Welcome to
the BP Presentation to the Financial Community Webcast and Conference Call. I now hand over to Jessica Mitchell, Head of Investor Relations. Hello and welcome to BP's Q1 2012 results webcast and conference call. I'm Jessica Mitchell, BP's Head of Investor Relations and joining me today is Brian Gavari, our Chief Financial Officer. Before we start, I'd like 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 all of you joining us today on the call. I'd like to start with an overview of Q1 financial performance. Our Q1 underlying replacement cost profit after interest and tax was $4,800,000,000 down 13% on the same period a year ago and 4% lower than the Q4 of 2011. First quarter operating cash flow was $3,400,000,000 including $1,200,000,000 of post tax Gulf of Mexico oil spill expenses. 1st quarter operating cash flow was impacted by higher working capital, including the effect of higher oil prices and inventory builds.
Group underlying replacement cost profit for the quarter was adversely impacted by $540,000,000 in respect of the consolidation adjustment for unrealized profit in inventory. As a reminder, this reflects unrealized profit in our downstream inventories related to our upstream equity barrels, which will be realized in future quarters. Accounting rules require this to be eliminated from group earnings, while this equity crude is held in our refinery inventories. In this quarter, the combined effects of high crude oil prices and a higher level of crude oil held in inventory has significantly increased the charge compared to the previous quarter. The effective tax rate for the Q1 was 33% compared to 37% in the Q1 of 2011.
Turning to highlights at a segment level. In Upstream, the underlying first quarter replacement cost profit before interest and tax was $6,300,000,000 compared with $6,700,000,000 a year ago and $5,900,000,000 in the 4th quarter. The result versus a year ago reflects a stronger environment more than offset by 3 factors. Firstly, higher costs, which include the impact of increased activity levels, sector inflation and higher depreciation, depletion and amortization. Secondly, loss of revenues associated with disposals and thirdly, lower production in some high margin areas.
Compared to the Q4 of last year, the result improved due to the better environment, a higher contribution from gas marketing and trading and lower costs. Liquids realizations increased 15% year on year in line with market grades, while gas realizations improved slightly over the same period with lower U. S. Gas prices offset by stronger gas realizations in other regions. Reported production excluding TNKBP was 2,450,000 barrels of oil equivalent per day, 6% lower than the Q1 of 2011, mainly due to divestments and production decline in the Gulf of Mexico, reflecting lower drilling activity in 20 10 2011.
This was partly offset by restoration production at Greater Plutonia in Angola. Underlying volumes excluding TNKBP and after adjusting for investments and entitlement effects in our production sharing agreements increased slightly year on year. Looking ahead, we expect 2nd quarter reported production to be lower and cost to be higher as a result of normal seasonal turnaround activity concentrated on high margin production in the Gulf of Mexico at Atlantis, Mad Dog and Holstein. We continue to expect full year underlying production in 2012 to be broadly flat with 2011 excluding TNKBP. Reported production in 2012 is expected to be lower than 2011 due to divestments which we currently estimate 120,000 barrels of oil equivalent per day.
The actual outcome will depend on the exact timing of divestments, OPEC quotas and the impact of the oil price on production sharing agreements. Turning to TNKBP. Our share of TNKBP underlying net income was $1,200,000,000 in the first quarter, which was up 3% versus a year ago. Our share of TNKBP production in the Q1 at 1,020,000 barrels of oil equivalent per day was 4% higher than the same period last year. And we received a cash dividend of $690,000,000 in the Q1.
Now turning to Downstream. For the Q1, the Downstream segment reported underlying replacement cost profit before interest and tax of $900,000,000 compared with $2,200,000,000 a year ago and $750,000,000 in the Q4 of 2011. All three downstream businesses delivered a higher underlying replacement cost profit than in the Q4. In our fuels business, we have had a challenging quarter delivering underlying replacement cost profit of around $500,000,000 compared with $1,300,000,000 in the same period last year in a broadly similar refining environment. We continue to capture the benefit of accessing WTI linked crudes in the U.
S. Midwest through good refining availability. This benefit was however more than offset by weak performance in supply and trading compared to the strong Q1 of 2011, unfavorable local crude differentials in Europe and a difficult fuels marketing environment due to weaker demand. In addition, our Cherry Point refinery has been under repair following the incident in February. Looking ahead to the Q2, we expect refining margins to continue to improve in line with seasonal trends and fuels volumes to remain subdued.
We expect that the Cherry Point refinery will resume full operations during May having completed both repairs and the scheduled 2nd quarter turnaround. In lubricants, underlying replacement cost profit was around $300,000,000 reflecting robust performance despite weak demand in some OECD markets and continued high base oil prices. In petrochemicals, underlying replacement cost profit was around $100,000,000 for the quarter, some $400,000,000 below the same period last year, reflecting a significantly weaker margin environment than the record levels seen in the previous year. Despite this, volumes have improved compared with the low levels in the Q4 as a result of stronger demand and higher availability. We expect the petrochemicals margin environment to remain challenging.
In other business and corporate, we reported a pretax underlying replacement cost charge before interest and tax of $440,000,000 for the Q1, an increase of $140,000,000 versus the charge a year ago, primarily reflecting higher corporate and functional costs and the loss of income from the aluminum business, which was sold in Q3 of 2011. Guidance for 2012 remains unchanged from that given in February with underlying quarterly charges volatile and averaging around $500,000,000 each quarter. The effective tax rate for the Q1 was 33% compared to 37% in the Q1 of 2011, which was impacted by a one off deferred tax adjustment of some $700,000,000 arising from the changes to the U. K. Taxation of North Sea production.
Guidance for the full year effective tax rate remains in the range of 34% to 36%. Next, I would like to provide you with an update on the costs and provisions associated with the Gulf of Mexico oil spill. In the Q1, an adjustment to provisions offset the usual quarterly expenses of the Gulf Coast Restoration Organization. The total cumulative net charge taken for the incident to date remains at $37,200,000,000 Under a settlement agreement finalized in late 2011, Cameron paid BP $250,000,000 in January, which was subsequently paid into the $20,000,000,000 trust fund. Pre tax BP cash outflow relating to the oil spill costs and the trust fund for the quarter was $1,700,000,000 As we indicated in previous quarters, we continue to believe that BP was not grossly negligent and we have taken the charge against income on that basis.
Turning to our divestment program. In the Q1, we completed the sale of our Kansas gas assets for $1,200,000,000 and announced an agreement to sell our Southern North Sea gas interests. In 2012, we will continue to focus our portfolio through divestments with a total of $38,000,000,000 expected between 2010 the end of next year. Announced divestments now stand at around $23,000,000,000 since the start of 2010. This comprises completed divestments totaling $20,800,000,000 and agreements in place for some further $2,000,000,000 of sales at the end of the quarter, including the sale of our natural gas liquids business in Canada, which completed on the 1st April.
Progress is being made with the divestments of our previously announced refining and associated marketing assets in the U. S. And we are aiming to announce both of these deals by the end of this year. We are also marketing for sale certain non strategic assets in the Gulf of Mexico, including our interests in the Marlin, Hall Mountain, Holstein, Ram Powell and Diana Hoover fields. Moving now to cash flow.
This slide compares our sources and uses of cash in the Q1 of 2011 and 2012. Operating cash flow was $3,400,000,000 in the Q1 of 2012 compared to $2,400,000,000 a year ago. After excluding Gulf of Mexico oil spill related expenditures of $1,200,000,000 underlying operating cash flow in the quarter was $4,600,000,000 We received $1,300,000,000 of divestment proceeds during the Q1. Our organic capital expenditure in the Q1 was $5,600,000,000 We continue to expect full year spend to be around $22,000,000,000 Total cash held on deposit at the end of the quarter was $14,100,000,000 1st quarter operating cash flow reflects around $3,000,000,000 net working capital build, including the effects of higher oil prices and inventory builds. At the end of the first quarter, net debt was $31,200,000,000 resulting in a gearing of 20.7%.
As noted in February, whilst uncertainties remain, we are targeting gearing in the bottom half of the 10% to 20% range over time. We remain confident that net debt and gearing will fall through the second half of the year and into 2013 as we see cash inflows and divestments, new higher margin projects coming on stream and the end of payments into the trust. I'd now like to update you on progress in the U. S. Active shoreline patrolling and maintenance continues across the affected areas of the Gulf Coast.
We are progressing projects for early restoration at the natural habitats along the Gulf under our initial $1,000,000,000 commitment for natural resource damages assessment. The first eight of these projects will soon begin along the Gulf Coast, following the finalization of the Phase 1 early restoration plan by the trustees. By the end of the Q1, we have paid a total of $8,300,000,000 to meet individual and business claims and government payments. Over $16,600,000,000 has been paid into the trust fund at the end of the Q1. On 18th April this year, BP announced that it reached definitive and fully documented agreements with the plaintiff steering committee to resolve the substantial majority of eligible private economic loss and medical claims stemming from the Deepwater Horizon incident.
The settlement agreements allow for new court supervised claims process to be set in place within 30 days of preliminary court approval, which will operate under the framework agreed as part of the settlement. In the meantime, a transitional claims process is in operation. BP estimates that the cost of the settlement expected to be paid from the $20,000,000,000 trust would be approximately $7,800,000,000 This is not expected to result in any increase to the $37,200,000,000 charge taken in respect of the Gulf of Mexico oil spill to the end of the Q1. A new schedule is expected to be set by the court for remaining proceedings under MDL-two thousand one hundred and seventy nine. Before closing, I'd like to say a few words about our strategic progress.
In October, we laid out our road map for growing value, a clear 10 point plan, 5 things you can expect and 5 things you can measure. As a brief reminder, we said we would focus relentlessly on safety, play to our strengths and be stronger, more focused, simpler and more standardized. We promise to create more visibility and transparency to value. In terms of measures, we said you will see continuing active portfolio management. We aim to divest $38,000,000,000 of assets by the end of 2013.
We said you can expect to see 15 new projects coming on stream over the next 3 years with operating cash margins around double the 2011 upstream average by 2014 and that's at $100 a barrel and excluding TNKBP. And you can expect us to generate an increase of around 50% in additional operating cash flow by 2014 compared to 2011, approximately half from the ending of Gulf of Mexico Trust Fund payments and around half from operations. We plan to use around half that extra cash for reinvestments and half for other purposes including shareholder distributions. And all of this will be underpinned by a strong balance sheet. We remain committed to a progressive dividend policy going forward with future increases contingent upon improved cash flow delivery balanced by the need to retain financial flexibility and our continuing obligations to the trust fund.
So let me update you on progress in the Q1. Consistent with our increased focus on exploration, BP has added significantly to its interests in promising South Atlantic Equatorial Margin Plays during the quarter with the announcement of farming to 4 exploration concessions with Petrobras in Brazil, deepening of our interests in offshore Namibia and being awarded 3 new blocks in offshore Uruguay. BP also gained access to the promising potentially liquids rich shale acreage in the Utica Shale Formations in Ohio. We continue to actively manage our portfolio. As I noted earlier, we have announced $23,000,000,000 of divestments to date against the $38,000,000,000 we aim to divest by the end of 2013.
I have mentioned the divestments announced this quarter. And as I said earlier, we continue to progress our plans to divest the 2 U. S. Refineries. In February, we said 2012 would be a year of milestones and we are seeing progress.
With over $16,000,000,000 already paid into the trust fund, we expect payments into the trust to end in the Q4 this year. In the Gulf of Mexico, 5 rigs are operational and we expect to have 8 operating before the end of the year. Of those 5 rigs, 2 are now undertaking production activity, 2 on appraisal activity and 1 is completing plugging and abandonment work. Work continues on our major projects and we are on track to start up 6 of them this year. In the Q2, expect to see the start up of Clocos Mavagola in deepwater Angola and Galapagos in the Gulf of Mexico.
You have also seen the increased visibility of our downstream business and the separate reporting of TNKBP the stock exchange announcement we released this morning. A separate rule of thumb for upstream and TNKBP is now available on our website. Of course, 1 quarter provides only a very narrow window to gauge progress. As we look towards the second half and into 2013, we expect to see this increasing momentum reflected in operating cash flow from the start of new upstream projects with on average higher operating cash margins. The strong year to date oil price environment continued to feed operating cash flow into the second half of the year without the associated step up in working capital, and as we make the final payments into the trust fund in the Q4.
Our intention remains to generate sufficient cash to both invest to build our portfolio and grow distributions over time as the circumstances of the firm improve. That concludes my remarks. Jess and I will now be happy to take your questions.
So the first question comes from Thipan Jockey Lindgren of Nomura. Go ahead, Thipan.
Jessica, hi, Brian. Three questions, please. Firstly, just in the Downstream, thank you very much for the increased visibility there. I was just wondering though, the rule of thumb as you mentioned does break down a little bit in the fuels business. I was wondering if you could talk more explicitly in terms of the delta versus Q1 last year for Cherry Point, the crude differentials in Europe and also supply and trading.
The second question relates to the upstream. Could you just talk a little bit about cost evolution in E and P? I've looked at the PLAS-sixty nine data. I was just wondering how you see cost inflation relative to Q1 last year, the impact of lower volumes and also in particular sort of high integrity costs? And then lastly, just coming back to Macondo, your discussions with the DOJ.
In February, Bob Dudley talked about BP being ready to settle at fair and reasonable terms. Is that still the case? And are you hopeful you can draw a line perhaps with the DOJ before year end? Thank you.
Thanks, Thi Pan. Let me take the first question on Downstream. 1Q in Downstream, which is why the rules of thumb won't work, is the most the biggest and largest component is the delta on the supply and trading result. We had a very strong quarter in the Q1 of last year and we had a very weak quarter in the Q1 of this year. So that's the biggest component in the delta between the two quarters.
The next biggest component is the petrochemical result, which I think you can see from the ARCOP results that we've published. And then Cherry Point was a circa over $100,000,000 effect if you look at the 1Q versus 1Q. So biggest effect on fuels was trading. You also see the petchem effects in the overall downstream result. On the upstream in terms of cost inflation and what we're seeing, The first priority we have is around obviously delivering safe compliance and reliable operations.
Over the last 5 years, if you look at the sector inflation, we've seen it round about 10% to 15% growth in sector inflation. And if you then look at BP competitively, we remain in the middle of the pack in terms of the industry. The sector inflation is continuing to run at roundabout5% to 10% per annum both for CapEx and operating costs across a number of different categories, which we try to mitigate through our supply chain procurement activities. We've seen increased investments in the upstream activity. A lot of the cost inflation we're seeing is around activity driven.
And there are 3 key areas where we're building capabilities both in engineering, technical capabilities, safety and operational risk. And over the last year, we've hired over 2,000 engineers in 2011. So we are seeing some inflation costs. A lot of that is driven by activity. And then on DOJ, really nothing to update today.
We are continuing to cooperate with the DOJ and we continue to hold the stance that we are prepared to settle all outstanding claims to the Department of Justice for only unreasonable terms. Thanks, Thipan.
Thank you.
The next question comes from Jason Kenney of Santander.
Hi, there and thanks for taking my question. I'm just trying to pinpoint a bit of the timing for cash flow delivery over the period of 2014. I know 1 quarter is only a snapshot. It looks like you've got €3,400,000,000 of reported cash. You've got the U.
S. Com €1,200,000,000 billion. The working capital movement is quite large. So EUR 7,600,000,000 has generated cash. This could imply nearly EUR 30,000,000,000 annually.
Is this a kind of run rate we could anticipate this year? Or is it too early to look for that kind of upside versus 2011 under a common environment? And bearing in mind, obviously, divestments still to come and new downstream support as well. But maybe just a bit of insight on how you see cash progressing over the next few months?
Thanks, Jason. It'd be premature to sort of book those sort of numbers at this point in the process. We typically see a build in stocks in the Q1 of circa 20,000,000 barrels. We saw the same effect in the Q1 of last year. So if you look at the delta year on year, you'll see that there is some underlying improvement coming through.
But we do typically build stocks through the Q1. Couple that with the higher oil price that we've seen come through. The overall effect is a net $3,000,000,000 build in working capital. That will unwind as the year progresses as the stocks restart to build ahead for the gasoline season as that throughput starts to work its way through the system. You'll see it correct.
So it's better to look at the operating cash over a typical 4 quarter average in terms of the trajectory. We put the targets out in 2014 at $100 a barrel. So it's sort of a clean comparison $11 out to $14 We're still confident that those targets are underpinned. And those targets will come from the big new projects that we've got coming on stream 6 projects this year 2 this quarter and 15 over out to 2014. That will be the big driver of the cash flow.
And of course also the Whiting Refinery which is well progressed over 60% completed will be a big piece of the second half of twenty thirteen. So I think it'd be premature to read too much into this quarter's operating cash flow. But the major impact here was actually building working capital. Okay. Thanks, Jason.
The next question comes from Irene Himona at Soc Gen. Go ahead, Irene.
Good afternoon, Brian. One question on gearing where you it has remained at the top of your targeted 10% to 10% range despite oil at $120 You are indicating that it will decline over time with new upstream production and so on. What needs to happen to the balance sheet before investors can anticipate any further improvement in the dividend payout please? Thank you.
So the financial frame we described to you back in February and we sort of segued in October of last year was that we were looking to get the gearing down to the 10% to 15% range. I think that's a prudent thing to do given the current economic climate and we've said we'll do that over time. But certainly by 2014, it should be in the bottom half of that new range of 10% to 20%. I think it's important that we do that because it shows up the balance sheet given the number of uncertainties out there both in terms of the economic outlook, but also in terms of the U. S.
Situation specific situation over the U. S. We've highlighted again in February a progressive dividend policy as the underlying performance of the firm comes through. The new projects come on stream and the Board will come back and revisit this each quarter, but typically on an annual basis. So we signaled an increase in dividend back in February of EUR0.08 which was a signal of confidence in the underlying cash flow coming through, but we need to balance that with the various other uncertainties that we have out there.
Thank you.
Right. Moving now to the U. S. Doug Terreson from ISI. Go ahead Doug.
Good morning everybody.
Good morning, Doug.
Brian, my question has to do with the consolidation adjustment, which you mentioned a few minutes ago. I mean, it lowered your profits by about 5% in Q1 just like it did last year, but it almost fully reversed in the next quarter. And so I wanted to see if there were any non timing related factors that might preclude this item from gravitating towards 0 on an annual basis as it has during most of the past 5 years, which I think you implied? And if anything, is there anything usual about this item in the current period that might prevent that from happening?
So Doug, I mean, the thing that's happened this quarter is if the increase in the oil price itself, so the absolute flat price has increased and an increase in number of equity barrels we're holding in our refining system. As we proceed with the disposals of Texas City and Carson that will take a big chunk of those equity barrels out of our system. And so therefore, I think this will become less volatile and dampened over time. But it just simply reflects that we've chosen to put an equity barrel into our refining system and therefore we're not allowed to book those profits for that barrels being run through the refinery. If they've been 3rd party barrels clearly they would have been booked as profits.
Sure. Okay. And also second on the Gulf of Mexico liability, it appears that you guys are following a kind of a parallel track in selling the claims with the governments meaning while you talked about your negotiations with the DOJ a minute ago, you've also settled with several of the more important municipalities on the Gulf Coast during the past several months too. So my question is whether or not this is an accurate description of the approach you guys are taking? And whether it is or not, is it possible that these 3 categories will be settled separately or necessarily at the same time?
Can you just comment on that Brian?
Yes, sure. Look, I mean, I think as I said on the call that we had with Rupert Bondi when we had the original PSC settlement. What that settlement did was take the vast number of personal and business claims out of the equation, which is what is probably one of the most complex class action lawsuits that the U. S. Would have ever had to oversee or view.
And that's we're still waiting for the for Judge Barbier to pine on the specifics of that settlement. But it did take away the vast amount of outstanding claims. That leaves the issue of NRDA Clean Water Act DOJ and the separate settlements with the absolute the state claims themselves. We would like to get a global settlement around all of those things. But we will again as Bob reiterated back in February only if we can do so on fair and reasonable terms.
Okay. Okay. Thanks a lot.
Thanks, Doug. Right. Back to the U. K. Could we have Peter Hutton from RBC?
Morning. Hi. Yes, just can I just ask if there's any more clarity around the movements you described in getting from the absolute decline in production from 6% to you say that excluding divestments and price effects, it would have been marginally positive? Is it possible to give a little bit more specificity on how much was divestments, how much was price effects? And also, how much is production coming on in India?
I think that would be particularly useful. The second is, I think, is a little bit of a follow-up on a question that was asked by Tipam in terms of the cost progression. And I see that costs were up sort of up 18% year on year. Is it possible to give a feel as to how much of that is underlying sort of the asset integrity? And because you're still not at full kind of activity levels that you would want to be in the U.
S. At least in terms of being reflected in volume, how much you think there is to go at on that kind of increase?
So Peter on the first question, the Delta 1Q1Q is 113,000 barrels a day is disposals. On India specifically, the new production coming on from India in the Q1 is 68,000 barrels a day. There's some offsets of that in terms of decline elsewhere in the portfolio. But overall, if you take out PSAs, you take out disposal effects, slightly increased 1Q, 1Q and it's a slight increase 4Q, 1Q. So hopefully that answers the production question.
It will indeed. Thank you.
And then on the second question around the ramp up, actually we're back to we will be by the end of this year back to higher levels of activity in the Gulf of Mexico than we have pre the deepwater horizon incident. So we're back to 8 rigs, which will be the most number of rigs we'll ever run-in the Gulf of Mexico and we've got 5 active today. So we are actually ramping up activity. We are hiring people. Projects most of the projects are on track for this year.
So a lot of the activity and the costs are coming through and that's what we're seeing some inflation. Cash costs actually in terms of the cash costs we monitor the Q1 they're higher than the Q1 last year, but they're actually below the Q4 and Q3 of last year.
Okay.
The next question comes from Martin Ratz from Morgan Stanley. Go ahead, Martin. Are you there, Martin? Okay. We'll switch back to the U.
S. Then. Robert Kessler at Tudor Pickering. Go ahead, Robert.
Hi, good afternoon. Brian, I might be probably splitting hairs a little bit on semantics, but just on the new KBP reporting, which I would say is not so new, but more of a promotion from the footnotes to the summary financials. In your press release, you highlighted that the new reporting reflects the way your investment in TNKBP is now managed implying it's somewhat different than before. I always thought of it as a separate entity managed on its own, one that you get dividends from. What exactly is there anything that I should be reading between the lines there in terms of maybe divesting your interest more quickly than you otherwise would or something else there?
No, Robert actually it's a good point. There isn't that much new disclosure here. But the reason why we shouldn't read anything into why we split it out this way. The simple reason we've broke it out is so you can get line of sight of the underlying upstream business that excludes TNKBP. If you remember the 10 point plan, we laid out that we will be bringing on these extra projects which will be double the margin of the existing portfolio.
You wouldn't have been able to see that if we continue to consolidate in here. So what we're trying to give you a sense of is something you can measure in terms of the improvement of the upstream as it comes as
these new projects
come on stream with double the margin of the existing footprint excluding T and KBP. So this is really just to give you line of sight on the promises that we laid out there in February October of last year.
That makes sense. I appreciate the external accountability on the ex TNKBP assets. So thanks for that.
Thank you.
Right. Next question from Houtan Yazari of Bank of America. Please go ahead, Houtan.
Hi, there. I just wanted to refer to your disposals program. Of course, you've indicated that you're looking to put 2 of the U. S. Refineries on the block.
Given the increasing demands for working capital coming from the downstream business, I wanted to see how much has the divestment program started veering towards more downstream disposals, whether it be the marketing assets or chemicals assets or anything that does have quite a big draw on your working capital? Thank you.
Yes. So we announced the Texas City Carson sales at the beginning of last year or maybe the end of 2010. I can't remember precisely, but it was certainly in the last 18 months we announced the intent to sell those refineries. That was purely driven by strategy. Texas City was not particularly connected to other parts of the downstream.
And the Carson Refinery and Southern Value Chain is a huge gasoline machine and we don't believe that's an asset we would have invested in. So the assets we're looking at in terms of disposals are completely consistent with what we've said around the overall program back in 2010. Where an asset is non strategic or we don't intend to invest in it and others would invest in it then their assets actually fall within this category of the program. We are not planning any further asset disposals in terms of the downstream at this point in time. We're very happy with the chemical business that we have over time, which has delivered good results historically currently challenged on the margin side.
But now we're very comfortable with the position that we'll have post the exit of Carson, Texas City with the Whiting refinery and its access to cheap heavy crude oil and the Carson and the Cherry Point refinery which is a bespoke boutique refinery in terms of diesel production. So no plans to go beyond where we are today.
Okay. Thanks.
Next question comes from Paul Spedding at HSBC. Go ahead Paul.
Afternoon. Just a quick question on the consolidation adjustment. I mean, as you mentioned, if your upstream division chose to deal with 3rd parties rather than your own refining basis that line wouldn't be there. Isn't it time to start considering that as a special item in much the same way you eventually decided to treat the long term forward sales of product and gas in your upstream division as a special item?
Yes. Paul, I think they're actually quite different. At the end of the day accounting rules dictate that these are unrealized profits. We can't as a group as PLC we can't book those profits until those volumes have actually moved outside the system. We could choose to just put 3rd party barrels into our refineries, but then that would not be commercially the right thing to do.
We take the decisions whether we move equity or 3rd party in based on availability of the barrels and secondly in terms of commercial optimization. So I think it's the right thing to do that we commercially optimize And I will leave it to market to decide whether there are profits that should be accounted for or not in terms of as you if you try to look through the results, the underlying results, clearly if they were third party barrels they would have been booked as profits.
You did use a similar argument to avoid doing something similar with your derivatives, but you eventually decided that it was probably more sensible to treat them as specials?
I think you're talking about the embedded derivatives, Paul. Yes, that's something very different. That issue is more around where if you have long term derivatives in place around gas contract you're not allowed to book those profits until those the gas the physical gas has actually moved. That's a very different accounting treatment.
Okay. Could we move to Blake Fernandez from Howard Weil in the U. S?
Good afternoon, Brian. Thanks for taking the question. I actually had 2 for you. For one, I hate to go back on the cost commentary, but if I look at organic CapEx in the quarter, it was about $5,600,000,000 and extrapolating that across the year, you're at roughly your guidance of $22,000,000,000 Typically, obviously, you would see a little bit of upward pressure for the balance of the year. So I'm just trying to see is that $22,000,000,000 still a good number?
Or do you think there's upward momentum on that? And then secondly, in the Gulf of Mexico, you've identified some assets being marketed. I'm just trying to see if there's a common denominator between those. In other words, is it a working interest or a field size or a play type? Just any kind of strategic shift in your Gulf of Mexico strategy?
Thanks.
Thanks for that. So in terms of CapEx, the $22,000,000,000 is still a good number. Historically, certainly, we've struggled to spend the numbers that we put out there. And there's been underspend certainly last year as we would took a little bit longer to get back to work from where we expected to. But the 22% is pretty robust and we don't see any upward pressure on that today.
So I think that's still a good number for the year. And then in terms of Gulf of Mexico, it comes back to focus in terms of where we want to focus our activity. And the focus will be around the 4 big hubs around Thunder Horse, Atlantis, Mad Dog and Nikita. So that's so if you look at point forward the assets we put up for sale are actually all outside of that those 4 main hubs and they were the 4 main hubs for us going forward. And of course, Galapagos is one of the Gulf of Mexico assets as it's a tie back to Nikhika comes on in the Q2 this year.
Thank you.
Right. The next question comes from John Rigby in the U. K. With UBS.
Yeah. Hi, Brian. Three questions quickly. Can I just again go back to costs in the upstream and clarify what you said potentially? In when Texas City took place, the next couple of years after that, there was a lot of integrity costs that went into your downstream business that then came off again once you were satisfied with them.
But you seem to be saying now that the costs in the upstream are largely or the increase in unit costs are largely due to lower volumes and that any improvement will be a rise in volumes in the second half of the year. Is that correct? Or are there some costs that actually will come off physically come off? The second question is on the Macondo liability. The headroom that you disclosed appears to be declining quite significantly.
And I wondered whether there was a move to just look at the methodology behind the accrual that you've put in the balance sheet of BP because that headroom is getting quite a lot smaller. And just a clarification on the distribution. I noticed you didn't say the words distribution not dividend. Does that imply that you will look very carefully at share buybacks as well as dividends once you're free to do so? Thanks.
Thanks, John. So first on the costs. There are costs that will be layered in and will still be there. So the safety and operational risk investment we've put in place, the investments in hiring new engineers all those costs will be laid in and they'll be with us going forward. Where you will see costs coming off is where we get more efficient around execution front end loading of the activity and actually delivering on the projects that we've laid out with the new central organization we have around developments under Bernard Looney.
So as they drive more front end loading, make sure that the right activity, planning of the well activity, effective procurements and executing efficiently that will then drive those underlying costs down. On headroom, you're right. The headroom is if that's the word you'd like to use, but effectively the amount inside the $20,000,000,000 provision for the trust fund that we have not yet allocated in terms of being able to find. There's been no change in methodology in terms of how we've assessed this at the end of 1Q. We'll do another analysis at the end of 3Q.
The reduction in headroom is effectively from what was 5.5 to 3.4 which was the PSCM settlement which is around additional activity that was withdrawn into the settlement. The reduction now from 3.4 headroom to 2.9 is made up of $200,000,000 of claims through January February, which have been caught through the quarter. A transfer of the provision around administration, we'd held the administration of the fund was actually held outside the fund inside the BP charge. We've now moved that as part of the settlement inside the fund. So there's a movement within the charge itself.
So that takes away $200,000,000 of headroom. And then we allocated I think in the SEA an additional $65,000,000 of NRDA charges that came through this quarter. So you're right John it's now reduced to $2,900,000,000 We'll reassess the overall charging provision probably in the Q3. And then your third question?
Distributions.
Distributions. Yes, we've used the word distribution back in February. We signaled the dividend increase back in February. And I think we signaled then until we have certainty in terms of what's happening in the United States, we would not consider buybacks at this time. But it is something which is in the armory once we get closure and settlement going forward.
Okay. Cool. Thank you.
Right. We'll take the next question from Jason Gammel of Macquarie.
Thank you. I had a few questions around the Gulf of Mexico, if I could please. First of all, the appraisal activity that you currently have ongoing, can you confirm if there is any appraisal going on around the Qiskita area? And how many appraisal wells you would expect to complete around Qiskita and Teiber this year? 2nd, with the ramping drilling activity, do you expect to complete any exploration wells this year?
And if so, could you talk about which those would be? And then finally, the assets that you've identified for sale in the Gulf of Mexico, could you make some commentary around the level of production that they contributed in 1Q or perhaps last year just to get the scope for what those assets are currently providing the portfolio?
Thank you. So the first answer to the first question on Cascadia, yes, we are doing appraisal work this year. I don't know precisely how many wells, but we can come back to you on that. But we do have an appraisal well on Cascadia this year. We will be doing an exploration well around Gila this year.
And in terms of the assets which we've now put up for sale in terms of the comp package that amounts to for in 2011 was 55,000 barrels a day production.
And Brian if I could please would you be able to talk about the Q1 contribution provided by Atlantis and Mad Dog to get an idea of what 2Q and 3 quarter effects and maintenance will be?
I will have to come back to you on that specific question. So we'll follow-up with that after the call if that's okay.
That's great. Thank you.
Right. The next question is from Ian Read at Jefferies.
Thanks Jessica. Hi Brian. I wonder if you could give us a quick update on what's going on in India. You're supposed to be putting in a revised development plan together with the Alliance obviously for the redevelopment of those assets. And so far we haven't seen that.
Can you just tell us what the time line is and what the issues are? And secondly, you talked about Gulf of Mexico activity. I wonder if you can just update us on what your key wells are going to be outside of the Gulf of Mexico this year?
Thank you. So if I turn to India first. The rationale for the India investment remains sound. It's an upstream joint venture accessing existing production and access to exploration potential with additional components of a downstream gas marketing joint venture in what is one of the fastest growing markets in the world, which also has a huge amount of upside in terms of market price and market price deregulation. So that's a sort of background backdrop to what the logic behind the Reliance JV and that from our perspective remains sound.
Performance of KGD 6, we were aware of the issue ahead of the deal being completed. And we'd expect production to grow over the medium term by developing existing multi TCF discovered resource blocks KGD-six and NEC-twenty five. The KGD-six satellite development plan approval was approved by the government in January 2012. So we are still comfortable with the India investment. I think it's sound going forward and you'll see more as the quarters roll on.
On the Wells question, we have wells in several key geographies we're looking at this year Brazil, Angola and India, but we don't tend to disclose the specifics of each one of those wells, so that's okay.
Just to come back on the Indian question, what sort of CapEx are we talking about in terms of the satellite development plan?
We haven't yet made that public at this stage. So I think it'd be premature to do that here today.
Okay. Thanks for your help.
Thank you.
Right. Could we take the next question from Pavel Molchanov at Raymond James?
Yes. Thanks very much. Two quick ones about Argentina, if I may. Given your ownership in PAE, I'm curious as to your thoughts about the recent developments in the country.
So on PAE, I mean, firstly, I presume the question is around the nationalization of YPF. Certainly. So I assume that's the sort of backdrop to the question. So BP as you'll be aware has a 60% stake in Pan American Energy. Pan American Energy is a United States registered company with independent management.
It's ultimately controlled by BP and Britas. We have got a long track record of investing in Argentina. We have been historically aligned with Argentina's interest through investment in growth delivery. PAE has continuously invested above its profit increasing investments over time. And we've honored all of our commitments made to the regulatory agencies and government.
Continuous reinvestment has delivered production growth. It's one of the best performing assets that they have in Argentina and a very healthy reserve replacement ratio. Cash outflows from Argentina to the head office are substantially lower than the profits particularly in the last 5 years And it stands out as a company versus the competition on growth delivery. So we're very comfortable with the investment and we're very comfortable with our position inside Argentina. I'll just reiterate this is a United States registered company.
Okay. And any update on drilling activity in the Vaca Muerta?
Yes. We have plans let me just come back to that question. We do have plans for 5 wells. Yes, 5 wells this year in Argentina.
Okay. And you're not changing any investment plans in Argentina based on the YPF development?
No. We are continuing to proceed with the plans that we have in place inside PAE.
Okay. Very good. Thanks.
Good. Could we take the next question from Lucy Haskins at Barcap?
Good afternoon, Brian, Jeff. Perhaps just a follow on question on Pan American first. I think last year, because the asset was held for divestment, there wasn't actually a dividend remitted. What expectations do you have for dividends moving forward from that business? And the second question was I understand Judge Barbier has convened a meeting on May 3, And I just wondered what your expectations were around that meeting?
Thanks, Lucy. In terms of the first question around dividends, we wouldn't normally make those public at this stage and that's really a matter for the oversight, the management team and committee they put in place to oversee that specific activity. And then in terms of Judge Barnaby, yes, there is going to be a meeting on May 3 in his chambers, which will determine certainly seek input on what the future schedule for the trial will look like.
And could I just ask what I mean, I think you're hopeful that the trial would not be rescheduled until you've got final approval for the PSC settlement. Do you understand where the other parties are positioned to present?
So the way things have stood up right now is we've requested both jointly with the PSC that the trial be deferred off to a date beyond the furnace airing which is scheduled for November this year. I can't comment on where the other parties are.
Thank you.
Okay. We'll now go to Oswald Clint at Sandler Bernstein. Go ahead, Oswald.
Yes. Thank you very much. Just back on T and K. I just want to clarify was there any benefit coming through from the sort of tax changes that were enacted in Russia, the 60, 66 in the TNKB business? And also just sort of the outlook for production for that business through the rest of 2012?
And then the second question was really back on the Utica Shale. If you could give us some indication on what drilling plans you have on that for this year. I know some a lot of the information was confidential, but also what scale of or what any sort of CapEx number or potential CapEx that this project could draw if deemed successful? Thank you.
So on the first question, yes, there would have been a benefit in the 4Q results for TNKBP around the new 6066 tax regime that was brought in. So there's a small benefit in their numbers. Effectively from our perspective what flows its dividend and we received a dividend in the Q1 of excess of $600,000,000 I think it's around $680,000,000 or $670,000,000 So really yes, there's a benefit for TNKBP internally, but really what we focus on is the cash dividend stream that comes out of TNKBP. On the second question could you just repeat the second question for me? Sorry.
Yes. It's on the Utica Shale. And I know you talked about understanding the geology of it better through 2012. Just an indication of how many wells you might be drilling or planning? And ultimately, what size of an investment is this to you?
We haven't shared any of that with the market at this stage. We're still in the early phases of having just acquired the acreage. It is a 300,000 square kilometer location northeast of Ohio Valley and we do believe it's liquids rich, But it's premature at this stage to actually lay out any plans that we have around that specific asset.
Okay. Thank you.
All right. We'll take now a question from the web from Ian Armstrong of Bruin Dolphin. Can you break down the production contribution of the Gulf of Mexico assets added to the disposal program? So the assets that we're adding to the disposal program from the Gulf of Mexico should be round and about 50,000 barrels a day. But of course, obviously, one needs to take account of decline in assets over time as well.
We will update you in time as these transactions take place. The next question will come from Kim Fustier from Credit Suisse.
Yes, hi, good afternoon. I had two questions, if I could. My first question is on production growth for this year. You've highlighted that 2 of your 6 project startups this year are on track, Closhaft and Galapagos. Could you also maybe comment briefly on SCARF and Angola LNG, both of which have been delayed slightly, as I understand.
Was there any kind of contingency in your initial guidance 3 months ago? And what impact do you expect from these delays on your 2012 production? And my second question is on project FIDs. You have a very long list of projects up for FID, such as Brazil and Angola deepwater projects or the Tengu expansion. Just wondering if you could give us an update on this as well.
Thank you.
Okay. On the first question, so yes, we've got cloccus mavacola, which is Exxon operated and Galapagos, which is BP operated coming through in the Q2. We have added a later SCARVE, which we've already I think announced to the market, where we're now seeing it delayed after the Q4. The major issue with Skaarf is really the weather windows that you have available to get the kit in place. So we are seeing that slightly later to scale.
And so that's now looking more like a 4th quarter.
All right. And I think Sorry the second question? Okay. Kim was there another question?
Yes. Just on project FIDs?
Sorry, Kim, could you repeat the question?
Yeah. Just wondering if you could give us an update on where you stand currently with your list of project FIDs and whether you've taken any final investment decisions in the last few months?
I can't recall any FIDs we've put through in the last quarter, Kim. But we'll probably we'll update you we typically update that annually as part of the investor presentation in
February. Thanks.
Right. And then we'll take the last question from Lucas Hermann of Deutsche. Please go ahead, Lucas.
Thanks very much, Jess. Good afternoon, Brian. A couple of topics, if I might. Just going back to the Gulf, firstly, can you just let us know where you're actually drilling producers at the moment, where you're using production work? And where are we on Mad Dog in terms of restart of that field, not the expansion per se?
Secondly, I wonder whether you can make any comments on the performance of Greater Plutonia through the Q1 and also the timing of start up of PSBM, which was guided towards the second half? And finally, Brian, if you comment at all on the solar business and whether you've actually written off all of the capital invested in those activities Or whether there's an amount that remains on balance sheet, which I guess would be a sum you'd hope to realize through a potential sale if that's a route you're choosing?
So our Mad Dog wheels still continue to have turnarounds through the Q2, but we should ramp back to full production in the Q3. We've actually got the rig is now on the spa. So that was put in place in the Q1. On the specifics of the solar write down, we have taken the majority of contracts have now been written off, but there are still some outstanding liabilities that we'll have to look at through the
coming quarters. Sorry, where else are you working on producers Brian in the Gulf? And when you say Mad Dog, I mean Mad Dog is not producing at all at the moment is it?
That's correct.
So where else are you working on production at the moment? I'm sorry. Sorry Lucas Production wells.
Yes Lucas we'll have to come back to you on the specifics of the production the 2 production wells that we're working on.
Okay. And was there any comment on Angola and PSPM and performance of Greater Plutonia through the Q1?
Greater Plutonia is performing well through the Q1. And there was a slight delay to PSVM in getting the rig out there. It's now there. It's in place. And that will progress through the second and third from the second into the third quarter.
So we're expecting that project to commence production in what final quarter of the year now?
3rd quarter is where we couldn't have it scheduled.
Okay. Brian, thank you.
Okay. So Lucas, we currently have production activities on Atlantis and Thunder Horse in the GOM.
Thank you.
All right. I think we will then be able to bring things to a close. Brian?
So thank you to everybody for joining us today on the call. As I've said in my concluding remarks, the Q1 gives us a very narrow window in terms of the targets we set out over the next 12 quarters to 2014. And I look forward to updating you again in the Q2 on progress around those milestones.