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, welcome to BP's first quarter 2012 results webcast and conference call. I'm Jessica Mitchell, Head of Investor Relations, and joining me today is Brian Gilvary, 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, now over to Brian.
Thanks, Jess, welcome to all of you joining us today on the call. I'd like to start with an overview of first quarter financial performance. Our first quarter underlying replacement cost profit after interest and tax was $4.8 billion, down 13% on the same period a year ago, 4% lower than the fourth quarter of 2011. First quarter operating cash flow was $3.4 billion, including $1.2 billion of post-tax Gulf of Mexico oil spill expenses. First 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 million 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 first quarter was 33%, compared to 37% in the first quarter of 2011. Turning to the highlights at a segment level. In upstream, the underlying first-quarter replacement cost profit before interest and tax was $6.3 billion, compared with $6.7 billion a year ago and $5.9 billion in the fourth quarter. The result versus a year ago reflects a stronger environment more than offset by three 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.
Thirdly, lower production in some high-margin areas. Compared to the fourth quarter 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 TNK-BP, was 2.45 million barrels of oil equivalent per day, 6% lower than the first quarter of 2011, mainly due to divestments and production decline in the Gulf of Mexico, reflecting lower drilling activity in 2010 and 2011. This was partly offset by restoration of production at Greater Plutonio in Angola. Underlying volumes, excluding TNK-BP, and after adjusting for divestments and entitlement effects in our production sharing agreements, increased slightly year-on-year.
Looking ahead, we expect second-quarter reported production to be lower and costs to be higher as a result of normal seasonal turnaround activity concentrated on high-margin production in the Gulf of Mexico as Atlantis, Mad Dog, and Holstein. We continue to expect full-year underlying production in 2012 to be broadly flat with 2011, excluding TNK-BP. 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 TNK-BP, our share of TNK-BP underlying net income was $1.2 billion in the first quarter, which was up 3% versus a year ago.
Our share of TNK-BP production in the first quarter at 1.02 million barrels of oil equivalent per day was 4% higher than the same period last year, and we received a cash dividend of $690 million in the first quarter. Turning to Downstream. For the first quarter, the Downstream segment reported underlying replacement cost profit before interest and tax of $900 million, compared with $2.2 billion a year ago, and $750 million in the fourth quarter of 2011. All three Downstream businesses delivered a higher underlying replacement cost profit than in the fourth quarter. In our Fuels business, we have had a challenging quarter, delivering underlying replacement cost profit of around $500 million, compared with $1.3 billion 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 first quarter 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 second quarter, 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 second quarter turnaround. In lubricants, underlying replacement cost profit was around $300 million, 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 million for the quarter, some $400 million 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 fourth quarter as a result of stronger demand and higher availability. We expect the petrochemicals margin environment to remain challenging. In other business and corporate, we report a pre-tax underlying replacement cost charge before interest and tax of $440 million for the first quarter, an increase of $140 million 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 the third quarter of 2011.
Guidance for 2012 remains unchanged from that given in February, with underlying quarterly charges volatile and averaging around $500 million each quarter. The effective tax rate for the first quarter was 33%, compared to 37% in the first quarter of 2011, which was impacted by a one-off deferred tax adjustment of some $700 million 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%-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 first quarter, an adjustment to provisions offset the usual quarterly expenses of the Gulf Coast Restoration Organization, so the total cumulative net charge taken for the incident to date remains at $37.2 billion.
Under a settlement agreement finalized in late 2011, Cameron paid BP $250 million in January, which was subsequently paid into the $20 billion trust fund. Pre-tax BP cash outflow relating to the oil spill costs and the trust fund for the quarter was $1.7 billion. As we indicated in previous quarters, we continue to believe that BP was not grossly negligent, and we have taken a charge against income on that basis. Turning to our divestment program. In the first quarter, we completed the sale of our Kansas gas assets for $1.2 billion 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 billion expected between 2010 and the end of next year. Announced divestments now stand at around $23 billion since the start of 2010.
This comprises completed divestments totaling $20.8 billion and agreements in place for some further $2 billion of sales at the end of the quarter, including the sale of our natural gas liquids business in Canada, which completed on the 1st of 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 interest in the Marlin, Horn Mountain, Holstein, Ram Powell, and Diana Hoover Fields. Moving now to cash flow. This slide compares our sources and uses of cash in the first quarter of 2011 and 2012. Operating cash flow was $3.4 billion in the first quarter of 2012, compared to $2.4 billion a year ago.
After excluding Gulf of Mexico oil spill-related expenditures of $1.2 billion, underlying operating cash flow in the quarter was $4.6 billion. We received $1.3 billion of divestment proceeds during the first quarter. Our organic capital expenditure in the first quarter was $5.6 billion. We continue to expect full-year spend to be around $22 billion. Total cash held on deposit at the end of the quarter was $14.1 billion. First quarter operating cash flow reflects around $3 billion net working capital build, including the effects of higher oil prices and inventory builds. At the end of the first quarter, net debt was $31.2 billion, 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%-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 from 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 of the natural habitats along the Gulf under our initial $1 billion commitment for Natural Resource Damage Assessment. The first eight of these projects will soon begin along the Gulf Coast, following the finalization of the phase one early restoration plan by the trustees. By the end of the first quarter, we have paid a total of $8.3 billion to meet individual and business claims and government payments.
Over $16.6 billion has been paid into the trust fund at the end of the first quarter. On the 18th of April this year, BP announced that it reached definitive and fully documented agreements with the Plaintiffs' 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 billion trust will be approximately $7.8 billion.
This is not expected to result in any increase to the $37.2 billion charge taken in respect of the Gulf of Mexico oil spill to the end of the first quarter. A new schedule is expected to be set by the court for remaining proceedings under MDL 2179. Before closing, I'd like to say a few words about our strategic progress. In October, BP laid out our roadmap for growing value, a clear 10-point plan, five things you can expect and five 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 promised 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 billion of assets by the end of 2013.
We said you can expect to see 15 new projects coming on stream over the next three years, with operating cash margins around double the 2011 upstream average by 2014, and that's at $100 a barrel and excluding TNK-BP. 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 reinvestment and half for other purposes, including shareholder distributions. 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.
Let me update you on progress in the first quarter. 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 farm-ins to four exploration concessions with Petrobras in Brazil, deepening of our interests in offshore Namibia, and being awarded three 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 billion of divestments to date against the $38 billion we aim to divest by the end of 2013. I have mentioned the divestments announced this quarter. As I said earlier, we continue to progress our plans to divest the two U.S. refineries.
In February, we said 2012 would be a year of milestones. We are seeing progress. With over $16 billion already paid into the trust fund, we expect payments into the trust to end in the fourth quarter this year. In the Gulf of Mexico, five rigs are operational. We expect to have eight operating before the end of the year. Of those five rigs, two are now undertaking production activity, two on appraisal activity, and one is completing plugging and abandonment work. Work continues on our major projects. We are on track to start up six of them this year. In the second quarter, you expect to see the start-up of Clochas, Mavacola 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 TNK-BP in the stock exchange announcement we released this morning. A separate rule of thumb for upstream and TNK-BP is now available on our website. Of course, one 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-up of new upstream projects with on average higher operating cash margins. The strong year-to-date oil price environment continues to feed operating cash flow into the second half of the year without the associated step-up in working capital. As we make the final payments into the trust fund in the fourth quarter.
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.
If audio participants would like to ask a question, they may do so by pressing star one. To cancel your question, please press the hash or pound key. If you are listening on the web, please submit your question using the web question facility. The first question comes from Theepan Jothilingam of Nomura. Go ahead, Theepan.
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 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&P? I've looked at the FASB 69 data. I was just wondering how you see cost inflation relative to Q1 last year, the impact of lower volumes, and also in particular, high integrity costs. 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? Are you hopeful you can draw a line, perhaps, with the DOJ before year-end? Thank you.
Thanks, Theepan. Let me take the first question on downstream. The three major component factors of 1Q versus 1Q in downstream, which is why the rules of thumb won't work, is the biggest and largest component is the delta on the supply and trading result. We had a very strong quarter in the first quarter of last year, and we had a very weak quarter in the first quarter of this year. 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 RCOP results that we've published. Cherry Point was a circa over GBP 100 million effect if you look at the 1Q versus 1Q. The 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 five years, if you look at the sector inflation, we've seen it round about 10%-15% growth in sector inflation. If you then look at BP competitively, we remain in the middle of the pack in terms of the industry. The sector inflation has continued to run around about 5%-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 investment in the upstream activity. A lot of the cost inflation we're seeing is around activity driven. There are three key areas where we're building capabilities, both in engineering, technical capabilities, safety, and operational risk.
Over the last year, we've hired over 2,000 engineers in 2011. We are seeing some inflation costs. A lot of that is driven by activity. 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, but only on reasonable terms. Thanks, Tipan.
Thank you.
The next question comes from Jason Kenney of Santander.
Hi there, thanks for taking my question. I'm just trying to pinpoint a bit of the timing for cash flow delivery over the period to 2014. I know one quarter is only a snapshot. It looks like you've got $3.4 billion of reported cash. You've got the US GOM $1.2. The working capital movement's quite large. $7.6 is generated cash. This could imply nearly $30 billion annually. Is this the 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 carbon environment? Bearing in mind, obviously, divestments are still to come and new downstream support as well. Maybe just a bit of insight on how you see cash progressing over the next few months.
Thanks, Jason. It'd be premature to book those sort of numbers at this point in the process. We typically see a build in stocks in the first quarter of circa 20 million barrels, and we saw the same effect in the first quarter of last year. If you look at the delta year-on-year, you'll see that there is some underlying improvement coming through. We do typically build stocks through the first quarter. Couple that with the higher oil price that we've seen come through. The overall effect is a net $3 billion build in working capital. That will unwind as the year progresses, as the stocks we start to build ahead for the gasoline season, as that throughput starts to work its way through the system. You'll see it correct.
It's better to look at the operating cash over a typical four-quarter average, in terms of the trajectory. We put the targets out in 2014 at $100 a barrel, it's sort of a clean comparison, 2011 out to 2014. 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, six projects this year, two this quarter, and 15 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 in the second half of 2013. I think it'd be premature to read too much into this quarter's operating cash flow. The major impact here was actually building working capital.
Okay.
Thanks, Jason.
The next question comes from Irene Himona at Société Générale. Go ahead, Irene.
Good afternoon, Brian. One question on gearing, where it has remained at the top of your targeted 10%-20% 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.
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%-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%-20%. I think it's important that we do that because it shores up the balance sheet, given the number of uncertainties out there, both in terms of the economic outlook, but also in terms of the specific situation over in 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. We signaled an increase in dividend back in February of $0.08, 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.
Morning, Doug.
Brian, my question has to do with the consolidation adjustment which you mentioned a few minutes ago. It lowered your profits by about 5% in Q1, just like it did last year, but it almost fully reversed in the next quarter. I wanted to see if there were any non-timing related factors that might preclude this item from gravitating towards zero on an annual basis as it has during most of the past five years, which I think you implied. Maybe, is there anything usual about this item in the current period that might prevent that from happening?
Doug, the thing that's happened this quarter is it's the increase in the oil price itself, the absolute flat price has increased and an increased number of equity barrels we're holding in our refining system.
Sure.
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. Therefore, I think this will become less volatile and dampened over time. 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 barrel that's been run through the refinery. If they'd been third-party barrels, clearly they would have been booked as profits.
Sure. Okay. Also, second on the Gulf of Mexico liability, it appears that you guys are following a parallel track in settling 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. 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 three categories will be settled separately or necessarily at the same time? Can you just comment on that, Brian?
Yeah, sure, Doug. I think, as I said on the call that we had with Rupert Bondy 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. 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 we're still waiting for Judge Barbier to opine on the specifics of that settlement. 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. Thanks a lot.
Thanks, Doug.
Right. Back to the U.K. Could we have Peter Hutton from RBC?
Morning. Hi. Can I just ask if there's any more clarity around the movement that you describe 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 more follow-up on a question that was asked by Theepan in terms of the cost progression. I see that costs were up 18% year-on-year.
Is it possible to give a feel as to how much of that is underlying the asset integrity and because you're still not at full 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?
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 first quarter is 68,000 barrels a day. There's some offsets of that in terms of decline elsewhere in the portfolio. Overall, if you take out PSAs, you take out disposal effects, it's slightly increased 1Q1Q, and it's a slight increase 4Q1Q. I hope that answers the production question.
It will indeed. Thank you.
On the second question around the ramp up, actually, 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. We're back to eight rigs, which will be the most number of rigs we've ever run in the Gulf of Mexico, and we've got five active today. We are actually ramping up activity. We are hiring people. Most of the projects are on track for this year. A lot of the activity and the costs are coming through, and that's why we're seeing some inflation. Cash costs actually, in terms of the cash costs we monitor, the first quarter, they're higher than the first quarter last year, but they're actually below the fourth quarter and third quarter of last year.
Okay.
The next question comes from Martijn Rats from Morgan Stanley. Go ahead, Martijn. Are you there, Martijn? 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 TNK-BP 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 the new reporting reflects the way your investment in TNK-BP 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. 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, Rob, actually, it's a good point. There isn't that much new disclosure here. You shouldn't read anything into why we split it out this way. The simple reason we've broken it out is so you can get line of sight of the underlying upstream business that excludes TNK-BP. If you remember the 10-point plan, we laid out that we would be bringing on these extra projects, which would be double the margin of the existing portfolio. You wouldn't have been able to see that if we continued to consolidate in here. What we're trying to give you a sense of is something you can measure in terms of the improvement of the upstream as these new projects come on stream with double the margin of the existing footprint, excluding TNK-BP.
This is really just to give you line of sight on the promises that we laid out there in February and October of last year.
That makes sense. I appreciate the external accountability on the ex-TNK-BP assets, thanks for that.
Thank you.
Right. Next question from Hootan Yazhari of Bank of America. Please go ahead, Hootan.
Hi there. I just wanted to refer to your disposals program. Of course, you've indicated that you're looking to put two 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.
Yeah. 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. 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. No, 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 Cherry Point Refinery, which is a bespoke boutique refinery in terms of diesel production. 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. As you mentioned, if your upstream division chose to deal with third 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?
Yeah, Paul, I think they're actually quite different. At the end of the day, accounting rules dictate that these are actually unrealized profits. As a group, as a PLC, we can't book those profits until those volumes have actually moved outside the system. We could choose to just put third-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 third party based on availability of the barrels, and secondly, in terms of commercial optimization. I think it's the right thing to do that we commercially optimize, and I will leave it to the market to decide whether they're profits that should be accounted for or not in terms of 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
Yeah
Paul. Yeah, no, that's something very different. That issue is more around where if you have long-term derivatives in place around gas contracts, you're not allowed to book those profits until the physical gas has actually moved. That's a very different accounting treatment.
Okay.
Thanks, Paul.
Could we move to Blake Fernandez from Howard Weil in the U.S.?
Good afternoon, Brian. Thanks for taking the question. I actually had two for you. For one, I hate to go back on the cost commentary, but if I look at organic CapEx in the quarter is about $5.6 billion, extrapolating that across the year, you're at roughly your guidance of $22 billion. Typically, obviously, you would see a little bit of upward pressure for the balance of the year. I'm just trying to see, is that $22 billion still a good number, or do you think there's upward momentum on that? 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. In terms of CapEx, the $22 billion is still a good number. Historically, certainly, we've struggled to spend the numbers that we've put out there, and there's been underspend certainly last year as we took a little bit longer to get back to work from where we expected to. The 22 is pretty robust, and we don't see any upward pressure on that today. I think that's still a good number for the year. In terms of Gulf of Mexico, it comes back to focus, in terms of where we want to focus our activity. The focus will be around the four big hubs, around Thunder Horse, Atlantis, Mad Dog, and Na Kika.
If you look at point forward, the assets we've put up for sale are actually all outside of those four main hubs, and they're where the four main hubs for us going forward. Of course, Galapagos is one of the Gulf of Mexico assets. As it's a tieback to Na Kika, comes on in the second quarter of this year.
Thank you.
Right. The next question comes from Jon Rigby in the U.K. with UBS.
Yep. Hi, Brian. Three questions quickly. Can I just again go back to costs in the upstream, and clarify what you said potentially? When Texas City took place, the next couple of years after that, there was a lot of integrity costs that went in to your downstream business that then came off again, once you were satisfied with them. You seem to be saying now that the costs in the upstream are largely, or the increase in unit costs are largely to do with lower volumes, and that any improvement will be a rise in volumes in the second half of the year. Is that correct? Are there some costs that actually will come off, physically come off? The second question is on the Macondo liability. The headroom that you disclose appears to be declining quite significantly.
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. Just a clarification on the distribution. I noticed you did 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, Jon. First on the costs. There are costs that will be layered in and will still be there. The safety and operational risk investment we've put in place, the investments in hiring new engineers, all those costs will be layered 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 layered out, with the new central organization we have around developments under Bernard Looney. As they drive more front-end loading, make sure we've got the right activity, planning of the well activity, effective procurement, and executing efficiently, that will then drive those underlying costs down.
On headroom, you're right, the headroom, if that's the word you'd like to use, but effectively the amount inside the $20 billion 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 billion-$3.4 billion, which was the PSC settlement, which is around additional activity that was drawn into the settlement. The reduction now from $3.4 billion headroom to $2.9 billion is made up of $200 million of claims through January and 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 this settlement inside the fund. There's a movement within the charge itself. That takes away $200 million of headroom. We allocated, I think in the SEA, an additional $65 million of NRDA charges that came through this quarter. You're right, Jon, it's now reduced to $2.9 billion. We'll reassess the overall charge and provision probably in the third quarter. Your third question.
Distributions.
Distributions. Yes, we've used the word distribution back in February. We signaled the dividend increase back in February. I think we signaled then until we have certainty in terms of what's happening in the U.S., we would not consider buybacks at this time. It is something which is in the armory once we get closure and settlement going forward.
Okay, cool. Thank you.
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 Kaskida area, and how many appraisal wells you would expect to complete around Kaskida and Tiber this year? Second, with the ramping drilling activity, do you expect to complete any exploration wells this year? If so, could you talk about which those would be? 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. To answer the first question on Kaskida, yes, we are doing appraisal work this year. I don't know precisely how many wells, we can come back to you on that. We do have an appraisal well on Kaskida this year. We will be doing an exploration well around Gila, this year. In terms of the assets which we've now put up for sale in terms of the GOM package, that amounts to for in 2011 was 55,000 barrels a day production.
Brian, if I could please, would you be able to talk about the first quarter contribution provided by Atlantis and Mad Dog to get an idea of what 2Q and three-quarter effects of maintenance will be?
I will have to come back to you on that specific question. We'll follow up with that after the call, if that's okay.
That's great. Thank you.
Right. The next question is from Iain Reid at Jefferies.
Thanks, Jessica Mitchell. Hi, Brian Gilvary. 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 Reliance Industries, obviously, for the redevelopment of those assets. So far, we haven't seen that. Can you just tell us what the timeline is? What the issues are?
Yeah.
Secondly, you talked about the 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. 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 the 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. That's the sort of background, backdrop to what the logic behind the Reliance Industries JV, and that from our perspective remains sound. Performance of KGD6, 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, KGD6 and NEC-25. The KGD6 satellite development plan approval was approved by the government in January 2012. We are still comfortable with the India investment.
I think it's sound going forward, 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, we don't tend to disclose the specifics of each one of those wells, if 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. 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?
Yeah, 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.
On PAE, firstly, I presume the question is around the nationalization of YPF.
Certainly.
I assume that's the sort of backdrop to the question. 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 that's ultimately controlled by BP and Bridas. We have got a long track record of investing in Argentina. We have been historically aligned with Argentina's interests through investment and growth delivery. PAE has continuously invested above its profit, increasing investment 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 five years, and it stands out as a company versus the competition on growth delivery. We're very comfortable with the investment. We're very comfortable with our position inside Argentina. I just reiterate, this is a U.S. registered company.
Okay. 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 five wells. Yes, five wells this year in Argentina.
Okay, 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, Jess. 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? The second question was, I understand Judge Barbier has convened a meeting on May third, 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, that's really a matter for the oversight, the management team and committee they put in place to oversee that specific activity. In terms of Carl Barbier, yes, there is going to be a meeting on May third in his chambers, which will certainly seek input on what the future schedule for the trial will look like.
Could I just ask, I think you were hopeful that the trial would not be rescheduled until you got final approval for the PSC settlement. Do you understand where the other parties are positioned at present?
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 fairness hearing, which is scheduled for November of this year. I can't comment on where the other parties are.
Thank you.
We will now go to Oswald Clint at Sanford C. Bernstein. Go ahead, Oswald.
Yes, thank you very much. Just back on TNK. I just want to clarify, was there any benefit coming through from the tax changes that were enacted in Russia, the 60-66 in the TNK-BP business? Also just the outlook for production for that business through the rest of 2012. The second question was Back on the Utica Shale, if you could give us some indication of what drilling plans you have on that for this year. I know a lot of the information was confidential, but also what scale of, or any CapEx number or potential CapEx that this project could draw if deemed successful. Thank you.
On the first question, yes, there would've been a benefit in the four key results for TNK-BP around the new 60/66 tax regime that was brought in. There's a small benefit in their numbers. Effectively, from our perspective, what flows is dividend, and we received a dividend in the first quarter in excess of $600 million. I think it's around $680 million or $670 million. Really, yes, there's a benefit for TNK-BP internally, but really what we focus on is the cash dividend stream that comes out of TNK-BP. 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.
We'll take now a question from the web from Iain Armstrong of Brewin Dolphin. Can you break down the production contribution of the Gulf of Mexico assets added to the disposal program? The assets that we're adding to the disposal program from the Gulf of Mexico should be around about 50,000 barrels a day. 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.
Hi, good afternoon. I had two questions if I could. My first question is on production growth for this year. You've highlighted that two of your six project startups this year are on track, CLOV and Galapagos. Could you also maybe comment briefly on Skarv and Angola LNG, both of which have been delayed slightly, as I understand. Was there any kind of contingency in your initial guidance three months ago? What impact do you expect from these delays on your 2012 production? My second question is on project FIDs. You have a very long list of projects up for FID, such as Brazil, Angola deep water projects, or the Tangguh expansion. Just wondering if you could give us an update on this as well. Thank you.
Okay. On the first question, yes, we've got Clochas, Mavacola , which is Exxon operated, and Galapagos, which is BP operated, coming through in the second quarter. We have had a delay to Skarv which we've already, I think, announced to the market, where we're now seeing it delayed out to the fourth quarter. The major issue with Skarv is really the weather windows that you have available to get the kit in place. We are seeing that slightly later to Skarv. That's now looking more like a fourth quarter.
All right. 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. 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. We typically update that annually as part of the investor presentation in February.
Thanks.
Right. Then we'll take the last question from Lucas Herrmann of Deutsche. Please go ahead, Lucas.
Thanks very much, Jess. Afternoon, Brian. 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 doing production work? 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 Plutonio through the first quarter, also, the timing of startup for PSVM, which was guided towards the second half. Finally, Brian, if you could comment at all on the solar business and whether you've actually written off all of the capital invested in those activities. 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.
On Mad Dog, we'll still continue to have turnarounds through the second quarter, we should ramp back to full production in the third quarter. We've actually got the rig is now on the spar, that was put in place in the first quarter. On the specifics of the solar writedown, we have taken the majority of contracts have now been written off, 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? When you say Mad Dog, Mad Dog's not producing at all at the moment, is it?
That's correct.
Where else are you working on production at the moment? I'm sorry.
Lucas
Production wells.
Yeah, Lucas, we'll have to come back to you on the specifics of the two production wells that we're working on.
Okay. Was there any comment on Angola and PSVM and performance of Greater Plutonio through the first quarter?
Greater Plutonio is performing well through the first quarter. There was a slightly later PSVM in getting the rig out there. It's now there. It's in place. That will progress from the second into the third quarter.
We're expecting that project to commence production in what, final quarter of the year now?
Third quarter is where we currently have it scheduled.
Okay. Brian, thank you.
Okay. 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?
Thank you to everybody for joining us today on the call. As I'd said in my concluding remarks, the first quarter gives us a very narrow window in terms of the targets we've set out over the next 12 quarters of 2014. I look forward to updating you again at the second quarter on progress around those milestones.