Welcome to the BP presentation to the financial I now hand over to Jessica Mitchell, Head of Investor Relations.
Hello, and welcome. This is BP's Q1 2015 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 Gilberry. 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 to everyone dialing in. I'll start with an overview of the environment for the quarter and then take you through the results along with a reminder of how we are approaching our financial framework in response to lower oil prices. I'll also update you on U. S. Legal matters and progress in our upstream and downstream businesses before taking questions at the end.
So starting with the environment. In the Q1 of 2015, Brent crude oil fell to an average of just under $54 per barrel compared to an average of $77 per barrel in the 4th quarter and $108 per barrel in the same quarter last year. This is the lowest quarterly average since the Q1 of 2009 and Brent has continued to average below $60 per barrel through April. Oil supply remains buoyant with a combination of OPEC increasing production and year on year production growth in the United States. At the same time OECD commercial stocks are at their highest level on record with inventories in the United States at their highest level since 1930.
Despite a significantly colder than normal February, Henry Hub prices in the Q1 were around 40% lower year on year at an average of just under $3 per 1,000,000 British Thermal Units as a result of continued strong production growth. By contrast, the overall refining environment improved in the Q1 impacted by planned and unplanned outages in the United States and Europe and improving demand. The upstream environment remains challenging and we continue to expect oil prices to remain weak in the short to medium term. In our results, you are also seeing a number of quarter specific impacts, including costs associated with the actions we are taking to respond and other accounting and tax effects. So I would characterize today's results as not only reflective of the new environment, but also of where we are in repositioning the company.
Turning to results for the group. BP's 1st quarter underlying replacement cost profit was $2,600,000,000 down 20% on the same period a year ago and 15% higher than the Q4 of 2014. Compared to a year ago, the result reflects significantly lower upstream realizations, partly offset by increased upstream production and improved downstream environment and performance, lower cash and non cash costs across the group and a one off tax benefit arising from the recently announced changes to U. K. Supplementary taxation.
1st quarter operating cash flow was $1,900,000,000 including a build of $2,500,000,000 in underlying working capital. The Q1 dividend payable in the Q2 of 2015 remains unchanged at $0.10 per ordinary share. In the upstream, the underlying first quarter replacement cost profit before interest and tax of $600,000,000 compares with $4,400,000,000 a year ago and $2,200,000,000 in the Q4 of 2014. Compared to the Q1 last year, the result reflects significantly lower liquids and gas realizations, a lower gas marketing and trading result compared to a strong result a year ago and cash costs associated with the cancellation of 2 deepwater rigs in the Gulf of Mexico of just under $400,000,000 partly offset by higher production, lower exploration write offs and lower cash costs resulting from ongoing simplification and efficiency activities. Excluding Russia, 1st quarter reported production versus a year ago was 8.3% higher.
After adjusting for entitlement and portfolio impacts, underlying production increased by 3.7% mainly due to the ramp up of major projects, which started in 2014. Compared to the Q4, the result reflects lower liquids and gas realizations, a lower gas market and trading result compared to a strong result in the 4th quarter and the costs associated with cancellation of the 2 deepwater rigs, partly offset by lower exploration write offs and lower cash costs from simplification and efficiency. Looking ahead, we expect 2nd quarter reported production to be lower due to significant seasonal turnaround and maintenance activity, particularly in the Gulf of Mexico and PSA impacts. Turning to Russia. Rosneft are expected to report their final results in the coming weeks.
Based on preliminary information, we have recognized $183,000,000 as our estimate of BP's share of Rosneft's underlying net income for the Q1 compared to $271,000,000 a year ago and $470,000,000 in the 4th quarter. Our estimate of BP's share of Rosneft's production for the Q1 is just over 1,000,000 barrels of oil equivalent per day, an increase of 2.1% compared with a year ago. Further details will be made available by the management of Rosneft on their results conference call. Earlier this year, we made 2 VP nominations for election to the Rosneft Main Board. These are Bob Dudley, an existing Rosneft Board member and Guillermo Cantero, an experienced member of BP's senior management team, who is currently Regional President for BP Interests in South America.
Their nominations will be considered at the Rosneft Annual General Shareholders Meeting in June. And finally, also subject to approval at Rosneft's AGM, we expect to receive our next dividend from Rosneft in the Q3 of 2015. In the Downstream, the 1st quarter underlying replacement cost profit before interest and tax was $2,200,000,000 compared with $1,000,000,000 in the Q1 last year and $1,200,000,000 in the 4th quarter. The fuels business reported an underlying replacement cost profit before interest and tax of $1,800,000,000 compared with $700,000,000 in the same quarter last year and $930,000,000 in the Q4 of 2014. Compared to a year ago, this reflects a stronger overall refining environment despite weaker crude oil differentials in the United States, increased refining optimization and production and improved marketing performance, stronger oil supply and trading and the benefits of our simplification and efficiency programs resulting in lower costs.
Compared to the Q4, the result reflects an improved refining environment, strong supply and trading and reduced costs, partially offset by lower marketing margins. The lubricants business delivered an underlying replacement cost profit of $350,000,000 in the Q1 compared with $310,000,000 in the same quarter last year. This reflects continued momentum in growth markets and improved efficiency resulting in lower costs, partially offset by adverse foreign exchange impacts. The Petrochemicals business reported an underlying replacement cost profit of $20,000,000 in the Q1 versus a breakeven result in the same period last year. Looking forward to the Q2, we expect refining margins to be similar to the Q1 and a significantly higher level of turnaround activity.
In other business and corporate, we reported a pretax underlying replacement cost charge of $290,000,000 for the Q1, a reduction of $200,000,000 on the same period a year ago. This reflects improved business performance and lower corporate and functional costs. We continue to expect the average underlying quarterly charge for the year to be around $400,000,000 although this may fluctuate between individual quarters. The 1st quarter tax charge includes a number of 1 off tax benefits, the most significant of which is the reduction in the rate of the supplementary charge in the United Kingdom. The opposite effect was reported in 2011 when the supplementary charge was increased.
In the near term, we do not expect that there will be any cash flow impact from this change. Excluding the one off North Sea deferred tax benefit, the underlying effective tax rate for the Q1 was 21% compared to 33% a year ago. This lower effective tax rate reflects changes in the mix of our profits and certain one off items, partly offset by foreign exchange effects from a stronger U. S. Dollar.
We continue to expect the effective tax rate to be lower this year than 2014. Turning to Gulf of Mexico oil spill costs and provisions. The total cumulative pre tax charge for the Gulf of Mexico oil spill to date is $43,800,000,000 The charge for the Q1 was $330,000,000 This reflects the ongoing costs of the Gulf Coast Restoration Organization and around $300,000,000 related to business economic loss claims not provided for. It is still not possible to reliably estimate the remaining liability for business economic loss claims and we continue to review this each quarter. The deadline for submission of all final claims is June 8 this year.
Regarding the Clean Water Act, 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 of the Phase 1 gross negligence ruling and we have maintained the provision at this level. The pre tax cash outflow on costs related to the oil spill for the Q1 was $690,000,000 This includes just under $600,000,000 representing the 3rd series of payments under the schedule agreed with the Department of Justice in 2012 relating to criminal fines and penalties. A further payment of $530,000,000 is due in 2016, dollars 740,000,000 in 2017 and a final payment of $1,200,000,000 in 2018. Of the $20,000,000,000 paid into the trust fund, dollars 15,700,000,000 has now been paid out with the remaining $4,300,000,000 available for distribution. Costs not provided for are being charged to the income statement as they arise each quarter.
Now turning to progress on divestments and our objective to divest $10,000,000,000 of assets over the 2014 to 2015 period. Agreed deals to date have reached $7,100,000,000 and this total includes the sale of a package of assets on the Alaskan North Slope, the farm down of 40% of our interest in the Amman Kazan project, the sale of our stake in the North Sea Central Area transmission system, monetization of part of our Gulf Mexico Paleogene interest, the sale of our global aviation turbine Ores business and proceeds from our Toledo refinery joint venture partner Husky Energy in place of capital commitments relating to the original divestment transaction. We remain on track to reach our $10,000,000,000 objective this year. Now this slide compares our sources and uses of cash in the Q1 of 20142015. Operating cash flow was $1,900,000,000 the Q1 of 2015 compared to $8,200,000,000 a year ago.
Excluding oil spill related outgoings, underlying cash flow was $2,500,000,000 This reflects the impact of lower oil prices on earnings as well as a build of $2,500,000,000 in working capital in the Q1 of 2015, which we expect to unwind as the year progresses. The working capital build includes $1,400,000,000 relating to inventory optimization in high return contango market structures. Our organic capital expenditure in the Q1 was $4,400,000,000 and our full year guidance remains around $20,000,000,000 We received divestment proceeds of $1,700,000,000 during the Q1. Turning to our financial framework. In 2014, our financial framework reflected a position where operating cash flow exceeded capital expenditure and dividends as planned.
We ended the year with gearing at 16.7 percent and this was against the backdrop of the near $100 per barrel average oil price environment in 2014. At the end of the first quarter, during which oil prices averaged just under $54 per barrel, net debt was $25,100,000,000 and gearing stood at 18.4%. Notwithstanding ongoing litigation in the United States, our intention remains to keep gearing within the 10% to 20% band, while uncertainties remain. We are now responding to the reality of what we expect to be a sustained period of lower oil prices. Along with a continued focus on delivering our businesses, we are working to complete our current $10,000,000,000 divestment program.
We have reset our capital frame to around $20,000,000,000 for 20.15 compared to our original guidance of $24,000,000,000 to $26,000,000,000 and we are actively resizing our cost base. These interventions are designed to support our dividend in 2015 in the current price environment without compromising core investments for the future. As explained in February, this requires an intense effort right across the group. We have booked a further $215,000,000 restructuring charges in today's results, bringing the cumulative charge to $648,000,000 against the estimated $1,000,000,000 non operating charge we expect to see before the year end. As well, the rig cancellation costs already noted illustrate the Upstream's focus on determining the right scope of activity in this new environment.
Over the medium term, we expect to take greater advantage of sector deflation, while continuing to reset our own controllable costs with an objective of reestablishing a position within our financial framework where underlying operating cash covers capital expenditure and dividends. As we have said before, our first priority within the financial framework is the dividend. This reflects the commitment of our Board to maintaining a stable dividend as you have seen today. We can sustain this by successfully resetting our capital and cost base and rebalancing sources and uses of cash in the prevailing oil price environment. We will continue to review progress as we move through the year.
Turning to the ongoing Gulf of Mexico litigation in the United States. The penalty phase of the MDL-two thousand one hundred and seventy nine trial is now complete. This is the third of 3 steps in the process of determining the amount of penalties under the Clean Water Act. We do not know the timing for the District Court's ruling, but it could come at any time. In the first phase, the court issued rulings, which included findings of gross negligence and willful misconduct by BP.
And in the 2nd phase, the court ruled that 3,190,000 barrels of oil was spilled into the Gulf as a result of the incident. We have appealed both these rulings. Phase 2 also found no gross negligence in our source control efforts. As we have said before, we will pursue fair outcomes in all legal matters, while protecting the best interests of our shareholders at all times. Following a detailed review of internal controls and fraud prevention and detection measures at the core supervised settlement program, BP recently withdrew its appeal related to its motion to remove the claims administrator.
The review demonstrates the improvements the settlement program have made and is continuing to make to the facilities administration, including the addition of scores of fraud investigators. BP looks forward to working with all the parties to continue to improve the facility's operations. We continue to compartmentalize these legal activities and BP's operational delivery teams remain fully focused on our core businesses. Now, reviewing milestones and progress in the businesses. In the Upstream, we remain focused on safe and reliable operations.
The selection, timing and execution of capital projects and driving cost efficiency into the business. At the same time, there are a number of key milestones that our teams are working towards in 2015. And during the Q1, we have made good progress on a number of fronts. In January, we announced the new ownership and operating model with Chevron and ConocoPhillips to progress 2 significant BP paleogene discoveries in the deepwater Gulf of Mexico. As we described to you in February, this deal will enable us to maximize synergies and support the development of a key part of our future in the Gulf of Mexico, while also providing expanded exploration access.
Meanwhile in Egypt, we made another important gas discovery in the North Damietta Offshore Concession in the East Nile Delta. Turning to projects. The first of our planned start ups for 2015, Gizomba Satellites Phase 2 in Angola is expected to begin production very soon. And we continue to make progress on 3 further start ups planned for this year. The Greater Plutonia Phase 3 development in Angola Block 18, the Insala Southern Fields project in Algeria and the Western Flank A project on the Australian Northwest Shelf.
Also following startup of steam operations last December, oil production began in March on the Sunrise Phase 1 project in Canada. Total production is expected to ramp up to full capacity of 60,000 barrels per day gross around the end of 2016. Looking forward to future developments, in March, we signed final agreements for the development of the West Nile Delta projects, which will develop around 5,000,000,000,000 cubic feet of gas resources in total, Along with our significant investments in Amman Kazan and the Shaktani Phase 2, West Nile Delta will contribute to the increasing share of gas upstream portfolio in the future. In our operations, we have maintained strong plant reliability at 94% across our operated assets in the Q1. We are planning 15 turnarounds this year compared to the relatively low number of 8 in 2014.
We began our 2015 turnaround program in April and we expect to commence 7 turnarounds in the Q2 including Thunder Horse and Naquica in the Gulf of Mexico. We also continue to implement our plans to improve planned reliability in the North Sea with specific plans for each of our operated assets. For example, we have already improved reliability on the Vonaven gas compression system and we are currently focused on our sand and produced water management plans for ETAP. Finally, but importantly, we are maintaining a clear discipline on capital and cost management. As you are aware, we have canceled drilling rig contracts in the Gulf of Mexico.
But beyond this, we have deferred discretionary activity such as the restart of drilling on the Magnus platform and made progress in engineering standardization across our projects and operations, all of which are delivering material savings. And across our portfolio, we are reducing headcount as we continue to simplify our business. In the Downstream, we continue our strong focus on process and personal safety performance. In addition, as outlined in February, our strategic priorities are to build an advantaged manufacturing portfolio, to selectively invest in high return differentiated marketing businesses and to deliver our efficiency and simplification programs to improve our resilience to volatility and bottom of cycle conditions. In petrochemicals, we started up our new PTA plant in Zhuhai, China, which has a capacity of 1,000,000 tonnes per annum.
With this plant's advanced technology, we expect to reduce costs to help us become more resilient to bottom of cycle conditions. In lubricants, our focus on growth markets and premium brands continues to deliver like for like profit growth. In retail, we continue to see volume momentum in our growth markets. We continue to actively manage our portfolio. In the quarter, we announced the sale of our bitumen business in Australia and completed the sale of our interest in UTA, a European fuel cars business.
And we're beginning to see benefits from the implementation of our simplification and efficiency programs as we streamline our businesses. We have significantly consolidated the number of our reporting units and are aligning our head office and functional support to capture the associated efficiencies. So to summarize, we are in the midst of a major transition as we work to reset the company. We remain confident that this is the prudent and right thing to do in the current market conditions. Looking at today's results, you can see the benefit of our integrated business.
We believe we benefit from having repositioned our portfolio to drive value over volume with rightsizing of the cost base already well underway. Our near term priorities remain those we set out in February. Delivery, the continued safe, reliable and efficient execution in our businesses divestments, completing our current $10,000,000,000 divestment program discipline on capital and costs, the resetting of our capital budget and rightsizing our cost base and most importantly, sustaining the dividend, which makes us keenly aware of the need to rebalance our sources and uses of cash for a lower oil price environment. Longer term, the road map is one of operating off a reset base. We will realize the potential of our portfolio as we start up the next wave of upstream major projects and look to improve returns in our downstream business, while maintaining strong cost and capital discipline.
Our focus throughout will remain firmly on value for shareholders. Thank you for listening. We are now ready to take your questions.
Welcome everybody. We'll take the first question from Alastair Syme of Citi.
Good afternoon, everybody. Brian, can
I just ask you to provide a little bit more color on how the sort of the provisions map into cost cutting? How will we be able to measure the outcome of this? Is it improved reliability? Or will we see a reduction in cash costs? And can you give us some attempt to quantify where we're at in that process?
Thanks, Alastair. It's a good question. And we're not going to quantify in dollar terms, but you should assume that if we set aside $1,000,000,000 of restructuring that's mostly around people. And therefore, you'd expect to get a minimum at least that amount of cost coming out of the system. It'll actually be a It will actually be a multiple of that.
You've seen about original $1,000,000,000 that we laid out in December of last year around the same time as the Upstream Investor Day that so far we've booked about $615,000,000 of those restructuring costs. If you look at the headcount, this is something we talked about 18 months ago, 2 years ago as part of repositioning the company, given the big wave of disposals that we had and looking to try and get our corporate and functional costs back in line with the new portfolio and having embedded a lot of our safety and operational risk into the business line. So it's sort of a journey that we've been on now for close to 2 years. And we're starting to see the benefits of that in lower costs across both the big major businesses and in particular across corporate and functions. So we haven't quantified an absolute number.
But maybe just sort of anecdotally to help you with that. If you look at the number of people inside the company, if you annual report and account at the end of 2012 to the end of 2014, if you sort of cut through and take out the retail staff and the sort of biofuels, farming, agricultural staff, it's about a 3,500 reduction in people. Now some of that comes with the disposals. But if you look at 1Q, we've seen a further reduction of about €800,000,000 in the Q1. So we are actually now starting to see the benefits of lower costs come through already with this now sort of trend over the last three quarters and we would anticipate to see more of that.
It's quite a painful process that we're going through. And we just need to move through that and treat people fairly and equitably as we go through that process. But you'd expect to see more of this come through in the results as we unveil the results for the rest of this year.
And do you think we would see most of this show up in the upstream business unit? Or would it be at the corporate level?
No, it's across the whole piece. You're seeing it in the downstream. You're seeing it in the upstream. We're seeing it in the corporate and functions that sits above the businesses and we're seeing it in the functions that are embedded inside the businesses. So it's right across the corporation.
Okay. Thank you very much, Brian.
Thanks, Alastair. Okay. Next question from Lydia Rainforth of Barcap. Go ahead, Lydia.
Thanks, Jess. And just to come back to Alastair's questions around the cost side. Are you actually seeing a change in the way that BP is working operationally? So, really you talked about the number of people being reduced, which is going to be a difficult process. But is that then leading to a change in the way that BP is actually doing things, which is then also helping the cost side?
And then just very quickly at the upstream day in December, the indication at that time was about 20% of upstream costs would come up for renewal in terms of third party procurement side over 2015. Are able to just give an indication of whether you are achieving the savings that you thought you would be in 3rd party procurements at this stage? And then just a very quick one at the end. Do you I think the previously the indication was that you would give Lower 48 disclosure separately. I'm just wondering where we are on that.
Okay. Lydia, thank you. On the latter point, I'll do that quickly. You will if you go searching on the Internet, I think you'll find on the 1 BP page, there is now data that we released today around Lower 48 around costs and volumes and structures in side Lower 48. So you will actually get line of sight on that and you'll find that on the website.
So that's our first run. I think it's got a couple of quarters or 1 quarter's worth of data and we'll look to update that as we go forward. In terms of the first part of your question, it's coming through in terms of I mean, I think Bob talked about this 2 years ago, but the 60 simplification projects that we laid in place, we are now starting to see the benefits of those. Some of that and it differs depending on where you are. In the Downstream, it's about delayering the organization, the 2 Finergan village has gone through and getting more of the operation closer to the day to day operations.
In the Upstream, I'll talk about some of the things that we're seeing now in terms of standardization and engineering design and some company wide reviews. So anecdotally, we've talked about the North Sea before. But as an example, we've seen 400 staff and 100 contractors leave in the North Sea. We've seen 380 onshore contractors that Bernard has talked about where we've got a renegotiated day rate. In Trinidad, we're seeing a 10% headcount reduction.
And Angola, we're seeing a 30% expat reduction. So we're seeing a number of changes across the piece. In terms of what Lamar laid out for you in December, anecdotally where we've got to so far and it's really as we progress through this year, we'll see more and more come through. But some examples, I spoke to Lamar before I came in today just to sort of get a sense of where he is on the journey at the moment. But we're seeing 20% CapEx savings in certain subsea production systems, 30% CapEx savings in certain control systems, 30% savings in subsea engineering CapEx and in some specific projects a 30% reduction in the major project defined estimates.
So it's across the piece. It's everything. And it's actually sort of going back to the nuts and bolts. And you may have heard Bernard Looney talk about this in some of the investor sessions that we've been having talking about how we need to get back to the basics of how we're designing some of the kits that we're operating today and actually get a lot simpler about how we do that. So there are no sort of single silver bullets.
It's kind of literally across the whole piece. We're looking at everything in terms of how we get everything into rebalancing the books going forward.
That's hugely helpful. Thank you.
Thanks, Lydia.
Turning now to Jason Kenney of Santander.
Hi, there. Thanks for taking the question. So I was just looking for a bit of further color on perhaps second quarter LNG lag effects and if there's anything we should be anticipating there? And also U. S.
Upstream, which I know was loss making in the Q1 and how that might play through the year? And then maybe a more broad question. I'm just wondering what your view is of the very wide range of consensus estimates for the quarter, which I think was almost as large as the actual result. Implicitly, this must be a very wide range for 2015 earnings. And I'm wondering how you can better guide us to probably focus on a more close number.
It's interesting how your trading statements or your Monday trading statements on a week to week basis have moved, but it seems very difficult to kind of get more on the operational side quarter to quarter and maybe we're not playing quite as fast as you are at this game.
Yes. Jason, I'll take that last point first. I mean, I absolutely empathize. And I empathize with you at a time when even when we lived through the quarters where it was $100 a barrel relatively stable quarter by quarter, it was pretty tough to predict results. Frankly, this is the Q1 where we've seen the full effect of the drop in oil prices down to an average of $54 a barrel.
That's a lot of moving parts. And for this quarter, you also have the tax effects that came through in the Q1, particularly around the North Sea, but are the one off effects across the piece. So I think that made it a particularly difficult quarter from a consensus perspective. Hopefully now as you see the oil price stabilize around the sort of levels that we are today and I think it's averaged about $57 so far in the Q2 versus $54 in the Q1. Refining margins are slightly up so far 2Q to date versus 1Q.
Henry Hub gas prices off a little bit. So hopefully as we get more stable pricing it may become that consensus range to start to narrow back into a sort of zone that's more acceptable whatever that means. But I think it's from that perspective. So I totally empathize where you're coming from.
Yes. Jason, if I could just add, we have put a new rule of thumb on our website. And with oil prices, if they stay a little more stable then you should find that that rule of thumb works a bit better than it's done in the quarter where we've had such a very big drop in oil price in 1 quarter.
Perfect. Okay. And on the first two, so on LNG lag prices, Jason, all I can give you is what I can see on the forward curve where you've got NBP going out about $7.20 out to the back end of the year. Henry Hub out at $2.80 and Brent crude parity around 11.60 in terms of 4Q. But other than that, I probably can't give you a lot of detail on LNG, but maybe we'll come back to you on any specifics on that outside of the call.
And then in terms of the U. S. Upstream, it was loss making for the quarter. And of course, the rig cancellation for Gulf of Mexico was loss making for the quarter as well.
And is that a trend that's going to continue into the Q2?
I think a function of what the oil price will do. And I don't like to sort of get into that particular discussion. But you'll start to see across the piece the benefits of what we're doing in terms of restructuring the organization and the company. But we'll measure this quarter by quarter.
Okay. Thanks.
Over to the U. S. Now and Blake Fernandez of Howard Weil. Are you there Blake?
Yes, Jess. Thanks. Good afternoon folks. The production was fairly robust in the quarter well above what we would have expected. And I was hoping you could maybe frame up the impact from our production sharing contracts in the quarter?
Yes.
Thanks Blake. I don't have the specific on the PSCs to handle PSA is to handle. We'll come back to that. But I think what you're seeing in the production numbers is a good uptick in reliability particularly out of the North Sea. We've seen strong reliability across the piece.
But if I look just at the North Sea that we've talked about previously about getting reliability back, it was running at about 6% higher than 2014 in the Q1. And that's certainly a big part of seeing that production growth that we've got we've got seen coming through in the Q1. PSA impacts we'll come back to you on.
Okay. Thanks, Brian. The second question for you. Divestitures, just looking at the sources and uses slide in the quarter and then gearing moving up a bit, it just seems like it's likely that you're going to have to re up the divestiture program. You're already 70% through that $10,000,000,000 Any sense of when we may hear a new target?
Or if you're thinking that there is a likelihood that we could increase that program?
No, not at this point. I think we laid that program out back in 2013 for 2014 2015. We're on track to deliver the $10,000,000,000 Beyond that date, we'll get back into a typical churn of around 2 to 3 per year and we'll review that at the middle of this year. In terms of rebalancing source and use of cash that is really going to come back through what we do around the efficiencies that we're driving into the organization and looking to rebalance the operating cash flows against the capital program going forward. The key here is that as we do that not to have major impacts on the long term growth profile of the company.
So I think everything we're doing at the moment is good for all seasons. Some FIDs may move sideways. Mad Dog Phase 2 is one that Lamar talked about on a number of occasions, but that will be a better project as a result. If you look at what's happening with rig rates now where we're seeing 40% to 50% reductions in rig rates. So I think it's premature at this point to suggest there's a bigger program.
And remember we sold €38,000,000,000 as part of the old program plus a significant amount of cash that was released out of the TNK transaction in addition to that. So our focus really now is on how we grow the company from here with the new portfolio that we've built over the last 3 years. And that's the sort of real focus here. Now we're not really in the sort of sale mode.
Fair enough. Thank you very much.
Okay. Thank you. We'll take our next question now from Thomas Adolff of Credit Suisse.
Hi. Thanks for taking my questions. 2, please. 1 on the higher level of maintenance in 2015 versus last year. Is this a function of let's do it this year when the oil price is low and have better uptime when the oil price recovers?
And also on the refining side, where exactly will maintenance be focused in the Q2? The other question I had was more on exploration and I guess asset deals. You never really quantified the cut to your exploration budget in 2015. But looking at your exploration expense this quarter, I think I can get a feel for it. But I guess adding resources inorganically, you talked about the bid to ask that still being too wide.
I wondered whether you can comment where we are today. And more specifically, if you were to add resources strategically, would you be looking to strengthen your existing hubs, I. E. Stuff you know pretty well deepwater, etcetera? And are you generally comfortable with the supply options you have in LNG?
Thank you.
Okay. Thanks, Thomas. That's a lot questions. So the first one on turnarounds. If you recall 2011, 2012, 2013, we had major turnarounds across the piece.
And just from memory, I think we ran at something like 45 to 48 turnarounds in 2011, 30 to 35 turnarounds in 2012, around 20 in 2013. And in 2014 in the Upstream is a relatively low year of around 8 turnarounds. You also have to remember over that same period of time, we've sold a number of assets and exited a number of countries and facilities and installations. So I think what you're seeing for this year around mid teens, 15 turnarounds this year will be more typical going forward. And I think we're now back into a more normal rhythm of turnarounds across the Upstream portfolio.
So I think this year is probably more of a typical year going forward compared to the big heavy turnarounds we went through post-twenty 10. So that's for the upstream. In terms of the downstream, it will be a similar series of turnarounds as we went through in 2014. So there's nothing particularly peculiar about that in terms of locations. So it will be similar to previously.
In terms of exploration and appraisal, I think as Lamar said at the 4Q results or Bob described the 4Q results, We have cut the exploration program quite significantly through 2015 as part of the rebalancing of capital down to $20,000,000,000 You have to remember that's off the back of 2 years of about 12 major discoveries that we had over 2013 2014. So I think a big part of what we're doing now is consolidating what those discoveries look like in terms of what choices we make going forward. And so far this year, I think the plan was to drill out 9 wells where we've already announced 2 discoveries and we have 2 under evaluation of 5 that have already been completed today. Does that answer your question Thomas? Yes.
Did I miss anything?
Yes. Anything on the asset deals? I mean anything interesting?
On the purchase or sales side?
Purchase.
I think we'll see where the oil price settles for this year. But I do believe and I think Bob said this at CERA last week that we will begin to see some potential financial stress in the markets in terms of potential opportunities for us. And Lamar is working his way through potential options of what portfolio we might like. But I would think typically you look at things where we can deepen. We're certainly not looking at corporate acquisitions at this point.
It's more in the deepening in existing asset positions that we have.
And you're comfortable funding this with cash or paper?
That is something I absolutely would not reveal at the moment on the call and you wouldn't expect me to either.
Okay. Thank you.
Next question from Anish Kapadia of TPH. Are you there Anish?
Yes. Good afternoon. I had a couple of questions as well. First one was surrounding the U. S.
Gas production a big, big part of your overall production portfolio. So I was just wondering if you see Henry Hub pricing stay around current levels, wondering what impacts you see that having on your CapEx in the U. S? I think you've guided to about $1,000,000,000 to $1,400,000,000 on the Lower 48. And also the kind of the long term impact or the impact over the next couple of years on production.
The second question was just on the tax side of things. I was just wondering if you can give some update on the underlying tax rate that you'd expect for the remainder of the year. Excluding the U. K. Impact, you still had a pretty low tax rate of 21%.
I think there was a mention of some one off items in there. So just wondering on a kind of normalized basis at current oil prices going forward what kind of tax rate would you expect? Thank you.
Okay. Let me take that actually I'll go through the gas question. If we think of Lower 48s, we haven't talked about that. I think we've learned a huge amount since David Lawler was brought in and the Marr moved the business more arm's length and off the Houston campus. We've now gone through a fairly major restructuring of that business.
And so therefore, we are seeing the benefits of the way in which Dave has approached effectively making that business competitive with the typical independents in the lower 48%. We have a specific financial framework around it with a specific CapEx allocated to it and an opportunity for them to reinvest in various options. So I think it's still early days. We've started to release some information that you can see on the website. We've had about 700 people leave the organization.
So we've seen the costs come down. We're currently operating about 9 rigs, 1 in Wamsutta, 1 in San Juan, 4 in Anadarko, 1 in Haynesville and 2 in Woodford. So I think we continue to pursue opportunities. Our cash breakeven is almost certainly coming down as we lower our costs in that business. But it's really about how we make that competitive.
And I think as we said before, there'll be more to follow on that as we progress through this year. On the underlying tax rate, we've tried to well, the guidance we've given you is that we're below last year. Of course, as we now move around the mix of earnings, it's very hard to predict what the number will be for this year other than it's certainly going to be lower than what the full year effective tax rate was for last year. But given you the figure for 1Q, I would expect something around 30 percent is probably where the underlying effective tax rate will be this year, but it's way too soon to sort of really give you guidance around that. But as I look at the numbers now depending on the sources of where the earnings come from across the various different geographies, something around 30% is probably a reasonable number to use for a planning basis.
We'll give you more guidance as the year progresses. So I wouldn't take that as a guidance other than it's for your sort of basic calculations. It seems like a reasonable sort of assumption going forward for this year.
Okay. Sure. That's helpful. Just a quick follow-up on the first question. In terms of your the CapEx numbers you put out at the investment day, I think things have kind of changed since then of $1,000,000,000 to $1,400,000,000 below 48.
Where do you see that actually shaking out now in 2015 with the CapEx cuts?
I think that number is still a good number. It's around $1,000,000,000 We can come back to you on the specifics on that, but I would guess it's just north of $1,000,000,000 So it'll be in that range of $1,000,000,000 to $1,400,000,000 that we've talked about historically. Great.
Thank you.
Turning now to Jon Rigby of UBS. Go ahead, Jon.
Yes. Thanks, Jess. Hi, Brian. Couple of questions, please. The first is on the dividend.
I noticed the last two quarters the script take up has been very low. Is that something that's a, have you got any observations on that? And secondly, does that impact or what is flex in your thinking around your financial framework with that lower take up and as it relates to your gearing, And then secondly, just on Rosneft. If you don't get a second director appointed on the board, as I think you mentioned you're putting one forward, would that prompt you to change your accounting for Rosneft within the BP Group going forward? Thanks.
Okay. On the dividends, well, we don't target a scrip take up. It was something that we actually from memory, I think we introduced it the quarter it's around the 4th quarter results of 2,009 from memory descriptive and was introduced. And it was at the based on dialogue with shareholders, it was something the shareholders are keen on. So we're seeing quite a trend now.
And from my memory, I can recall we've had anything up to 45% take up on the scrip historically. I think the last couple of quarters have been relatively low around 5%, 6%. But we don't target it John. It is what it is. Our shareholders have the choice as to whether they wish to take scrip or cash.
And we don't intend to incentivize them either way. So it is what it is. And it's sort of more of a backward looking measure that we look at, because it's not something we try and target. But you're right, it gives you flexibility or inflexibility around the financial frame. But frankly, we don't really see that as being a major driver of what we need to do in terms of rebalancing sources and use of cash, which is the sort of number one priority at the moment.
So you wouldn't feel that the financial framework was jeopardized if take up continues to be quite low?
No. It's in the overall scheme of things, no. It's de minimis in that respect. And in terms of Rosneft, we've talked about this before, but there are 5 criteria that we look at around the equity accounting of Rosneft. So Board seat is having a Board seat and having influence on that Board is important.
We get that through Bob's attendance to that Board and membership of that Board. But the 2nd Board seat won't make a difference in terms of equity accounting at this point, but we fully expect to get I think there are 14 nominations for 9 seats or 13 nominations for 9 seats. We've put 2 forward and we'll find out more in June.
Okay.
Thanks.
Next question from Irene Himona at SocGen.
Yes. Thank you, Jess. Good afternoon. Brian, I had two questions. So firstly, Mad Dog 2.
I wonder if you can talk a little bit about this as a very specific case of the work you're doing on improving costs. I mean, you started with a budget of EUR 22,000,000,000 a few years back. Last December, it was down to EUR 14,000,000,000. Whereabouts
are we now?
And is there any clearer timing on the FID? And then secondly, on the Downstream, on fuels in particular, the result was really very materially 40% ahead of market expectations. Apart from margins, can you talk a little bit about trading profit and cost reductions? In other words, the other factors that have helped in the quarter? Thank you.
Okay. On Mad Dog Phase 2, I think there's still a reasonable chance we'll get an FID before the end of the year. I don't think I can give you any more updates on that. If you look at what's happening with rig rates right now, there's no question that moving it sideways will from a value over volume will be absolutely the right thing to do. We're seeing now rigs, deepwater rigs.
I think the last time I looked there is something like, at the end of 4Q, we had 13 rigs at the end of 4Q, we had 13 rigs stacked. I think that number now sits at 21 rigs stacked. And at the end of last year and the Q1 this year, there's 41 rigs have been highlighted as potential that will be scrapped. So I think the rig market is still looking pretty soft right now. So I think Mad Dog Phase 2 gets stronger.
But I would expect it to be FID this year. At least there's a reasonable chance it will be FID this year. On the downstream result for the Q2, we did talk about a strong trading result. And maybe just to sort of give you a little bit of guidance on that. It was in the ballpark of $300,000,000 to $400,000,000 stronger than what we typically would have seen for an average quarter from our oil trading results, similar to sort of what we saw in the Q1 of 2019 in terms of performance.
So something around $300,000,000 $350,000,000 better than what an average quarter would be for all
trading. Okay. Thanks so much.
Thank you, Irene. We'll go now to Martin Ratz of Morgan Stanley.
Hi. Hello. I just wanted to ask you two things.
First of all, the charge related to the deposit horizon incident of a little more than €300,000,000 Last quarter, it was a little more than
€400,000,000 And I know these things are
taken as non operating items, I wanted to ask I wanted to ask you if you provide some ideas around that. And secondly, I wanted to ask about Egypt where you've taken an important FID that is quite sizable and quite an interesting point in the cycle. Now from where we are sitting admittedly behind our spreadsheets in offices, Egypt is not known for paying very quickly nor for very high gas prices. So I wanted to ask you what gave you the confidence to do this now? What are you seeing in the project that is that makes it so attractive?
Well, Egypt is a great project, which I'll come back to. Maybe we'll just pick up the business economic loss claims. As you all know, in terms of our provisions going forward, as a result of the various decisions that were taken around business economic loss and the appeals that we made, if you recall we had the matching issue which is known as 495. We won at the 5th Circuit Court of Appeal. And then the issue on causation wasn't actually seen by the Supreme Court.
But we're now back into sort of more stable steady state now with the facility in Louisiana. And so what we will do is take business economic loss claims as they arise each quarter both in terms of determinations and paid. Anything over and above the $20,000,000,000 we now take to the P and L in NOI. And this quarter it was $300,000,000 associated with business economic loss claims. We'll intend to make a provision of this once we have a pattern of payments.
The facility closes on the 8th June for all final claims of this year. And then I think it would probably take a couple of quarters before we'll be in a position where we can make an actuarial calculation to come up with a provision around this going forward. I should also point out Martin, it's pretty important that of course that cash comes out of the $20,000,000,000 trust fund, which still has something in excess of if you take away the fisheries piece that's left $3,500,000,000 of cash to be dispersed to various pieces including the PSC settlement. So that's on business economic loss claims. On Egypt, we've got a very long and successful track record of over 50 years and something close to $25,000,000,000 investments in Egypt.
We're one of the largest foreign investors there. I think the project that we've announced around the West Nile Delta is one of the most significant developments we'll look at. There's 5 fields involved. It utilizes all the existing new infrastructure inside Egypt that goes into the domestic gas market that's priced off international prices. I think there's something like 5 we mentioned on the call 5 TCF of gas.
And so we see this from an economics perspective as being a very deep and important strategic investment for BP over many, many decades into the future. And I think it's a great opportunity. It builds on our gas portfolio as we said on the call around the Mankesan and Shaktani Phase 2. And we see it as a great project going forward.
All right. Thank you.
Next question from Chris Kupland of Bank of America.
Thank you. Thank you, Jess. Thanks, Brian. Just two questions. Firstly, on your trading again during Q1, you commented on the impact that had on your cash flows.
Just wonder whether we've seen a lot of that in terms of the earnings impact or given that this is about
contango, you
expect this to trickle through into already Q2 or even later in the year? So just understanding how the CapEx budget now sees €20,000,000,000 almost at the upper end of a scale that could potentially have downside. Just wondered whether you already have any comment to make on where the journey is going to take you into 2016 and whether you are worried or whether you think we should be worried about decline rates possibly edging towards the higher end of your range that you've guided us towards in the past? Thank you.
Thanks, Chris. I think on that last question, I think the thing that we're very conscious of is making sure that at this point as Lamar and his team has gone through the whole list and series of projects and we'll continue to do that to make sure that we don't jeopardize the future growth that we see. So I think this year we've talked about the cuts in exploration. We've talked about looking to reposition the capital budget. We're being very cautious about what we do for 2016.
We will expect
to see, as I
mentioned earlier, just some anecdotes around the engineering CapEx savings that we can come in the subsea and the control systems that we will start to see some deflation naturally come into that capital budget for next year. There's some deflation this year 2020, but not that much compared to what we would expect through into 2016 as the oil prices continue to remain fairly soft. So I think it's too soon to say at this point. It's something we'll come back to later in the year on future quarter calls. But it's something we're very, very cognizant of in terms of what choices we make to make sure that we don't damage the potential for future growth further down the curve.
In terms of the oil trading result, I mean, of course, I can't tell you. All I would observe is that in the early part of the Q1, we saw contango structures of up to $13 in WTI and $8 in Brent. I don't think we ever got to the floating storage economics, because I think it's about $1 a month is what you need per barrel to go to floating storage. So I don't think we actually got that far to that. The curve has flattened out quite significantly.
We allowed our oil trading business as we have done historically to put certain positions on around those contango market structures. And the profits associated with those will unwind through the year. As you know, we'll use mark to market accounting and therefore we won't realize those profits for later in the year. And the profit we booked in 1Q for contango is relatively modest in the tens of 1,000,000, certainly up to 100.
Okay. That's great. So you'd agree with a statement that says you saw a lot of it in cash flow, but not a lot of in earnings, which is about to come?
No. So the $1,400,000,000 that we invest in contango stocks those positions will unwind as the year progresses.
Yes. Okay. Thank you.
Thank you. Next question from Teepan Joffeelingam of Nomura.
Yeah. No. Hi, good afternoon. Thanks, Jeff. Brian, just I want to come back to your cash balance.
It's impressively increasing in this environment and I know you're raising debt. So I just wanted to understand what you thought your optimal level in terms of cash is. Would you consider raising more debt through the rest of this year? And then I'm sure you've run different scenarios and you talked about in the past in the event of a penalty being announced by the district judge. Could you just talk about scenarios?
Would you use cash? Do you see a greater likelihood that BP would post a bond against any liability and just run through any potential scenarios that might arise in the coming months on the back of any announcement?
Thanks, Deepam. You saw our net debt rose through the quarter as we are in balance in terms of sources and uses of cash. We've continued to raise debt. I think we raised $7,000,000,000 in the Q1 at very attractive rates. We will continue to look to be able to tap those debt markets at different opportunities as they arise.
But we continue to manage the overall portfolio in terms of cash that we're holding on deposit. In terms of the penalty phase that I would fully expect that at some point the District Court there will be a ruling around Phase 3. I think post trial briefs went in on the 24th April. So now it is in the hands of the District Court. We could hear a ruling on Phase 3 at any time.
And that will simply set a number for BP Exploration and Production Company to then have a discussion in terms of how that is dealt with vis a vis bond or cash. And that's really a matter for BP Exploration and Production Company and one that we will come back to on future calls I'm sure.
Okay. Thanks, Thipan. Fred Lucas of JPMorgan. Are you there Fred?
Yes, I am. Thanks, Jess. Good afternoon to you both. Just one question around the cash flow framework and dividend prioritization, which is clear. I'm just wondering if you could help, Brian, on the cash flow bridge.
So just looking at Q1, which I know was an odd quarter in many respects, but taking the quarter's cash flow €1,900,000,000 adjusting from Macondo, which was €700,000,000 And then as you referenced, the inventory associated with contango of €1,400,000,000 that gets you to around €4,000,000,000 I wouldn't call it normalized cash flow, but something closer to a normal cash flow for that type of quarter annualize that that's about 16,000,000 just under. But clearly, you need to get to a cash flow balance, dividend costing just under 7,000,000 CapEx 20,000,000. So I'm wondering the bit that's missing, how should we think about that? Is that a combination of 1,000,000,000 of dollars of cost savings, headcount simplification, etcetera? And also some macro improvement, I guess.
I guess, even though you're various, you're seeing things get better from $54 Brent. And is there also another piece we should consider because you seem to be referencing CapEx deflation much more to come in 2016? Should we be thinking about €20,000,000,000 of CapEx actually falling to 2016,000,000,000 in which case we only have to make €23,000,000,000 So I can see how we might bridge that. So can you give us a bit of help bridging that gap please Brian?
Yes. Fred, I mean, it's well, it's only a quarter, right? So I wouldn't I mean, I think I spent most of last year on the $30,000,000,000 to $31,000,000,000 target saying please don't multiply a quarter by 4. Well, actually as it happens, it probably would have worked out for the Q1. So I wouldn't just take the Q1, but I think what you see in the Q1 is the full impact of where the oil prices have now appeared to settle.
I mean, there could be still some downside from where we are and there may be some short term respite in terms of upside that we're seeing at the moment. If you go back to your simple math, I think you could probably add €1,000,000,000 of working capital build as well that we talked about, which should get you to a number of around €5,000,000,000 But our real focus going forward is in terms of how we rebalance sources and uses. So we are keenly aware that where we got to last year was that we had something like a $3,800,000,000 surplus in terms of operating cash versus CapEx and dividends. We know we need to get back to breakeven going forward in terms of balancing up those sources and uses of cash and that's what we'll work on each quarter. And actually I think you've answered the question yourself.
Some of it will come through deflation in terms of capital. So you'd expect to see some deflation come through. I've given you some examples of that in terms of the subsea and control systems where we're seeing up to 20% 30% reductions on specific projects. And of course, a big part of this will be actually the overall cost base coming down to get that back in line with the $50 to $60 a barrel that we see today. So I think it's all of the things that you've described Fred and we'll continue to report it quarter by quarter going forward on that.
Okay. Fair enough. And just quickly on the rig cancellations, which cost you €375,000,000 are there any more imminent? As you see the rig right now? Does it still make sense to be considering canceling anymore?
We've let one other one go, which came up for expiry, which was from memory of the enterprise. I think it was in the Gulf of Mexico. So we're now down to 9 rigs in the Gulf of Mexico. With those 2 more cancellations, we'll be down to 7 rigs in the Gulf of Mexico. And we continue to look at the rig portfolio.
We continue to look at the cost base. The projects that we are moving some of the projects are moving sideways and we will continue to reevaluate it. And you may see more to come going forward. As I said earlier, it's still a very, very soft rig fleet right now with at the end of the quarter 21 deepwater rigs stacked.
And just finally and hopefully it's not a silly question, Brian, but do you think BP needs any protection from the U. K. Government?
Oh, that's not a silly question Fred. That's a leading question. That's a very leading question. It's not one that I'm going to comment on. Our focus here at BP is being on delivering the things that we said we'd deliver for our shareholders.
We laid those out back in 2011 around the 10 point plan. We're now in a period of resetting the company through this lower oil price environment and then we'll come back with you what the future growth the company looks like. But I'm not going to get drawn on those sort of questions. No. Thank you.
Okay.
Thank you, Brian.
Thanks, Fred. And we'll take a question from Rob West of Redburn.
Hi, there. Hi. Thanks very much for taking my question. Maybe going into the portfolio a little bit. Looking at Iraq, I think I've read you're taking more cargoes from Iraq in the past month and possibly I wonder also in 1Q.
Is there any change in the amount that's contributing to the cash flow coming in or going to change as you recover more cargoes or any comments around that? And then more broadly on the North Sea, I have a question for you, Brian. How do you think that basin resolves itself? On the one hand, you read over the weekend unions lamenting a war on wages by oil majors and complaining that they're not being paid enough to do too much. On the other hand, there are service companies saying they're not going to do any more North Sea fabrication work because all the previous ones blew over their budgets and labor costs are too high and not achieving enough.
Do you feel like there's an impasse there? And what's your role in resolving it?
Well, maybe just going to Iraq first. As you're aware, there's a lot of problems in the north and the west of the country. And so far, we're virtually untouched in Ramallah in the south. We continue to work with the government around lifting. You've seen further liftings.
Of course, as we take liftings, it's not a surprise you should see those increase with the lower oil prices. So as the oil prices have come down, of course, in terms of remunerating the investment, you need more liftings. You will start to see that a trend going forward. But we are working locally with the Iraq government in terms of how we manage that program.
Is there any quantities you could put around it in terms of cash impact?
No. We wouldn't normally get into that level of detail by asset. But no, we're managing it like we do other positions that we have around the globe and it's really that's where the benefits of the portfolio come in as different locations go through different cycles. North Sea, I mean, I think you have to recognize, I mean, we're 50 years in or now 51st year in. We had the 50th celebration last year for the North Sea.
And it is a very, very late life province. And we are having to deal with all the issues that we have to deal with the late life province in terms of maintenance and investment and the investments going into the kit. Our focus is very much around some of the big new developments around Clare Ridge and Quad 204. I think the recent changes to the tax fiscal regime in the North Sea will help, but that won't be sufficient. I mean, I think the companies and working with the service contractors, we have to come up with a solution that makes sure that the North Sea continues to be strong going forward.
And that's what we're trying to do around our big new investments. We're investing significant billions over the next 5 to 10 years in those big projects that we talked about. And this year we've had reliability improve as we've seen from Canul and Rome and Andrew through the quarter. But you have to accept the fact that we're in this late life development of the asset and it's really about how we renew it going forward. And I think it's a matter for all parties involved in the North Sea.
Were you profitable in North Sea in 1Q, can you say?
We don't normally give again specific guidance on an asset within margin.
I'll be reaching asset.
Okay. Thank you.
Thanks, Rob. And we have no further questions being pulled. So with that, I'll leave it to Brian to make a few
last remarks. Great. Thanks, Jess. Well, look, thank you for taking the time today. This is just a one Q1 for the year.
We are going through massive changes in the industry as we can see it with where the oil prices are today. We continue to believe that the oil prices remain soft. And our mission will be continue to be able to reposition the company going forward to make sure that we bring everything back into balance and we'll continue to support each quarter going forward on our progress against that. So thank you very much for taking the time today and I look forward to speaking to you in the Q2 with Bob.