Welcome to the BP Presentation to the Financial Community Webcast and Conference Call. I now hand over to Jessica Mitchell, Head of Investor Relations.
Hello, and welcome. This is BP's Q3 2014 results webcast and conference call. I'm Jess Mitchell, BP's Head of Investor Relations and I'm here with 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 that 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 Brian. Thanks, Jess, and welcome everyone to today's webcast. Before we go through today's call,
I would like to say how deeply saddened we all are by the tragic loss of Christophe De Margery. The oil industry has lost one of its most distinguished champions, a charismatic leader and a man for whom I had great personal respect and affection. We will all miss him greatly. Turning to today's results. It has been an eventful quarter with significant volatility and uncertainty, both geopolitically and in the markets.
BP's 3rd quarter results have shown further progress in our business operations along with strong operating cash flow, which supports delivery of the 10 point plan we laid out to you 3 years ago. I will start with a brief overview of the environment before taking you through the numbers in more detail. I'll then provide the usual update on our U. S. Legal proceedings followed by the business highlights for the quarter.
At the end, there will of course be time for your questions. Starting with the environment. Oil and gas prices have shown significant volatility over the last decade. Recently, we have seen a prolonged period of Brent crude trading around $110 per barrel. In the Q3, this fell to an average of just under $102 per barrel and we have seen a significant decline in recent months with Brent averaging around $88 per barrel in the Q4 to date.
A number of market fundamentals are driving this trend. Global supply has increased from the return of shut in production in a number of locations as well as continued production growth in the United States where inventory storage also remains relatively high. At the same time, there is weaker demand growth globally. In China, demand growth has weakened to roughly half the rate of 12 months ago. Henry Hub gas prices also fell in the Q3.
The cold winter in the United States at the start of the year led to some large spikes in the gas price, followed by an increase in supply and a significant build in inventories. These supply and inventory increases saw prices falling through the middle part of the year with stocks now around average levels ahead of the forthcoming winter in the United States. As you would expect, we have seen some impact from lower oil prices in our results today and the outlook remains uncertain. In the environment, we benefit from being an integrated business with a strong downstream, but we expect weaker oil prices will impact our results while these conditions prevail. Turning now to the financial results in more detail.
BP's underlying replacement cost profit in the 3rd quarter was $3,000,000,000 down 18% on the same period a year ago and down 16% on the Q2 of 2014. Compared to a year ago, the result reflects a much lower contribution from Rosneft following the significant depreciation of the ruble as well as lower oil prices and the associated tax duty lag effects, lower oil realizations and the absence of a one off benefit in the Q3 of 2013 related to the TransAlaska pipeline system, partly offset by a recovery in the downstream environment. Operating cash flow for the 3rd quarter was $9,400,000,000 The 3rd quarter dividend payable in the 4th quarter increases to $0.10 per ordinary share, an increase of 5.3% year on year. This reflects our confidence in delivering our 2014 operating cash flow targets and the robustness of our financial framework in a weaker oil price environment. Turning to the highlights at a segment level.
In the Upstream, the underlying 3rd quarter replacement cost profit before interest and tax of $3,900,000,000 compares with $4,400,000,000 a year ago and $4,700,000,000 in the 2nd quarter. Compared to the Q3 of 2013, the result reflects lower oil realizations, the absence of the 2013 one off TAPS benefit already mentioned and higher DD and A, partly offset by increased production in high margin areas, primarily the Gulf of Mexico and higher gas realizations. Excluding Russia, 3rd quarter reported production versus a year ago was 2.7% lower, primarily due to the Abu Dhabi onshore concession expiry in January. After adjusting for this and for entitlement and divestment impacts, underlying production increased by 4.1%. Compared to the Q2, the result reflects lower oil and gas realizations, slightly higher DD and A and lower gas marketing and trading results, partly offset by increased production in higher margin areas.
3rd quarter production benefited from the absence of seasonal adverse weather in the Gulf of Mexico. Depending on weather and the closing of the Alaska package sale to Hillcorp, we expect 4th quarter reported production to be slightly lower. Turning to Rosneft. For the Q3 of 2014, we have recognized $110,000,000 as BP's share of Rosneft's estimated underlying net income compared to $810,000,000 a year ago and $1,000,000,000 in the 2nd quarter. BP's share of Rosneft's estimated production for the 3rd quarter was just above 1,000,000 barrels of oil equivalent per day, an increase of 4% compared with a year ago.
Geopolitical uncertainty in the region continued in the Q3, but did not have any significant impact upon Rosneft's day to day operations. Financial performance was adversely affected by the significant depreciation of the ruble as well as by lower euros prices and the associated tax duty lag effects. In July, we received our share of Rosneft's dividend in respect of 2013, which amounted to around $700,000,000 net of taxes. BP will continue to comply with all relevant sanctions. We remain committed to our strategic investments in Rosneft and hope for diplomatic solutions to the current issues.
We have worked in Russia over many decades and continue to believe in the opportunities that reside in this vast hydrocarbon province. Rosneft's recent first discovery in the Arctic's Kara Sea is a clear indication of the long term potential of the region and its importance in balancing the world's energy demands. In the Downstream, the 3rd quarter underlying replacement cost profit before interest and tax was $1,500,000,000 compared with $720,000,000 a year ago and $730,000,000 in the 2nd quarter. The fuels business reported an underlying replacement cost profit before interest and tax of $1,100,000,000 in the 3rd quarter, compared with $340,000,000 in the same quarter last year. The increase reflects a significantly stronger refining environment, stronger supply and trading and a higher contribution from our fuels business underpinned by the Whiting Refinery.
The lubricants business continued to deliver consistent performance with an underlying replacement cost profit before interest and tax of $340,000,000 compared with $330,000,000 in the same quarter last year. The petrochemicals business reported an underlying replacement cost profit of $70,000,000 in the Q3 compared to $50,000,000 in the same period last year, mainly reflecting improved margins in the asset sales business. Looking to the Q4 in the fuels business, we expect a similar level of turnarounds to the Q3 of this year. Additionally, we anticipate lower seasonal demand versus the Q3 to negatively impact margins in both the fuels and petrochemicals businesses. In other business and corporate, we reported a pretax underlying replacement cost charge of $290,000,000 for the Q3 compared to $390,000,000 a year ago.
This reflects a number of one off benefits in the quarter. Our full year guidance of an average charge of $400,000,000 to $500,000,000 per quarter remains unchanged. The underlying effective tax rate for the 3rd quarter was 41% compared to 31% a year ago. This primarily reflects the impact of the strengthening of the U. S.
Dollar on deferred tax balances and the significantly lower contribution of equity accounted income from Rosneft, which is reported net of tax. We continue to expect the full year effective tax rate to be around 35%. The charge for the Gulf of Mexico oil spill was $43,000,000 for the 3rd quarter, primarily reflecting the ongoing costs of running the Gulf Coast Restoration Organization. The total cumulative pre tax charge for the incident to date is unchanged at $43,000,000,000 This does not include any provision for business economic loss claims that are yet to be received or processed. There is a small provision for some claims that have been processed and are not subject to appeal within the claims facility.
As we have previously advised, it is still not possible to reliably estimate the remaining liability for business economic loss claims. We will revisit this each quarter as we continue to contest what we consider to be unreasonable claims, a process which could take some time. Regarding the Clean Water Act, as you know, we will be appealing the recent gross negligence ruling. We continue to believe that our original provision of $3,500,000,000 represents a reliable estimate of the penalty in the event we are successful in our appeal and we have maintained the provision at this level. Today's stock exchange announcement includes further information on the provision and contingent liabilities associated with this matter.
The pre tax cash outflow on costs related to the oil spill for the Q3 was $290,000,000 The cumulative amount estimated to be paid from the trust fund has now reached $20,000,000,000 The previously reported headroom in the trust of approximately $700,000,000 has now been utilized, primarily by higher estimates for claims administration and also charges in the quarter for business economic loss claims and natural resource damage assessment costs. Going forward, additional costs not provided for will be charged to the income statement as they arise. At the end of the quarter, the aggregate remaining cash balances in the trust and qualified settlement funds totaled $6,000,000,000 including $1,100,000,000 remaining in the SIFU compensation fund with $20,000,000,000 paid in and $14,000,000,000 paid out. I will provide a more general update on the legal proceedings later. Turning to progress on divestments and our objective to divest $10,000,000,000 of assets by the end of 2015.
Agreed deals have now reached $4,000,000,000 These include the sale of a package of assets on the Alaskan North Slope, the farm down of 40% of our interest in the Aman Kazan project, the sale of our Texas Huguerton and Panhandle West gas assets and the sale of our global aviation turbine oils business. Our intention is to use the post tax proceeds from this divestment program predominantly for shareholder distributions with a bias to share buybacks. Moving to cash flow. This slide compares our sources and uses of cash in the 1st 9 months of 2013 and 2014. Operating cash flow in the 1st 9 months was $25,500,000,000 of which $9,400,000,000 was generated in the 3rd quarter.
Excluding oil spill related outgoings, underlying operating cash flow in the 1st 9 months of 2014 was $26,700,000,000 $9,800,000,000 higher than a year ago. This includes a working capital release of $2,300,000,000 year to date, of which $1,000,000,000 is in respect of the Q3, in part reflecting the recent fall in oil prices. Note as with previous years, we expect working capital in the Q4 to include an outflow for German mineral oil taxes, which is typically around $2,000,000,000 Organic capital expenditure was $16,300,000,000 in the 1st 9 months and $5,300,000,000 in the 3rd quarter. We now expect capital expenditure for the full year to be around $23,000,000,000 relative to our guidance of $24,000,000,000 to $25,000,000,000 In the 1st 9 months of the year, we have bought back $4,000,000,000 of shares including $1,600,000,000 in the 3rd quarter. The cumulative total since early 2013 is now $10,000,000,000 Around $8,000,000,000 of this reflects the proceeds of the sale of our interest in Tiank BP, with the balance coming from the proceeds of our $10,000,000,000 divestment program.
Net debt at the end of the third quarter Net debt at the end of the 3rd quarter was $22,400,000,000 with gearing of 15% compared to 13.3% a year ago. This largely reflects the impact of our share buyback program over the course of the year. Our intention is to keep gearing in a target band of 10% to 20%, while uncertainties remain. Turning to our financial outlook. The strong operating cash delivery in the quarter and the year to date total of 25.5 $1,000,000,000 leaves us on track to deliver the $30,000,000,000 to $31,000,000,000 of operating cash flow planned for 2014.
This will mark the delivery of our 10 point plan. Relative to 2013, it reflects the higher expected contribution from major projects in the upstream, the progressive ramp up of the Whiting Refinery and some reversal of the working capital builds seen in 20122013. Looking out to 2018 and notwithstanding the impact of a period of lower oil prices, the principles of our strategy remain as we laid out to you in March. Our intention is to build on this platform to realize growth in underlying operating cash flow and to manage capital in a very disciplined way in order to grow free cash flow and in turn distributions. This is underpinned by our quality upstream project pipeline, our repositioned downstream and the opportunities we see to drive efficiency across the group.
As already discussed, oil prices have weakened considerably in recent weeks. This is prompting the whole sector to consider the implications of a sustained period of lower oil prices. As we stand today, our balance sheet is very robust with relatively low gearing of 15% and strong cash balances. In 2014, we expect underlying operating cash flow to cover capital expenditure and dividend payments. Our financial framework aims to underpin this position over the long term.
Over time, free cash flow grows materially at average oil prices of $100 per barrel, while we see downside support at average oil prices of around $80 per barrel, the level at which we sanction projects. In addition, we have the surplus cash from our $10,000,000,000 disposal program that is currently being used to fund our buyback program. So we have a lot of flexibility to withstand a period of low oil prices. Our first priority within the financial framework will always be the dividend. Our aim is to grow dividend per share progressively in accordance with the growth in underlying operating cash flow from our businesses over time.
We then judge the use of cash for discretionary reinvestment and other forms of distribution on an ongoing basis with a bias to distributions. We will look very closely at levels of capital spend, where we have room at the margin to payer back or reface spend without compromising future growth, we will do so. Relative to current guidance, I expect this could make a difference of $1,000,000,000 to $2,000,000,000 in 2015, with lower spend in the Downstream following the completion of the Whiting Refinery Modernization Project. As we move further into 2015, you might also expect to see the benefits of a greater focus on streamlining activity, a process we began some 18 months ago in response to resizing the group. We have a strong drive towards operating efficiency currently underway in our upstream.
In the downstream, we have introduced a more streamlined organization structure that we expect to drive more efficiencies across the portfolio and we have around 60 simplification initiatives at the corporate level. At the same time, our industry tends to be self correcting, so one would expect to see some deflation if current oil prices remain low relative to recent history. We will keep you updated on our plans as we move into the New Year. Now, let me give you a brief update on the main Gulf of Mexico related legal proceedings in the United States. The first and second phases of the MDL-two thousand one hundred and seventy nine trial have been completed.
And on the 4th September, the court issued its ruling on Phase 1. As we outlined on our investor call, BP strongly disagrees with the court's gross negligence ruling. The law is clear, the proving gross negligence is a very high bar and BP believes that the court's findings were not warranted by the evidence presented at trial. BP will appeal this decision and in the meantime has filed a post trial motion with the District Court asking the court to amend its findings or order a new trial. We have done this as BP believes the court's findings and conclusions are based substantially on expert witness opinions that the court appropriately and expressly excluded from evidence at the trial.
The District Court's ruling is the first of 3 steps in the process of determining the amount of penalties under the Clean Water Act. The court still needs to rule in the Phase 2 proceedings on the amount of oil that was spilled and the penalty phase is scheduled to begin on the 20th January, 2015. Appeals notwithstanding, by law, the penalty is not automatically assessed at the statutory maximum. The district court must consider 8 statutory factors in determining an appropriate penalty between 0 and the statutory maximum. BP Exploration and Production will submit strong evidence in support of these potentially mitigating factors.
Regarding business economic loss claims, a new policy that provides for the matching of revenues and expenses in calculating loss profits for business claims is now in place and business economic loss payments have resumed. In the Q3, dollars 120,000,000 was paid out on business economic loss claims. This compares with over $810,000,000 in the same period a year ago. BP's notion to allow it to seek restitution from claimants who were overpaid as a result of the previous policy has been denied and we have filed a notice of appeal with the 5th Circuit. Separately, BP is seeking Supreme Court review of the issue of causation as it relates to approval of a settlement and certification of a class.
In the NDL-two thousand one hundred and eighty five secondurities litigation, the trial for the class action is set for the 18th May next year, subject to the ongoing appeals around certification of the class. BP believes that all of the plaintiff's securities claims are meritless and we will continue to vigorously defend against them. As we've said before, we are determined to pursue fair outcomes in all legal matters, while protecting the best interests of our shareholders at all times. We compartmentalize these legal activities and BP's operational delivery teams remain fully focused on our core business. Turning to the upstream.
We continue to focus on delivery of this year's key milestones. 16 exploration wells have already been drilled this year, on track for our stated goal of completing between 15 2020. We have recently made 3 discoveries at Cerro Leche in Brazil, Vorlick in the North Sea and Guadalupe in the Gulf of Mexico, bringing the total for the year to 5. We also continue to acquire new acreage. In the Q3, we accessed the outer offshore Canning Basin in Western Australia and were also awarded a number of blocks in the Gulf of Mexico Western lease sale.
This is in addition to 24 blocks we were awarded in the Gulf of Mexico Central lease sale in the Q2 of 2014. We have also been awarded the Almataria and Karawang concessions as part of the recent bidding round in Egypt subject to final approval. Turning to major projects, the start up of Canul is now in progress, which will bring the total number of start ups this year to 6. Our year to date start ups continue to ramp up their production as planned and are contributing significantly to operating cash flow this year and beyond. Of the 7 planned major project start ups in 2014, the one remaining project Sunrise Phase 1 in Canada is on track with construction of the central processing facility over 95% complete.
Final commissioning continues and start up is expected to begin in December. Turning to operations. In the Q3, we successfully completed 5 turnarounds, 3 in Alaska as well as Bruce in the North Sea and Mad Dog in the Gulf of Mexico. This takes the total completed for the year to 7 against our planned total of 8. One final turnaround is scheduled for the Q4.
Additionally, operations at the Rum Gas Field in the Central North Sea have resumed in accordance with the agreed temporary management scheme. We have now completed all of our priority wells for 2014 with just one remaining to be brought online. We expect them to contribute 2 thirds of total new well production in 2014. Lastly, in India, the government announced a new domestic gas price formula as part of a package of oil and gas sector reforms. This increase is the gas price applicable for existing production and is a positive first step towards creating the more competitive economic landscape required to encourage the development of India's gas resources.
We expect further clarity on the new pricing policy and the premiums for future developments to emerge in due course. In the Downstream, we continue to deliver strong operational performance across our refining system with Whiting now fully operational. Additionally, we have sustained strong year to date Solomon availability at 95% during the year. We continue to focus on the overall quality of our portfolio. The lubricants business is delivering consistent results by focusing on growth markets, premium brands and advantage technology.
In the Q3, our petrochemicals business completed a strategic review. This resulted in a decision to halt operations at some of our older and less advantaged facilities, while continuing to retrofit several facilities with new technologies. We expect these changes to lower fixed and variable costs as well as to improve returns. And as previously announced, Tufan Egenbilich became the Chief Executive of the Downstream on the 1st October. Tufan brings a deep knowledge of BP's Downstream operations having held a variety of roles across the segment.
Tufan is a great addition to the executive team. So in summarizing, it has been an eventful quarter and one where operational momentum is continuing to feed through into results. This is evident in our progress on major project start ups, in further exploration successes, in the strong contribution from our Downstream with its modernized Whiting refinery and in our continued drive towards operation efficiency across all of our businesses. As we approach the end of the year, delivery of our 10 point plan is firmly on track. At the same time, we continue to work towards completing our divestment program and on maintaining strong capital discipline, ensuring we have a robust financial frame.
The environment has its challenges, but we remain clear on the direction and focus of BP. So on that note, thank you for listening. And now Jess and I will be happy to take your questions.
If audio participants
Thank you. This is Jess back again. Thank you all for holding. And we will take the first question from Jason Gammel of Jefferies. Go ahead, Jason.
Thanks very much, Jess. Just wanted to ask about the reduction in capital spending for 2014. Is this essentially slower level of expenditure that you would expect to then flow into 2015? Or has this been an actual reduction in spending levels? And if so, where?
And would you expect it will have any effect on forward production?
Thanks, Jason. It's basically just some slippage in the spend in terms of phasing of what we're doing. I don't think it will have any impact in terms of 2015 in terms of production. We just looked at where the run rate was sitting at the end of the Q3 and then looked at what we thought the likely spend would be in Q4. But it's not as a result of any intervention at this point on capital.
But we are looking now we're in the lower oil price regime that we were sort of anticipating may come about depending on a variety of circumstances. We're now looking at what we do next year with capital. But in terms of this year, it's just simply some slippage.
Understood. And if I could just follow-up, Brian, that wouldn't have any effect on the €1,000,000,000 to €2,000,000,000 of potential for reductions that you referenced in the comments you made earlier?
That's correct. I mean the guidance we've given you out to 2018 was in the range of $24,000,000,000 to $26,000,000,000
Great. Thanks very much.
Thank you, Jason. Next question from Oswald Clint at Sanford Bernstein. Are you there Oswald?
Thank you very much. Yes. Brian, two questions please. Thank you. First just on India.
It sounds like you still expect the prices to move in the right direction over time. Could you maybe say what time period that might be? And therefore why did you take the impairment in this quarter? And secondly, you also mentioned the successful exploration you've been having through 2014 and obviously on the back of 2013. I wonder if you could venture any volume numbers yet at this stage.
It just would be helpful to compare to some of your competitors. Thank you.
Thanks Oswald. I think on India the first point to note is actually we did get last weekend a positive signal in terms of the new formulas that have been put in place, which will see our existing production, the prices we realize increase by just over $2 an MMBtu. So I think we see that as a positive signal. The question mark going forward was more around actually understanding what the various statements meant around premiums associated with new discoveries and how they will actually pan out going forward. I think what we saw was a positive development.
That was good. But as we looked at the V6 existing carry that we had on the books with the uncertainty around what those premiums would look like going forward from an accounting perspective, we felt it was prudent to take the impairment that we did. And we continue to work with the new Indian government going forward in terms of what those premiums may look like. And I think the big picture here is there is a terrific resource that sits off the coast of India and the development of that resource we believe is crucial for the growth of Indian gas. And we want to basically with our partners reliance on the ground there develop that gas and with the right incentives that's what we intend to do.
On the exploration side, we haven't quantified the volumes at this point. There's the 5 discoveries that we've had this year in Angola, Egypt, Gulf of Mexico, North Sea most recently in Brazil. We're still in the appraise of those discoveries and looking what they look like, but we haven't actually put any volumes out at this point Oswald.
Okay. Thanks for the answers. Thank you.
Thanks Oswald. Turning now to Jason Kenney. Go ahead Jason.
Hi, there. Thanks for the opportunity to ask a question. So in 2010, you estimated a number for the trust fund, obviously, with the U. S. Government, dollars 20,000,000,000 Just wondering how significant it is that you've actually reached that total 4.5 years later at $20,000,000,000 And how you see any particular commitment over and above $20,000,000,000 just going forward?
It's obviously quite a big feature of the last 4.5 years of your commitment in the U. S. Gulf. And secondly, with respect to the Rosneft dividend and its support for annual cash, I'm just wondering if you could share with us any thoughts on particular sensitivities or risks that you plan for or are aware of in respect of future year dividends from Rosneft.
Great. Thanks, Jason. On the $20,000,000,000 fund, yes, this is indeed the 17th quarter now that we've been tracking the provision. And the headroom that have built up of around $700,000,000 just shy of 700,000,000 dollars was used up this quarter based on our current estimates of administration costs going forward. There's a bulk of the increase, but also some business economic loss claims under the new scheme that's being put in place that actually went out.
And each quarter, we will now provide for those and there will actually any Bell charges that come through in terms of payments going forward will now be charged to P and L given the $20,000,000,000 is exhausted. That said, we still have $6,000,000,000 of cash in the $20,000,000,000 fund for distribution against the original provisions that we did around ensuring that. So there's still $6,000,000,000 in cash to be distributed of which $1,200,000,000 is associated with the C Fund that was put in place. But effectively now any new things over and above what's within the overall $43,000,000,000 provision will be taken to the P and L as we've done in previous quarters. So I don't think there's anything more significant to say about it other than the fact that now as business economic loss claims come through And it's probably worth saying they under the new scheme that's been put in place around the matching supervised by the court they have been drastically reduced from where they were a year or 2 years ago when the scheme first got up and running.
On Rosneft dividend, it comes through once a year typically. We received $693,000,000 in July of this year, which is a very important signal out of Rosneft. And we would expect to receive a dividend the same time next year. It will be based on 25% of earnings from 2014 and our share of that 19.75%. And at the moment, we don't see any major risk to that dividend.
But in terms of the overall financial frame, it is nothing like as significant as it would have been under the old regime where we own 50% of T and KBP. So in terms of financial frame, it doesn't really cause us any major concern. And certainly, we have no signals that it's something we need to worry about. It's quite a long way off in terms of next year's financial frame. It's another nice and 9 months away.
So it's not something which is which we're concerned about at the moment.
Perfect. Appreciate the view.
Thank you. Next question from Teepan Joffeelingam of Nomura.
Yes. Thanks, Jess. Good afternoon, Brian. A few questions, please. Could you just come back quick on the business economic losses?
Could you just clarify what's been awarded but not paid and the level that you are still sort of contesting? My second question is just on working capital. We've seen some unwinding in Q3. I was just wondering sort of relative to the build we saw in 2012, 2013, can you just remind us how much you believe is left? And the last question was just conceptually buyback versus sort of use of proceeds for acquisitions.
Clearly BP share prices come back, but there are some opportunities, I guess, in the Upstream. Could you just sort of weigh up the opportunity cost between the buyback and potentially buying resource at attractive prices? Thank you.
Thanks, T Pen. I mean, maybe I'll take the second question first because it's probably the easiest. I think we said at the end of Q3 last year that we expected roundabout of the $5,000,000,000 working capital build about 2 thirds to unwind. It's probably tracking somewhere around that for this year. So we've seen I think $2,300,000,000 come out already so far this year.
The actual bulk of it in the Q3 actually came from price. So that was somewhat unexpected. But as we see the working capital reduce the price reduce, so you see some working capital release that we saw at the end of the quarter. So I wouldn't say that there's any further guidance we give around that other than the fact that we're still on track for 30% to 31%. On business economic losses, I think the actual payments that went out in the quarter were in terms of cash.
I think in total, we have 113,000 business economic loss offers that were submitted as of the 1st October. But within the quarter, roundabout $120,000,000 went out as payments. And within the provision, we provided around $200,000,000 within the quarter. So there are certain Bell claims that go through that we don't have the right of appeal on. I think the cutoff is $25,000 and below we can't appeal.
But we can appeal things above that and we do that where we don't believe it matches up with the matching policy we put in place. On buybacks versus acquisitions, it's a great question, Tapan. In some respects, I would say given where we are with the portfolio and having brought on stream the projects that we laid out in 2011 as part of the 10 point plan for 2014. Our balance sheet has got progressively stronger as the average cash margin of the portfolio has increased. What that means is that we're actually in a very good position to certainly withstand a sustained period of low oil prices in the range of $80 to $85 a barrel within the existing frame.
And I think as we've said in many investor calls previously and in meetings, I think a period of $80 to $85 a barrel probably offers more opportunities for us than threats. And on that basis, we will look at how we deploy the cash that we have available to us in terms of investments, in terms of buybacks, in terms of progressive dividend and in the round. And of course, acquisitions will certainly be an option, but not of a corporate nature just to be absolutely clear on that. And Bob's been clear on this in the past. But in terms of being able to deepen strategically in some existing positions we have I think there may be some opportunities for us.
Okay. And just coming back to the BEL, is there a sort of dollar amount you would say that BP would be contesting at this point that's been already paid out? I think you gave an update a couple of quarters back on that number.
Let me just Tifan will come back to you towards the end of the call on that, if that's okay.
Yes.
I think we've contested something close to $1,000,000,000 of the old claims. But we have the existing issue where we've gone to the court with a request on clawback which was denied on claims that have actually gone out. But we will be appealing that decision as we laid out in the investor presentation.
Thanks, Thi Pan. Over to the U. S. And Doug Terreson of ISI. Are you there Doug?
I am. Good afternoon, Brian and Jeff.
Hey, Doug.
Brian, the downstream results were very good during the period, led by the strength in the fuels business, although it seems like global oil demand may be deteriorating somewhat based on the tone of your comments. So my question is whether or not you could elaborate on some of the trends that you guys are seeing in global oil demand and also any views that you may have for coming periods?
I think what we've certainly seen is a as we mentioned in the presentation a slowdown in the Far East around demand. Actually if we look at this year and particularly in Europe with the issues that we've had post-two thousand and eight, we have actually seen some growth in the fuels markets businesses. So we are actually seeing some growth around that. And we've of course but we're also at the same time seeing inventories build globally which is what's creating the softening in the oil price. We've also seen some additional production come on in places like Libya and of course the shale oil production.
So I think what you're actually seeing now is a rebalancing which is leading to softer oil prices. You've also seen as I said Asia demand growth falling. Even though China is still growing relative year on year, it's not growing at the same sort of rate that we were seeing a year ago.
Okay. And then second, given BP's historical position and the positive performance that you guys have enjoyed in the deepwater, I wanted to see how recent market changes in that area might affect your immediate term outlook, meaning you talked about deflation earlier and what the specific implications might be for BP over the immediate term?
That's a great question actually. It's one that we've been looking at Doug for the last 12 months. It's sort of interesting. If you look at the ultra deepwater rig this is something that Bernard Looney on the team has brought back to us. We've discussed this on a number of occasions.
But the if you look at the ultra deepwater rig inventory back in 2007, I think they were around 33 rigs. We've seen that grow to 150 of where we are today. We've already seen 5 ultra deepwater rigs being laid idle. So I think you're going to go through this period now of as the sector has curtailed some of the capital that was being poured in 2 or 3 years ago And the general sector message around capital, a softening in the oil price, some of these ultra deepwater rigs being laid idle, I think you will start see a softening in rig rates going forward. And I think from our perspective that can only help projects like Mad Dog Phase 2, which I know Bob has talked about in previous quarters around the re churn of Mad Dog Phase 2.
That can only possibly get better in terms of where we are given that's a project that will probably require something like 1 to 2 rigs to be committed over a period of 5 years. Sure.
Good for BP. Thanks a lot.
Thanks Doug. Right back to the U. K. And a question from Thomas Adolff of Credit Suisse.
Hi, Jess. In March I believe it was March you highlighted the some organizational efficiency measures and something you call the 60 simplification initiatives. I wondered whether you can comment how material it is and whether you've actually already reflected this in your cash flow guidance from 2015 onwards. The second question is, I guess, around projects. You've highlighted CapEx flexibility to the tune of €1,000,000,000 to €2,000,000,000 next year.
You also made a comment around we sanctioned projects at the €80 Brent. I wonder whether in a low oil price environment as today you can sanction projects like Tungu Expansion, Browse FLNG. Certainly these projects need a higher oil price. Thank you.
Great. Thanks Thomas. So on the 6 piece simplification projects, this is something we sort of initiated and put in place over 18 months ago. It was January of last year. And it was really precipitated by the $42,000,000,000 of disposals of assets.
So a very repositioned portfolio and exiting a number of countries places like Colombia, Venezuela, Vietnam and so on, led us to look back at the corporate structure that we had that was supporting the effect of the footprint that we had left. And that has led to a period of 18 months coming up to this year. We have now laid in plans that we'll see quite a reduction. We haven't given any guidance around numbers on that. But we laid out the 60 individual projects that we've looked at.
Things like combining corporate functions that we have. So for example previously we had 3 different audit teams. They're all combined under one leadership now. It means that they go into a business as a single unit rather than 3 separate units. So it's actually how do we get things more streamlined and simplified.
Now I don't think this isn't something which you ever stop. It's something which is continuous and you continuously look to try to improve. But we have seen significant benefits coming through already this year in part, but they are built into the forward plans as we look out to 20 18 in terms of what we showed you in March. So in some respect it's part of the risk mitigation around the delivery of the cash flow targets we laid out already. On the major projects in terms of $80 a barrel, everything we've sanctioned at $80 a barrel now for the best part of the last 5 or 6 years that I can recall.
We do stress tests down to $60 We do cases up to $100 And then we lay out a plan for the short term. And we're in the process right now of looking at where we'll set the oil and gas prices and the refining market margins for next year's operating plan. And I think the key we play with things like Tengu Train 3, we already have a number of contracts in place have been put in place. And we already have 2 consortia have been awarded onshore front end engineering and design FEED for the Tangu project. So I think to the degree we get some of those margins locked in ahead of time that still makes the margins and the projects pretty attractive going forward.
On Browse, we're still in the process of working on the floating LNG option in terms of its development concept. So it's too early to say.
Got it. Thank you.
Thank you, Thomas. Next question from Irene Himona of SocGen.
Thank you, Jessica. Good afternoon, Brian. My first question, going back to the issue you highlighted in your prepared remarks that in 2015, we should expect a greater focus on the streamlining activities you were discussing. Is that a new initiative additional to what you presented in March? So that's the first question.
My second question on Whiting, if you can perhaps give us a bit of visibility on the Q3 contribution and where we are currently given the present price differentials? And then finally, you took a EUR 550,000,000 impairment on petrochemicals after a strategic review. I wonder if you can highlight what particular negative is that review uncovered that led to that decision? Thank you.
Thanks, Irina. So sorry the first I'll take the last question first as my team let me know what the first question was again. On the petrochemicals, we given the market that we've seen particularly in the aromatics business that's in the sort of the piece that we have in China we've seen a lot of overcapacity come in. We've moved on our own technology internally and we had a strategic review with Bob in the Q3. And we went through where we think that market will be going into the future.
So and on that basis, we chose to close a number of what we call sort of older plants, which historically we may have mothballed with the anticipation that the oversupply might actually work its way out in future years. We don't believe that technology is sustainable going forward. And therefore, we thought it was the right thing to do is to shut those plants down and take the impairment which we did through the quarter. So I think the first question was around the new initiatives. There's still the 60 initiatives we laid out earlier this year on the corporate side, But we've also just recently gone through a restructuring of the organization within downstream under Tufan's leadership.
And I think that will create some efficiency opportunities in terms of how the downstream is run going forward. And Lamar has also gone through some major changes within the upstream in terms of that structure. In some respects ahead of what we've seen with the oil prices recently getting ready for ensuring that we stay competitive going forward in the lower oil price environment. And one tangible example of that would be the low 48% separation. And if you look what we've done with North American Gas, it's probably a good example of it where we've now appointed the new Chief Executive Dave Lawler from SandRidge.
We've now moved the office to a separate location in Houston. We expect at least 400 jobs will go and that's been announced already. And we are already starting to see the financial benefits of the restructuring that business has gone through. So I think this is just something it will be a theme that you will see more of. But I think just to make a really important point, this is all activity driven.
To the degree that we can take activity out, we can make things simpler. It's not simply about cutting costs. It's actually about taking activity out at the source, while we focus on safe and reliable operations.
Okay. And Whiting?
And on Whiting, we saw an improvement in terms of the Q3 comparison. Obviously, now we've got the that the 6 cokers all fully commissioned. The average light heavy spread for memory for the quarter was just on $20 a barrel through the 3rd quarter. We've seen that come off through October. So that will clearly impact results in the Q4.
But in terms of the Q3, we saw still good margins compared to where we sanctioned the project at. And the production stayed pretty constant from where we ramped it up to. So Whiting was operating well through the Q3.
Thank you very much.
Thank you, Irene. Back to the U. S. And Blake Fernandez of Howard Weil. Go ahead Blake.
Hi. Thank you for taking the question. Good afternoon. First question is on divestitures. You've got about 60% of your targets still ahead of you.
And given the collapse in oil prices, one may think that could be a challenge. I'm just curious if you have an appetite to sell more assets in order to achieve that? Or if you're perfectly fine to maybe come in short on that target? The second question back to the Lower 48. From what I understand, there's been a bit of a progressive shift away from gas toward liquids.
And now with this new phenomenon and lower prices here and potentially, I guess going to battle with OPEC if you will. I'm just curious is the new CEO driving that strategy or is that still being dictated from BP corporate level? Thanks.
Okay. Well, on divestitures, it's a great point you make. It was I'm sort of sitting here pleased that we did the disposals that we did when we did them at $115 $110 a barrel because clearly at these prices it's pretty tough to get those sort of prices that we were getting previously. So I think it's good that we don't have that big a challenge ahead of us. Equally, I think where we said the next tranche of $10,000,000,000 compared to the original $38,000,000,000 program would be a very different mix of assets.
That big first tranche that we sold off the $38,000,000,000 were typically late life assets highly depreciated and quite cash accretive. And we got some very attractive prices given where the oil price was at the time. The next tranche of the 10,000,000 which we've now got 4,000,000 is a far more diverse and dispersed group of assets that we're looking at. It's things like the aviation oil business that we talked about. So I'm not concerned about being able to deliver on the €6,000,000,000 In fact actually I've got line of sight on at least half of that as we look into 2015.
So I'm comfortable that we'll be able to deliver on that going forward. But you are right to point out that with the softening of the oil price, I think coming back to one of the earlier questions, I think there's as many buying opportunities as selling opportunities at the moment depending on what part of the portfolio you're looking to deepen in. In terms of Lower 48, we've gone through quite a transformation of that business over the last 4 or 5 years certainly since Macondo and having shrunk down the size of it. We now we're down we've gone from 24 rigs in 2010 down to 3 rigs today. Those 3 rigs are we've got 1 in 1 Sutter 2 in Haynesville.
And if you look at our overall gas position about 21% of it are liquids driven within that mix. So sort of gas liquids NGLs that sort of come out of the mix. Dave Lord is working with Lamar. It's a 100% owned company still a BP. So Dave is still working with Lamar in terms of the strategy of what we do going forward with that business.
But I think all the early indications are very positive in terms of what we can do with the existing footprint and looking at how we transform that going forward. So I think there'll be more to come on that next year as we step into 2015 and we start to give you some more line of sight on the performance of that business.
Okay. Thank you, Brian.
Thank you. And we'll take the next question from Jon Rigby at UBS.
Thanks, Jess. Hi, Brian. So three questions if I can, quite quick ones I think. The first is in terms of how you think about CapEx, should we be thinking about the way you sort of use your oil price sensitivities and think about you trying to balance cash in and cash out through a short term period of weakness as you might see it? So kind of sort of $1,000,000,000 for every $4 or $5 $4 of oil price.
Or is there stuff you can take out of the operating side as well? 2nd question is on Iraq. Given what's going on, I guess, with both the security situation and I'm guessing Baghdad not being the most efficient place in the world right now, is could you just update on how you're operating there? And then the last one, just a point of clarification on the Lower forty eight business. Is the idea to just drive a more efficient business around the sort of perimeter that you have right now?
Or is it a process of divesting exposure to Lower 48? Or indeed, is it a vehicle for perhaps expanding your presence in the Lower 48 onshore? Thanks.
Thanks, John. So if I just pick up the CapEx question, no that's not the way we're thinking about it. We're not going to try and cut CapEx commensurate what drops the oil price. I think that would actually put at risk the long term future cash flow. I think the key here is to not do anything sort of jerky in terms of CapEx.
I think it's important that we continue to invest in the future upstream projects. And there will be a natural re equilibration of capital in and capital out in the industry. You'll start to see the deflation kick in. If we saw a period of probably typically 18 months of sustained these sort of levels of sustained at this sort of level you start to see the CapEx naturally readjust itself. But at the margin, we'll always have projects where we can pair things back or rephase.
But we're not looking at cutting CapEx in line with the oil price. I think that would actually peril the future growth that we laid out for you in March. And I think the key here is the balance sheet can more than comfortably handle a period of $80 a barrel. And if you come back to what we talked about in terms of the repositioning of the portfolio, we have a portfolio that towards the back end of the profile that we showed you back in March naturally balances more towards $80,000,000 than $100,000,000 And today it's actually cash breakevens below 100 dollars a barrel. So I think that's kind of an important backdrop as we think about CapEx.
So we certainly don't want to be sort of cutting that in a sort of jerky fashion. It wouldn't make would put a peril to future growth. In terms of Iraq, clearly the violence in the north and west of the country so far has not affected any of BP's operations and we're continuing in the south pretty much unaffected with sustained production from Mahler. And we're confident in delivering the continued operations and production growth into the future. We don't typically talk about security concerns at a call like this.
Think that would be inappropriate at this point. But we did conclude the new Ramallah contract terms, which Bob did in September. And that also included reducing the plateau production from 2,850,000 barrels a day 2,850,000 barrels a day to 2,100,000 barrels a day. And so things are still going incredibly well notwithstanding what's happening actually in the north and the west of the country. On the low 48%, really this was about the fact that we have this terrific position in what has been the most prolific oil and gas basin in the last 5 years, if you look at the growth of what's happened with the shale.
However, we were applying different models in terms of how we run it. It's more as Bob has said on it on previous call, it's more of a manufacturing business. And it's really bringing that manufacturing know how to bear. And then in terms of options going forward, I think Dave Lawler has got a pretty much blank sheet of paper to work with in terms of coming up with options about how we can grow that business. And we have a lot of choices around what we do with it going forward.
But I think the key was actually to get it operating more efficiently on today's footprint and then look at where we can take it going forward.
So you would see it
as potentially a growth vehicle?
It is potentially a growth vehicle going forward. But John in the short term this is really about making sure that it was running as profitably and efficiently as some of the other independents and that's really what Dave Lawler has brought in.
Okay. Perfect.
Thanks, John. Gordon Gray of HSBC. Are you there Gordon?
Yes, I am. Thanks. Just one thing left to ask actually. It was about the fact that in the last few years you spent a lot of time and a lot of capital expenditure on asset integrity in the upstream. I wonder if there are any figures around that that you could give us for the outcomes in terms of how you're seeing better uptime across the asset base?
It's a great question, Gordon. It's one that we've picked up from I think Bob touched on in the last call actually on my 2Q results. We went through in 2000 if I get these numbers right, but from memory, we went through a period in 2011 of about 48 turnarounds, 35 the year after 22 to 23 the year after that. I think this year we're running at around about 8 or 9 turnarounds. And so what we're starting to see already is a major improvement in reliability of the kit given how much of the upstream kit has actually been taken out of service over that period of time.
We still have areas where we can improve and that's important going forward. But we have seen some major efficiency improvements in all the basins globally. And that's really come off the back of that the focus on maintenance. And we continue to see that going forward. We're now into a more even program of turnarounds and back to something which is more normal, but not at the sort of levels that we're running at over 2011 through to 2013.
Great. Thanks.
Thank you. Next Martin Ratz from Morgan Stanley. Hello Martin, are you there? Not getting a reply from Martin. So we'll go to Lydia Rainforth of Barclays.
Thanks, Jess, and good afternoon. A couple of questions, if I could. Just coming back to India, right. Would you be able to just confirm what gas price assumption you're putting in that or sort of within what else you would need to see to stop further write downs within that area? And then the second one, you did reference earlier that the very strong project portfolio that you still have within BP.
I'm just wondering, can you just talk us through which you see as the highest return BP projects either in development or pre sanction at this stage? Thank you.
Thanks, Lydia. On India, the new formula that was laid out last weekend is effectively sets a price now from the 1st November through the 31st March. And that price equates for our net production at around $6.17 an Mcf. So that's kind of the price that we've assumed going forward. It's based on a basket of 4 different market prices.
So I think it's an important signal in terms of move towards moving towards market based pricing. And then we've taken some pretty conservative assumptions around what we believe the premium would look like. But there is so much uncertainty around that it's impossible to say at this point. So that's really I mean the key here is the premium will need to incentivize that the potential for the new developments of the impairment that impairment that we did this quarter. But other than that I really can't share any more information around our assumptions on prices.
Sorry Lydia your second question was around the projects. Yes.
It was just given that you talked about the exciting project portfolio that you have. I'm just wondering where you see the highest returns within the portfolio at the moment in terms of developmental projects that still not functioned yet?
So when we look at returns across the portfolio, clearly a tieback to an existing facility will have much higher returns projects to come on stream next year, some of those deepwater, some of those tiebacks. And then 2016 through 2018, I see here a list of 15 projects each one in different phases of development in terms of appraise and pre sanction. But it's I think there's quite a portfolio of projects we have and we have the opportunity to optimize which ones we do and how we phase those with an overall focus on returns and cash flow. So, yes, a tieback is clearly going to give you the biggest bang for buck right now. Somewhere like a tieback in the Gulf of Mexico is clearly a very attractive opportunity.
But equally, we need to make sure that we also focus on the big greenfield developments things like Chac Taniz Phase 2 and Amman Kazan in terms of future growth in production in places like that.
That's great. Thank you very much.
Thank you, Lydia. We'll go now to Alastair Syme of Citi. Are you there Alastair?
Yes, I am, Jess. And thank you and good afternoon, Brian. Two questions. You mentioned the 7 projects coming on stream this year. Can you give me a little bit about Sunrise?
But on average across that portfolio, are we sort of on time and on budget versus original expectations? And as you look at some of the major capital projects that are working through the system, does that statement also hold true? And then secondly, I think you mentioned in previous calls that you did expect to sanction Mad Dog 2 before the end of the year. I wonder if that still applies?
Well, on the latter one, I suspect that's not going to happen now. I think we're actually right in the middle of it. And as I said earlier, I think given what we're seeing with rig rates right now, I think it's right to just hold a little and I think that will probably get sanctioned in the Q1 of next year. But there's no question that the current market is providing a big opportunity for Mad Dog Phase 2. So what's already become a far more attractive project, I think may well get more attractive, but that's a whole lot.
So I wouldn't expect that we would sanction that now in the Q4 probably more likely the Q1. In terms of Sunrise, it is on schedule in terms of what was originally laid out. We've got 1st theme coming through in December. We expect 1st production in the Q1. But I do think Husky last week did say something about some cost overruns that they've seen on that.
But I would say generally for our portfolio from the new central projects team that was put in place back in 2,009, we are starting to see now projects come through on time, on budget, the way we set them up to operate. And the greatest example I could give you is probably PSVM, which I think has now hit plateau from the original production. And it represents I think something like 0.7% of the world's production of oil. So it's quite a major achievement that coming on and hitting plateau. So but we never we're always restless in the project space and we never take our eye off the ball and it's kind of key that we stay focused on the especially during this period of lower oil prices, but we stay focused on costs in terms of those projects and bringing those projects on stream.
And so supplementary, I mean, what do you think if you just sort of pinpoint what's delivering that improvement? Is it more contingency, better budgeting, better supply chain?
I think it's all of the above. But if Bernard Looney was sat here, because Bernard only tells me this and Neil Shaw both are part of the Mars team would be front end loading and the front end engineering that goes into the pre planning. And when you sit down with our projects team and they talk you through things like Jacques Deli Phase 2 which is right now on track with everything that we've laid out in terms of that project Anaman Kazan, The amount of front end engineering that goes into that to ensure that we have the right design in place that we don't try and reinvent the wheel time has made major step changes for us.
Thank you very much, Mark.
And next Guy Baber in the U. S. Of Simmons and Co.
Thanks very much for taking my question. Apologies for revisiting this, but I wanted to continue on the capital spending theme a bit and was just hoping you could elaborate on the comments already made about the $1,000,000,000 to $2,000,000,000 flexibility in CapEx. But could you talk a little bit more about where specifically in the portfolio you see the most flexibility to potentially adjust lower versus planned? And maybe talk about how internally you may rank some of the primary spending buckets? I mean, could you trim in the downstream?
Is there opportunities to perhaps slow an exploration if that was necessary? And then as a point of clarification, do we still think about the floor for CapEx over the next couple of years as €24,000,000,000 or would that be under review? And then I had a follow-up on production also.
Well, on the 24,000,000 that's clearly not a flaw because we've just indicated 23,000,000 for this year. And we will look at what the programs look like through to next year. But other than saying that we will look at the margin and we think we can trim €1,000,000,000 to €2,000,000,000 a proportion of that will certainly come through the downstream because we've obviously having completed the Whiting investment which is a very major investment for us. And we've also shrunk our refining footprint radically over the last 14 years. We've taken 14 refineries out through mostly sales, but also 1 or 2 closures.
Over that period, we have nothing like the capital footprint that we would have had 10 or 15 years ago. So I think there's a natural you'll see some of the capital naturally drift down in that space. There'll be some other projects which at the margin we may choose not to pursue. But they're really at the margin. It's not the sort of big projects that we've laid out for you in terms of the future growth.
So I think I would just pause and wait till we come around to 4Q results where we'll be giving you specific guidance for 20 15 and whether that outlook looks very different going forward. But clearly the 2024 is not a floor given where we are today. And indeed if the oil price stays at 80 dollars a barrel you will start to see some natural deflation kick in. But it is lagged. It takes a period of 9 to 18 months for that to happen.
Okay, great. And then I'm trying to better understand the 4Q guidance for the decline in production, but you've been performing very well so far this year. Reliability is improving. You have the 6 new projects that should be up. You've completed your priority wells.
Even if the Alaska deal closed soon, it would still appear like you should deliver, some production growth 4Q quarter on quarter. So I'm just trying to better understand if there's any substantial downtime 4Q, any unsigned outages or specific areas where you expect lower production or if that's just an element of some
conservatism in the guidance?
Thanks. Well, what we do, I mean, 3Q of
hurricanes in of hurricanes in the Gulf of Mexico, which can typically have quite a major impact for us in a quarter. So we did benefit from that in 3Q. Equally in 4Q, we have the uncertainties that you just flagged around Hillcourt and closing the Alaska deal. We still have some weather risk, because the hurricane season doesn't officially close till the end of November or certainly from my time when I lived in the United States it didn't close until the end of November, so it can still surprise you. And we also have some maintenance activity at places like Thunder Horse, a shutdown in Australia and some maintenance work in low 48.
These are maintenance programs that we wouldn't typically classify as turnarounds, but nevertheless they will have impact on volume. So we're expecting volumes to be slightly down. We'll see what happens around weather and we'll see what happens around the closing of the Alaskan piece. But there is a potential that it may be flat, it may be slightly up. But right now on balance of probabilities, we're simply signaling that it will be slightly lower.
Yeah. That's helpful. Thank you.
Thank you, Guy. Fred Lucas from JPMorgan.
Thanks, Jeff. Good afternoon, Brian. Couple of questions, if I may. We know what the range is for CapEx and you've alluded to what the potential cut at the margin to CapEx could be. Can you put a number to the operating cost pool even if you can't put a figure to how much you might be able to produce that as part of the efficiency price?
I'm just trying
to get an idea
of how big that is and let's say 5% or 10% might do to cash flow. The second question is if this macro environment gets worse for a prolonged period of time and takes your gearing to its upper limit, if not through it, what goes first, the buyback
or CapEx?
And just thirdly, if you could, could you give me a list of the projects that's over the next 6, 12 months that you would expect to sanction upstream? Thank you.
Projects. Thanks Fred. On the operating cost pool, we wouldn't really put a figure out there and we haven't put that out there. But I mean I think it gets back to activities and taking activities out. And the only comment I'd probably make is as we look at the Q3 results, we are seeing costs running below deflation in places like the upstream.
So we're already starting to see a little bit of a trend, but I don't want to sort of signal that as benefits and effic benefits and efficiencies coming through and we're seeing those come through already, but there's more to follow on that. So I can't really give you guidance on specific numbers in that space. But there is no question some of the efficiencies in reducing activity is starting to have benefits. I don't anticipate certainly in the range we're now $80 to $85 the question on the upper end of the gearing. If we did reach that, it's hardly unlikely.
I think the oil price would need to be down at more like $70 to $60 a barrel. And then I think you get some major corrections in terms of forward program. So I don't think it will be something which will transpire. I think the key here is that we continue to stay focused on the capital that's really supporting the growth of the business going forward that's committed. And then in terms of the projects that we have coming up for 2015, we have I'm going to come back to you on that Fred.
Okay, Ryan. Can I just slip a quick one in on Angola LNG? Hearing some quite disturbing news about when that plant may be back up and running and also what the plant repair costs might be. Any comment on either of those facts?
I think the only information we have is I mean, Chef Tack is the operator, but we're now expecting the restart in 2015. I don't think there's any guidance as to when in 2015, but that is a concern. And then in terms of the 5 FIDs for next year that we're looking at around projects that we'll be sanctioning would be Mad Dog Phase 2, West Nile Delta, Trinidad Onshore Compression, Zinnia Phase 2 and Western Flank B.
Great. Thanks very much.
Okay. Thank you, Fred. Next Chris Kupland of Bank of America. You there Chris?
Yes. Thank you. Good afternoon. Just a few last crumbs I think I've got left. Just on gearing Brian, what needs to happen?
What are you waiting for to consider moving your target range back to 20% to 30%? Is that a long way off considering how long some of the appeals processes that you started might last? Thank you.
Thanks, Chris. I mean, that's really a matter for the board and the financial frame. We went from the 20% to 30% to 10% to 20%. Certainly, the front end of 2011, we had an awful lot of uncertainties in place. A lot of those have been resolved.
We have $38,000,000,000 of disposals behind us. We have the reposition Russia position that allowed us to liberate a significant amount of cash that supported the $8,000,000,000 buyback program. We have certainty around Macondo vis a vis the criminal issues and the SEC issues. They're behind us in terms of settled and behind us. So we've always said that we'll maintain this gearing of 10% to 20% while uncertainties remain.
Of course, those uncertainties are probably more biased towards the environmental outlook right now as they are towards the other typical issues that we might talk about. So I think given where we are today, it's prudent to stay in the 10% to 20% range. It served us incredibly well since 2010. And I think it will certainly serve us very well during a period of low oil prices which we would expect certainly to be in that position over the coming months over the next 6 to 9 months. So I don't think that's something we would be moving on today, but it's something that we look at in terms of more longer range of where we think the markets are moving.
And it's always an option. But right now, I think it's prudent to keep it in the 10% to 20% band.
And you would say it's not directly linked to the interest rate environment and your ability to raise debt?
No. And actually we have I mean if you look at what we've been doing over the last 2 or 3 years, you'll see that we've been quite active and we've found it very straightforward to raise the debt that we needed and we are carrying quite high cash balances.
Great. Thanks.
Next question from Lucas Hermann of Deutsche Bank.
Brian, yes. Hello. Thank you. A couple of them, Mike. Brian, I wondered whether you care to talk a little bit about some of the discussions on the board around the decision to increase dividend.
I won't say it wasn't expected, but given the nature of the environment and the relatively bearish comments you've been making on price going forward the next 2 years, it's interesting nonetheless. Secondly, North Sea, it almost feels as though that there's some momentum in the business or beginning to build in the business. I wonder whether you just care to expand, particularly with projects coming on. And thirdly, back to Rosneft. So it's 10% or so of your market cap or at least the value that you carry on the books is.
The environment and relations with Russia have clearly changed whether that's permanent or not. I guess none of us know, but axes are changing by the feel of things. Where does that leave the board in terms of thinking about the value that you have capped in that or locked in that business at the present time? Not that I'm suggesting now is a sensible time to be exiting, but certainly a time to be thinking.
Thanks, Lucas. So we start with Board and dividend. I mean, I think we had a very lengthy discussion on dividend and where we should go with this. But I think all roads lead back to strategy and the strategy that we laid out back in March to you as investors, which was a financial frame that could be flexible to a period of low oil prices. Our portfolio is naturally moving to be more balanced at $80 a barrel over the period that we laid out to you in March as I said earlier.
And we have downside support at $80 a barrel. There is surplus cash available to us both this year and next year. And therefore, we felt that actually it was an important signal in terms of the strategy that we laid out and the continued progress on the dividend. Of course, if the oil price stays where it is, I mean, the Board will look at all these things. We changed last year to have the Q1 and Q3 has been the quarters when we would look at the dividend with the Board and if they would consider a dividend going forward.
Clearly in the round, we'll look at where we are at the end of 1Q next year as to whether where we go with the dividend next. But in terms of being able to grow it sustainably over time is a core principle of the strategy that we laid out. And we felt it was well supported by the performance this year and the financial frame that we have going forward and where the balance sheet is.
Okay. Thank you.
In terms of North Sea, I think I was up with the North Sea team with Bernard earlier in the year. And I think they're pretty restless in terms of what they're trying to do around reliability of what is a very, very aging asset. It's a very late life asset. But we have seen the Andrew field restart as part of the prerequisites for bringing Canoole up and the rum field restart. And of course, we also have Quad 204 and the Clare Ridge projects proceeding to plan.
And so I think there is a lot of opportunity still in the North Sea into the future. And I think the biggest thing that they are focused on is reliability of the existing infrastructure along with the new projects coming on stream. In terms of Rosneft, we have it's a great investment. It's something that we did strategically in terms of repositioning out of TNKBP, working with a company of oil and gas people from the industry. And it's an investment that we saw over a 30 year period.
And right now it's very difficult from a geopolitical perspective. But our day to day operations with the business on the ground are very good. With the team that we have based in Moscow, Bob is still attending Board meetings which is important. And we still think it has huge potential going forward. But of course, we also have the backdrop of the geopolitical concerns and the sanctions and we just hope that a diplomatic solution can be found through all of this, because we believe the world it's key that those resources that are available in Russia can meet some of the demand that we see in terms of demand growth in the world elsewhere.
Okay. Brian, thank you.
Thanks, Lucas. Moving on, we'll take a question from Rob West at Redburn.
Hi there, Brian. My question is on Thunder Horse. I see some pretty strong data coming out of the BOEM, suggesting pretty good flow rates at the wells you're bringing on there. I wonder if you could comment on that and the kind of production expectations there for next year. And then secondly, I'm kind of looking at LOSAR, which is looking really interesting to me.
And I noticed a news story last week that in the UAE, they're kind of thinking of using some of that technology that I guess you'd be operating with them. And so my question is, what kind of further running room for low cell do you see throughout your portfolio after bringing Clare online into your course? Thanks very much.
Okay. Thanks. On the first question around Thunder Horse, I mean, I think what I would comment more generally in the Gulf of Mexico, we have production peak at just under 300,000 barrels a day during the quarter. Now, I don't take that as an indication of point forward, but nevertheless it gives you a backdrop flavor of how well the Gulf of Mexico is performing at the moment. We've got 10 operating rigs 4 at Thunder Horse, hence why you're seeing the production volume numbers that you're seeing coming out of Thunder Horse 2 at Mad Dog, 2 at Atlantis and 2 from memory working on exploration and appraisal.
We also had the 3 major project start ups in 2014 around the Atlantis North expansion, Makika and Mars B. So I think you're right. You will have seen some strong numbers coming through. And all I would say the drilling machine is working incredibly well. We're now running with those 10 deepwater rigs.
Historically pre-twenty 10 we'd typically have 5. So I think and that's a big part of what you're seeing in terms of performance in the upstream. In the Q3 even with the drop off in oil prices the underlying production growth coming out of GON. In terms of low sal, it's a great technology. It clearly moves towards enhanced ore recovery by deploying that.
And a place that we are looking to deploy it right now is in Clare Ridge in the Clare Ridge development in the North Sea. And I think there's an awful lot of potential for low south further afield outside of that region.
Thanks very much. Sorry, my question wasn't very clear. I guess, what I meant on low sal is there anything else coming through the hopper where you're thinking you could deploy that? Or is it really more a function of how Claridge works out?
I think I will reserve comment on that for our Upstream Investor Day, which is scheduled for the 10th December where we'll be able to showcase some of the things that we're doing around all the new projects and we'll certainly be touching on technology as part of that.
Very good. All right. Thanks.
Thanks, Rob.
Thank you. Over to the U. S. And Stephen Simcoe of Morningstar.
Hi, good afternoon. Just two quick ones. And first would just be when you look at liquids volumes in the rest of the world, there was a something like 50,000 barrel a day sequential uptick Q3 versus Q2 this year. And I'm just wondering what caused that. And then in terms of the recent discoveries that you guys have had via exploration in the last 18 months or so, I'm just wondering, I know it's very, very early days on these, but would there be an ability even now just to give a best estimate of what would be the first projects or discoveries that would be moving towards pre engineering and design stages?
And that's it for me. Thanks.
Great. Thanks, Stephen. In terms of the exploration success, it probably is a bit premature at this point. We had 7 significant discoveries last year, 5 this year. Fact actually last year was probably the best year we've had in over a decade.
And therefore on that basis, it's probably too soon to say which ones we'll be pursuing first. But it's a great inventory to have available as we start to think about which projects we'll pursue. In terms of production, I would guess although I don't have it to hand, but we can come back to you is that we probably saw some increase in the North Sea, but certainly also in Angola with the Clov startup. And of course, as I mentioned earlier PSVM did come up to plateau. So there would have been some growth in PSVM through the quarter.
Great. Thanks.
Next question from Anish Kapadia of Tudor Pickering Holt.
Hi. Good afternoon. Yes, a couple of questions for me as well. I was just wondering given that you're seeing in the market extremely low rig rates starting to come through, you're seeing the same on the seismic costs. How does that affect your exploration CapEx budget for next year?
So just I suppose from a cost perspective and also potentially in terms of activity for next year. And then secondly, I was just wondering if you can give a bit of an update of where you are with your plans for the lower tertiary, I suppose all the way kind of from exploration through appraisal and potential developments over there? Just kind of get an update on that in the Gulf of Mexico. Thank you.
Great. Thank you. In terms of rigs and rig rates and seismic, I'm just trying to come back to our rig rate. I think we run something over 30 rigs. And of course, they're all on different contracts.
Typically in the last 3 or 4 years, we've really been trying to work more closely for basically 3 to 7 year light contracts. So depending on where they are sitting, for basically 3 to 7 year light contracts. So depending on where they are sitting on the contract, we'll start to see some benefits of that coming forward or not. So you will see some deflation start to kick in as we start to renew some of the rigs, but we're not seeing a major change in the short terms. It will take some time for that to flow through.
In terms of the lower tertiary, what were you thinking specifically?
Just in terms of where you're at in terms of further appraisal on your discoveries over there?
Right. Okay. I understand. Yes. So what we've had most recently we've announced is the Guadalupe discovery where we've hit significant oil pay in the Paleogene around 30,000 feet down and I think about 4,000 feet of water.
And that of course builds on the previous three discoveries we've had in the Paleogene around HeLa, Tybur and Cascida. And we did drill out an appraisal well for Cascida last year. So I think all of that is progressing going forward. And there'll be more to follow on that on the Upstream Investor Day in December, but there's probably nothing more to say at this point.
Thank you.
Thanks, Anish. And we'll take a last question from Neil Morton at Investec.
Thank you, Jess. Good afternoon, Brian. I've just got one question left and it's a hypothetical one on Macondo. You talked about the importance of fair outcomes. Let's say, say, in 2015, you're busy going down the various appeals routes against the gross negligence finding.
But meanwhile, Judge Barbier pronounces in Phase 2, he holds Phase 3 and announces a penalty applying the various mitigating factors of $3,500,000,000 in line with your provision. Do you then drop the gross negligence appeal? Is it money or is it the principal? Thank you.
I think Neil it's that's a very hypothetical question and that would really be a matter for the board. But I think if we come back to principles, we believe the bar set for gross negligence was a high bar and we don't believe it was met. Hence the filing that we made a couple of weeks back around the way in which that decision came about. We intend to appeal that. I don't believe at the end of the day this was an industrial accident.
It was multiparty, multicausal. It had process safety failures, individual errors and machinery failure. It was an industrial accident on a huge scale. And I don't believe for 1 minute and I think anybody in the company believes for 1 minute that actually that the borrower gross negligence has ever met or anything was ever intended in that basis. So but the specific scenario you've laid out would really be a matter for the board consideration.
All right. Thank you all.
So with that, I think Neil I hope that answers your question. So look, thank you all for taking the time today. In summary, it's been from BP's perspective another quarter of momentum building on the strategy that we laid out for you back in 2011 around the 10 point plan. We continue to remain confident around delivery of that 10 Point Plan recognizing that we are in a very different environment today than we were then. And I think the robustness of the strategy that we've laid out will see us through during this period of uncertainty around oil price with a very strong financial frame that we have.
And I look forward to speaking to you at the next quarter results along with Bob as we announce the full year results. Thank you very much for taking the time today.