BP p.l.c.

Hello, and welcome to BP's first quarter 2012 results webcast and conference call. I'm Jessica Mitchell, BP's 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, 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 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 and 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 the 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 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 fourth quarter of last year, the result improved due to the better environment, a higher contribution in 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 defects in our production sharing agreements increased slightly year-on-year.

Looking ahead, we expect second 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 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 is 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.

Now 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 3 downstream businesses delivered a higher underlying replacement cost profit than in the fourth quarter. In our fuels business, we've 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 incidents 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 level 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 in corporate, we reported a pretax 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 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 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 remained 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.

Pretax 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 the charge against income on that basis. Turning to our divestment program.

In the first quarter, we completed the sale of our Kansas gas assets of $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're also marketing for sale certain nonstrategic 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% 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 onstream 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 Damages Assessment. The first date 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 first quarter, we have paid a total of $8.3 billion to meet individual and business claims and government payments. Over $16.6 billion is being 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 Plaintiff's Steering Committee to resolve the substantial majority of eligible private economic loss and medical claims stemming from the Deepwater Horizon incident. The settlement's 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, the 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 to 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, we laid out our roadmap 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 will 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 onstream over the next 3 years, with operating cash margins around double the 2011 upstream average by 2014, and that's with $100 a barrel and excluding TNK-BP. 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 of that extra cash for reinvestment 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 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 announcements of farmings 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 billion of divestments to date, against the $38 million we aim to divest by the end of 2013. I had 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 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, 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 one is completing plugging and abandonment work. Work continues on major projects and we are on track to start up 6 of them this year.

In the second quarter, we expect to see the startup 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 a 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 startup of new upstream projects with an average higher operating cash margins, the strong year-to-date oil price environment continuing 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 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.

So the first question comes from Theepan Jothilingam of Nomura.

Brian, 3 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'm wondering if you could talk a bit more especially 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 EMP?

I've looked at the Page 69 data. I was just wondering how you see cost inflation relative to Q1 last year, the impact of low 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?

Let me take the first question on downstream. The 3 major component factors of 1Q versus 1Q in downstream, so 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 first quarter of last year and we had a very weak quarter in the first quarter of this year. So that's the biggest component in the delta between the 2 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 million of effect if you look at the 1Q versus 1Q.

So 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 5 years, if you look at the sector inflation, we've seen at around 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 inflations continue to run at around about 5% 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 we're building capabilities, both in engineering, technical capabilities, safety and operational risk. And over the last few, 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, but only on reasonable terms.

The next question comes from Jason Kenney of Santander.

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 reported cash. You've got the U.S.

GoM $1.2 billion. The working capital movement's quite large, so $7.6 billion 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 common environment?

And bearing in mind, obviously, divestments still to come, a new downstream support as well. But maybe just a bit of insight on how you see cash progressing over the next few months.

I think 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 first quarter of circa 20 million barrels.

We saw the same effect in the first quarter of last year. So if you'll look at the delta year-on-year, you'll see that there are some underlying improvement coming through.

But 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 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 fourth quarter average in terms of the trajectory. We put the target 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 onstream, 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 has well progressed, over 60% completed, will be a big piece of the second half of 2013.

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.

The next question comes from Irene Himona of Soc Gen.

Brian, one question on gearing, where you -- it has remained at the top of your targeted 10% to 20% range despite oil at $120. You are indicating that it will decline over time with some 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?

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 at 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, specifically the 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 onstream, 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 $0.08, which was a signal of confidence in the underlying cash flow coming through, but we need to balance that with the various sort of uncertainties that we have out there.

Moving now to the U.S., Doug Terreson from ISI.

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 fully -- 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 mainly, 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 it's the increase in the oil price itself, so the absolute flat price has increased, and an increase in the 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 refinery system, and therefore, we're not allowed to book those profits, for that barrels being run through the refinery.

If they've been third-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 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 and 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, Doug. I mean, 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, which is to say, was 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 the -- for Judge Barbier to opine 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.

Back to the U.K., could we have Peter Hutton from RBC?

Just -- can I just ask if there's any more clarity around the movement that 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, it's a little bit of a follow-up on the question that was asked by Theepan in terms of the cost progression.

And I see the cost 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 what's being reflected in volume, how much do you think there is to go at on that kind of increase?

So, Peter, on the first question, the delta, 1Q-1Q, is 113,000 barrels a day as disposals. On India specifically, the new production coming off from India in the first quarter is 68,000 barrels a day.

There's some offset to them in terms of decline elsewhere in the portfolio, but overall, if you take out PSAs, you take out disposal effects, it's slightly increased 1Q-1Q, and it's a slight increase 4Q, 1Q. So I hope that answers the production question.

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 had pre the Deepwater Horizon incident. So we're back to 8 rigs, which will be the most numbers of rigs we've 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 where we're seeing some inflation.

Cash cost actually, in terms of the cash cost we monitor, the first quarter, they're high in first quarter last year, but they're actually below the fourth quarter and third quarter of last year.

We'll switch back to the U.S. then.

Robert Kessler at Tudor Pickering.

Brian, I might be -- I'm probably splitting hairs a little bit on semantics, but just on the new TNK-BP reporting, which I'd 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 -- 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 -- you shouldn't read anything into why it was splitted out this way.

The simple reason we've wrote 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 with 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. 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 the new projects come onstream with double the margin of the existing footprint excluding TNK-BP.

So 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.

Well, that makes sense. Appreciate the external accountability on the ex-TNK-BP assets.

Next question from Hootan Yazhari of Bank of America.

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?

Yes, so we announced the Texas City, Carson sales 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 in southern value chain is a huge gasoline machine, and we don't believe that's an asset we would've 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 nonstrategic or we don't intend to invest in it, and others would invest in it, then they're assets that actually fall in 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 challenging on the margin side. But no, we're very comfortable with the position that we'll have post the exit of Carson and 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.

Next question comes from Paul Spedding at HSBC.

I have a quick question on the consolidation adjustment. I mean, as you mentioned, if your upstream division chose to deal with third parties rather than your own refining bases, 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 the product in gas in your upstream division as a special item?

Yes, Paul, I think these are -- they're actually quite different. At the end of the day, accounting rules dictate that these are actually unrealized profits.

We can't, 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, and 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 the market to decide whether they are profits that should be accounted for or not in terms of as you -- if 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 to your derivatives, that 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 contracts, 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.

Could we move to Blake Fernandez from Howard Weil in the U.S.?

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 $5.6 billion.

And 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.

So I'm just trying to see, is that $22 billion 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.

So in terms of CapEx, the $22 billion 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 took a little bit longer to get back to work from where we expected to. But the $22 billion 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 the 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 Na Kika.

So that's -- so if you look at point forward, the assets we've put up for sale are actually all outside of those 4 main hubs, never the 4 main hubs for us going forward. And of course, Galapagos is one of the Gulf of Mexico assets, as it were, to tieback to Na Kika.

It comes on in the second quarter this year.

Right. The next question comes from John Rigby in the U.K.

over at UBS.

Three questions quickly. Can I just again go back to cost 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 cost that went in to your downstream business that then came off again once you were satisfied with them. Well, you seem to be saying now that the costs in the upstream are largely of the increase in unit costs, so 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? 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 the headroom is getting quite a lot smaller. And just a clarification on the distribution.

You -- I noticed you didn't say there was 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?

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 layered in and they'll be with us going forward. Where you'll 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.

So as they drive more front-end loading, make sure we get 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 is, if that's the word you like to use, 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 -- well, it was 5.5 to 3.4, which was the PSCM settlement, which is around additional activity that was drawn into the settlement.

The reduction now from 3.4 headroom to 2.9 is made up of $200 million of claims through January and February, which we -- which are being called through the quarter, a transfer of the provision around administration. We'd held the administration of the fund -- it 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, and so that takes away $200 million of headroom.

And then we allocated, I think, in the SCA, an additional $65 million of NRDA charges that came through this quarter. So you're right, John, it's now reduced to $2.9 billion.

We'll reassess that, the overall charge in provision, probably in the third quarter. 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 in settlement going forward.

We'll take the next question from Jason Gammel of Macquarie.

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 expect to compete around Kaskida and Tiber this year?

The second with the ramp in 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 in the portfolio?

So the first answer, the first question on Kaskida, 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 Kaskida 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 of production.

And, 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 Q2 and 3 quarter effects in 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.

Right. The next question is from Iain Reid at Jefferies.

Brian, I wonder if you could give us a quick update on what's going on in India. You're supposed to be putting a revised development plan together with Reliance, obviously, for the redevelopments of those assets.

And so far, we haven't seen that. Can you just tell us what the timeline 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 the Gulf of Mexico this year.

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 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.

So that's the sort of background, backdrop to what the logic behind the Reliance JV, and that, from our perspective, remains sound. Performance of KG-D6, 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 KG-D6 and NEC 25. The KG-D6 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, 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, so I think it'd be premature to do that here today.

Right. Could we take the next question from Pavel Molchanov at Raymond James?

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, we firstly -- and 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 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 interest through investment and 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 reserves replacement ratio.

Cash out for us from Argentina to the head office, though, is 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, and 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 since RPE.

Good. Could we take the next question from Lucy Haskins at Bar Cap?

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, as I understand, Judge Barbier has convened a meeting on May 3, and I just wondered what your expectations were around that meeting.

In terms of the first question around dividend, we wouldn't normally make those public at this stage. And that's really a matter for the oversight, the management team and committee that we put in place, to oversee that specific activity.

And then in terms of Judge Barbier, 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 -- I mean, I think you are 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 at present?

So the way things have stood at 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 this year. I can't comment on where the other parties are.

Okay. We'll now go to Oswald Clint at Sanford Bernstein.

Just back on TNK. 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 TNK-BP 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 of -- a lot of the information is confidential.

But also, what scale or what -- any sort of CapEx number or potential CapEx that this project could draw if deemed successful?

So on the first question, yes, there would've been a benefit in the 4Q results for TNK-BP around the new 60/66 tax regime that was brought in, so 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 of excess of $600 million. I think it was around $680 million or $670 million.

So really, yes, it's a benefit to 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.

All right. 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?"

So the assets that we're adding to the disposal program from the Gulf of Mexico should be round at 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.

And the next question will come from Kim Fustier from Crédit Suisse.

I had 2 questions, if I could. My first question is on production growth for this year.

You've highlighted that 2 of your 6 projects started this year are on track, Clochas and Galapagos. Could you also maybe comment briefly on Scarb and Angola LNG, both of which have been delayed slightly as I understand.

And 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, Angola deepwater projects or the Tangguh expansion.

I'm just wondering if you could give us an update on this as well.

Okay, on the first question, so, yes, we've got Clochas-Mavacola, which is Exxon operated in Galapagos, which is BP operated coming through in the second quarter. We have a little acreage in Scarb, which we already, I think, announced to the market -- where we announcing the delay there for the fourth quarter.

The major issue with Scarb is really the weather windows that you have available to get the kit in place. So we are seeing that, a slight delay to Scarb.

And so now that's looking more like fourth quarter.

All right. And I think...

I'm sorry, the second question?

Okay. Kim, was there another question?

Yes, just on project FIDs?

Sorry, Kim, could you repeat the question?

Yes, 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. But we probably will update you -- we typically update that annually as part of the investor presentation in February.

Right. And then we'll take the last question from Lucas Herrmann of Deutsche.

A couple of topics, if I may. Just going back to the Gulf, firstly.

Can you just let us know what your actual drilling produces at the moment, where you're doing 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 Plutonio through the first quarter, and also the timing and startup of PSVM, which was guided towards the second half. And 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.

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 the route you're choosing.

So on Mad Dog, we'll still continue to have turnarounds through the second quarter, but we should ramp back to full production in the third quarter. We've actually got the rig, is now on the spur, so that was put in place in the first quarter.

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.

I'm 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? New production wells?

Sorry, Lucas -- yes, Lucas, we'll have to come back to you on that -- on the specifics of the production, the 2 production wells that we're working on.

Okay. And 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. 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 -- it's -- from the second into the third quarter.

So 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. So Lucas, we currently have production activities on Atlantis and Thunder Horse in the GoM.

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'd said in my concluding remarks, that the first quarter gives us a very narrow window in terms of the targets we've set out over the next 12 quarters to 2014.

And I will look forward to updating you again at the second quarter on progress around those milestones.

Thank you.