acquisition in Tengu, no additional overhead whatsoever, accelerates that project to help get it approved. These were things that were not essential, as Brian said, but just strategically makes sense for us. Even the Australian one, which does require the regulators approval, probably get done sometime next year in 2018. You'll know in the U.
K. We've got a great model with Marks and Spencer's and our retail growth in revenue growth and we've got a chance to replicate that very successful strategy in Australia. I mean these were things that I think are all going to help build where we're going. That along with a very, very solid organic set of projects that we've got the pipeline. And we'll go through this more detail with you on February 28, where we'll have a strategy update.
In fact, we're looking forward to that.
And then Oswald, in terms of operating cash, I'm going to try and help you a little bit in terms of what we can see coming through this year that gives us confidence around the balance point. So we exit 'sixteen at roundabout €17,800,000,000 back out the working capital release that came through the results through the back end of last year. So they take another £3,000,000,000 out of that. If the oil prices stay where they are today, and of course, there's a lot of environmental movements that you can't see beyond the rule of thumb around like, for example, non Henry Hub gas and what's happening with local refining margins. But let's just assume the environment helps where today's oil prices are around €4,000,000,000 So that sort of positive €4,000,000,000 maybe more than that if we get up towards €60,000,000 which we're not anticipating at the moment.
I think something around €50, €55,000,000 is a good planning assumption for this year. You then got the Abu Dhabi piece comes in, and that's cash accretive for this year. We also have rationalization expenditure of $500,000,000 to $1,000,000,000 of cash that went out last year that won't go out this year. There will be some going out this year, but the delta is somewhere from $500,000,000 to $1,000,000,000 We've got volume and margin improvements coming through in both upstream and downstream. It's about fifty-fifty of about $1,500,000,000 to $2,000,000,000 And then some other movements get you to a sort of cash figure this year of somewhere around €21,000,000,000 to €22,000,000,000 at today's price set, which means that the CapEx and dividend, cash dividend is covered with an imbalance of about $1,000,000,000 Now of course, we actually want to cover the full scrip part of the dividend, which we'll be able to do as we go into 2018, delayed only by a year because of course we've now got the new transactions, which will require an extra €1,000,000,000 of CapEx or thereabouts for this year, as Bob said.
So actually, everything boxed balances for this year, and then we've got the momentum through into 'eighteen with the ramp up of the projects, which says we start to see free cash flow growth from there. So it's nice to have the scrip. We'd like to offset that scrip, but we will offset the scrip at the first opportunity we get. But in terms of cash balancing, that's how you get from 2016 to 2017. And of course, there may be some upside on the oil price.
And a footnote, Oswald, you mentioned are there any hubs that aren't coming through that we felt like we needed to fill. The answer is no on that. You might be thinking of India, but those are coming forward. The economics were very attractive given the new gas price in India as well. Maybe that's the one you're thinking of, but we don't have any gaps really.
And Oswald, just to be clear, in my little balancing at them here, I'm assuming CapEx at around about 16,000,000,000
Excellent. Thank you very much.
Yes. As well, it's probably also worth noting that the EUR 16,000,000,000 to EUR 17,000,000,000 CapEx guidance this year, although it's a little bit higher in terms of specific guidance for 2017, that's still within that overall $15,000,000,000 to $17,000,000,000 frame we showed you in Baku. Okay. We'll take the next question now from Gordon Gray of HSBC.
Thanks, and hello, everyone. Two quick ones, if I can. Firstly, on the M and A side of things. I think it's fairly obvious that this could be a good point in the cycle to be building the upstream positions. But to some people, I guess, the downstream acquisition, the Woolworths acquisition is a little bit less obvious.
Maybe you can just give us a little bit more rationale around that one. And secondly, if you can give us a little bit of insights into the reserve replacement outlook or position excluding the Abu Dhabi acquisition? Thanks.
On the latter one, we'll come back on reserves replacement ratio when we file our annual report and accounts in 20 F. So we'll come back to the split of that. And you'll also see what the Rosneft piece looks like underneath all of that in terms of reserves replacement. Bob Woolworths?
Yes. Gordon, on Woolworths, this is really very consistent with strategy. Our U. K. Retailing has done extremely well.
We don't lay out all the details of that. But by acquiring and rebranding the operating Woolworths stations in Australia, a brand that unless you're familiar with Australia, you won't realize how strong the Woolworths brand is in Australia. We'd acquire 5 27 fuel and convenience sites. And again, subject to the approvals there, probably completed in early 2018. It's accretive to earnings.
It's operating cash flow with returns that are competitive with the rest of our downstream portfolio. It's a somewhat unusual opportunity. It's very consistent with the strategy we have in the downstream, which is develop these high quality differentiated fuels and convenience offers in the downstream. And again, it works really well here with Marks and Spencer in the U. K.
And REWE in Germany also is another model for us. So this one was we feel is very attractive for us. And on reserve replacement of 100 and 9, again, Brian said we'll break those out later, but it's really a renewal of the concession we had before. We've had healthy reserve replacements across the rest of the company as well.
Next question now from Anish Kapadia of TPH.
A couple of questions for me. First one was on your net working capital position. If I look back to 2013, the end of 2013, your net working capital position was over $20,000,000,000 calculate, obviously, in a much higher oil price environment. I think now at the end of 2016, it was close to 0. I was wondering, I'm guessing oil price is a big portion of that, but if you could explain if there are any other impacts in there and how you'd expect that to trend, especially in a rising oil price scenario?
And the second one was related to your planned disposal program for this year of about $5,000,000,000 Just what's your kind of estimate in terms of the cash flow that you'll be selling alongside that $5,000,000,000 And any kind of idea of the split upstream versus downstream?
Okay. On the net working capital piece, as you can imagine, as you move from you're absolutely right, the oil prices go higher working builds. And therefore, we have assumed some working capital build into 20.18. And at $55 a barrel, we're assuming it's kind of neutral. It actually will be neutral for this year.
Obviously as you go through the big correction we've been around the oil price, costs working capital, capital all sources of cash are worked through and we've been systematically reducing our working capital uses in both the downstream, but also in the upstream around inventory management. So it's kind of part and parcel of everything we've been doing around costs and CapEx, hence why you've seen the working capital balances come down so significantly. For 2015, we're assuming it's neutral. So there isn't any assumption that there's any working capital release nor build. But as prices if prices move up in 2018, we would expect a modest increase in working capital.
And that's built into our forward cash flow projections. In terms of disposal proceeds for 2017, the bulk of what we're looking at is in terms of the cash flow impacts have already been built into our projections for this year. So they sort of sit inside all of our portfolio adjustments. The big cash accretive pieces were really sold off in the last big series of transactions we did over sort of 2013, 2014, 2012. They won't have anything like the same impact.
A lot of the assets are actually more in the sort of utility type returns if you look at midstream and some of the terminals that we're looking at. And actually some of the examples I could give you for this year was some of the offices that we sold off that we hold. Obviously, there's no cash associated with those. There's a small increase in costs in terms of the lease. But from an IRR perspective, they're very good returns for us.
And you will have some of the transactions we got away. So nothing that causes any concern in terms of being cash accretive or dilutive. If anything, they tend to be on the lower end of the cash return.
Great. Thank you.
Thanks, Inish. Turning now to Guy Baber in the U. S. Thank you for joining us, Guy. I realize it's quite early in the morning there.
So very glad to have you on the call. Will you go ahead with your question?
You bet. Thank you very much. You guys reached the $7,000,000,000 cash target for cash cost reductions early. Can you just talk about that a little bit? And now what the expectations are from a cash cost perspective going forward?
Are there opportunities for continued reductions? And where may you see those? And are you beginning to see any inflation anywhere in your business that you operate? If you could just help us understand that, that would be great. And then I had one follow-up.
Yes, Guy, a very good morning, early morning to you. Some color here on our cash cost reductions. We did hit the $7,000,000,000 reduction in cash costs versus 2014 a year earlier than planned, took them down from 27.2 to 20.2. The split on that is around 3.7 has been in the upstream, 3 in the downstream and about another third or third of a $1,000,000,000 on other operating other corporate businesses. 2 thirds of that is roughly from self help driving cost reduction simplification in.
A third of that is from deflation of costs. And that self help really is how we work more efficiently with the activity optimization, simplifying how we do things. The organizational size has come down. So staffing costs have come down. Getting into more of the details, the kinds of things that we drive is with BP headcount and reductions to expatriates.
Agency staff has come down quite a bit, headcounts and rates for agency staff. We've had a lot of 3rd party spend come down just by more competitive bidding. We've got a real drive to eliminate waste, common sense at scale we call it, inventory control operated by others. We're working hard on those where we're not the operator to push them as well. And for BP, we're pushing as our partners do with us, improve cost recovery over time.
Brian, do you want to add anything?
Yes, I mean, I think it's across the piece. And I think the only other comment I'd add is that, of course, we started in 2012 in the corporate space in terms of trying to take out significant costs. And those corporate and functional costs have stripped out about 40% since that date, which the high watermark was around 2012. If you think about all the redundancy we built into the system after the year end of 2010. And then in terms of Upstream, as Bob said, going forward, 75% of the reductions that we've driven through here, we believe, are sustainable.
25% will be exposed to inflation, but I don't think we see any of that coming anytime soon.
That's very helpful. And then my follow-up was, I was hoping you all could touch on the Lower forty eight Onshore business a bit, but can you discuss the appetite now to increase spending there in light of the strides you've made operationally? Maybe what the implicit range of spending is for that business within the overall CapEx range? And where does the Lower 48 fit in terms of your appetite for perhaps some incremental acquisitions? If you could just discuss maybe what you might be looking to add there, that would be helpful.
Well, I
think our team there have really their capability now and driving the rigs and the rig work and getting results has really, really come through. Production in the quarter was over 300,000 barrels a day now, which is its highest Q4 since we've had since 2011. So Dave Lawler and that team have been doing a great job. We've got our highest quarterly operating cash flow from there as well. So we like what the team is doing.
We will look at ways to incrementally see how we can take that capability expand it. We'll do it creatively. There's a lot of there are a lot of targets I would say that are out there on offer. They seem highly priced to us. So we're going to use a lot of discipline here before we take it off.
We've got you'll remember a few years ago we had about 2 rigs running. Now we've got 13 rigs running in the 4th quarter. Sorry, we've reduced our rigs down. We've got 5 rigs running in the Q4 compared to 13 in the Q4 of 2015. But what we're getting out of those rigs is quite astounding.
And of course, there's some weather issues right now. But Brian, do you want to make any comments?
Yes. The only thing I'd say is what the team have done, which I think is really important, is get the cash breakeven of that business right down to therefore justify the capital spend going forward. And I think Bernard and the team will look at opportunities with Dave Lawler in terms of where we take that business going forward. But it's in and you'll know from the external data we publish, it is in a markedly better position than it was when Dave and the team came in. And our cash breakeven numbers come down significantly from where we were by the time we got to the Q4.
And our liquids production is up to about 15% of that total as well, 1.5 Bcf a day, but we've got about 15% liquid, so that's giving it a boost as well. Guy, thank you.
Thank you very much.
Thanks, Guy. We'll take a question now from Teeth Panjotirlingam of Exane.
Yes. Hi, good morning all. Thanks, Jess. Couple of questions actually. Firstly, just on Macondo.
Could you talk about, in particular, the Bell payments and how you see that phasing in 2017? Will that also be sort of front end loaded? And perhaps just give a little bit of color in terms of the process and what's remaining in terms of the claims to that BP needs to run through? Second question, just in terms of major turnarounds. We saw 1 in Q4 with Whiting.
I just wanted to ask if there were major turnarounds in the BP portfolio either in the upstream or the downstream for 2017? Thank you.
So, T Pen, on the first piece, the Bell payments have been significantly accelerated through the back half of last year through various process we did under the court supervision. But effectively now, we're left with the sort of final piece of the claims facility. But I'll just give you some data. We started with about 149,000 total claims in the Bell process. Half of those were closed with no payment and 65,000 of them have now been finalized with 15,000 being resolved in the 4th quarter.
Hence, why you've seen the reassessment now in terms of provision. We've been able to work through a big number of claims through a process aligned with the court supervised settlement program, which leaves about 9,000 claims now to be resolved. So we will expect to see all of those, the majority of those get worked out through here. There will be some appeals. So actually in today's provision, anything which is of a significant nature where we believe that actually the payment is not a representation of the actual loss, we will appeal those through to the 5th Circuit.
So you will see some of those come through and that will take some time to get resolved. But generally, we would expect and as we've said in our press release today to get a major resolution of what's left in terms of the overall claims, not just business economic loss claims, but the big chunk of business economic loss claims have now effectively been resolved through the Q4 with 9,000 left to be processed this year.
Yes. Thanks, Brian. And on turnarounds, we did complete 11 of them in 2016 ahead of schedule. You're right, we had a Whiting turnaround that's in the upstream. We had a Whiting turnaround right near the end of the year.
There will be turnarounds in 2017. I don't have the exact schedule in front of me, but the industry, the refining industry itself is slated in North America for a heavy set of turnarounds later in the spring. We'll have some
of theirs
of ours there as well. But it's not an overly burdensome set of upstream turnarounds in 'seventeen and you can check-in with our IR team at another time.
Thank you. Brian, I was just wondering just on the actual payments for the Bell claims through 2017, is that going to be sort of we're trying to model the quarter and watch BP's gearing, is that going to be front end loaded or?
It will absolutely be front end loaded, which is and Tipam, maybe just to sort of decode some of this. One of the reasons why we're front end loading and accelerating is that the administration comes down and that facility under Pat Uno's excellent supervision will start to wind down as we get towards the end of this year, of course, all in the supervision of the court.
We'll take a question now from Jon Rigby of UBS.
Thanks, Jess. Yes, I've got 2 questions. First is on trading. This 4Q pattern of reduced or negligible contribution from trading seems to recur. And I just wonder whether you could talk about what drives that?
Is it risk? Is it opportunity? I mean, consciously, your upstream business runs 24 hours a day, 3 65 days a year. I'm kind of curious why your trading business only runs for 3 quarters. The second question just on your tax guidance.
Obviously, you're taking the ATCO tax below the line as corporate tax. So I just wonder whether you're able to give us some sort of indication of what an apples to apples tax rate would be, I. E, what the underlying tax rate would be without the AGCO impact that takes you to 40%. Thanks.
So John, on the first question, I mean, I can tell you from personal experience, but I asked the same questions of the Chief Executive of IST, Paul Reed, who's done a great job over the last 6 years and is stepping down this year. Actually, this Q4 every Q4 is different, but generally what happened this 4th quarter, this was not and it's oil trading, it's not gas trading. Gas trading actually had a good result in the 4th quarter. But in terms of the oil books, I think generally coming into the Q4, given all the uncertainty around what OPEC was going to do and just the sensitivities around supply and demand balances, this was not a quarter to try and take big positions. And therefore, I think there was a natural inclination to flatten up all of the books.
There was also an adverse court ruling against us, which is actually a $70,000,000 hit that was in the public domain that made the actual 4th quarter a loss. Otherwise, it would have been just above breakeven. But I think it's more a reflection this 4th quarter is different to the last time we had a 4th quarter where there was either breakeven or small loss. And I've actually looked out over the last 20 quarters, something like 12 or 13 of those or at least close to 50% of those are above average. There's about 25% significantly above average.
And then there's about 4 or 5 quarters where it's breakeven or just a slight loss or just on plan. So just to caveat this, the oil trading books actually were above plan for 2016 as they were in 'fifteen. But 4Q was really not a quarter where you want to be taking significant risk given all of the uncertainties around what was happening around supply and demand balances. So that explains, I think, 4Q oil. And then on the tax rate, I'm sorry, I apologize, it's a messy quarter in terms of trying to give guidance around effective tax rate.
Effective tax rate for last year was about 23%. If you add Abu Dhabi, it moves it up significantly, but there's also a change in the mix of profits around gas and oil and where those profits sit. So also has an impact to take the effective rate up to around 40%. If you looked at 'seventeen without Abu Dhabi, the effective tax rate would be somewhere around 30% and a cash tax rate of 23%. And I think just an important point, John, just in terms of using our rules of thumb because, of course, we've gone through all the sort of various back of envelope calculations.
The marginal tax rate you should use on the rule of thumb and our new rule of thumb will be about $340,000,000 for every dollar a barrel if you include Abu Dhabi. The marginal tax rate you should use on that piece is somewhere between 10% to 20%. So 15% is probably a good marginal cash tax rate to use as you start to think about deltas year on year.
Okay. Going now to Lydia Rainforth from Barclays.
Thanks, Jess, and good morning, everybody. Two questions, if I could. The first one, just to come back to the acquisitions and perhaps if you could give us the average return on those when you talk about the mapping value that we should have a look at. But just within that, I'm just going back to Brian said on the once the rebalancing is achieved, then you look to offset the dilution from the script, I think, at the first opportunity. What confidence can you give us that in a year's time that we're not thought here thinking that it's going to be delayed for another year because there's been other attractive options that have come into the portfolio that you want to take advantage of?
And then the second one was actually just back on the cost question that Guy asked. Are you actually looking at whether you can do more into 2017 on the cost target that you've given or is it just case of given the oil price increase that we basically look at locking that into the year? Thanks.
Well, Lydia, on the acquisitions, they've obviously been competitive in our capital ranking process. On Abu Dhabi, I shouldn't actually say the terms are different than they were. But Abu Dhabi themselves and ADNOC are still negotiating with potential people to join the partnership. So I shouldn't comment on that. Certainly with Tengu, it's just straight bolt on to a project that we know is healthy and economic.
Same with Zohr. The economics of that project we think are good with lots of optionality and there's lots of optionality in all three of these projects that I mentioned. And again, the Woolworths deal, if approved, will be accretive as well. So these were and the extension was which the commercial terms were worked out before the holidays in Azerbaijan are certainly very economic and healthy with our returns as again they're just an addition on to what we're already doing. So I think that's probably all I should say about the specific economics of the projects.
Yes. On the cost front, Lydia, actually, if you go back to the high watermark we talked about 2012, our cash cost base has reduced by about 50%, which is quite significant from where we were back at 2012. So that's kind of an important data point. I think what you will now start to see going forward is our unit efficiency operating costs start to improve. So we'll look to hold costs flat here, notwithstanding the earlier comments about in the upstream, 75% of the costs we believe are sustainable, 25% will be exposed to inflation.
So we'll look to hold the unit the absolute costs flat where they are, even though we have a huge amount of projects coming on with investment both in upstream and downstream. So we've got there's a natural increasing cost pressure in the system and inflation, but we'll look to hold flat. And what you'll start to see is our unit operating costs and those unit metrics in terms of the operations, in terms of upstream, it will be around operating costs and production costs. And in terms of downstream, it will be the amount of costs that are going into generating margin, which is the way that really the marketing businesses look at this in terms of costs over a gross margin measure.
Okay. Thanks, Lydia. Next question from Rob West of Redburn. Are you there, Rob?
I'm here. Yes. Thanks very much. I guess, first question I'd like to ask is on CapEx. Brian, Bob, to the extent that you have the breakdown at a more project level than the headline level you've given us.
Are there any projects you know about within your split where there's been a significant change versus how you see it now versus how you would have seen it maybe 6 months ago or when we were all in Baku. Within that, I'd like to ask about Oman specifically. I think Guy asked you about the drilling productivity improvements in the U. S. And I know Amman is another area of unconventional drilling activity.
And so I was wondering if those recent wells have come in just over the last 3 to 6 months, how are they comparing on a drilling productivity basis versus where you would have seen them? And then the final one I wanted to ask you is just on the downstream business and contango impacts there. So a year ago, it was maybe $10 a barrel per year looking at the contango. And I think I remember back to 2015, you talked about filling your boots in that kind of contangoed environment. Is there any change in that business now that we're at a more flattened forward curve, either in terms of inventories coming out or in terms of maybe profitability booked on the contango that we should be aware of maybe not recurring?
If you could talk about that a little bit, that would be interesting to me. Thanks.
Rob, yes, good questions. I'll take the first one and then Brian on the contango and he can explain that technical term filling your boots for all of us. I think on the CapEx, we've continued to see with projects that are even in midstream now with the cost coming down. The Shadaniz project, the one that's working its way in the pipelines across Turkey, the steel costs have come down significantly in that. The Mad Dog sanctioning the one we went from 20 down to 9, it gives you some idea of the reduction in both in scope.
We reengineered these things, take a fresh look at it and look at how we would do it and that took a lot out of the scope. And then of course drilling costs have come down significantly. The Thunder Horse South expansion that just came on stream near the end of December, again 10% under budget, probably $150,000,000 savings in 11 months earlier. So things are happening faster. They're happening at lower cost.
So there isn't a project out there that I would say we're worried about. The ones that will come on stream this year have been moving along the West Nile Delta. The big, big project in Egypt we have 83 percent of that. Also the drilling is much reduced cost and much faster. So that project hopefully will come on early rather than the summer or the fall which we'd originally planned on.
On Oman, we've got a number of breakthroughs there. In the southern part of Oman and we've signed an agreement that will expand the acreage there by another 50%. We're getting well rates out of there that are even straight wells that we had not expected that I think are going to lead us to be able to do the original project and the 50% expansion for around the same price as the original FID for the first phase. We're using new techniques and new data so that every time a well is drilled, we automatically rework the entire development plan to optimize where the next well moves to, things that we never actually seen in our history before in terms of being able to use new technology. We've got 45 development wells drilled to date and they're completed definitely potential production levels above plan and the liquid production levels that we're testing are higher than planned.
So we like that project a lot. So keep an eye on that. That will be on stream before the end of the year. I don't know if that helps Rob.
Yes, that does. Thanks.
And then Rob, on the question for Hank and Tango, I'm fairly confident Fur U Boots never came off this call, but it may be some other company you've been dealing with. Unless it's a very private session. It's been a long time since I last used that phrase, probably about 20 years ago when I was on the trading floor. No, we have actually we don't let and our trading floor would let you know this. We actually keep quite a discipline on the amount of oil that we would use in contango plays when those opportunities arise.
And I will give you another phrase, which is flat as a pancake, which is exactly where the Brent market is right now. So I don't think there's much carry that we see in Brent certainly not on a CAL basis if you look at the forward curve right now. There is some carrying gasoline. I think we'll always allow our traders to take advantage of that when that arises in terms of using the storage facilities we have and the working capital that we can deploy towards that activity. But we do actually limit it and we do have a very strict resource allocation group within trading that looks to allocate the scarce working capital we allow in terms of that activity to make sure that we're getting the highest returns in the ones that we look at.
There are some people that will be comfortable investing in cost of capital. We'd look to want to get significant returns way above cost of capital before we'd look to deploy our working capital into that sort of space. So we will do contango when it arises. Right now, the only opportunity you'd see here in gasoline, and we have some of those positions on for this year. But right now, in crude, there's really nothing there.
Got it. I'm sorry for the false attribution of that comment.
No, I think I know where it came from, but you need to talk to somebody else.
Don't worry, Rob. I don't think your memory is that bad. Okay. Moving on now to Christian Manek of JPMorgan.
Hi. Thanks, Jess, and thanks for taking my questions. Good morning. Just two questions, starting with oil prices. You talked you're justifiably bearish early last year and that sort of reflect itself in terms of discipline around CapEx.
What is your view at this point? I mean OPEC has done a deal and therefore you're more constructive, but I can't help associating that move higher in oil prices with how you've done more deals. And so the first question is if oil prices are still in its 40s, would you have done those deals? The second question links to this back to around CapEx versus cash flow. Can you just remind us what exactly is the priority around cash flow breakeven, if that was the true priority as much as it's tempting to do deals that are accretive and deliver long term production, wouldn't you have resisted to get that cash flow breakeven lower, particularly given all is so volatile?
Just two questions, please.
Can I just I'm sorry, Paul? Can I just pick at the front end of the question? I think if the oil prices stayed at $40 we would look to have done this. I think if you go back to one of the earlier questions, the confidence we have was that we could get back to breakeven at 55%. And I think while we said lower for longer 2 years ago, I think my partner here said lower for longer, but not forever, a year ago.
And I think structurally, we can start to see the overhang in the crude supply start to work their way through this year. It's taken longer than was anticipated, because I think actually some of the supply last year wasn't anticipated that came on particularly Libya coming back in terms of production there. So I think if the oil prices stayed at 40, you have to remember a lot of the transactions we looked at are either low cost oil and therefore a good for the long term in terms of strategy or gas in terms of those transactions that you saw at the back end of last year. So even at $40 a barrel, they would definitely be within the suite of options that we might have looked at.
Yes, let me just add to that. That's exactly right. Tengu gas prices generally fixes or gas prices are fixed. The Mauritania is just such a large low cost gas source there. Low cost oil Abu Dhabi, that one I'm not sure, but it was the flexibility of ADNOC and the government of Abu Dhabi to take our shares that made that one different.
I think it's I think as I've said to them, we would not have done that deal even last year if that required the cash. I think that had some characteristics, flexibility and some creativity around it. But we certainly would have been you're right, Christian, we would have been nervous at 40. We would have continued to think very, very, very carefully about all these deals here. On what our view is on OPEC, all of us in the company travel a lot.
We spend time in various countries. We do talk to the views of various ministers. Obviously, we operate in Russia and Azerbaijan, which are part of the non OPEC producers of these agreements. And I have to say that the confidence and sort of the steely resolve that they speak about is sort of reflected in country after country after country. So we'll see there's risk to it, but it does feel like this is holding with resolve by these many countries.
Just so if I could just follow-up, I mean, not to wish low oil prices of anybody, but I mean, if we do go back into the mid-40s, is it safe to say that you would be willing to lower your CapEx Or is 16 a hard fall?
No, no, no. We would absolutely lower the CapEx and we would probably repaste things. Some of the economics of projects would change. The big ones that we're halfway across the stream on, we'd obviously continue to go forward with. We would look at all the discretionary base and wedge drilling activities.
They have to make sure that the returns which are generally very high on those happen. But you would see us slow down some of the FIDs, I'm sure.
Moving on now to Chris Kupland of Bank of America.
Thank you, Jess. Good morning, everyone. Just two questions. The first one on CapEx. Could you comment a little bit about your new CapEx commitments on the back of acquisitions, whether it's Zohr or whether it's ABCO, etcetera?
Should we think about that as displacing previously unsanctioned projects in your resource base? Or is that one reason why you've gone to the higher end and slightly upgraded your 2017 CapEx number? And the second question is really asking you for a little bit more detail about your cash flow outlook. You previously gave us more or less the same CapEx guidance, the same Henry Hub guidance, refining margin guidance and guided us to a 2017 breakeven of 50 to 55, now it's 60. So I just wondered whether you could let us know a little bit more in detail where those, I guess, dollars 1,500,000,000 to $2,000,000,000 have gone.
Thank you.
Actually, Chris, it's the same answer to both questions. If you remember at the end of Q3, we talked about CapEx on the Q and A session. We talked about CapEx in the range of 15 to 17. But for next year, this year, 50 to 55 we were guiding that CapEx in the range of the lower end of that range, so somewhere around €15,000,000,000 to €15,500,000,000 The new acquisitions and projects have brought with them an additional €1,000,000,000 hence why I say assume CapEx of around €16,000,000,000 or just north of €16,000,000,000 for this year. That's the €1,000,000,000 And that €1,000,000,000 actually bridges you from 55 to $60 a barrel on a post tax basis in terms of rebalancing.
So it's $1,000,000,000 out in terms of organic balancing for this year, hence €55,000,000 to €60,000,000
Thanks, Chris. Irene Himona of SocGen. Go ahead, Irene.
Thank you. Good morning. I had two questions and apologies if they have been discussed before. Firstly, on the downstream, where for the full year, your lubricants profit is up 10%, chemicals is up 2.5x. And together, those two subdivisions generated about 3x more than your Upstream.
But a lot of the cash cost reduction has been delivered in the Downstream businesses. So I wonder how we should be thinking about further upside on these businesses from here on, if there's any guidance? And then secondly, on the Upstream and the 500,000 barrel a day start ups by year end, your own organic growth. Obviously, these don't ramp up immediately to plateau and initially costs will be higher to start with. And there is a risk of initially perhaps overestimating the cash contribution of the organic growth.
And I mean is there any guidance you can give us on how we should think about the, let's say, cash contribution of those 500,000 barrels in the 1st year of production in 2018?
So Irene, if I just take the downstream question, I think it's also worth pointing out that just on the straight rules of thumb, the environmental impact that Tufin and the team had to deal with last year was around $2,000,000,000 around the RECA margin margin and actually bigger than that if you build in the local margin differences. So actually, it's quite significant and hence why it was important that extra value is generated elsewhere inside the business both in terms of actually fuels as well as lubricants as well as chemicals. I think outlook for lubes, it was a record year last year for them. Whether they can repeat that this year, but I think you should assume flat to growth going forward for lubricants. On Chemicals, we've come out of and still not fully out of what has been a 3 to 4 year very suppressed period for our chemical margins in terms of net activity.
You may see some recovery this year, but we're not assuming there's any major uptick in chemicals through this year. And I think what you'll see in terms of downstream is the continued focus on efficiency. It's where the costs go in terms of generating margin and fuels growth where we've seen significant fuels growth across the piece.
And Irene, I think on the upstream projects, the biggest indicators rather than I think it's more you've got to see us bring these projects on for us to be able to prove what we've been saying. We do have these 6 more, 7 if you count the one that started in December, Thunder Horse. I would gauge whether they're on time or ahead of schedule or on budget or under budget. The Thunder Horse South one certainly has come on like that. I think keep on your radar screens over the next 3 or 4 months the West Nile Delta project, Taurus Libre coming on and Quad 204.
These are probably the first two that will come on large projects. All of these, you're right, are ramp up to 500,000 barrels a day. And so it doesn't happen overnight. It's 500,000 barrels of capacity that will be put in place. And of course, then we'll continue to drill and drill out some of these well into 2018.
But I think it's are we bringing projects on time and under budget And I just ask you to wait and we'll go into a little bit more detail on this on February 28.
Okay. Thank you.
Thanks, Irene. Turning now to Biraj Borkhataria of RBC.
Hi, thanks for taking my questions. Just going back to Macondo. You mentioned the drivers for the increase in guidance was more to do with phasing, but the 2016 number was higher than or the top end of guidance. 2017 numbers increased and 2018 2019 are unchanged. So I'm wondering, is this really a phasing issue or are the payments just higher than you were expecting maybe 6 months ago?
And the second question is, just could you clarify the scrip uptake assumption in that $60 per barrel breakeven target? It looks like the 2016 uptake was a bit higher than has been over the previous few years. So just clarity on that will be good.
On the last one is the last question is straight they're both pretty straightforward actually. But the last question is we've assumed 20 percent as the long run average on the scrip uptake. Last year was significantly higher and above that. But in terms of our cash balancing, we're assuming about a 20% uptake on scrip. And then in terms of Macondo, you're right to point out that actually the payments are higher in 4Q and anticipated for this year because what has happened is if you look at where we last reassessed the each quarter we look at the overall provision.
At 2Q, we had about 34,000 bell claims to still be processed. We're now down to 9,000. So of course, we've got 2 quarters worth of Bell claims have now been processed. Some of those have come through at higher rates, hence why we've reevaluated the provision. But we're now in a more confident position than we would have been in given that we're down to 9,000 claims left, hence why the provision has come up.
So it's a combination of both. 1, the provision has moved up, and it's about $625,000,000 around the claims piece for this quarter. And then we have the forward view in terms of now we're down to the last 9,000. Having accelerated 15,000 claims through the 4th quarter puts us in a better position in terms of assessing what the provision looks like going forward.
Very clear. Thanks.
Thanks, Biraj. And turning now to Brendan Warne of BMO. Go ahead, Brendan.
Yes. Thanks, Jess. Look, a lot of the questions have been asked and answered. But I'll just follow-up and just in terms of any expectations for FIDs or sanctions this year, just referring to your Baku trip. You talked about sort of 40 odd projects in work.
Just any thoughts on what we may see this year? Or is it another year of sort of hiatus for FIDs from BP?
We generally don't lay out the FIDs directly because we have to do it sometimes with our partners. I mean we've had 5 FIDs in 2016 which those are the Atoll Phase 1 project in Egypt which is an early production scheme. It's 100% BP. The Tango Expansion project, which we're now up to 40% in has been FID. We FID at Trinidad onshore compression, which will drive higher production in Trinidad into the LNG plants.
That's another 100% one. You read about the Mad Dog Phase 2, 1. We've FID ed it and we've got partners Chevron and BHP that are looking at it now. So those and another operated by others in the Gulf of Mexico was previously called Hopkins, now Constellation, we've got a 67%. So those are done.
We have deferred a couple of FIDs. We have deferred 1 in Australia, a big LNG project and another one in Canada that we think that's the right thing to do for both strategy and where the estimates are. And then I think keep an eye on us with some other things that we may do in Trinidad, in Oman, as I mentioned earlier, there's more potential there. India, with new gas price there, we have some very, very good looking prospects there as well. And there's a couple of others that are operated by others.
So I think I'd rather wait before I mention those. But those are some and yes, we've got a pipeline of things out there as well. There's some other higher lower probability ones on the list as well, but not worth mentioning yet.
And just in follow-up, just can you talk about the base declines you're talking that you're keeping that above your or better than your target rate of 3% to 5%. When can we sort of see start to see the impact of lower maintenance CapEx coming through on the base decline, please?
Well, we've got a base decline of around 3% now. We've held that for some time versus the historical average 3% to 5%. So you'll see that coming through in 1, the reliability numbers in the plant in the upstream are now up to 95%. You'll see that in lower turnarounds. I know the question was asked earlier.
We had 11 turnarounds in the upstream last year. I think we'll probably have about 5 this year. So you should see it sort of all around in small pieces everywhere.
Thanks for that.
Thanks, Brendan. Next question from Jason Gammel of Jefferies.
Thanks very much, everyone. I actually had two questions. The first one coming back to Abu Dhabi. I was hoping you might be able to address your desire to use equity in that particular transaction. I recognize the long dated nature of the asset, but your equity is relatively expensive right now given the dividend yield.
And Brian also mentioned that it was a cash flow accretive project. Can you confirm that that's the case on a per share basis and also covers the incremental dividend payment? Then the second question I had was on the potential for a U. S. Border tax adjustment.
Have you given any do you have any preliminary comments on what that can mean for your refining business, given the heavy slate of Canadian crude that you use at Whiting?
I'll take the first part of that question while Bob thinks about import for the U. S. It's Abu Dhabi was a yes, it was really straightforward. I think most of our majority of our investors, if not all of them came back to us very positive about it, which was it's immediately cash accretive. The cash that comes from it covers the dividend for the shares that were an issue and its earnings accretive.
So I think this was a good use of equity and was unique. And of course, the sovereign country wanted access to BP shares. I mean that was kind of part of this whole transaction was their desire to own. And we've been talking to them over a number of years about the potential for them stepping into position in BP. This was just the perfect opportunity that came together in a relatively small window to allow us to actually go forward on the renewal of that license.
Yes. And I think I'm really happy about that transaction, Jason, with a supply there working with Abu Dhabi and crude supplies and the implications it has on our trading organization out to 2,055. Those don't happen very often. On the border tax, well, I was watching you asked about Canada specifically, but there's also issues around Mexico and just imports and exports in general. I'm going to take the position of the Canadian government because I watched and listened to them last night and they more or less just said, we're
going
to scratch our heads and we're going to think about what this means and not comment. And I think I should probably do the same thing.
Fair enough.
Thanks, Jason. And we'll take the last question from Lucas Hermann. Are you there, Lucas?
Yes. Jess, thank you very much. Gentlemen, good morning. Just some points of clarity, if I could. Firstly, Brian, just going back to the answer you gave, I think, was to T Plan around balance or Oswald around balance.
And you mentioned price driving an improvement in cash flow of an estimated €4,000,000,000 this year. I assume that's the movement in refining market back to your average level, gas prices to your average level and as well as oil prices to your average level?
Lucas, let me pick that one up straight away. Actually, the hit in 'seventeen in 'sixteen versus 'fifteen was close to $8,000,000,000 of environmental impacts across the 2. You can get to about $5,500,000,000 of that through the rules of thumb. There's also about $2,500,000,000 from non rule of thumb type activity like non Henry Hub gas. So in terms of the assumption for this year, it's a modest improvement to refining margins, certainly not back to the long run average that we've been assuming previously.
It's modest improvement in the Henry Hub gas price and it's oil prices around close to $55 a barrel.
Okay. And Brian, can we just go back to the sensitivity comment you made as well, same thing really, dollars 3,400,000,000 move, I think you said, for a $10 move in the price. Then you talk about the marginal rate of tax of $10,000,000 to $20,000,000 which seems remarkably low on incremental price driven cash flow?
No. Well, actually if you go back and look at the size of our portfolio and the mix of upstream and downstream on the corporate tax rate, actually it's not that low. If you look at the sort of cash tax rate for those upstream barrels, it is lower than the corporate tax rate.
Okay. And sorry, final point of clarity, just to be absolutely clear. ADCO, the operating cash contribution that you expect in 2017 from that concession will outweigh the capital spend? And the reason I ask simply is that I appreciate the CapEx goes up as you take things on. I just ATCO looks as though it should be a decent contributor though.
It's hard to see quite where the negative €1,000,000,000 overall is coming from.
Oh, you've got the CapEx that needs to go into Zohr this year. You have the CapEx that will go into Mauritania in Senegal, you've got some CapEx going into Abu Dhabi. The cash coming out of Abu Dhabi more than covers the dividend associated with the shares that were put into issues. So no EBITDA was cash And the
CapEx, Brian?
I'd need to come back and look at the free cash flow figure. I haven't actually got the CapEx to hand, but it would be pretty close, if not accretive. Okay.
All right. That's great. Thank you.
Thanks, Lucas. So we do have a question on the web from Jason Kenny. So Jason is asking about returns to the end of the decade. Jason, we are going to talk at some length to returns on the 28th February. So if you don't mind, I think we'll hold that question until then.
And this oh, no, but Brian is looking at me and he says he really wants to comment. So
No, we should never take a question, Jess. I think I can even remember the Philly Boots quote now as well. I'll just suddenly come back.
No, it's Paul, my presentation for the 28.
All I would say, Jason has raised this point about where do you see ROACE from. It's on the web, but for BP for end 2017 and also at the end of the decade, can you get ROACE ahead of your weighted average cost of capital in the next 2 years? I'll pick up the latter part of that question. I mean, you'll know the history. You know that we sold off $55,000,000,000 of assets.
The average returns of those assets was in excess of 50% post tax. And therefore and we've gone through the massive period of oil price adjustments. So we have a lot of capital that was laid in at $100 a barrel, now needs to work its way through the system. And our returns are down below weighted average cost of capital. We would be disappointed if we can't get our returns back up in the next 12 months to 2 years back up above the weighted average cost of capital for the corporation.
And this is also a big focus for the board in terms of the long term plans. And so I'll just segue what Jess will lay out for us at the end of February to say we'd be disappointed not to get there in the next 12 months to 2 years. We would expect to be above the weighted average cost of capital by this time next year. And then we'll be able to show you the trajectory of what returns look like going forward in terms of getting us back to where we should be in terms of where we were historically over the last 50 or 60 years. Sorry, Jess.
No, that's great. Thank you, Brian. And thank you, everybody. Bob, do you have any closing remarks?
I'll just keep it very brief. First, a big thank you very much to everyone. Very good questions, as always. A few thoughts, again, You're going to see us focusing on safety and reliability that makes our assets run more reliably, which creates the reliable cash flows from the company. Again, big focus right there.
And then as Brian laid out, rebasing our capital and cash spending going forward, rebalancing the company, we have a good sense of confidence about doing that not only from our existing assets but the new things that are coming on. Keep an eye on these projects that are coming on. And then just remembering for the long term, it really is our primary objective to remain to grow our sustainable free cash flow distributions to you all our shareholders. And we look forward to seeing you on the 28th February. Thank you very much.