英國石油 (BP) 2005 Q2 法說會逐字稿

Welcome to the BP presentation to the financial community conference call. I will now hand the call over to Fergus McLeod, Head of Investor Relations. Please go ahead, sir.

A very good day to you all. I'd like to welcome you to BP's second-quarter 2005 conference call. My name is Fergus McLeod, BP's Head of Investor Relations.

Before we start, I'd like to draw your attention to two items. First, today's call refers to slide we will be using during the webcast. These are available to download from our website, bp.com. Those of you on our e-mail list should have already received them. If you would like to be placed on our list for future releases, please do let us know.

Second, I would like to draw your attention to the words on this slide. We may make forward-looking statements which are identified by the use of the words "will", "expect", and similar phrases. Actual results may differ from those plans or forecasts for a number of reasons, such as those noted on this slide.

Now, over to John.

Good afternoon to all of you in Europe and good morning to all those in United States. I hope you have had a chance to read our stock exchange announcement.

Joining me today are Byron Grote, the CFO; Vivian Cox, Head of Gas, Power & Renewables; Tony Hayward, Head of E&P; and John Manzoni, Head of R&M. As usual, Byron and I will do the formal presentations, but the team is here to answer your questions after our presentations.

This morning we were delighted to report our 2Q and first-half results -- replacement cost profit for the first half of $10.5 billion, a record up 29% over '04 and that's equivalent to $0.49 per share, a record also, and up 33% over '04, showing the additional benefit of share buy backs; our quarterly dividends to be paid in September of $0.892 per share, up 26% over the same quarter last year, and up by 5% over the previous level; strong post-tax operating cash flow of $16.1 billion, up 32% over the first-half of '04; share buy backs of over $4 billion conducted during the first-half; a strong financial condition with gearing at 18% below the bottom of our target range of 20 to 30%; and a strategy with associated targets and indicators which is on track and unchanged.

The financial highlights have of course been magnified by the external environment, but they could not have been delivered without the investments and improvements which have been made over the last decade. That's due to strategy and to the disciplined way in which we're pursuing that strategy, in the way we manage capital, in the way we plan the business, and most important of all, in the way we handle the additional free cash flow resulting from higher oil prices, returning capital to shareholders after investing for the future.

So today we will talk about the overall trading environment, highlights of our first-half results with Byron later covering the second quarter in more detail, our prospects for medium-term growth in the E&O segment, and the use of funds in the short and medium-term. So let me start with the oil price.

In the first half the Brent oil price averaged nearly $50 a barrel, up 47% from the first-half '04 level of about $34 a barrel. This was on the back of further demand growth and limited surplus production capacity now estimated to be below 1.5 million barrels a day. Inventories are higher than normal for this season, perhaps in anticipation of a tight balance between supply and demand in the back half of the year.

As we began to say see a year ago, and recently reinforced, we think that it is likely that medium-term crude oil prices will remain strong and probably average around $40 a barrel over the next four years or so. This of course presumes no major downturn in demand which could result from a deep global slowdown.

Supply capacity is being built, not least in non-OPEC, but all of this takes several years to come on stream. Surplus capacity is therefore likely to take several years to rebuild to its historic average of around 3 million barrels a day.

Over the longer term conservation and substitution effects, potential policy interventions to manage demand, and increased supply of crude resulting from increased investment could increase surplus supply capacity and could lead to weaker prices in the range of, say, $20 a barrel to, say, $35 a barrel. Quite how, and indeed when, the transition takes place between the medium-term and the long-term is in my view incapable of prediction.

Turning now to gas prices, in the US where gas prices are generally moving in line with oil prices, the first half's natural gas prices were $6.51 per million BTU, up 11% compared with a level of $5.84 per million BTU in the first-half of '04. Demand remains flat but domestic supply is tight. LNG imports through May rose to a level of 1.7 Bcf a day with nearly 80% coming from Trinidad. BP has about a 52% interest in that gas.

Gas prices in the UK are no exception to high-energy prices in other markets. Concern about tightness of supply in the UK at the year end are reflected in forward prices. However, the new Isle of Grain LNG terminal and expansion of the interconnector should add some 1.2 Bcf a day to import capacity in the winter months.

BP’s global indicator refining margin stood at $7.19 a barrel for the first-half, up by $0.60 a barrel over the first half of '04. Margins remain robust worldwide because of demand strength, significant utilization of capacity, and lower inventories of certain products such as distillate.

For as long as capacity additions lag oil demand growth, it is more probable than not that medium-term global indicator margins will remain strong when compared to historical averages. Unless demand growth slows sharply, light crudes are expected to remain in relatively short supply and less valuable, heavier crudes are expected to trade at a significant discount. This favors upgraded refineries like BP's over less complex sites.

Our view of the medium term, and indeed longer term, is now more bullish than it was a few years ago. We use different oil prices for different purposes. In the E&P segment we still test projects at $20 a barrel and expect them to produce a risk-adjusted return of at least our cost of capital. However, we also look at projects at higher prices to understand their leverage to price so that we design projects both commercially and physically to realize this leverage. The same applies in the R&M segment using similar ranges for the relevant variables.

As the price of oil has moved up, the costs of goods and services has also increased because there's little or no snag in the service sector. In the E&P segment for our mix of goods and services we saw prices increase by 9% in '04 with this trend continuing in '05 and expected to continue in '06. We have and continue to offset a good amount of this inflation through technological improvements and supply chain management. All of these points lead us to believe that while the trading conditions are stronger than previously expected a few years ago, we must continue with a disciplined approach to investment. The level of investment is set so that we can maintain our historic underlying growth rates into the future and so that the dividend is appropriately covered and the balance sheet maintains strength under downside stress conditions.

We have a deep opportunity set. Selection of which specific projects to invest in depends on their state of readiness, gaining competitive advantage, and agreements with partners and governments. We match the rate of investment to our human capacity. For the longer term we're investing in our technological capabilities in critical areas such as hydrocarbon recovery, gas to products, automated control and renewable and alternative energies. I will talk more about all this a bit later.

Let me now talk about the operational highlights of the first-half, starting with E&P. It was a record in terms of production at 4.1 million Boe per day, growing by 2.9% versus the first-half of '04. New project startups at Mad Dog in the US Gulf of Mexico, Clair in the North Sea, Kizomba B in Angola, the Azeri project in Azerbaijan, and the Ust-Vakh development in the Samotlor field in Russia all contributed. In addition, the Baku to Ceyhan pipeline from Azerbaijan to the Mediterranean was inaugurated with line fill now underway and first shipments expected by the end of the year. Overall, the pace of new project startups is expected to continue in the second half of '05 and into '06.

We're clearly not going to start production from Thunder Horse until we have sorted out the recent incident. While there's been no damage to the subsea parts of Thunder Horse, we still need to examine the floating facility to see what damage it might have suffered. We will update you on when we expect to start production with our 3Q results. Other than that, the new projects are on track.

As previously indicated, we expect BP's average production for '05 as a whole to be in the range of 4.1 to 4.2 million Boe per day. That indication was given based on a planning assumption of $20 a barrel. At $50 a barrel the number would be around 50,000 barrels a day lower, due principally to lower volume entitlements under production sharing contracts.

Our track record of exploration success continues, particularly in our new profit centers with discoveries in the US Gulf of Mexico and Angola. We accessed new acreage in Algeria and Egypt and extended concessions in Egypt.

In the R&M segment we benefited from our flexible refining system, which allowed us to capture incremental margin through crude sourcing and the optimization of refinery operations. Refining throughput was flat versus the prior year on a like-for-like basis.

We responded quickly to the tragic events at our Texas City refinery. As promised, we completed and published a preliminary report into the causes of the incident and moved to agree compensation for those affected and their families. We have agreed settlements in respect to most of the deaths and many of the serious injuries, and our second-quarter results include charges of $127 million and a provision of $573 million in respect of estimated future costs.

Also in Downstream, our retail store sales continue to grow and we have been successful in maintaining fuel sales volumes in the face of the rapid rise in crude and product prices. We also launched our premium fuels, Ultimate, in two more markets.

In aromatics and acetones we announced the signature of a joint venture contract between BP and Sinopec to build a 500,000 ton per year acetic acid plant in Nanjing, Jiangsu province.

In the UK, BP and its partners announced that they intended to progress plans for the world's first industrial scale decarbonized fuels project, which will generate carbon free electricity from hydrogen to the equivalent of a quarter of one million homes.

We expanded our solar facilities in Spain and opened a wind park in the Netherlands.

We started up our SECCO joint venture, the largest petrochemicals complex in China, and signed an MOU on a major petrochemicals investment in Saudi Arabia.

Innovene was created as a wholly-owned subsidiary of BP on April 1st. We expect to begin to divest this company later this year, probably by way of an IPO, subject to approvals and market conditions.

Let me now turn to our prospects for growth, but first let me try and establish how we've done over the period 2000 to 2004 against two different benchmarks -- against what the world has done, and against what the super majors have done.

BP's oil and gas production has grown more than twice as fast as the world's production from '00 to '04 -- 5.4% for BP against 2.0% for the world. This strong contribution is set to continue. BP is directly involved in oil fields which are expected to contribute almost half of non-OPEC's production growth over the medium term.

During the period '00 to '04 the super majors grew production on average by 0.3%. BP was the fastest-growing entity with growth of 5.4%. That growth was based in part on reserves being recognized and resources being added through exploration. We replaced more of our production with reserves than any of the other super majors. More resources continue to be added through the continuation of our successful track record in exploration.

Of course our track record of production growth and reserves and resource additions is not sufficient. There is the question of the impact of all of this on our returns. As you know, we view cash-based measures of returns as the most meaningful measures, but we don't ignore profit-based measures of return on capital employed. Of course, measurements of return on capital employed are neither simple nor standardized.

For the first half of '05, after adjustments for non-operating items and on replacement cost basis, BP's ROCE was 22.1%, up significantly from the 16.7% in the first half of '04. These are the returns derived from our accounts. However, there are some special factors which disproportionately effect BP's returns in comparison to those of the other super majors. These effects are goodwill and asset revaluation resulting from the Arco and Burma Castrol acquisitions and excess capital not in service in the E&P segment, the scale of this being a function of growth.

This chart shows the estimated impact of each of these factors in '04 and the range of competitor replacement cost returns. The point to note from this chart is not the detail, but that BP's rates of return are strongly competitive.

We talked a little about the long-term future for production in February. Production is of course based on reserves and resources. Our base is very strong, amounting to some 18 billion Boe of reserves and 39 billion Boe of resources, distributed as shown on this chart.

Over the next five years our plans show the startup of some 35 major projects as listed on this next chart. This is on top of the 8 projects which have already come on stream in '04 and '05. The projects in green are already under development. These are developing around 2.5 billion Boe of BP net reserves for a life-of-field capital cost around $17 billion. The projects in yellow are still under appraisal and are expected to develop between 3 and 4 billion Boe of BP net resources with a similar level of capital expenditure per barrel.

A key point to note is that none of these projects rely on exploration success. More projects will be added to the list, and of course there are already projects being planned for startup in 2011 and beyond.

We have not changed our existing view about the decline in production from our existing profit centers. That is a decline of around 3% per annum on average from '04 to '08. This is underpinned by three things. Firstly, underlying performance remains on track. Existing reservoirs in the North Sea, North American gas and Alaska continue to perform as expected. Secondly, we have started new projects such as Clair, the ETAP satellites and the Valhalla water injection platform. We continue to make projects with Rhum and have identified new opportunities in North American gas, Alaska and Egypt. Finally, operating efficiency has remained stable or improved everywhere except in the North Sea where we experienced some very severe weather disruptions in the first quarter of '05.

This chart shows all these statements converted into estimated production. There are some important points to note. Firstly, the forward projections are based on $20 a barrel oil prices, not because we think $20 a barrel is a realistic expectation, but to provide consistency with previous guidance. At an oil price of $40 a barrel reported production would be lower due to lower entitlements under production sharing contracts. In '06 it would be about 40,000 barrels a day lower at $40 than at $20. And by 2010 it could be as much as 250,000 barrels a day lower. Secondly, we continue to estimate that our production will grow at a cumulative average rate of 5% per annum for the period '04 to '08. Finally, it's too early to be precise about the production growth rate beyond '08. Suffice it to say that at $20 a barrel we would expect the cumulative average growth rate from '04 to 2010 to be around 5% per annum.

In the longer-term we expect it to lie in the range from 2% to 5% per annum, above the average expected growth rate of the world's oil and gas production, but unlikely to exceed our historic level. All of this is of course in the absence of acquisitions and divestitures which we will continue to pursue where we see value to be captured.

Let me now return to the use of funds. We expect capital expenditure in '05 to be around $14.5 billion. Divestment proceeds to date have amounted to $1.8 billion. We expect this to rise to around $2 billion, excluding any proceeds from the divestiture of Innovene. Post-tax operating cash flow in 1H '05 was $16.1 billion, up 32% from 1H '04, and the gearing ratio was just below our target band at 18%.

We've increased the dividend in line with our view of future sustainable performance. Our ability to increase per share dividend is of course enhanced as the number of shares outstanding shrinks as a result of share buybacks. Our new level of dividend means that dollar-based investors will have seen a 26% increase in the quarterly dividend compared with last year. For sterling investors the increase is around 33%.

We are managing our gearing in the lower half of our band of 20 to 30% to provide the appropriate cushion against oil price volatility and to maintain an efficiently leveraged balance sheet.

Finally, we remain committed to returning 100% of excess free cash flow to our investors. As you can see from this slide, between the completion of the Arco acquisition in 2000 and last Friday we have brought back some 2 billion shares for $18.9 billion, reducing the number of shares in issue by about 7% after accounting for the issue of shares to employee stock option programs and to AAR in respect of TNK. In the first half of '05 we brought back $4.1 billion of shares. We expect to buy back at least $6 billion of shares in 2H, subject to market conditions and constraints.

Let me conclude with an update on our targets and strategic indicators. As a reminder, we have three targets. The first target is to underpin growth by a focus on performance, particularly on returns, investing at a rate appropriate for long-term growth. As we said last year, this can be tracked by looking at strategic indicators which are guidelines, not targets, to which we manage the group.

To highlight three key indicators, one, production growth, in the first half of '05, we grew production by 2.9% over the first half of '04, and our estimate of this indicator to 2008 at around 5% per annum cumulative is unchanged. We're confident that on the basis of our strong base of reserves and resources the growth can be extended beyond '08, certainly to 2010 and possibly beyond. Two, returns, which are on track on an underlying competitive basis, as I've already discussed. And three, CapEx levels. In today's trading environment we regard around $14.5 billion to be the appropriate level of investment for the group in '05 and around $15 billion in '06.

The second target is to increase the dividend per share in the light of our policy given to you in March '04. This I've already discussed.

And the third target is to distribute to shareholders all free cash flows in excess of investment and dividend needs. And again, I've already discussed that.

To summarize, our success so far is due to the combination of strategy and discipline. Over the past few years, we've built a strong base for the group with material assets and markets into which we are continuing to invest. We continue to search for and acquire new business opportunities, as evidenced by our recent acreage acquisition in Algeria. We're achieving the targets for growth we've outlined, and we're improving quality and we're maintaining our financial strength. Importantly, in spite of the significantly better than expected trading environment, we're maintaining our disciplined approach to the execution of our strategy, and consequently making sure that excess free cash flows are appropriately distributed to shareholders by dividends and in the strong oil price environment by large share buybacks.

There is a growing momentum in our activities and a growing confidence in our future. Our commitment to the combination of strategy and discipline is unchanged, and it's working.

Now let me hand over to Byron who will focus in more detail on our second-quarter financial and operating results. Byron?

Thank you, John. Good day to those listening to our webcast.

As John indicated, prices and margins this year have been stronger than in 2004 and also strengthened between the first and second quarters. The table shows the percentage year-on-year increases in BP's average upstream realizations and the industry indicator refining margins for both 2Q and year-to-date. These higher prices and margins contributed to the strong quarterly earnings and cash flow we announced this morning. Our 2Q replacement cost profit of $5 billion was 29% higher than in the second quarter of 2004. Our profit of $5.6 billion, including inventory gains and losses which we previously referred to as historical cost profit was also up 29% year-on-year. Operating cash flow rose 31% compared with a year ago to $6.7 billion. The increase in each of these figures was even greater on a per-share basis, reflecting the benefits from share buybacks.

Our 2Q earnings included significant charges related to non-operating items. I will describe those in the moment. Excluding non-operating items, our replacement cost profit per share was up 47% year-on-year and a record for the Company. The $0.08925 per share dividend announced today which will be paid in September is up 26% compared with a year ago.

Our second-quarter earnings included more than $800 million of post tax charges for non-operating items. The main items for the quarter relate to the explosion and fire at our Texas City refinery in March and marked-to-market IFRS accounting impacts for embedded derivatives. Our stock exchange announcement provides further details of all these items.

This chart shows the main elements driving the 29% improvement in our first half replacement cost profit from $8.1 billion last year to this year's record $10.5 billion. Non-operating items varied by around $850 million from a gain of nearly $600 million in the first half of last year to net charge of $300 million in 2005. Higher prices and margins added $3.5 billion year-on-year. Three quarters of this was due to higher oil and gas prices, and the remainder reflects higher margins in the customer facing businesses. The weaker dollar had a relatively minor negative impact compared with 2004 of around $50 million.

Acquisitions and divestment activity decreased our first-half results by around $100 million. This mainly relates to last year's sales of non-strategic assets in our Exploration & Production segment.

The $250 million year-on-year impact of higher depreciation, depletion and amortization was also mainly in E&P. Much of this relates to the production ramp up from higher-margin fields in our new profit centers.

Other factors showed a $100 million year-on-year increase. We saw benefits from higher production volumes, a greater margin contribution from supply optimization, and improved performance in olefins and derivatives. We also saw higher costs for new field startups, well work, repairs related to last year's Temsah blowout and Hurricane Ivan, and higher refining turnaround activity.

Our effective tax rate increased by around 1% from 31% last year to 32% in the first half of 2005. This represents our current view of the effective tax rate for the year including benefits from tax settlements and restructuring which allowed the release of prior provisions. Consistent with the guidance I provided in March, our marginal tax rate is about 40%. In the very strong pricing margin environment we're seeing in 2005, this would indicate an underlying effective tax rate of around 35%. Other factors being equal, we would expect our rate to increase towards this level next year under similar market conditions.

Overall, our business performance remains on track with the strategies we discussed in February, and we're pleased with the extent that we're able to capture the benefit from the stronger environment in our results.

Turning to the segments, our E&P result increased 38% to $5.9 billion. The 2Q '05 result included more than $650 million of charges for IFRS marked-to-market accounting of embedded derivatives. Excluding non-operating items, the E&P result was 44% higher than in 2Q '04. This reflects higher oil and gas prices, as well as increased production in TNK-BP and our new profit centers which more than offset declines in our existing profit centers. Production in the quarter was up 3.6% over last year.

TNK-BP contributed more than $600 million to our 2Q '05 result, around $250 million more than last year, reflecting higher realizations, higher production, and the continued benefit of the lag calculation of tax reference prices in a rising market.

Our Refining & Marketing result was $1.3 billion. Excluding non-operating items, the year-on-year result was up 21%. This reflects higher refining margins, supply optimization benefits, and stronger results in our business-to-business activities which now include aromatics and acetyls. Refining availability in the quarter was 93% compared with the 95% we achieved consistently last year and in 1Q. This mainly reflects the full quarter impact of the Texas City incident.

Our Gas, Power & Renewables result of $174 million includes a net gain on embedded derivatives. Excluding this non-operating items, the result was down 54% on the second quarter of last year. This reflects weaker results in our gas marketing and natural gas liquids businesses and the change to fair value accounting under IFRS which has increased the earnings volatility of the segment.

Other Businesses & Corporate, or OB&C, contributed a net profit of $175 million compared with a nearly $200 million lost in the second quarter of last year. Excluding non-operating items, the improvement reflects a nearly $250 million year-on-year increase from olefins and derivatives, driven by higher volumes and margins in both the petrochemicals and refining operations of Innovene. Costs related to corporate activities were also lower year-on-year. We provided further details on olefins and derivatives in our stock exchange announcement.

Turning from earnings to cash, this slide compares our sources and uses of cash in the second quarter of 2004 and 2005. Cash inflows exceeded $7 billion in 2Q '05. Operating cash flow increased to $6.7 billion and disposals provided a further $400 million.

Uses of cash remain consistent with our strategic intent. Organic capital expenditures were slightly above $3 billion and remained on track for a full-year estimate of around $14.5 billion. We returned nearly $4 billion of cash to shareholders via dividends and share buybacks.

Our pretax cash returned in the second quarter was 42%. This is up 5 points on the first quarter and up 8 points compared with the second quarter of last year. This represents progressively stronger cash generation on a growing capital base.

The data shown are based on actual prices and margins. As best we can estimate, our cash generation is on track with our strategic indicator to increase underlying cash returns by 2% over the 2003 to 2006 period based on price and margins assumptions that are substantially lower than those today.

Our net debt ratio remained around 18% at midyear reflecting the strong cash flows I just mentioned. In the current price environment we expect gearing to remain near the lower end of our 20 to 30% band in the second half of the year, even with the $6 billion of share buybacks John mentioned earlier.

These charts compare shareholder distributions for the past three years with those in the first half of 2005, shown on a proportionate scale. For the first half of the year dividend payments have totaled $3.6 billion and share buybacks have exceeded $4 billion. Since the start of the third quarter, we have already purchased approximately $1.4 billion of shares under our close period buyback program. Based on the dividend increase announced today and the indicated minimum level of buybacks in the second half of the year, full-year cash distributions would exceed $17 billion, up from around $14 billion in 2004.

Our strategy is unchanged -- we remain committed to passing on the incremental benefit of the strong pricing margin environment to our shareholders as increased distributions.

That concludes my review of the results. We would now be pleased to respond to your questions.

(OPERATOR INSTRUCTIONS)

Neil Perry (ph), Morgan Stanley.

Can I ask two quick questions, please? One is on the CapEx and it is sort of a general question. You talked about the opportunities that you have in your portfolio, and we all know that you have plenty of cash. Why is it that we only see CapEx really increasing with the natural industry inflation? Why do you not take a move to step out and increase the CapEx and take advantage of what you see as a more bullish environment both upstream and lastly in the downstream?

I think I'll (technical difficulty) quite a lot of this in my remarks. It is, I think, about sizing the firm to a steady-state growth level, making sure that we have the right structures, the right technical skills, the right people in place so that we can make all the capital investments we make work as well as we can. So we have taken the view that we should therefore keep the capital rising broadly with inflation -- a little bit more, depending on the cost of goods and services -- so that we can get the projects that we are investing in ready and in good shape before we invest in them. And there are plenty of them. We're not opportunity constrained certainly in the upstream and indeed in the downstream. We have our eye on these refining investments, notably in North America.

Can we take the next question from Bob Kessler at Simmons & Co. in the United States?

I also have a question relating to your CapEx guidance. This one is more numbers related as opposed to strategy. Specifically, what portion of your revised CapEx is now even E&P related, just sort of matching up your prior guidance with the new guidance? I'm assuming around 10 billion for '05 and close to 11 for '06. Is that a reasonable estimate?

It's about 10 billion this year and about 10.5 for '06.

Can you confirm whether all of that is entirely inflation related, or is there any activity response on your part?

It's approximately half and half based on success, primarily to do with appraisal drilling.

Thank you very much.

Can we take the next one from Tim Whitaker (ph) at Lehmans in London?

I have two questions. On your recent buybacks it looks to me as if you could have done maybe more in the first half and you might have scope to do more than 6 billion in the second half if the current and environment prevails. Would you also consider using buybacks to lift your gearing in your target range?

And secondly, on decline rates in existing profit centers you said 3%. Given your capital position, is it the case that return on the marginal dollar is the barrier to reducing that decline rate from 3% to something lower, or is it something else?

Let me ask Byron to answer the first part and Tony to answer the second. Byron?

Tim, we're trying to maintain a buyback program that doesn't suffer from starts and stops but is as close as we can ratable (ph) over the course of the year. We've now determined that as a consequence of the continued very strong prices and margins we're seeing that it is appropriate to increase the rate over the second half of the year, as John just indicated.

Clearly, as long as we're operating below our band there is scope for increase buybacks. The commitment is unchanged. We're going to utilize any excess cash that we have beyond our requirements to buy back shares and we're going to maintain our gearing within the band. So from where we are today there's increased scope. We think we have factored that into the level that we're indicating for the second half of the year.

On the EPCs (ph) a couple of important points. 3% of course is the average for the EPC portfolio as a whole, so within that there's lots of things going on. Egypt is growing, Alaska is flat, North Sea is declining something above 3%.

The 3% is again a view of portfolio. If you stepped the new projects that we're bringing into the existing profit centers out the decline would be about 5%. So the fundamental driver is the pace at which we can pool resource into reserves and then into production. We will continue to look for opportunities at the margin to mitigate it, but our best view of the portfolio as a whole today is that 3% is about right going forward.

Not a diminution of returns.

Can we take the next question please from Mark Iannotti at Merrill Lynch, London.

Just a quick question. I think it is fair to say your differential growth performance in E&P over the 2000 to 2004 period is largely due to the TNK acquisition. If you adjust (indiscernible) acquisition it looks like growth is pretty much the same as the other super majors. Giving what seems a more bullish view on medium-term oil pricing can you make some general comments about the role you think M&A can have in the business going forward?

We did, of course, not only buy things, but we also sold quite a lot of production over that period, just to note the point. But indeed, we still see a role for M&A. But it has to be the right targets, the right opportunity, and it has to make a difference. I think, therefore, it is more special and unusual than routine, and you would expect that. So we don't bank on it. We don't count on it. But we're always looking out to see whether there is something which really does make sense and does already add value. The hurdles are much higher as the price of oil goes up, and indeed as that is reflected in both assets and companies. But we still examine the situation to see what else we can do, where we can apply our skills of pulling out value from things that other people do.

Thanks.

Could I have the next question from Jon Rigby at UBS?

Two actually. The first is unfortunately there's been two quite significant incidents concerning two very important assets in your portfolio. And obviously they're not related, but has it created some form of internal review of the insurance processes that you have over the assets that you hold because obviously they are important generating value going forward?

The second, just to go back to the point I think other people have covered already, but I think you said on your last conference call that oil prices and the view of oil prices was a continued debate within the Company and you keep trying to challenge the views that you take. If you were to change your view of oil prices how fast would it give rise to a change in behavior either through increasing new people or embarking on new projects?

Thank you very much. Could I defer the second question, I'm going to ask Byron to take the second question. Let me talk about the first with the incidents and we can cover any more detail.

Well, these incidents are not related and each one has to be examined, I think, on its merits to ask whether it is related to anything else in the Company -- and so far we think Texas City is not -- and what we are actually going to learn from the tragedy. So we're doing that. We've done our first report at Texas City. We're going to put out a subsequent report. And many of the findings already have been implemented in Texas City and the learnings added to the way in which we assure ourselves of operations in the refining sector.

It's too early to tell what we're going to learn from Thunder Horse. We don't know why the platform listed during the hurricane. What we do know is we have it stable. We do know that we haven't damaged the subsea part of the development. We do know that the facility has had no breaches to it. But we've yet to check out the equipment. When we've done that and we've got the root cause, then of course we will look at that and put everything, all the learnings we have, into our insurance processes. It's something we take very, very seriously indeed. Of course, the bigger the projects, the bigger the facilities, the more we have to be very mindful that any small changes in them make a big difference to our future. So we're very minded about that.

Byron, oil prices?

Jon, as we've talked previously per your indication, it's taken a very long time to size this firm at the level that it's at. It's been constructed with an eye towards growing at a rate -- a rate that is greater than the underlying growth rate in the sector as a whole. It's based upon both people and assets that we have developed over a long period of time.

To change the rate of growth of the firm not only would require a long leadtime because of the projects associated with the upstream in particular have such a long leadtime, and therefore one has to size activity not for next year, but for 10 years down the road. The question is whether or not good opportunities would exist that would be capable of sustaining the sort of rate of growth that's even greater than that that we're seeing today.

We feel comfortable that growing at about two times the rate of the underlying growth in this industry is the right place to pitch oneself for the long term, and anything that we did to try to change that would be short lived and potentially self-defeating.

Could I go to Neil McMahon at Bernstein in London?

I have got two questions. The first one is I think the industry is not (indiscernible) yourselves, but are particularly bad at forecasting future production over time. I was just intrigued by your chart on page 18 where you've got your production buckets from existing profit centers, new profit centers and TNK-BP. I was just wondering where do you see any slippage or acceleration of projects within -- of production within those buckets over time? And I've got a second question on demand to follow up.

I'll ask Tony to do the first bit.

It is fair to say that this is a representation. It's a risk-based assessment based on the totality of the portfolio with sufficient headroom in it against the unforeseen which we know continues to happen. So I think we wouldn't expect to see significant acceleration of things in this, and what we've done is actually taken a relatively prudent, as I say, risk-based approach with sufficient headroom in terms of a full projection.

Your second question?

It's just a follow-up on demand, which is really that given your global scope I would be very interested in your views in terms of product demand and gas demand globally at the minute. There have been many comments that we're going through a very significant slowdown, or at least some sort of slowdown. It would be very interesting to see are you seeing a weakening in terms of the demand for your petroleum products.

Let me ask Vivienne Cox to start on gas and John Manzoni to do oil products.

Certainly on the gas inside we see no significant reduction in demand. We still see gas growing at about 2.5 to 3% per annum globally, and that's what it's been over a run of years.

I would say the same answer as Vivienne -- not significant impact on oil products demand. Oil products demand in the US is holding up the refining margin, so there's continuing strong demand there. There are spots where the economic impact -- for instance in Germany, big economy there; we've got a big piece of business there -- that is slower. That is more to do with the economic conditions than it is to do with the price of the products. But really other than a few particular areas which we are obviously observing, there really hasn't been to our detection anyway a noticeable reduction in demand patterns on oil products across the world.

Thank you. Can I take the next question from Pascal Mayes (ph) of Exane?

I have two questions. The first is regarding the production profile. Comparing BP production profile (indiscernible) the one of February 2005 we have the perception that BP's production profile seems flat a little bit and push back. With this perception on board, can you please tell us what are the underlying assumption for (indiscernible) in 2006 and 2007 and (indiscernible) Thunder Horse (indiscernible) reviewed production profile?

The second part of the question is what is the additional contribution from these recent exploration successes that you're reporting logically pushing up your CapEx?

There's no real material change between these two production profiles. The question I think is best answered in Thunder Horse -- about Thunder Horse, in terms Tony used just a moment ago, which is oil production profiles are risk-based. They cannot be specifically the sum of everything. In the end you have to risk everything because we know that things go wrong. And so we have taken and that into account. We will be updating you, as I said, on Thunder Horse when we actually have new information. We have no reason to believe anything is wrong, but we have no reason to believe that everything is right. Right now we're really simply waiting on more information.

As to the exploration successes, of course in most of the activity that we work in, it takes time for these to come through to production. Exploration successes go normally into resources, they are proved up, and then when sanctions they become reserves. So chances are it's going to be off the end of charts 2011 and beyond. Today's exploration is not going to appear in the short to medium term.

Thank you.

Could I take the next one from John White please at Citigroup?

Two questions please. The first, you've painted quite an optimistic outlook for oil prices in the medium term at $40. Does that change in any way the way you look and rank the projects within your Upstream portfolio?

And secondly, just looking at slide 16, some of the projects that are being appraised for 2008 to 2010, I noticed (indiscernible) developments is within that. I wondered if you could perhaps update us on the outlook and expectations for the export developments as well.

I'll ask Tony to answer the second part of the question.

The first part of the question, is, no not really because we look at these projects with the single exception of projects that really are over and done with and have covered generation revenue very rapidly in a very short period, we look at them at a variety of prices. Again, we use $20 to test to see whether risk-adjusted cost of capital at least is generated. We look at $35 to see whether we've designed it both commercially and physically to get the upside. We look at a variety of prices. There's no one specific price that we use, and different prices are used for different things depending on the risk profile. So other than the very short term, which is rare to find, I may say, access to equipment and the opportunity to get something which can produce and have expenditure put in and produce, recover its cost and more in let's say a year or so is very rare to have that.

So Tony, (indiscernible)

As you have noted from the chart, we're moving ahead now with the regional projects. We've entered the front end engineering design. We will be conducting that activity over the next two or three years and expect to have that on production in back end of 2008, 2009.

In terms of the export scheme, we continue to discuss with Gazprom the basis on which Kovykta volumes will enter the export market. It's clear to us that Gazprom will become part of this. They will certainly be involved in the export scheme. Our view has always been that this is unlikely to occur much before the early part of the next decade, so sort of 2012, 2013. And that remains the case.

Can I take the next question from Mark Gilman of Benchmark in the US?

Good afternoon. I had two TNK-related questions, if I could; one financial, one a bit more strategic. The financial one, which perhaps Byron could comment on, I'm very curious as to why it is that BP-TNK has made provisions for back tax liabilities that theoretically and legally apparently are the responsibility of the former TNK shareholders.

Secondly, I was hoping you might be able to discuss just briefly the $1.8 billion capital budget for TNK, given that it appears that something is constraining that level and the partners have seemingly made the choice to raise dividends, as evidenced by the very strong dividend payment in the second quarter, which is well above previously indicated target payout ratios.

Thank you very much for those questions. Let me ask Byron to do the first bit and Tony to do the second bit.

As far as the TNK-BP provision, the provision taken by the joint venture, that is the assessment of the TNK-BP joint venture of what will be required to settle the assessment for 2001 that they've received from the Russian Federation.

As BP, we have indemnities that we agreed with TNK at the time we performed the joint venture. The fact that they sit on TNK-BP's books is a reflection that TNK-BP is the aggregation of the two companies. And how any payment for back taxes, if indeed that is the assessment of the Russian Federation, is made will then be sorted out internally within TNK-BP.

The $1.8 billion of CapEx clearly not limited by opportunity. Great opportunity. The limiting factor today is primarily the capability in the Company. So our approach is to progressively build the investment program with our ability to build capability in the Company to execute. So over the last couple of years the focus has been very much on brown field activity, workovers, new field drilling. As we move forward we will be moving into more green field development. New developments upstream requires different sort of skill sets and capabilities that we're in the process of building. And indeed increasingly looking at refinery investments against very high refining margins in the domestic market in Russia. So the fundamental driver is not really about the financial framework; it's about our ability to execute to the (indiscernible) that we would wish, the capital program driven by capacity and capability building in TNK-BP.

Can I take a question from the Web? It's a simple one from Kevin Simpson at Miller Tabak. With oil field inflation running close to 10%, the planned CapEx increased to 15 billion from '06 from 14.5 in '05 implies a decline in activity. Is this your plan or do you expect greater efficiencies to offset oil field inflation?

I think the answer is this. First of all, the oil field inflation is running -- has been running in '04 at 9%. That's the only information we have. We've been offsetting about half of this, and it only applies to the upstream. So I think if you do the mathematics you'll find this is not actually a decline in activity; it's at least the same activity level if not a slight increase.

Can I now take another question from the telephone from Ed Westlake, CSFB.

Just a quick question on Angola. Obviously Block 18, Block 31, key projects in successful exploration. But is there a constraint on the pace of development from the government?

And then just the other question is on TNK. Good Russian realizations in the second quarter relative to the first in the domestic side. Why is that and what is the outlook?

Tony, pace of development in Angola constraint?

I think clearly the government of Angola is quite thoughtful about the pace at which it wishes to see production grow in Angola. All I would say is that we continue to have a very good dialogue with them and our judgments around projects yet to be sanctioned are the judgments that we formed consequent on the discussion and dialog with the government of Angola. So I think it will probably be a moderating pace, and that's built into our plans.

Thank you very much Tony. Realizations in TNK-BP, Byron?

We've seen in TNK-BP what we see in Russia -- a seasonality associated with domestic prices. They tend to drop in the winter when it's more difficult to export volumes through various transport means out of the country and then they tend to strengthen over the course of the spring and summer months.

There's no doubt that the change in the tax regime, the increased export duties, has further exacerbated this by creating a very high incremental tax rate on those volumes that are exported into international markets.

So there's a seasonality factor. There's probably a step change taking place as well. I would expect that the sort of prices that we've seen domestically, which are firmer than in the past, will probably be with us at least through the remainder of the season that is unimpeded with respect to export capability.

Thank you. Could I take the next question from Joe Tovey (ph) at Tovey & Co. in the US?

I had two questions. Number one, do you anticipate that the limitation factor, or a major limitation factor judging by some of the descriptions of resource limitations in terms of implementing projects, are those of getting adequate and adequately trained personnel up to speed given the comments that I've been reading in the trade press about the relative lack of people going into the field in terms of petroleum engineers and so forth?

And secondly, which may not be entirely unrelated, is there an anticipation that there's an overall hold back for political as distinct risk and the overall plans of the Company as distinguished from a pure economic or technological risk?

There is a lot talked about people constraints in the business. We don't find that we are people constrained. We obviously keep a balance on the number of people we have. And the key also of course is to get good people -- good people rather than just a number of heads. So there is always a balance but with our recruitment of both experienced hires and university graduates around the world we're able to have quality people inside BP.

I guess it's a bit of a chicken and egg. I suppose if we wanted to double the number of people we couldn't find them. But on the basis of what our expectation is, we're able to keep the quality up.

Secondly, our resource allocation is not overly colored by political risk. Obviously the political risk is factored in when we start investing somewhere. But when we start investing, then we would expect to complete an investment program to complete a strategy to get revenue out of the initial investments that we've made, whether that is Russia or whether it is Angola or anywhere in the world, or whether it's Alaska. The same applies. We carry on investing appropriately and managing the situation, making sure that we manage our relationship with whichever place we're in to the appropriate level. Thank you very much.

Can I take one from the Web? It's a question from John Herrlin of Merrill's in North America. Royalty term changes in Trinidad. There have been many press articles discussing Trinidad wanting to renegotiate royalty terms. Can you address BP's current position? Tony Hayward.

We are in discussions with the government in Trinidad around terms, primarily an issue around how they get access to price upsides for gas landed in the US. It's too early to say where we will end up in that, but I would expect we would have a resolution by the end of the year.

Can I now go to Peter Hutton (ph) at NTB (ph) in the UK.

I'll follow the trend, so two questions, if I may. First one, there's been no real active divestment activity in the first half, and you described divestment as special rather than routine. Is this a change from what you used to talk about, the continued portfolio upgrading where you used to talk about something like up to $2 billion of portfolio changes over time, this sounds like a slight change in tack.

The second question is on the marked to market. We're encouraged to strip these out as non-operating items, but obviously it's very, very difficult for us as outsiders to get a feel for this. This is a very material figure which makes a big difference between what people will call the clean and what people will call the reported number. Where would we see the other side of this? And are there any indicators that we can use to try and predict where this number is going?

I'll ask Byron to answer the second part of the question. There's no change in attitude in divestments. We've been an active divestor of assets that are better -- we get better value from if we divest. We've done that this year -- $1.8 billion so far in the first half of this year. We just announced the divestiture of the Trinidad oil interests. These are the smaller interest we have in Trinidad, not the natural gas interest, the oil interest. And it's typical of us looking at the book value of not resting with it and making sure that the focus is in things that we have confidence in for the future. So this year, for example, we divested (indiscernible) and we've divested Trinidad to name but two. We will continue to high grade the portfolio. This will continue.

Let me just ask Byron to talk about the marked to market.

What you're seeing is a direct consequence of the shift to IFRS accounting beginning in 2005 which brings with it substantially more marked to marking than was occurring under UK GAAP. Some of this we are booking through our underlying results, and we've made a point in the stock exchange announcement that one of the factors in the Gas Power & Renewables result for the second quarter had to do with the volatility associated with marked to marking a number of instruments in that business.

The element that we've chosen to pull out and treat as non-operating items relates to embedded derivatives. In our case the largest element of that relates to North Sea contracts for gas that were signed in the late 1990s. The contract is restructured not along gas prices, but along a number of other indices -- gas oil, heavy fuel oil, inflation indices, UK power. So there's a market basket of non-gas related elements which underpinned the long-term sale of gas from some of our North Sea Fields into the industrial and power sector in the United Kingdom.

These are under IFRS required to be marked across the residual life of the contract relative to as if it was sold at the forward curve of the gas market. What you see in the second quarter was the steep jump in the UK gas prices in particular over the course of the next couple of years which rose more sharply than the indices against which these embedded derivatives are measured. So it's a reflection of the change in the forward curve over what is more than a 10-year period; speaks nothing to cash whatsoever, just speaks to the nature of the movement of these contracts in the future. And as I indicated when I talked about the introduction of IFRS back in March, we expected this to be highly volatile. It has shown itself to be highly volatile. It might well be equally positive in the second half of the year. And the consequence of that coming around full circle is that we believe it's appropriate to isolate this, so that investors can look through this into our underlying results if they so choose to do so.

Thank you. Can I ask Paul Spedding of HSBC.

A quick question on the refining side. I'm just curious as to how your expenditure on upgrading capacity is moving within the downstream budget. And perhaps if you can give an indication of the scale of any additions that are coming on stream, specifically on upgrading, and the timing of those additions.

The answer of course is that the conditions in the refining sector speak right into the upgrading investments. The overall refining outlook looks well supported from where we are now. And that brings forward of course opportunities for investment, as John has said. And those opportunities for investment relate both to upgrading, but also (indiscernible) small commercial opportunities which increase the flexibility of the refineries, which increase the opportunity to trade different crudes into the refineries and such things.

So we're looking at all of those opportunities, and indeed we will be. We are looking at several upgrading projects which are going to increase the investment patterns into our refining system over the course of the next few years. And any of these projects which deal with, for instance, taking heavier crudes which our refining system is already well-suited to do, but can be made more so economically and commercial, those tend to be fairly major investments which take therefore some years, frankly, to move from concept into realization. And we're looking at a number of those things. They will be of the several hundred million to over a series of years to more than $1 billion of investment. We already invest, as you know and as we have said, around $1 billion a year into the refining system. But I would imagine that's going to increase over the course of the next two or three years for sure as we crystallize some opportunities, particularly with regard to processing heavier crude oils.

Can I turn please to Matt Lanston (ph) Goldman's in the UK.

I had one quick question on dividend policy and then one on UK Downstream. On the dividends, when you talked previously about managing surplus cash flow you have shown an illustration of various oil prices with dividends segment and obviously the buyback using the surplus. The dividend spend tended to stay flat on a 20 and 30 (indiscernible) $40 scenario. We've seen a very big increase in the dividend this year and last year. Can you talk us through whether you're still using $20 as the backdrop to setting the dividend policy or whether that's moved a little bit?

On UK downstream, obviously still a negative result there. Can you talk us through what is happening with retail margins or how much that is overhead allocation and what the outlook is for that UK business please?

The chart we showed you on the distribution to shelves (ph) of course had an assumption that the dividend was constant. So that actually was an assumption in those charts. So it didn't actually -- we said that that was the assumption, not to actually demonstrate how the dividend was moving.

So we're moving the dividend according to underlying performance improvement. We check at low stress conditions, stress conditions to see whether we're satisfied with the cover if those stress conditions took place. It's very important to us to do that. So as you think about it in terms of stress conditions, we think about it as and from here what is the performance improvement and how best to reflect it. And then of course we think about the dividend as a total flow outflow and then we divide by the number of shares. As the number of shares goes down, clearly there's more dividend per share available. We don't keep track that in a very, very precise way. We build up until we get a material amount to make a difference. So those are the ways in which we deal with this. The policy is unchanged.

As to the UK downstream, quite a lot of this of course is overhead in the UK. Our accounts are drawn in that way. A lot of the overhead for the downstream is represented by activities in the United Kingdom. That of course is debited against the overall trading amount for the UK downstream. But actually in terms of performance, John?

Just a comment (inaudible) overview. I would say the performance is improving. Certainly we're seeing an improvement in the refining business in the same way that we are across the world. That's looking pretty healthy in the UK downstream. And of course our retail business in the UK is also improving by virtue of the fact that we're improving the offer continuously. That doesn't mean to say that it hits -- that we're making lots of money at the expense of the consumer, of course. The retailing business in the UK continues to be highly competitive. But our underlying activity, by virtue of investments into the offer, into the stores, and into the distribution fields is slowly but surely improving the quality of the margins that we're earning in the UK. So quite satisfying in the underlying sense that this business continues to improve. As John said, it's masked totally in the end by the way that we account for overhead activities and our head office activities.

The last question from Jason Kenney at ING.

Following on from Paul's question earlier on upgrading and John's comments on refining investment opportunities in North America specifically, do you see any opportunity for green field capacity additions in the US? And do you have any comments on environmental or regulatory barriers for green field investment in the Downstream in the states?

Maybe I'll do this directly with John. I am very struck by the quantum of regulation and documentation that we would have to submit in order to do the brown field changes in our northern tier refineries, Whiting and Toledo. This will be quite an extensive set of activities.

I think in green field activity, I would say it would be an uphill struggle of some very considerable effort with an extremely unlikely outcome; I think probably more negative and not almost anywhere in the USA, probably Canada and the whole of Europe. I think the green field refinery investments are much more likely to take place in the locus of the demand growth which is China and indeed India. And indeed that I think is what we will be looking at ourselves. We already have a small foothold in refining in China. I would hope for the medium term that we will make progress in this area. And while I think probably not as completely as mature as the thoughts in China, I would expose expects, I hope for the period that we will do something in India. But of course it all depends on what sort of arrangements we can make.

Ladies and gentlemen, that concludes all the questions. Thank you very much for joining us. We look forward to doing this again. I hope that we've done -- I hope that we have answered your questions, and thank you very much for joining us. Good afternoon.