Apr 26, 2016
Operator
Welcome to the BP presentation for the financial community webcast and conference call. I now hand over to Jessica Mitchell, Head of Investor Relations.
Jessica Mitchell
Hello and welcome. This is BP's First Quarter 2016 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 Gilvary.
Before we start, I need to draw your attention to our cautionary statement. During today's presentation we will make forward-looking statements that refer to our estimates, plans, and expectations.
Actual results and outcomes could differ materially due to factors we note on this slide and in our U.K. and SEC filings.
Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website.
Thank you and now over to Brian.
Brian Gilvary
Thanks Jess. Welcome everybody and thank you for joining us.
It’s been a challenging start to the year for our industry, it is also a quarter in which we have seen considerable progress in our own business as we work to reposition the group. We continue to see real momentum in resetting the cost base.
This is working to low the point in which we expect to rebalance organic cash flows in 2017 and support our continue commitment to sustaining the dividend as you’ve seen in this morning’s release. Our focus on costs together with sound operations has also supported the solid underlying earnings and cash flow delivery you’ve seen today despite the much weaker market conditions.
So I’ll start today by looking at the business environment before covering our first quarter numbers in detail. I’ll update you on our medium term financial frame where we continue to demonstrate both flexibility and resilience in our approach to resetting the company.
I’ll finish with the brief look at the first quarter progress in our businesses before Jess and I take your questions. Starting with an update on the macroeconomics where the markets is responding to low oil prices and progressing broadly along the path we laid out to you early in the year.
Global oil demand look set to increase strongly again this year supported by low oil prices. We expect demand growth to be around 1.4 billion barrels per day this year, a little weaker than last year but still comfortably above the historical average.
At the same time, global supply growth is likely to be flat to falling with U.S. tight oil supply falling in particular and partially offset by increases in uranium production.
So our view hasn’t changed materially over the past six to nine months, we continue to expect the combination of robust demand and weak supply growth to move to market closer into balance by the end of this year. This will still leave record high oil inventories to be work down before more settle position immerges.
Looking more specifically at the price environment so far this year, we continue to oversupply Brent crude oil felt to an average of $34 per barrel in the first quarter compared to $44 per barrel in the fourth quarter and $54 per barrel a year ago. Henry Hub gas prices continue to decline in the first quarter with spot prices averaging just below $2 per million British thermal units.
The mile winds from the United States continue to suppress demand while supply remained down pool including gas and storage at unseasonably high levels. The global refining market margin averaged $10.50 per barrel in the first quarter, the lowest since the third quarter of 2010, way down by weak diesel demand and high gasoline stocked in the United States.
Refinery margins have recovered averaging $12.70 so far in the second quarter. This weaker environment is consistent with the assumptions we built into our plans for the first part of the year, while it had a significant impact on our results in the first quarter, this is also a period of strong operational delivery and visible progress on our cost and efficiency agenda.
Turning to the results for the Group. BP’s first quarter underlying replacement cost profit was $530 million, down 79% on the same period a year ago and 170% higher in the fourth quarter of 2015.
Compared to a year ago, the result reflects lower upstream realizations, a weaker refining environment and the absence of a one off tax benefit arising from changes to UK supplementary taxation. This was partly offset by lower cash costs across the group.
Compared to the previous quarter, the result reflects lower costs across the group and higher contribution from supply and trading, partly offset by lower upstream realizations and a weaker refining environment. First quarter underlying operating cash flow which excludes Gulf of Mexico oil spill payments was $3 billion.
The first quarter dividend payable in the second quarter of 2016 remains unchanged at $0.10 per ordinary share. In upstream, the underlying first quarter replacement cost loss before interest and tax of $750 million compared to the profit of $600 million a year ago and a loss of $730 million in the fourth quarter of 2015.
Compared to the first quarter of 2015, the result reflects significantly lower liquids and gas realizations partly offset by lower costs from simplification and efficiency activities, lower rig cancelation costs and lower DD&A. Excluding Rosneft, first quarter reported production versus a year ago was 5.2% higher.
After adjusting for entitlements and divestments impacts, underlying product decreased by 1.1%. Compared to the fourth quarter, the result reflects lower realizations largely offset by significantly lower costs including lower exploration write-offs.
Looking ahead, we expect second quarter 2016 reported production to be lower than the first quarter reflecting PSA entitlements impacts and seasonal turnaround maintenance activity. In the downstream, the first quarter underlying replacement cost profit before interest and tax was $1.8 billion compared with $2.2 billion a year ago and $1.2 billion in the fourth quarter of 2015.
The fuels business reported an underlying replacement cost profit before interest and tax of $1.3 billion in the first quarter, compared with $1.8 billion in the same quarter last year and $890 million in the fourth quarter of 2015. Compared to a year ago, the rest reflects a significantly weaker refining environment and a lower contribution from supply and trading compared with a very strong result in the same period last year, partly offset by lower costs from our simplification and efficiency programs, strong refinery operations and higher retail result supported by volume growth.
Compared to the fourth quarter, the result reflects a strong contribution from supply and trading compared with the small loss last quarter, lower costs and strong refining operations partly offset by a weaker refining environment and seasonally lower fuels marketing margin capture. The lubricants business delivered an underlying replacement cost profit of $380 million in the first quarter, compared with $350 million in the same quarter last year reflecting strong premium brand performance and margin growth despite adverse foreign exchange impacts.
The petrochemicals business reported an underlying replacement cost profit of $110 million compared to $20 million a year ago, reflecting improved operations, lower costs and slightly improved margin environment. In the second quarter, we expect the significantly high level of turnaround activity particularly in the United States and some seasonal improvements in industry refining margins.
Turning to Rosneft, based on preliminary information, we have recognized around $70 million as our estimates of BP’s share of Rosneft’s underlying net income for the first quarter compared to around a $180 million a year ago and $235 million in the fourth quarter of 2015. Our estimate of BP's share of Rosneft's production for the first quarter is just over 1 million barrels of oil equivalent per day, similar to both a year ago and the fourth quarter.
Additional details will be made available by Rosneft with their results. On the 22nd of April, the Rosneft broad indicated an intention to increase its dividend payout to 35% of IFRS earnings.
At current exchange rates, this would imply dividend payable to BP of around $330 million after tax for 2015 payable in the third quarter of 2016. The final decision regarding the payout will be taken at Rosneft’s annual general shareholder’s meeting in June.
In other business and corporate, we reported a pretax underlying replacement cost charge of $180 million for the first quarter, a $110 million lower than the same period a year ago. This reflects lower corporate and functional costs and foreign exchange benefits.
We continue to expect the average underlying quarterly charge for the year to be around $300 million, although this may fluctuate between individual quarters. The underlying tax rate in the first quarter was 18% and reflects tax credits from the reported upstream loss of certain tax charges elsewhere in the business together with the defer tax benefit from the weaker U.S.
dollar. This compares to a rate of 21% in the same period a year ago after adjusting for the U.K.
North Sea supplementary charge in 2015. In the current environment and with our existing portfolio of assets, we continue to expect the effective tax rate for the full year to be lower than the adjusted 2015 rate of 31% which excludes the previously mentioned North Sea tax credit.
Turning to the Gulf of Mexico oil spill costs and provisions, earlier this month the court entered final judgment on the Consent Decree relating to the 2015 agreement to settle all federal and state claims arising from the Deepwater Horizon incident. As a result, the Consent Decree and settlements agreement are now effective.
The total cumulative pretax charge for the incidence to date is $56.4 billion or $40.7 billion after tax. The charge for the first quarter is $970 million, which includes $593 million related to business economic loss claims not provider for.
$201 million of costs relating to the settlement of certain civil claims outside of the 2012 class-action settlement and other administration costs and financing costs $723 million. It is still not possible to reliably estimate the remaining liability for business economic loss claims and we continue to review this each quarter.
We have however now agreed simplified and accelerated procedures for processing claims which you see reflected in today’s higher charge. Of the $20 billion paid into the trust fund, $19.8 billion is now being paid out with a remainder allocated to amounts already provided for.
The pretax cash outflow on costs related to the oil spill for the first quarter was $1.1 billion including $530 million in late into the 2012 criminal settlement of the United States Department of Justice. We also expect to further $1.1 billion of payments in respect of the 2015 settlement as well as further payments related to business economic loss claims under the costs not yet provided for.
We will continue to update you on a quarterly basis including any further developments with the Private Securities Litigation under MDL 2185. Now looking at cash flow, this slide composes our sources and uses of cash in the first quarter of 2016.
Excluding oil spill related outgoings; underlying cash flow for the quarter was $3 billion including a working capital build of around $800 million. Gulf of Mexico oil spill payments of $1.1 billion were offset against the divestment proceeds which also amounted to $1.1 billion in the first quarter.
Including oil spill payment, operating cash flow for the quarter was $1.9 billion similar to a year ago. Organic capital expenditure in the first quarter was $2.9 billion compared to $4.4 billion a year ago.
Turing now to our financial frame and starting with some context. Our financial frame work is designed to grow long term value for shareholders, while maintaining the financial health and liquidity of the group.
This requisite to determine the right level of reinvestment to continue to grow value well ensuring we distribute sustainable returns to shareholders. We believing getting this right is strongly length to making the right decisions about our portfolio.
At its simplest, we are prioritize value over volume and will continue to do so on an ongoing basis. We look to divest assets which no longer fit with our strategy and deepen in assets which are the most value.
At the same time, we drive returns through disciplined investment into the best projects. In the current environment, all this still applies but we have an added imperative to make very careful judgments about how we use [indiscernible] capital.
We have to balance the pace of investment to capture maximum deflation which ensuring we maintain safe operations and preserve future growth. We also wish to retain flexibility to add to the portfolio at the lowest point of the cycle if the right opportunities present themselves.
So there is a lot of moving parts that we need to continue to manage which the environment remains unsettled. We entered this down cycle with the strong balance sheet and we have a strong portfolio with the resilient downstream in a new wave of material upstream projects startups insight.
We have also move very quickly to reset the cost base of the company for a lower price environment consistent with many others we anticipated modestly more favorable oil price environment in 2017 than we see today. But believe we have the flexibility to extend the range of outcomes.
If oil prices remain lower for longer than anticipated there will inevitably be tradeoffs that we need to take. But we will continue to be governed in these decisions by what we can still to be in the best long term interests of shareholders.
Looking the specifics of our financial frame. We continue to make strong progress on resetting both the capital and cash cost base of the group.
We now expect capital expenditure in relation to the current portfolio to be around $17 billion this year. We see room to reduce this to between $15 billion and $17 billion per annum for 2017 in the event of a continued low oil price.
This compares to our guidance of $17 billion to $19 billion per annum for the same period, while at that time 2016’s spend was expected to be at the lower end of that range. Today’s guidance suggest that 30% to 40% drop in capital expenditure by 2017 compared to around $25 billion of spend at the peak in 2013, when Brent oil prices averaged a $109 per barrel.
The reduction has come through pairing back exploration spend prioritization of marginal activity and the capture of accelerating deflation the supply chain as we are time our investment decisions. Significantly it also reflects a strong drive towards capital efficiency in our development plans which is allowing us to deliver the same activity for less spend.
In areas where we still see flexibility to optimize activity, we will judge very carefully the implication of the business, retaining the ability to increase activity if prices strengthen. We will continue realize deepening deflation and balance the overall best use of funds to the prevailing oil price.
Our intention remains to stay very focus on both safety and our growth plans for the future. We also continue to move quickly to lower controllable cash costs across the group.
The Group’s cash costs over the last four quarters were $4.6 billion lower than 2014. This demonstrates the ongoing momentum behind our efforts to reduce costs and put as about two thirds of the way through to delivering the $7 billion of cash cost reductions by 2017 compared to 2014.
As we continue to look in capital efficiencies and embed structural simplification along with the more controlled organization, we expect the large part of the cost savings to be sustainable for the future. Non-operating restructuring charges are expected to approach $2.5 billion in total by the end of 2016 with around $1.9 billion incurred so far since the fourth of 2014.
Of this around $350 million was incurred in the first quarter. Our principal aim is to reestablish a balance where operating cash flow covers capital expenditure and the dividend overtime.
In this way, we look to ensure the levels of reinvestments and distributions are consistent with the long term growth of our underlying business. We’ve been working towards a goal of rebalancing by 2017 at the prevailing oil price which back in October 2015 we paid at $60 per barrel consistent with the forward curve at that time.
As we steadily take more costs down, the Brent oil price which we would expect to breakeven continues to move lower. We now anticipate rebalancing organic sources and uses of cash by 2017 at oil prices in the range $50 to $55 per barrel.
This currently refines the basis for our ongoing commitment to sustaining the dividend as the first priority with our financial framework. Actual inflows and outflows will be subject to ongoing recalibration to the environment including the judgments we make around levels of capital expenditure and any changes to the portfolio.
Once rebalancing is achieved, organic free cash flow is expect to start to grow at constant prices supported by the stronger cash flows expected from our upstream project startups over the medium term. This will in turn support distributions to shareholders.
With divestments having reached $10 billion over 2014 and 2015, we continue to expect $3 billion to $5 billion of divestments in 2016 and around $2 billion to $3 billion per annum thereafter in line with our historical norms. The proceeds from these divestments provide additional flexibility to manage oil price volatility and capacity to meet our Deepwater Horizon payment commitments in the United States.
Turing to gearing. At the end of the first quarter, net dept was $30 billion with gearing at 23.6%.
This includes the impact of the Consent Decree and settlements agreement with the Gulf States and on our balance sheet during 2015 and the scheduling of payments over an extended period. As a reminder during 2010, we lowered our gearing band from historical range of 20% to 30%, down to 10% to 20% to manage uncertainties, mainly in relation to the Deepwater Horizon incident.
Having finalized these agreements, we are reestablishing a 20% to 30% gearing band going forward. Now turning briefly to the highlights of the quarter from our businesses.
Starting with the upstream, we’ve seen continued strong operational performance. Plan reliability was 95% across our operator producing assets and we saw strong drilling performance particularly in the United States Lower 48 and Azerbaijan delivering both cost and efficiency benefits.
The first quarter saw the startup of the In Salah Southern Fields major project in Algeria and we also recently saw the startup of the Point Thomson project in Alaska. We also have two projects in the commissioning stage and two further projects continue to progress well for startup later in the year with facilities work nearing completion.
For example, we saw the safe arrival of the new FPSO for Quad 204 in Norway, ahead of its installation to the West of Shetland this summer ready for startup around the end of the year. Overall, we continue to have momentum on our upstream major projects portfolio as we look beyond this year.
Our 2017 startups are on track and together with our six 2016 startups we expect to put in place 500,000 oil equivalent barrels per day of new net BP capacity by the end of 2017 versus 2015. For example, our Khazzan project facilities are now 69% complete with 46 well pads completed and startup expected to a little ahead of schedule.
Juniper, which will back for production in Trinidad LNG trend, is progressing well with over 55% facilities completion. In Egypt, facilities for the Taurus/Libra phase of our West Nile Delta project are also on schedule and around 50% complete.
While the top side modules for Clair region in North Sea, our own rig from South Korean and are expected to arrive later this quarter. Beyond these 2017 startups, the production facilities for our Shah Deniz Phase II are ahead of plan and around 90% completion with first gas scheduled for 2018.
All of this means we made on track for the delivery of over 800,000 barrels per day of production from new major projects by 2020. In February, our first exploration discovery of the year was announced on Nooros East prospect in Egypt by the operator Annie who have now tied it back for production.
Meanwhile we have completed evaluation of the BP operated Kepler 3 discovery drilled in late 2015 and are in the process of tying this well into our Na Kika platform with the aim of starting production later this year. These are great examples of the opportunity for record monetization of near field discoveries of what we call infrastructure led exploration.
The first quarter was a strong quarter for new access including farm-ins and licenses awarded for new acreage in Norway and new farm in Canada with an aggregate total of around 12,000 square kilometers. In Oman, we singed a major agreement to extend the Khazzan license to access a further 1,000 square kilometers, estimated contain around 3.5 trillion cubic feet of gas.
Combined plateau production from Phase I and II is expected to total approximately 1.5 Bcf of gas a day equivalent to around 40% of Oman’s current total domestic gas production. Additionally in the first quarter, the Governments of India announced the series of policy initiatives including marketing and pricing freedom for natural gas produced from deepwater discoveries which we believe is a positive development under evaluating for future projects.
We also signed two new agreements, one with Kuwait Petroleum Corporation to enhance recovery of existing oil and gas resources and pursue future oil and exploration opportunities and a production sharing agreements in China to develop shale gas resources. In the downstream, the first quarter saw strong year-on-year underlying performance improvement mitigating the impact of a weaker refining environment.
At the same time, our refineries are 4% increase in utilization while we increase the amount of advantage to heavy crude processed by more than 20%. And in petrochemicals, we are improving the cash breakeven of the business making it more robust to a bottom of cycle environment.
Our marketing growth strategy continues to deliver results. The global rollout of our ultimate fuels with active technology represents our biggest fuel launch in over a decade.
We also expanded our convenience retail partnerships in Germany and The Netherlands and we became the world’s first supplier for commercial jet fuel using existing airport infrastructure. In lubricants, we continue to see double-digit earnings growth supported by strong premium brand performance and growth market positions.
And simplification and efficiency has progressed across the downstream into 2016 keeping the business on track to deliver $2.5 billion of cost efficiencies by the end of 2017. Taking together, this momentum in underlying performance improvement continues to support the increase resilience of the downstream business.
In summary, the environment is very challenging but we are seeing the benefit of how we move quickly to respond. We have considerable momentum around resetting our cost base.
This is driven by both the pace of which we are capturing deflation and our own simplification efforts. You have seen move evidence of this across all our businesses in today’s results.
We are steadily lowering the oil price that which we expect to balance organic sources and uses of cash by 2017, while retaining sufficient flexibility to make the right choices about our portfolio to sustain growth. I believe we are making strong progress, we are executing our project safely and more efficiently, driving down costs and making careful judgments about the best use of capital.
And all our decisions continue to be guided by our ultimate aim to grow sustainable free cash flow and distributions to shareholders over the long term. On that note, thank you for listening.
And I’ll now open up for questions.
Jessica Mitchell
[Operator Instructions] Thank you for all those waiting on the line. We’ll take the first question today from Irene Himona at Société Générale.
Are you there Irene?
Irene Himona
Thank you, Jess. Good afternoon.
I had three questions relating to CapEx if I may Brian. The new budget for next year is 15 billion to 17 billion, what proportion of the reduction versus this budget, would you say is inflation?
Secondly, within the 15-17, roughly how much would you say is maintenance versus let’s say growth? And then finally, in your comments regarding the financial framework, you referred to effort to set the right level of reinvestment, I wonder if you can clarify how the 15-17 fits in that, in other words how do you ensure that is the right level of investment perhaps in terms of I don’t know reserve replacement or other?
Thank you.
Brian Gilvary
Thanks Irene. Maybe if I just sort of start with what we came into this year.
As we thought about work capital would fall out in terms of the various projects that we pursue, we said your range to $17 billion to $19 billion and that was in the middle of this sort of effectively rebalancing the company out to 2017. It now transpires as we’ve seen more deflation come through, more things we’re doing around the ways in which we are working in terms of our own self-help.
We are not confident that actually the capital is coming out of somewhere around $17 billion, so we’ve sort of revise that guidance for this year. The range for next year is really been set to say actually if the oil price stay - which stay low levels that we see today that would have flexibility within the financial frame to move that capital lower, that isn’t something we would choose to do it today in terms of rebalancing of $50 to $55 a barrel.
So I think the basic assumption is that to the degree that we see oil prices staying low, there will be similar deflation come through. But you should assume next year if all things being equal and we see the second half of this year the forming up of the oil price somewhere we see today and a small recovery, quite a modest recovery, so we are not talking the major movement from where we are.
That in the range of $50 to $55 a barrel, you would expect that oil capital will come out somewhere between $15 billion to $17 billion, but it probably would not be at the lower end of that range, would only move to the lower end of the range that we saw continue pressure on the oil prices and that’s on today’s portfolio. In terms of the maintenance first is growth spend.
I think we’ve laid out for you all the various projects that we look at the drive growth in terms of ‘16, significant growth in ‘17 with the projects that come on in the second half of next year. Typically historically, our maintenance CapEx will come back and confirm it, but just from memory from previous calls, typically it’s around about 40% of the capital budget would be around maintenance versus growth.
Irene Himona
Thank you. And in terms of the, let’s say right level of reinvestment longer term, how do you think about setting that reinvestment?
Brian Gilvary
If you look historically both the sector and BP, typically we’ve reinvested anywhere to 70% to 80% of capital back into the business in terms of driving future growth. So far we haven’t limited the growth that we laid for you five quarters ago in terms of 17, 18, 19, so we feel that it’s the right level of reinvestment as we go through this transition would be oil price but something around 70% to 80% is typical in terms of the sector.
Irene Himona
Thank you very much.
Jessica Mitchell
Thanks Irene. We’ll take a question now from the U.S., Blake Fernandez of Howard Weil.
Blake Fernandez
Thanks Jess. Couple of questions on production if you don’t mind.
If I recall the previous guidance was for relatively flattish type of production in ‘16, it looks like 1Q is off to a pretty good start. So I am just curious for one, do you think that flat profile was still the right way to look at it?
And then secondly with 500,000 barrels a day of new production coming on through ‘17, can you give us an update on what the portfolio decline looks like currently?
Brian Gilvary
Yes. So I think first I’ll start by saying that of course the PSC impact quarter-on-quarter be like 1Q this year versus 1Q last year, there is an uptick in terms of where, how the PSC works around the actual price itself.
But we are actually see the strong performance out both the North Sea, Lower 48 and the Gulf of Mexico in terms of first quarter production offset a little bit by some issues around some declines in some more lower margin fields in places like Trinidad and North Africa. So in the round, it looks strong 1Q versus 1Q but a big chunk of that is coming through the PSC effects.
In terms of looking out into 2016, I think as Lamar laid out on the last call that we had and Bob talked about are relative decline, the base has been relative low because we’ve had a lot of capital focused on the higher return in field development work. So actually this year it’s running more closer.
Historically we’ve said 2% to 3%, it’s more of the 2% range in terms of this year.
Blake Fernandez
Prefect, thank you, Brian, I’ll level it there.
Brian Gilvary
Thanks.
Jessica Mitchell
We’ll take the next question from Jason Gammel of Jefferies.
Jason Gammel
Yes, thank you, Jess. Brian, I just wanted to come back to the capital cycle and looking into 2017 guiding for the breakeven of 50 to 55, at the upper end of the CapEx range of 17 and with the dividend about 6.5, that’s implying cash from ops of roughly 23 billion, does that include the proceeds from divestitures or is that we expect from operations organically?
Brian Gilvary
No, thanks Jason. Actually what we’ve done is we’ve actually changed back in October of last year, we relayed out the financial frame I think because now we had certainty around the vast majority of Macondo liabilities.
What we’ve done is effectively said operating cash needs to cover CapEx and dividends and disposal proceeds would be used in terms of Macondo liability. So if that is not relay on the disposal proceeds in terms of that rebalancing.
So it is basic simple operating cash needs to cover dividend and CapEx, since we be clear within the frame that we’ve laid out, it is total dividend, it’s not just the cash dividend.
Jason Gammel
Understood and if could just follow-up Brian on the divestiture process, obviously not a massive target but still on an oil price environment where we’re at. How are you expecting to be able to deliver these divestitures, are you going to be more reliant upon midstream and downstream type of assets or would you actually see a market for upstream assets that could achieve value that you would find acceptable?
Brian Gilvary
Yeah, everything comes back to the basic principles of what we laid out for you back in 2011 in terms of value of volume and to a degree that there are assets within our portfolio that we believe a better in the hands of others in terms of reinvestment versus those ones that we would like to maybe acquire. So this is not just about disposals that we believe we can value to them.
We look at both sides of that equation. In terms of the quantum of 3 to 5 this year and 2 to 3 going forward, the 2 to 3 is the historical average but of course as Bob has said on previous quarters, we saw include or exclude TNK-BP, we’ve sold up to $75 billion if you include TNK-BP, or $50 billion if you exclude it over the last three of four years, so it’s there for not surprising and there were $100 a barrel which was sold, it’s given where we on the cycle.
It’s not surprising that actually we’re really into what is the non-strategic tail of the business. And 2 to 3 feels right going forward.
The current sweets of assets that we are looking at that you will see it from the various sales announcements that happened, they are more midstream, but certainly more predominately downstream last year and the first quarter this year, but midstream, downstream. And we will still to look to exit upstream assets where we believe that the better in hands of others and equally potentially investing upstream assets and the downstream going forward.
Jason Gammel
Thanks very much Brian.
Jessica Mitchell
Moving now to Lydia Rainforth of Barclays. Are you there, Lydia?
Lydia Rainforth
Thanks Jess. Yeah, three questions if I could please.
The first one on the cost savings and the 4.6 billion versus 2014 which is incredibly the number, can you - are you able to spit for us kind of how much of that is upstream, how much of that is downstream, how much is corporate and just kind of where there are way you actually had what your expectation would be and if there is anywhere where it’s actually still lagging behind that needs to be more work? And then the second question was coming back to the $50-$55 per barrel breakeven in 2017, at that stage it looks like the financial framework is rebalanced but then if I look at, the project, so you do have the Khazzan, Shaktonese, it actually - is it right to think of that oil price breakeven moving down beyond 2017?
Thanks.
Brian Gilvary
That’s a great question actually. So the first question on cash costs, it’s across the piece, it’s upstream, it’s downstream and it is corporate, so it’s - I’ll start with corporate because that’s the one that we lay down for you in 2013 and you’ll see from the annual reporting accounts, it’s actually one of the things that we targeted in terms of the group performance scorecard.
We’ve seen a significant reduction, so over 30% of costs coming out of those corporate activities. Equally we are seeing significant reductions in absolute costs in both the upstream and downstream.
And in terms of what’s doing in the downstream, it’s efficiency drive in terms of the margin of the boundary is generating, so it’s both absolute cost reductions, but also getting more efficiency about the way in which those operations run. And in the upstream, it’s really about more efficient ways of working, activity optimization, organization size and staffing cost, but it’s also around agency staff and how are those important of the organization.
And in the case of the upstream, it’s something like I think the peak was 30,000 and the intent is to get down to something around 20,000 by 2017 in terms of total staff BP and agency staff, so it’s across the piece. On the breakeven economics, there is lots of moving parts hence where there is a range around that.
Of course it also depends on the Henry Hub gas price, it depends on the refining margin, it depends on what’s happening in any different many parts of our business. So I’d tied to be - but I am focusing on a specific point in time oil prices, the balancing point, because we have a lot of flexibility within the frame itself in terms of how we’ll get things back into balance.
But all other things being equal, I think to the degree that the oil price where to be lower next year and with the new projects coming on and ramping up into ‘18 and we’ve tried to layout for you just what it look like in terms of balance, in terms of surplus cash. That obviously elevates any other pressures that we have around refining margins and other components of the financial frame.
Lydia Rainforth
Thank you very much.
Jessica Mitchell
Thanks Lydia. Turning now to Jon Rigby of UBS.
Jon Rigby
Thank you. Can I ask three actually questions actually.
The first is on the CapEx number and the sort of visibility you are getting of cost deflation. Presumably you are staring to talk to the market around new sanction, so maybe you’re able to just talk a little bit about what the kind of feedback you are getting on some of those larger sanctions that you may be coming to and that give you the comfort around that cost deflation.
And the second is just on the dividend and the oil price progression. So you talked about looking to get cash into sort of cash neutrality with a full cash dividend, does that mean that you would expect to move to full cash dividend or you’re sort of expecting some sort of highbred of some sort of anti-dilution buyback and continue scrip?
And then the last question and this is of your background Brian as well, is that - there is a big beat in the downstream but there is clearly some significant moving parts on trading both 4Q to 1Q, 1Q to 1Q and I am very clear that the market is tended to give very little in terms of multiple to trading businesses anyway, but with that lack of visibility, I am somewhat concern that you won’t get very much credit for what looks like a very good number today. So is it possible that you can get some more guidance around the moving parts 4Q to 1Q, 1Q to 1Q on that downstream figure?
Thanks.
Brian Gilvary
Okay. So I’ll sort of work backwards.
So in terms of the downstream result, it wasn’t just about supply and trading, that’s the first of the point. I think that’s going to pull one and we actually look at half of that be probably just in the half that came from the supply and trading business which had a stronger quarter than 4Q where we had a slight loss in 4Q, but didn’t have as good of course the first quarter of last year.
So I think it’s just to put into context, yes it was a certainly above average quarter of supply and trading in the downstream, but there was lot of other things going other side of the downstream as well and I think Tufan and his team reacted early to what they could see in terms of what was happening with refining margins and got after further cost efficiencies and also good reliability through the quarter. So if you think about the balance for downstream in the first quarter, I think half - just on the half we came from supply and trading, but actually half we came from lower costs and better operations of the kit, so I think that’s kind of important.
I think there is components of our supply and trading result Jon which you alluding to which is actually that business has changed a huge amount in the last five to ten years where there is actually a base level of business inside there. Now that actually reduces the risk around the volatility of that going forward.
And maybe we’ll try through this year, maybe to illuminate that through future quarters in terms of maybe just some of the activities would be physical nature of that business that actually has more of a margin component it like a fuels business rather than what you think is trading. In terms of cash neutrality, yes, the intent as we lay down in October included the script of course that gives us some flexibility.
There is no intense at this point to get back in terms of what we off in the way of script, that’s a matter for a board and for our shareholders. It’s something our shareholders like.
We had a very big script uptick in the first quarter. For 2015, the script uptick was around about 9% from memory, for 1Q it was just over 40%.
So it was - there is a big trance of our shareholders like the script as an alternative. So I don’t think there is any intense at this point to withdraw that.
However, we do recognize that then dilutes our shareholders. So that’s why we say in terms of cash neutrality, we would look to want to offset that script at some point in the future and you’ve seen the buyback program we had in place prior to the drop in the oil price.
But that would be a matter for the board going forward. On CapEx and cost deflation, it’s really across the piece and yeah, you are just taking to Bernard in terms of the activities that he can say and what’s happening on each one of the projects, even with projects where we in development, an 80% of the design and kit is built into the price already.
There is still being opportunities for us to get back and renegotiate 20% of the final cost. So it’s really across the piece and I’ll save a little bit a part of the Bernard liked this year and I know Jess is talking about Upstream Invested Day at some point this year ideally in the first half of the year.
And I think Bernard and the team will be able to give you a lot of flavor around what we’re seeing, but it really is lectured as we sound how to review with the Bernard and his team a few weeks back and we went through at least six or seven different projects where there are lots of components of examples where $150 million has been taken out through 11 wells, it want specific development that we are looking at, how $100 million of that’s been booked already and $50 million also followed but it’s just across the piece Jon.
Jon Rigby
Right, okay, thank you.
Jessica Mitchell
And thanks Jon. We’ll take a question now from Rob West of Redburn.
Rob West
Right, thanks very much. I’ll up to relatively financial, that’s one is on the business economic loss payments.
Should we expect it to continue running this quarter to $600 million run rate in the coming quarters for 2016? And if it does, do we burn through the entire overhang of all payments by the end of the year?
My second question is on the commodity price assumptions that you’re using to manage the business, so clearly the breakevens have come down again today. Are we driving any read across that so the long run $90 oil price assumptions going into the impairment test and when would you look again it those?
Thank you.
Brian Gilvary
On the later question, we don’t use 90, 90 is the long term assumption, so we use the forward cure for the next five years and then 90K, so we’ll be looking at our long term price assumption this year, so actually most of project that went economics today $60 a barrel in terms of those options that are coming forward to our resource commitment committee today. On the bell assumptions, this is a quarter where we agreed with the PSC and the facility to simply the claims to accelerate claims to look to what was the final completion termination of that facility on a faster timeline than we were on.
That is let you lower administration cost, but of course the higher number of claim. So we sort of very large in the claims go through this quarter hence the $600 million.
We kind of this point actually given what is left in the facility provide provision around future bell claims and we’ll continue to update this quarter, but maybe just anecdotally to help you what is publically available is that we’re now over two thirds of the way through processing claims in that facility at the 147,000 claims submitted, 99,000 have been finalized by the CSSP where 39,000 office were made and 59,000 that were closed with no payments. So that kind of gives you a flavor what I am so far, but there are still 48,000 claims that progress through that facility and it’s impossible from the work that we’ve looked out and what we are seeing to come up with it this stage of best estimate what that provision looks like going forward but we’ll continue to update that each quarter.
Rob West
Very clear, thanks. Thank you.
Jessica Mitchell
And over to Guy Baber from Simmons.
Guy Baber
Thank you very much. So on the acquisition were highlighted as an objective look at the slide deck, where in the portfolio or in the market might there be opportunity add to the portfolio here, what’s the criteria on what you will screen for acquisitions.
And I know you guys have constantly looking at lot of assets all the time, and how would you characterize the current M&A market as it stands right now?
Brian Gilvary
Okay, so the M&A market stands right now in the upstream as there is lot of assets out there available. I think one of the overwriting principals and it comes all the way back to October 2011 is this concept that making sure that its value, and is value accretive for our shareholders.
So we have looked across the market. We’ve looked at various options around infill asset acquisition around existing positions that we have or strategic infill options for us.
I think the key test has to be accretive for shareholders. The things are dilative and really question why you be using your cash on that.
So we have done small acquisitions. We’ve done some last quarter, we mentioned some in the Lower 48 that we did around some of our existing positions in the San Juan Basin.
And we will continue to look at where we can see an asset acquisition where we believe we can add value typically we made with the operator or deepening in those positions or indeed actually looking at swap options. But it’s being pretty tough to actually find things which are value accretive in the current market and there are a lot of assets up for sale right now.
So we’ll continue to look and see and actually as I said last quarter, we did do some small acquisitions. We’ve deepened one of two positions where with the operator and we’ll continue to look at those options going forward.
Guy Baber
Thanks Brian. And then I had a one follow-up.
You’ve highlighted the 95% reliability for your upstream operated assets and the improvements you’ve made in the underlying upstream operations have been impressive and important to the profitability. What steps are you taking, how are you ensuring that that progress, does it begin to erode in an environment where you’re materially cutting back on your spinning levels assuming are cutting back some into the day spending and where you’re letting people go as well?
Is that a risk that you guys are focused on addressing or that you see?
Brian Gilvary
That’s a great question. And the thing - everything starts with no compromise on safety.
It’s the overall guiding principal that we’ve done for everything and that actually guided us through 2010 through the 10 point plan through what we lay down for you two years ago and actually what you are seeing through these results. And the absolute correlation between reliability, all the way to safety is very clearly there and you can see it through the results.
And you’ll hear Bernard talk about that, you’ll hear Lamar talk about it, you’ll hear Tufan talk about it, Bob always lays it out in terms of everything we do. It’s the overwriting piece, it’s the kind of the safe place that we go back to is safety being the absolute number one priority.
And of course that leads to a good reliability of the kit. And if you think about the number of turnarounds we went through in 2011 something like 48 turnarounds in ‘11, 35 in ‘12, something like 23-24 in 2013, we are back to much more stable steady state now in terms of those turnarounds, but that’s absolutely whether the liability is conforming in terms of the kit.
Guy Baber
Thanks Brian.
Jessica Mitchell
And right back in the U.K., Henry Tarr from Goldman Sachs.
Henry Tarr
Hi and thanks for taking my question. I just want to get back to Irene’s question on CapEx.
If oil prices did remain low and you considered activity reduction in the environment, how would you sort of split to prioritize between major project deferrals and lower spend on ongoing existing production? And then if CapEx spend where to come lower, would you still expect that sort of 2% are the lower part of the decline rate on the base production looking into 2017?
Brian Gilvary
Yeah, I think that’s get tough and actually once you get out to sort of ‘17, you are probably back in the 3% to 5% historical average in terms of decline, the 2% I talked about really in the context of 2016. So I think it gets difficult once you get down to $15 billion and what we see today and today’s portfolio because at that point, we started look in terms of future growth out to 2010 and 2021.
And it’s important that we continue to reinvest into the future and that’s really we’re at this point you’d have questions around all components the financial frame that you’d need to look at. Based on all the fundamentals of what we see around supply and demand today, I think that’s unlikely but nevertheless if that’s what transpires and we find ourselves in 2016 in the oil prices where is today then we’ll have decisions to take around all components of the financial frame.
And I think Bob said in the last quarter, we’re not going to drive the bus off the cliff on the basis of everything being fixed in the financial frame. We’d have to look at all components of that.
Henry Tarr
Okay, that’s great. And I just one follow-up on deflation and how you think about deflation generally and how much is being driven by FX and is there a cyclical services cost reduction component in there or would you see the bulk of the cost coming out now is secular?
Brian Gilvary
Yeah, I think there was FX benefits we saw last year that that was actually weakened against most currencies other than the U.K. pound which is more a phenomenon of the various issues going around the U.K.
Europe right now. So I think the dollar itself actually through the quarter weaken slightly versus other currencies.
So we’re not really seeing forex come through. And deflation is sort of one of those strange.
I know Lamar talked about this on previous calls but deflation isn’t something that just sort of arrives on your doorstep, it’s something you have to work out, you have to work with the contractors and you have renegotiate right, you have to look at your activity, you have to find more efficient ways of working. And I think if you go back certainly from previous comments, we’ve said about two thirds of the savings that we are seeing coming through in the upstream from self-help and about a third is from deflation.
That deflation is actually from renegotiating contracts. Of course there is a components if the rig - if you look at the water rigs, there is no questions, the rates have come down by 50% compared to where a couple of years ago and that of course feed into the underlying cost base.
Henry Tarr
Okay, that’s great, thank you.
Jessica Mitchell
Thanks Henry. We’ll take the next question from Oswald Clint if Sanford Bernstein.
Oswald Clint
Yes, hi. Maybe just a question on U.S.
gas please. I think you’ve said previously about a $2, kind of Henry Hub breakeven price, can you maybe just give us an update on that price point please, Brian?
Thank you.
Brian Gilvary
Well, I think that’s probably that’s a cash breakeven price and probably maybe - probably $2 a barrel right. In terms of earnings, it’s more like closer to 300-350 in terms of oil portfolio is today.
That’s after the work that Dave Lawler and his team has done in terms of bringing the costs down quite significantly in terms of our activity in the Lower 48. But I think a breakeven earnings number will be closer to 350, cash breakeven will be much lower than that which reflects a sort of activity that would doing in the Lower 48 over the last five quarters.
Oswald Clint
Okay, thank you.
Jessica Mitchell
Thanks Oswald. Aneek Haq of Exane.
Go ahead, Aneek.
Aneek Haq
Hi. Just a very quick question on refining, I think you’ve highlighted Brian as well that you are expecting sort of heavy turnaround in Q2, if I look back over the last at least couple of years, I think refining availability has been quite high, so I just wondered how we should think about by quarter-on-quarter in terms of refining availability in Q2?
Brian Gilvary
Yeah, I think we’re seeing certainly some of the refiners out there cutting runs right now, we’re not doing that. And I think it really comes back to where your refinery is positioned in terms of the barrel and the margins available to those refineries.
I think we are now down to about ten operated refiners in last time I counted. Most of those refiners are well upgraded, have good margins available for me through these downtimes, so we haven’t seen any run cuts of our own in our own system, but we’re all seeing run cuts across other refineries and other refiners certainly in the first quarter.
I think refining margins look pretty robust now we’ve come in seeing. 1Q 2016 was the lowest we’ve seen in since 2010, so it was actually quite a tough quarter, a lot of that driven by diesel and distal demand.
We’ve now come through that and we’re seeing margins that recover already this quarter to about $12.70 quarter-to-date and they are looking pretty robust as commence the driving season, but right now we’re not looking at run cuts.
Jessica Mitchell
Thanks Aneek. And we’ll take the next question from Anish Kapadia of TPH.
Anish Kapadia
Hi. I had couple of questions please.
First I was just wondering if you could give small update on where you are with some of your FIDs decisions was kind of driving, you are thinking so things like Mad Dog, Hopkins and Tangguh for this year? And then the second one, just thinking about acquisitions again, you know given your long terms planning assumptions of $80 barrel real and $5 Henry Hub and there is quite the opportunities rising in the current market.
I was wondering would you consider cutting the dividends to do a large acquisition that you believe to be long term value accretive to BP shareholders.
Brian Gilvary
I’ll come to that. So on FIDs, specifically now isn’t the time announce what we’re doing at Mad Dog Phase II but I’ll be looking forward to the quarter where we can talk about the FID having been done.
But I would expect there will sometime notwithstanding what we’re with partners towards the end of this year. I think that’s something Bob alluded to on the last call when we talked about 4Q results.
In terms of the Hopkins, well we’re in appraisal of that well and looking at where we go with it next. On the other developments, we had four FIDs last year.
The other potential FID this year that Mad Dog faced to will be around the Tangguh expansion that we’ve talked about before on Train 3 and that’s something that we’re looking at this year. In terms of acquisitions and dividend and financial frame, I think everything comes back to the financial frame and how we balance all the various components of that frame up.
The dividend is just one component of the frame as is the capital as is the cost base and it’s actually relatively small component in comparison. I think the key is provided, we can get things back into balance next year which is what we would anticipate now certainly as we’ve seen the costs frame up from being close to $7 billion coming down to actually $7 million.
The resetting of where the capital frame is, I think we have a lot of flexibility within the financial frame. We have a lot of capacity in terms of cash on the balance sheet if we were to look at those.
But as I said earlier, there is nothing at this point that we see to be accretive for shareholders that we look pursue.
Anish Kapadia
Great, thank you.
Jessica Mitchell
Alright, thank you. So we do have a question coming in on the web from Nikesh Patel of the Wesleyan Assurance Society.
If the market rebalances quickly above $60 a barrel, would you increase capital above 17 billion or would you remain conservative?
Brian Gilvary
I think we have flexibility as the price begins the firm which we’d expect by the end of this year and then into next year, we still even at the end of this year assuming things start to rebalance in the second half of the year that way we’ve described. It will still take probably a year to work through the access capacity.
So I wouldn’t I mean - let’s just assume that moves back to something around $60 a barrel and therefore we have surplus cash available. Then there is no question that replaces where we can ramp up activity relatively in short order in places like the Lower 48 in terms of the drilling program, Oman Khazzan, Oman exploration Iraq, Alaska, there are places where we can look to relatively easy ramp up drill rigs that we have available in terms of activity.
But we’re not going to try and get into boom and bust, we have to get it back to the basics of what are the long term growth options that we see we have a number of significant projects coming on stream in the second half of ‘17, we have then a long list of projects that we’ll be looking to FID and price in terms of ‘18, ‘19 and ‘20, but we wouldn’t be looking to significantly ramp it up if we set oil prices come back to 60, it’d be really be around what we do at the prefer of the existing portfolio.
Jessica Mitchell
Thanks Brian. And we’ll take a question now from Chris Kuplent of Bank of America.
Christopher Kuplent
Hi. I am going to make it quick and probably quite boring Brian.
If I may ask you to update us on your 2016 outlook on all those rather pedestrian items like depreciation, production, maybe you can give us number on the Gulf of Mexico payment schedule as well as your effective tax rate that would be greatly appreciated. Thanks.
Brian Gilvary
Okay, Chris. So effective tax rate will be lower this year than what it was last year.
It has a lot of moving parts around the tax rate, I mean it’s coming quite low this quarter I think it’s below 20% the effective tax rate for 1Q, but I would expect it to be lower than last year is really the any guidance we can give you. In terms of production, we laid out for you already that we expect it to be broadly flat with 2015.
DD&A again broadly flat with ‘15, although beyond that I would then expect to start to see some of the projects come on stream in ‘17 that there will be a slight uptick in DD&A but certainly for ‘16, I would expect it to flat at around I think - around about $15 billion. OB&C charge relay therefore about $300 million a quarter, it’s quite low this quarter.
There is lots of moving parts again in that figure. But I think most of it you should find Chris on the website on the presentation.
Christopher Kuplent
Right, thank you.
Jessica Mitchell
And thanks Chris. Next question from Neill Morton of Investec.
Neill Morton
Thank you. Good afternoon.
Two questions please. You mentioned in previous calls Brian that you were in the process of renegotiating well services costs.
I just wondered what progress you’d made by end of the first quarter and whether those benefits were included in the 4.6 billion number you mentioned? And then just secondly on gearing, is maybe net picking but back in February you talked about managing gearing around the 20% level, now you’ve gone back to the old band whole house change, is it simply the core settlement or is it anything else change in terms of the trajectory of oil prices, piece of disposals et cetera?
Thank you.
Brian Gilvary
Yes, so in terms of well services, I mean it’s across the piece but maybe one particular occasion but we’ve completed the attend, we have 80% of the well services, scope is already be competitively bid with 20% still to be renegotiated and we’ve seen a 15% reduction in well services spend in that particular location. That would just one example but there’re many across the piece that Bernard and the team can have for you later this year.
In terms of the gearing, it was really it was as you just alluded to was - it was convenient to run 10% to 20% strategy when we did because it wasn’t only just the issues around Macondo, it was also the oil price outlook where we’ve been pretty bearish since the middle of 2014 in particular where we expected a correction not as big as we sold but certainly a correction. But neither we have the Consent Decree as final and it is now done in terms of the quarter proving that.
It’s seen absolutely logical that we went back to the old bend. And actually we’ve got a lot of push from our investors to say why haven’t you gone back to the 20% to 30% ban because even at 30% that still gives us a huge amount of flexibility not that we have any intense of going anywhere near this year, but the idea that you are back in the 20% to 30% ban make complete sense given that now the vast majority of exposure around Macondo is it’s not only taking care of in terms of that one legal settlement which quote a huge amount of components of the Macondo liabilities that created the uncertainty that move in the lower end of the range.
But it was also the certainty that we now had in place a plant to rebalance the portfolio going forward at this new lower oil price set. So it’s - and I think it resonates with investors where feeding back to us.
Neill Morton
Right, just a follow-up on the costs, when you are signing new contracts or the price concessions you achieve or is typically time limited or the contracts linked to the oil price?
Brian Gilvary
It depends on what the nature of the contract is. Some of them those contracts are linked obviously to oil price in terms of how you recover that capital.
Neill Morton
Are those benefits typically wouldn’t go into the 7 billion target in 2017?
Brian Gilvary
No, just to be clear because actually that’s more on the capital side in terms of what you are asking about then in terms of the costs it will be across the piece, so the cost there benefits coming from headcount activities, renegotiations of contracts, it’s across the piece, but some of them to run well service, a lot of that is capitalized.
Neill Morton
Great, thank you.
Jessica Mitchell
Thanks Neill. Turning now to Lucas Herrmann of Deutsche.
Lucas Herrmann
Yeah, afternoon, Brian and thanks for your time and sorry about Saturday [ph] as well. Three if I may quickly.
First one, in terms of divestments, they are becoming increasingly small, it’s increasingly difficult I think in our side to try and assess what the cash associated, the income associated with the assets you are selling is ensure, how should we think about the cash or the income that you are foregoing, all the obligations you are taking on if you stop to dive - if you divest more assets if there are indeed any? Secondly, provision spend on restructuring, when you do actually expect it to end, is 2016 sort of predominantly you are going to see an end to it and 2017 will be relatively clean?
And thirdly, as we go through this period where a number of businesses is probably in tax loss, how much tax upside is there, is profits starts to recover and you find those profits is sheltered?
Brian Gilvary
Okay, Lucas. So - and thank you for the comments about Saturday and I am sure most people wouldn’t know what you are talking about, but that’s very much appreciated.
In terms of divestments, there is some operating cash with them but they are nothing like as accretive as they were historically, we just think about where the oil price is. So - and those midstream assets and some of those downstream assets that we’ve talked about, some operating cash has gone but nothing like at the same level that we divested and that big first trounce of the 75 billion.
In terms of provisions, we have to each quarter look at what the carrying value is all of the assets. I presume you are leaving to the things around Macondo provisions that we take in this quarter?
Lucas Herrmann
No, I am really referring to restructuring and trying to think 17 how clean is, so what extend we’re going to see the full benefit of the restructuring savings not pricing that were coming through either there wouldn’t be offset by a billion or so of restructuring charges?
Brian Gilvary
Yeah, so it’s probably second half of ‘17 will be the first time you will see a clear set of our costs with both normal provisions, so I expect - actually I’d expect the bulk of the provisions to be cleared out through this year. However, there will be some potential cash that flows out with those provisions in the first half of ‘17 as people leave the organization towards the back end of the year and cash payments gone in the first half of next year.
I would expect probably 2Q has been the early as next year where you get a clean set of costs and cash numbers coming through. So there is a hidden benefits if you like coming through each quarter because of course cash payments are going out each quarter effecting our pricing cash flow and they will come back in the end of the second half of ‘17.
And then in terms of taxes, yes you are right, actually we’ve got a number of tax credits that occurring forward in the moment in the case how we utilize those differed tax credits. But as we see recovery in the environment through the second half of this year, we are comfortable that those tax credits will get fully utilized going forward.
Lucas Herrmann
Okay, so Brian thanks very much.
Jessica Mitchell
And thanks Lucas. A question now from Brendan Warn of BMO.
Brendan Warn
Yeah, thanks Jess. So Brian most of my questions have been answered but just follow-up and you probably answered in saying oil projects starting ‘16 and ‘17 are on track, but just no specific comments on Thunder Horse, you can give us an update on those two projects please?
Brian Gilvary
Yeah, actually on track we are ahead of schedule but Thunder Horse is the south expansion I presumably talked about.
Brendan Warn
And water injection.
Brian Gilvary
And on those, right now we are - let me just come back on south expansion, right now the facilities progresses about nearly 50% complete just below 50% and fabrication for critical path manifold and the sled is ahead of plan. And on the water injection, last time we looked at it, it was ahead of plan in term of where we were but I’d have to come back to on the specifics of where we are in terms of developments of that.
Brendan Warn
Okay, thanks, I’ve level at there. Thanks for your time.
Jessica Mitchell
Thanks Brendan and we’ll follow-up with you on that. Thomas Adolff of Credit Suisse.
Thomas Adolff
Hi. Thanks for taking my questions.
I’ve got two on project execution please. Firstly if I take the IPA statistic and they basically said the industry has destroyed value versus initial expectations on 75% of all projects completed in the last decade on a price normalize basis, they also said in total the value loss relative to project planning assumption has been around 35%.
So I wondered how PB’s performance has been and versus the initial budget over the past ten years? That’s the first question.
And the second question, again on project execution and I am focusing here on current developments, I spent just over two weeks recently in Asia was lot of fun that some of the feedback around shipyards and sounds very encouraging versus you know kind of the messaging we get from corporate generally for the industry. So I wondered whether you see further risk on project delivery especially those project where you know some work has been done at some of your South Korean shipyards beyond Clair Ridge assuming the information flow from the bottom to the top works as they should.
And also regarding Shah Deniz Phase II, I understand and I might be wrong here one of your partners has struggled to secure some funding related to the pipeline, is that the case are you still comfortable, everything is in line was expectations? Thank you very much.
Brian Gilvary
Okay, it’s almost. So let me work in way through those three questions.
So the first one, I would say simply that in the later part of the last decade, our performance is significantly better than it was in the first part of the last decade in terms of project execution. And in terms of the stat that you quoted, we were probably as certainly on average as bad in terms of that the way you’ve laid stat out as anybody else in the sector.
We put in place in 2009 a centralize projects organization which really I think - we talked about this on previous calls, really got into action over those subsequent years, but particularly 2011 was the big year that that projects organization really got after the 15 big projects we talked about around the 10-point plan, the majority of which with the exception of one or two for different reasons we delivered on time, on budget. And right now I could layout for you every one of our projects where we are in terms of specific execution versus everything else that we layout.
And I think one of the things that you’ve heard Lamar talk about and Bernard in particular since that project organization here we saw a lot of that was really around how you front-end loading activity ahead of time in terms of planning and scheduling activity. So in terms of your specific question and in terms of where we are on the execution for existing projects, a lot better in the last five years than the previous five.
Then your next question, I’ll come to Shah Deniz Phase II that is probably the easiest one to take. Next, actually now you’re asking about Korean shipyards.
On the Korean shipyards, actually specifically this example you had in terms of Clair Ridge, last time we looked, we’ve got five, all five modules are on their way from Korean on route to the West of Shetland and we have no issues around that right now. But I do understand some of the constrains that are out there in terms of the shipyards and the acidity, certainly what we could see about 18 months ago was there was a lot of stacking of activity in terms of getting all the projects through that will be in lined up through some of those shipyards, but we don’t see any major problems right now around the existing projects.
And then in terms Shah Deniz Phase II that’s progressing really well right now in terms of where we are. If there are other partner issues there really question that you should ask those partners not ourselves, but so far Shah Deniz Phase II is progressing really well.
And to your exact question, we’re about 71% versus - completion versus 60% is what the plan I would say.
Thomas Adolff
Okay, thank you. And just a quick follow-up.
Brian Gilvary
Come up, Thomas you just had three question, so what you mean a follow-up.
Thomas Adolff
Okay, fair enough, fair enough, fair enough, thank you.
Brian Gilvary
No go ahead please. No, no please, now go ahead.
Thomas Adolff
You understand that the industry is working to get better at executing projects and front-end loading is a key component to that because you’ve highlighted. I wondered given that no one is taking any FIDs at the moment for various reasons, would it not be the perfect time to be really doing projects because you get the best teams, you get excess of all the best shipyards, et cetera, et cetera, is opposed to waiting until everyone comes back and then actually prices recover as well, I mean?
Brian Gilvary
Yeah, that’s a really good question. And actually on that respect, we’re not trying to catch the low here in terms of rates for activity, but there is no question I think the pools at Mad Dog Phase II is probably the best example of this, the pools that we did around in number of projects to go back and reengineer, re-scope, reschedule and re-contract some of the activity has led to yes the projects moving sideways but the economics and therefore the value to shareholders significantly being better but equally we don’t be sitting around waiting for the absolute low, low, low before we go FID.
So I think it’s a fair push to say that actually was sort of in that window right now Mad Dog Phase II is a good example of that.
Thomas Adolff
Okay, thank you very much.
Jessica Mitchell
Alright and we’ll have a question from Biraj Borkhataria of RBC.
Biraj Borkhataria
Hi. Thanks for taking my questions.
I had a couple if I may. One going back to the Lower 48, we’re seeing cost go down like Q-on-Q.
I was wondering if you could comment or talk about how that business is performing relative to the rest of your portfolio in terms of efficiency gains and productivity is up faster or slow in terms of those gains? And the second question would be on Oman, there were some reports over the last month of so about a potential gas pipeline between Iran and Oman to be built and I was wondering if you could talk about the potential implications for the Khazzan project, if there is an issue there?
Thanks.
Brian Gilvary
I think the last one is difficult to talk about until something I should get to announce, but there is no question if there is Khazzan is progressing really well, developments is going incredibly well and we now expect to drill. I think last summer we reviewed this will Bernard 85 few wells compared to the original scope that we had in place, so that would obviously be an opportunity but that’s not something I can comment on without having knowing the specifics of whether actually let’s go ahead in terms of the pipeline.
And then in terms of Lower 48, you will - first of all, again Bob and Lamar and Bernard have talked about this historically. Yeah, this is more of a manufacturing business, so it’s a little bit different to offshore facility and in a full offshore development that means you can take the rigs up much quicker, you can also bring those rigs back down again.
There is no question there that bringing Dave Lawler and his team and the reengineering of that business, the move get off the main West Nile complex, the restructuring of the people inside that business and the refocusing of the engineers back on the field developments has led to all of the improvements that you can see that we know publish each quarter in terms of the drilling costs coming down, the cost of production coming down. And so difficult to replicate versus I say deepwater type alternative but there is no question.
Actually Lower 48 creates for us huge advantage in other options that we look like in our onshore developments like Oman Khazzan potentially maybe around China Shale that we’ve announced recently. But that is an important part as an asset base for the company in terms of the technology that we develop inside that we deploy elsewhere in the world.
Biraj Borkhataria
That’s great, thanks.
Jessica Mitchell
Thanks Biraj. And we have a late entry and so last but certainly not least from Jason Kenney of Santander.
Jason Kenney
Hi Brian. Thanks for hanging on for this question.
Just looking some longer term energy semantics and you just mentioned China Shale there, I wonder if you could give us some insight on the scale of the price and the potential commitment from PB over the next few years and is it going to be game changing in the same way that U.S. saw a turnaround over a decade and its gas markets anytime soon?
And the second on global LNG, are you feeling the need to create demand a long term LNG, I am just wondering what happens to fundamentals over the next five, ten years in global LNG?
Brian Gilvary
Well, yeah, the last question is quite interesting one in terms of where this LNG go given the number of projects that we see coming on the backend of the decade. And certainly over between now and 2010, there is significant amount of LNG we can see coming on the market.
In terms of China, I can’t tell you a lot, I am afraid Jason, other than the fact, it’s 1,500 square kilometers, it’s in the Sichuan Basin. And it’s a great step forward in terms of our corporation and working with CMPC who will be the operator.
It ties back to an agreement we put in place back in October in London that’s Bob signed and covers also some of the possible opportunities even it’s a field retailing in China, exploration of oil and potentially LNG trading which definitely interested in. So I think it’s a - it was a great landmark deals that get done in terms of progressing forward.
I think it’s a little bit earlier this point sort of say what opportunities will flow off the back of that. In terms of LNG, we’ll see the first cargos of gas probably export out of the Lower 48 out of North American certainly next year.
We’ll see our own gas start to export in 2018. I think the whole gas portfolio in the rebalance of gas globally, I think you’ll continue to have the three zones around North America, the Far Eastern Europe whether there will be more connectivity as we see more LNG projects coming on.
I think you’ll see more LNG pricing into the Far East non-oil related which we see in certainly in more recent times. But there is no question there is be a lot of LNG available on the market.
We obviously can’t create demand that will be something much will be taken probably in the Far East and potentially in terms of power development if you look at the Lower 48 and the U.S. and you are seeing a lot of industry activity being built off the Lower 48 gas prices in North America.
And I would not be surprised to see more of that trend especially in terms of chemicals and manufacturing.
Jason Kenney
Yeah, it’s a big topic.
Brian Gilvary
Yeah, Jason, we can go on for long time, but I think you are now the final question.
Jason Kenney
Good, thanks very much.
Jessica Mitchell
Alright, thank you everybody. That is the end of our questions and I will just hand back to Brian to close the call.
Brian Gilvary
Well so first of all thank you for your patience. We’ve try cover all of the questions that you had today.
Just to summarize, safety and we talked about the safety reliability remains the number one priority that we have within the firm. We have demonstrated that I think continue momentum on costs and capital and repositioning the company to the lower oil prices that we see.
Even it remains a key priority and we have laid out for you how we believe we can balance it about to $50 to $55 next year. And we look forward to reengaging with you certainly at some point this year around an Upstream Investor Day and if not then our 2Q result where we’ll have our segment heads and Bob available for the call.
Well thank you for your patience and time.