英國石油 (BP) 2002 Q4 法說會逐字稿

Good morning, ladies and gentlemen. It's a very great pleasure to be in New York, as always. The whole team is here. I will introduce them in a moment. In fact, more than the whole team is here. I'll explain that in a moment. I know that yesterday some people tried to ask questions on the web or on the telephone, and I'm very sorry that we didn't get around to them. Yesterday for disclosure reasons as you will fully appreciate, we had to have, unusually for London, a meeting both with the press as well as investment analysts. It was very large, and very difficult to chair the nature of the questions that were coming from what was quite a mixed audience. I'm very sorry about that. However, here we have a lot of time. I very much hope you have the opportunity to join us for lunch after this. The whole team will be there, and give us a chance to have a chat across lunch table as well as the Q & A at the end of this session.

As always in modern times with great communications, a tradeoff we have to make is should we come here and simply say, let's have some Q & A, or should we present to you what we presented in London. We always come down on the side of presenting to you what we presented in London so you can see the texture of what is actually being said by the people who really said it rather than listening to audio or a report of what was said. So, I hope you will indulge us there and maybe after this I'd like to get some feedback sometime to say what's the best way of having a New York meeting. It may be one day we should do this in New York to start with. That's always been my ambition, I must so say. But tradition is always tough to change, but we tend to change tradition.

Finally, in the audience here is Rodney Chase. I just want to say a few words with Rodney if I can, because he knows all of you, a lot of you very, very well. I guess I'm the person that knows him the best. We have worked as a team for over 20 years, which is quite a long time. On April 23 this year, which is St. George's day, why I know that, I have no idea, Rodney retires from BP. He doesn't retire. He retires from BP. He's done some pretty extraordinary things over this 20 years. He did some pretty extraordinary things before those 20 year, but he always started well, and he always finished well. What he finished with for me, as the -- as my special adviser for the last few months is the negotiation of our deal in Russia where Rodney was the principal negotiator and spent quite a lot of time in airplanes and in Russia, and finalized this transaction which we'll talk about this morning. It's great to have him here. I'm certain Rodney will be delighted to answer any questions on Russia as well as the rest of my team and me.

Well, we are delighted to see everyone here. I think the faces on the stage are some familiar, some brand new. But let me introduce them. First, Dick Culver, who for many years on the ENT segment and was now promoted to my deputy after Rodney's retirement. Byron Grote, who you know, who recently ran petrochemicals and was before that treasurer of the corporation and now the chief financial officer of BP. David Allen, who is in the audience here, has the title of chief of staff, that is to say, he runs everything from Corp indicate communications to planning, performance management and control. He is a member of the board of directors.

Now, Dick and David don't have presentations to make today. But they will be leading teams to see investors on a won on one basis. Now, the people on my right, and they're only here because it's convenient to put them all on the right are the newest members of the team. All have been in their jobs for a little while, but a set of individuals on extraordinarily broad experience with whom Dick, Byron, David and I have worked for many, many years. This is their debut before you. Let me introduce them. Tony Hayward when runs the upstream. Ralph Alexander who runs gas power renewables. John Manzoni (ph), who runs the downsteam and Ian Kahn will runs petrochemicals. You will a have a chance to see many of them in one-on-one over the year.

We're going to start in a traditional way with 2002 and setting the figures in context and Byron will take you very rapidly through the details. I'm going to step back and talk about strategic thinking in the way ahead, then we'll talk about the business segments in detail and I'll come back and wrap things together having said a few things about Russia. But first, 2002. I think when you step back from 2002 it was on balance a successful year. It was a year which saw some great achievements, one missed target -- one missed target --and many lessons learned. I want to give you a balanced scorecard starting with safety, which has improved enormously. Fewer people were hurt while working for BP. I think this was the 16th year of continuous improvement. And our performance is in line with the leaders in safety in our industry. There's not much to choose between, say, the performance of Exxon and ourselves.

Secondly, our financial performance was strongly competitive with our peers. In a world of significantly lower natural gas prices and retaining margins compared with 2001. We forget that now. We delivered a result of 8.7 billion dollars. We generated a lot of cash flow. We generated 19.3 billion dollars of pre-tax cash from operations, and also 6.8 billion pre-tax from disposals. Our return on capital was 13 percent. And our gearing dropped by 2 percent to below 28 percent. In underlying terms, that is against the set of standardized, so-called mid-cycle assumptions, our performance improved by 1.2 billion dollars before tax. Results per share on those standardized assumptions rose by around 15 percent per annum on average between '00 and '02. And that exceeds our target of 10 percent average annual compound rise through the period from '00 to '03. As a result of that underlying improvement, the board increased the dividend by 9 percent in dollar terms.

We completed the acquisition of Veba, giving us the largest oil products market share in Europe's largest economy and immediately enhanced our earnings. We replaced 175 percent of our production compared to a range of 50 percent to 120 percent through our main competitors who have reported results. This is the 10th consecutive year of reserves replacement through exploration of above 100 percent. This is very important, because it reinforces our inventory of growth options for the future.

But as you well know, for all the reasons we explained at the time of the third quarter, we missed a high-profile target. Operational and political events added to, in the fourth quarter, by the developments in Venezuela, gave us production growth for the year of just under 3 percent rather than the 5.5 percent we had aimed for. Of course, in an ideal world, we would have had sufficient head room to cover all or at least part of that shortfall, but we didn't. And that was the consequence of the choice we had made in 2001 and 2002 to allocate capital in favor of higher value projects in the new growth areas. As I told you last October, that led us to question whether it would be appropriate to add 1 billion dollars of capital into the base in order to meet the production target. As you will see, we have decided not to do that, because there are better opportunities elsewhere. The decisions to sell 40s (ph) is one outcome of that choice.

Now, missing a target leads a performance-driven company like ours to undertake a thorough review of the reasons. We have concluded that our strategy is sound, on track and creating a business which is distinctive in its capacity to deliver value today, tomorrow and subsequently -- a business distinctive in its assets, markets and in its business model. We have concluded that our extraordinary team of great people has a very clear understanding and alignment with our strategic objectives and is excited about our future. We have concluded that while production volumes can be a useful indicator of growth, they are only really useful when combined with a balanced view of all the other factors which go to create value.

Finally, we concluded that we should tighten up our process of resource allocation for capital and revenue. That was important in itself but even more so in the current circumstances. It is already evident that 2003 is likely to be an uncertain and potentially volatile year. The world economy has faltered in its recovery from the 2001 recession. There are hopes and expectations that a renewed recovery will take hold during this year and that would underpin the demand for all our products. But we can't rely on a recovery. Financial markets are weak, consumer and business confidence has been hit and remains influenced by war fears. Crude oil prices are presently strong, with (inaudible) over $30 a barrel having averaged $25 a barrel in 2002. But this strength has predominantly been driven by exceptional events -- the strike in Venezuela, and fears of war with Iraq.

The underlying fundamentals are less strong. Growth of world oil production capacity has been exceeding the growth of consumption for the last three years and this growth is expected to continue this year and beyond. These fundamentals will eventually reassert themselves, but we can only guess when, what the response of OPEC and others will be and what prices will do. In the face of this uncertainty, we will manage the company with a quarters view of oil prices.

The U.S. natural gas market is, however, fundamentally strong, which is helpful given our positions as the largest producer of gas in North America. Weak supply and growing demand make it possible that U.S. gas will continue to trade at a premium to residual fuel oil for much of the coming year. The market facing businesses, refining, retail and petrochemicals, have been affected by both weaker economic growth and rising feed stock costs. Both these effects might reduce during the coming year, but it looks unlikely that margins will exhibit sustained strength.

All in all, this is a difficult and unusually uncertain trading environment. That's why we managed the business on a set of very prudent assumptions, within a very disciplined financial framework. Now, we have described those assumptions as mid-cycle. But it is increasingly clear that the cycle is impossible to predict. So we should think of them as simply standardized assumptions which give us a base line which is useful just for two internal purposes. First, to test underlying improvements in performance and secondly, to shape financial planning. We have used this technique very successfully over several years -- keeping the standardized assumptions unchanged despite significant volatility in the market.

We believe it's now right to change three things. First, the assumption on natural gas prices from $2.40 to $2.70 in BCF (ph), simply in order to get the oil price $16 unchanged and the gas price assumptions more equivalent. Secondly, the chemicals industry margins, which we have been using, we're reducing from $150 a ton to $135 a ton, a reduction of $15 a ton. And thirdly, retail margins in the oil products marketing segment, where we're reducing the assumption by 13 percent. Again, a reduction of 13 percent. These assumptions better reflect recent experience. We are not changing anything else. Those are the points of context.

Now before taking you through what we propose in more detail, let me hand over to Byron Grote, who is going to discuss our 4Q and full-year 2002 results - Byron.

Thank you, John. Good afternoon.

As you know, this is my first time presenting to you as chief financial officer. So it's great to start from a sound base, a healthy business enterprise with a strong control environment and a disciplined financial framework, which I have inherited from my predecessor John Buchanan (ph) sitting in the front row here.

Before discussing BP's fourth quarter and full-year results, I would like to draw your attention to the statement on the screen and in your handout. This is your eye test for the day. My colleagues and I will use various terms such as shown here to describe our action and strategies. These will include forward-looking statements that can be influenced by unforeseen events. This slide is a summary of the trading environment for our main products.

Oil and gas prices at year end were at the top of their 2002 trading range and well above 4Q 2001 levels. Looking at the year as a whole, liquids realizations were basically flat, while our average gas realization fell by 25 percent. Refining margins were volatile throughout the year, periodically coming under extreme pressure due to crude oil price spikes and competitive factors. The fourth quarter refining indicator margin was the highest of any quarter in 2002. However, it was still well below the average margin of 2001. And the full-year indicator margin was down by nearly half when compared with the prior year.

Our petrochemicals business, where I spent most of the past two years, remained under intense margin pressure across almost all products. Our fourth quarter and full-year 2002 petrochemicals indicator margins were both down on the previous year, as the business continued to experience weakness driven by an uncertain economic outlook, over capacity, and rising feed stock prices. I'll be using the term standardized assumptions rather than mid-cycle throughout my remarks. This is more than just semantics. It represents a clear change in philosophy as we evolve the way we evaluate our business.

The new assumptions that John mentioned earlier, higher U.S. gas price, lower petrochemicals and retail margins, plus a simplification of the basis of our calculations, which eliminates a number of second order effects, all together these result in reduction in ROCE (ph) of about 1 percent versus the previous mid-cycle basis. However, this change does not materially impact any of the remarks that I will be making about the 2002 results.

In this context, looking back at 2002, overall conditions during the year were broadly reflective of our standardized assumptions with the strength in the upstream, offset by low margins in our two downstream businesses. Before moving to the financial figures, I should note that we are reviewing the generic indicator margins we currently use in our external reports and would expect to make some modifications in 2003 to better reflect our specific asset portfolio.

Turning to the financials, this chart shows the key results for the fourth quarter and for the full-year. As a U.K. registered company, we must report our results under U.K. accounting standards. However, we continue to believe that adjusting our reported earnings for special items and the acquisition premium for the ARCO and Burmah Castrol deals provides a clear view of our underlying business results and better comparability against the performance of our competitors -- that's the basis for our pro-forma representation.

Fourth quarter pro-forma earnings of 2.6 billion dollars were the highest of any quarter in 2002, up by nearly one-half on 4Q 2001. The reported result, which doesn't adjust for specials and acquisition premium, more than doubled to 1.7 billion dollars. Pre-tax cash flow from operations at 6.2 billion dollars was up 12 percent on the equivalent quarter, reflecting both better 4Q trading conditions and more importantly, underlying operating performance improvement. Pro-forma return on capital employed in the quarter was about 15 percent.

I would like to take a moment to point out a modification that we have made in our returns methodology. We have reviewed the ways that various parties calculate return on capital employed. There is no single universally accepted approach. Many of you calculate it differently, as do many of the companies in our industry. We have opened for a more economically consistent method than the one we previously used, one that we believe represents a general consensus. It remains a pro-forma representation because that's the way we run our business. So we will continue to exclude purchase price premium in our calculations. The net result of the changes, the biggest factor is to add back interest on a post-tax rather than pre-tax basis, is to reduce BP's return on capital employed by about 1 percent compared to our former method.

To be clear -- this is a different 1 percent than the assumptions driven change I discussed earlier for the combined impact will be to make ROCE, at standardized assumptions, about 2 percent lower than under the previous mid-cycle methodology. Nothing real has changed here. This is a representation which is now developed on a more conservative basis. Details of a new calculation are contained in your handout.

Returning to the slide, for 2002 as a whole our results were lower than the prior year. The underlying improvements made in the business were not sufficient to offset the weaker environment. But our annual pro-forma return on capital employed at 13 percent remains at the top end of the competitor band. I will now show you a bridge between the two years. This chart shows the main factors driving the change in our pro-forma result from 11.6 billion dollars in 2001 to 8.7 billion dollars in 2002. The softer trading conditions in 2002 impacted our after-tax result by around $4 billion. Two factors primarily drove this -- lower gas prices and lower refining margins. Countering a portion of this, our business streams achieved year on year underlying performance improvements totaling $1.2 billion pre-tax. This is $200 million less than we indicated last February for reasons which I will discuss momentarily.

The remaining improvement is lower interest expense. We actively managed our debt book during the year to capitalize on the lower market interest rates and reduced our average cost of debt by 1.6 percent, saving around $300 million pre-tax. We anticipate further savings in 2003.

Overall, stripping out the impacts of the weaker environment, our post-tax improvement represented a double-digit year on year increase in earnings per share. This kept us well ahead of the multiyear targets we set out in early 2001. A year ago, we anticipated 1.4 billion dollars in underlying improvement in 2002. As is always the case, the year turned out differently than forecast and we made many tactical responses to optimize performance against the actual environment.

Performance improvements in the upstream totaled $200 million pre-tax. This was $400 million less than anticipated and more than exceeded the group overview that we had provided. It consisted of $250 million attributed to the difference between the 5.5 percent projected and the 2.9 percent actual volume growth and 150 million dollars of higher than anticipated dry-hole expenses. The upstream's volume growth was nonetheless highly competitive and our fourth quarter production of nearly 3.6 million barrels of oil equivalent per day was the highest in company history, benefiting from 11 project start-ups during the year, seven in the fourth quarter alone.

Our gas power and renewables stream offset the impact of the mid-2002 sale of Vergas (ph) with underlying improvements in other operations. More importantly, we secured new gas markets such as the right to supply China's first two LNG import terminals to underpin future value creation in the upstream. Refining and marketing and petrochemicals both achieved the indicated performance levels delivering pre-tax improvement of $400 million and $600 million respectively. In the case of refining and marketing, this reflected earlier than anticipated delivery of some Veba integration benefits as well as other cost saving initiatives, which offset the impact of decisions to periodically curtail volumes when margins were severely depressed. Petrochemicals showed tangible bottom line benefits from the operational and portfolio improvements that the management team put in place over the past two years.

We have a stronger set of assets, operating more efficiently and with a significantly leaner cost structure, which together have begun to reposition the income capability of the stream. Before leaving the slide, I would like to note that the performance improvement we achieved in 2002 was after accounting for 200 million dollars of higher pension and retiree medical charges. Current indications are that these charges, which are impacted by changes in projected longer term cost trends, investment returns and interest rates, will increase by another 300 million dollars in 2003. This chart shows our special and exceptional charges for the past seven years. These items were more or less net neutral in the years before our major merger and acquisition activity. Following the Amoco merger, the group took a $3.5 billion pre-tax charge in 1999. Since then, net charges have shown a reducing trend as we completed the wave of integration and portfolio rationalization activity associated with building the current BP. Our fourth quarter 2002 specials and exceptionals are summarized in the box in the lower right hand corner of the slide.

When we presented our third quarter results, we expected full-year combined specials and exceptionals to remain net positive. At that time, we did not anticipate the completion of the recently announced upstream sales prior to our 4Q reporting. These deals represent a fast start to implementing the high rating strategy that Tony will be describing in more detail. All together, they generated 1.2 billion dollars of fourth quarter charges for expected losses on disposals. Accounting rules require us to report any losses on these sales in 2002, even though the sales agreements were concluded in early 2003. Although not shown, we expect exceptional gains totaling $1.2 billion from other disposals with signed agreement. These will be reported during the quarter in 2003 in which these transactions are closed. As such, we believe that a better indicator of progress towards a net neutral special and exceptional charge is to look across 2002 and 2003 together. My preceding remarks have focused on accounting results. Accounting is often subject to debate, but cash is a reality. This chart shows sources and uses of cash for the past two years.

We plan and manage our business on a cash basis, with a goal of balancing sources and uses of cash at standardized assumptions. Our 2002 pre-cash flow from operations in a year that was broadly reflective of these standardized assumptions totaled $19 billion. Against this and consistent with our through-cycle investing strategy, we maintained organic cap-ex flat at slightly less than 13.5 billion dollars in spite of the weaker year on year environment. Acquisition and disposal activity was significantly greater in 2002, with most of it linked to the Veba transaction.

Overall, sources and uses of cash were essentially balanced in 2002. This is in line with our established financial framework. The 1/4 cent dividend increase announced today on top of the 1/4 cent increase in the second quarter brings fourth quarter dividend to 6.25 cents per U.K. share. This represents a 9 percent year on year growth for the fourth quarter and the full-year. I know the dollar-based dividend are currently a sensitive issue for our U.K. shareholders. The dollar weakened during 2002, it's now back to its 1999 level. As a consequence the annual dividend in sterling terms is up only about 1 percent. Although yesterday was yesterday and today is today, U.K. shareholders were beneficiaries of a strengthening dollar in both 2000 and 2001. We bought back $750 million in shares in 2002. This compares with 1.3 billion dollars of share buybacks in 2001. John will speak further on our philosophy of buybacks later.

We held our worldwide effective tax rate to around 35 percent in 2002, down slightly on 2001. Indications are that the 2003 rate will remain in a similar range. This reflects tax planning and internal restructuring initiatives which more than offset the effect of the exploration of U.S. non-conventional gas credits in 2003. In addition to distributing more than $6 billion to shareholders, via dividends and share buybacks, we reduced gearing ratio from 29.5 percent at the beginning of the year to 27.5 percent at year end. This is well below the midpoint of the 25 to 35 percent target band. In summary, during 2002 we further strengthened an already strong financial position and we start 2003 not only with very strong oil and gas prices, but also with nearly $4 billion of proceeds due from already agreed group disposals.

This is a great foundation on which to tackle the opportunities and challenges that we'll face in 2003, which John will now describe. Thank you.

Thank you, Byron.

I would now like to return to the subject of strategy, how we create competitive advantage and how we track success in its delivery. All of our strategy is designed to create value from a distinctive set of opportunities, towards the upstream, which through a disciplined approach to long-term investment growth can produce returns which are both secure and highly competitive. How do we do this? And what is the business model?

Since 1999, we have been in a phase of significant acquisitions and mergers and developing opportunities for the future. Now we're in a phase which is about making choices and about allocating capital and revenue investment to assets and markets based on their value potential and risk. Those that don't know it in allocation, we consider for divestment. At the same time we scan for growth opportunities and take up those where we can create value by integrating new activities in a cost effective way in line with our track record. These steps are all designed to ensure that we invest only in distinctive assets and distinctive markets. Then we control the rate of investment within the financial framework, which under our standardized assumptions is designed to balance cash generated with cash used over the medium term, not each and every year.

Productivity comes from many, many sources, including most importantly technology. Productivity controls costs, where we have a good track record, but where there is more to do. The role of operating management then is to focus on maximizing growth margins, that is the difference between revenue and the cost of goods sold while dealing with productivity, and they work within a maximum budget for cost and with clear central allocation of the pattern of capital and revenue investment, and this is a dynamic process, which takes into account actual performance. In other words, the process of management as I'm sure everyone knows is not about the administration of fixed budgets, but about on the margin dynamic allocation of resources.

The investment in to the distinctive opportunities and careful attention to productivity is designed to increase cash flow earnings and the return on capital over the medium term. And this doesn't happen every year, year on year, because in reality the trading environment changes. It's also important to remember that investment proceeds revenue. So capital employed may rise until it's in service and generating income. But that's purely a timing issue. So that's the business model. From that model flows the returns. Now, the board sets the dividend on a balance of a variety of factors. They consider not only present earnings, but also long-term growth prospects and cash flow. They also consider our competitive position and examine the payout which broadly corresponds to around 60 percent of sustainable earnings calculated on the standardized assumptions over a run of years. Of course, this is not a mechanical calculation. The board judges the balance between all the factors and all the options available.

Track record is that our dividends, which are set in U.S. dollars, have increased by 17 percent between 2000 and 2002. And over the long run, 20 years, they have increased by an average of 4 percent above inflation in dollar terms and by an average of 3 percent per year above inflation in sterling terms.

Now, my colleagues will later take you through the details of each business segment. I want now to pull out the foremost significant things which effect the future of the group -- the finding of reserves, the building of new profit centers upstream, the dynamics of investment and return upstream, and the growth of refining of oil products, marketing and of petrochemicals. Before my team and I describe the strategies, I want to caution you that all the statistics we're showing you are based on our internal plans. Those plans are subject to continuous change for the reasons I mentioned earlier and do not take into account acquisitions and disposals, some of which have been announced but which weren't completed on the 31st of December, 2002 because at the moment it is simply too difficult to predict precise date for financial completion.

So, starting with the three upstream points -- our upstream strategy was set in place in '89 and has been unchanged since then. I think it can best be described in terms of four components -- the creation of new material profit centers, the building of those centers, the process of maximizing productivity in the existing profit centers and the divestment of activities which do not merit investment. I'm going to focus on the first two. The creation of material new profit centers by accessing the right hydrocarbon basin is one of the most important competitive skills of this company. Our strategy is to have a disproportionate share compared to our competitors of the world's largest and lowest cost oil and gas fields.

The key to success is winning against the competition for access. The test for success are the numbers of John's discoveries and the reserves added through exploration alone. That is only discoveries in addition, along with the finding cost per barrel. We passed these tests and that establishes the future. The second point is the building of material new profit centers by selecting the -- for development the best opportunities that we found. Right now we're developing five new material profit centers in the deep water Gulf of Mexico, in Trinidad, in Angola, in Azerbaijan (ph) and in Asia Pacific LNG. We expect these to begin to contribute significant annual improvement in earnings and pre-cash flow starting next year.

I cannot stress enough how important this moment is in the long history of BP. For us, this set of moves is analogous in terms of both capital and reserve to the development of the North Sea and Alaska 30 years ago. Over the next five years, more than 50 percent of the entire capital allocated for investment in the upstream is intended to go in to these five new profit centers. The pace is fast, directed not only by our own choices, but also by the decisions of government, some timing, by the access we need to growing gas markets, and by the wishes and the choices of our partners. Here is a chart of the total capital going into our builds portfolio and the production capacity expected in the medium term. These figures are internal assessments, they're directional indicators, but they are not targets.

Significant capital expenditure in the early years builds capital employed fast and delays the increase in return as you can see on this slide. However, as Tony will explain, the fact that we will have better margins from the build portfolio than our average, current upstream average means that our overall returns are expected to benefit as new projects come fully on stream. Of course, these numbers are based on our standardized assumptions, including $16 oil. It's worth noting that returns from this build portfolio are sensitive to hydrocarbon prices by around 1 to 1 1/2 percent in return for each dollar increase or decrease in the price of a barrel of oil equivalent.

As Tony will describe in a moment, these new profit centers are intended not only to renew BP for the medium term, but even more importantly to give the company legs for the long-term future because in most of these areas, we estimate that there is many reserves yet to be found as there are proven reserves under development. Tony will deal with the existing profit centers and divestments. But I would like to talk now about the overall dynamic of investment return and cash generation for our upstream segment. And this chart shows our internal indicator ranges of production against our indicator ranges of capital investments and the resultant indicator for return on capital employed at our standardized assumptions. In 2003 we intend to invest around $10 billion, this is higher than the amount we need for reinvestment beyond '04, when we expect investment to return to a level centered around $9 billion per annum.

If there had been no change in our portfolio, we would have seen production capacity grow modestly this year, with 2003 showing a production profile with output flat or perhaps growing by up to 3 percent. On that same basis, over the period 2000 to 2005, we would have expected production capacity to grow on average between 3 and 4 percent a year. But of course, events have moved on, we have initiated a series of divestments and as I will describe later, we're in the process of adding some very significant new assets in Russia. I would stress two things about these figures. First, we expect the percentage of gas produced to remain very nearly constant at slightly above 40 percent of total production. This is important to us as an indicator because of global gas demand growth. Secondly, all these are estimates of capacity, not targets for production from that capacity.

Growth rates will vary from year to year. As spending tails off and the new profit centers come on stream, you can see that there is an opportunity for significant free cash flow beyond the medium term. The judgment on the amount of capital to be invested will depend on our analysis of risk and value generation in the light of the then prevailing reality. As the chart shows, we expect overall upstream returns using standardized assumptions as the basis for the calculation, to lie in an indicator range of around 12 to 13 percent over the next five years. In practice, there are steps we are taking to improve further our return on capital employed in the near term. For example, through divestment of poorer quality assets and by reducing costs where appropriate.

Now to refining and marketing. We think of our downstream business as having four elements -- refining, retail, lubricants and business marketing. John Manzoni will cover this in more detail. But let me make a few overarching points. The downstream business has experienced a period of dramatic growth over the recent past as we have assimilated the assets and market that's we have acquired. We have been making choices on value and risk on how to allocate capital and revenue investments to these assets and markets and this has led to divestments. Our approach now is to keep capital employed broadly flat over the next three years, while we continue this process of choice. This feels like the right approach, particularly in the light of the low economic growth the world is now experienced. Actual returns from this segment have been volatile, primarily due to refining. They have averaged 15 percent between '99 and 2002. Returns based on standardized assumptions are expected to be in the indicator range 12 to 14 percent over the next three years, with improvement coming from reduced cost and slowly increasing volumes of product made and sold with unit gross margins stable or potentially rising.

In petrochemicals we have a similar strategy. We focus on seven core products, for which we have strong market segment shares and in many cases, a distinctive technological advantage. This gives us a competitively advantaged structure of gross margins. We will continue to reduce our operating costs and to add selectively to capacity while keeping the total level of investment and hence capital employed, broadly constant. Returns based on standardized assumptions are expected to rise by around 3 percent from 2002 to 2006.

So now I would like to hand over to the heads of our business segment who will give you more detail on how we implement the strategy and how we direct operations to maximize gross margins. But first, Tony.

Thank you, John. Ladies and gentlemen, good afternoon.

Before I begin, let me say how excited I am to have the opportunity to lead the upstream business through the next phase of its developments. I would like to begin with strategy. As John said, the upstream strategy was put in place in 1989 and remains unchanged. Simply stated, it is to create, build and produce material businesses in some of the world's most prolific hydrocarbon provinces. The strategy can be described in four components. First, we create new profit centers by accessing the right basins. Our objective is to have a disproportionate share of the world's largest and lowest cost oil and gas fields. The second step is to build projects which are of high quality because we select only the best opportunities for development. The third, produce phase, is about maximizing the productivity of the installed capital base by managing the business called cash and returns. And finally, we have to know when to stop -- when to stop investing in opportunities that do not fit within our risk and return cutoffs, but in which others may see value.

Throughout, the strategy is underpinned by two basic principles -- focus to drive materiality, choice to drive quality. I would like to take you through each step and describe how it is being applied in materials of the seven profit centers operating today and the five new profit centers that we're in the process of building. Creating new profit centers begins by exploring in the right basins. The principle drivers of success are firstly, early access, the key to obtaining a disproportionate share. And secondly, focus, pursuing only those opportunities that offer materiality and therefore, through cost efficiencies of scale, high returns. Our track record over the past five years in executing this strategy is good. We have made more joint discoveries, replaced more reserves and had lower finding costs per barrel than any of our major competitors.

In 2002, we continued the track record. We replaced around 120 percent of produced reserves with the drill bit at an average finding cost of 78 cents a barrel, better than the four-year average. Combined with the improved recovery and revisions to our existing reserve base, we replaced over 2 billion barrels of oil equivalent and that brought the total organic reserve replacement to around 175 percent, a very competitive result that underpins our long-term growth plans. Actual new discoveries in 2002 are estimated to total over 1 billion barrels of oil equivalent of new resource, these new discoveries include Iron Horse in Trinidad, Great White in the Gulf of Mexico, and Plutow (ph) in Angola. The create phase has given us legs for the future. The evidence of this success is the resource base we have established in our five new profit centers, a total of around 15 billion barrels of oil equivalent.

Our exploration program today is focused primarily on the deep water Gulf of Mexico, Trinidad and Angola, where the industry has an estimated 25 billion barrels of oil equivalent of remaining discovered resource. In these areas, BP has developed an industry-leading resource position with an average share of nearly 40 percent at around 10 billion barrels of oil equivalent. In all these areas, the industry's judgment is that only 50 percent of the ultimate recoverable resource has been discovered. Taking together our track record of success, the know-how and capability we have established in these areas and the acreage we hold, we're confident that our share of the future resource will be equal to or better than the success we have achieved to date. All five new profit centers have legs for both the medium and long-term.

In summary, our create strategy is to be in the right basins, to find big fields, and not to drill dry holes. So how do we do it? We see it as a matter of the right tools, the right capabilities and the right decisions. Firstly, we develop and use the right tools. We focus on building world class capability and a few key technologies that really matter -- a typical example comes from the complex world of seismic imaging. Over the last two years, we have developed new techniques to enhance our ability to see beneath the complex salt of the Gulf of Mexico to generate the next tranche (ph) of major discoveries. These advances are made possible through focusing world class science on to real problems and of course, investing in the most advanced computing power commercially available. The transformation in our ability to see prospects is akin to the change in astronomy brought about by the Hubble telescope.

Secondly, we apply the right capabilities. We developed the know-how in our people through longevity and depth of experience in a focused set of hydrocarbon basins to provide the best in class regional evaluation. A good example is the evolution of our exploration strategy in the deep water Gulf of Mexico. Our knowledge of the basin led us to realize that most of the deep water discoveries to date were located at the top of the regional hydrocarbon migration system. We decided to explore from the source rock up as opposed to drilling from the amplitudes-top-down. As a result, we found a new breed of giant fields like Atlantis and Thunder Horse sitting immediately above the source rock. This may seem like a simple story, but then most breakthroughs are in retrospect. The capability that our people have developed over a long period of time is what makes such breakthroughs possible. possible.

Thirdly, making the right decisions. Access to a deep opportunity set enables us to achieve quality through choice with the ultimate goal of improving the quality of earnings and returns. The next phase of activity, the build phase, focuses on choosing only the best projects from the opportunity set and on designing and building those projects in the right way at the right pace to maximize capital productivity and minimize full life-cycle costs. Industry-leading success in the create phase has established an unrivaled opportunity set and as John as already emphasized, over the next five years we plan to build five new profit centers in the deep water Gulf of Mexico, Trinidad, Angola, Azerbaijan, Asia Pacific LNG. You can obtain more detail about these developments from a description of our growth projects in your handout and on our Web site.

This slide shows the significant production contribution we expect from these five new profit centers out to 2007. 100 percent of this production will come from the discovered reserves and by the end of this quarter, every project required to deliver this production should be sanctioned and under construction. In addition, all of the gas is sold or will be sold in to fungible (ph) markets. As Ralph will show, he and his team are doing a fantastic job of developing markets well ahead of production coming on stream. So through the application of technology and know-how we are delivering results that underpin our confidence that these projects bring material, margin enhancement with production growth. I'll return to that later.

Building the new profit centers is expected to require investment of around 20 billion dollars between 2003 and 2007. This is projected to account for more than 50 percent of the total upstream capital over this time period. As you can see, it is creating a spike in capital spending plans between 2002 and 2004, and as John has indicated, this puts pressure on returns over the next couple of years. I will talk about how we are responding to that later.

Many people look at the number of deep water developments in our portfolio and draw the conclusion that there is significant technical risk. In reality, all that we'll do in the future is to build on what we have learned in the past. For example, we transferred the lessons of deep water, sub-sea engineering and system installation from the west of Shetlands area to the Girasal (ph) project Angola. We will have the benefit of the experience from blocks 15 and 17 in Angola as we move ahead with the greater plutonium project in block 18. In the Gulf of Mexico, lessons from the construction installation and start-up of the Horn (ph) Mountain Spa, which came on stream last year will be used in the Holsteen (ph), Mad Dog, Atlantis and Thunder Horse projects.

Finally, we operate most of our build portfolio ourselves. This allows to us intervene in a more direct way to define the scope, make choices on the pace of investment and the use of technology to ensure capital efficiency and to manage full life-cycle costs. Not only are we growing volumes in the new profit centers, but also improving the quality of our portfolio by bringing in higher margin barrels. In 2002, the new profit centers earned slightly above stream average profit margins, defined as pre-tax operating profit and shown in green on this chart, and cash margins defined as pre-tax operating cash flow shown as green plus orange on this chart. As we look towards 2007, post-tax profit margins in the build portfolio should improve as we bring on projects with lighter, sweeter crudes. In addition we expect a flat or even slightly declining production tax burden on these barrels. Over the same time period, cash margins are anticipated to improve even more.

Improving margins in the new profit centers should increase stream average margins, not only through their underlying improvement but also through the increasing proportion of build barrels in the portfolio. In 2002, the five new profit centers comprised just over 20 percent of our total annual production. By 2007, this is expected to nearly double to nearly 40 percent. We are high grading the portfolio through our organic investment choices. Let me give you some examples. In the Gulf of Mexico, Holsteen, the next BP operated project, is expected to come online next year with gross production of around 100,000 barrels a day.

Build development costs are under $4 a barrel with anticipated lifting costs of 80 cents and transportation costs of less than $2 a barrel. As a result, total union costs in Holsteen are expected to be around 10 percent below the current stream average. In Azerbaijan, development costs are expected to be $3.50 a barrel, with net lifting and transportation costs forecast at just over $2.50. As a result, total unit cost in Azerbaijan are expected to be nearly 15 percent below our current stream average. In both examples, we are benefiting from economies of scale through the developments of large fields and the application of leading-edge technology.

To summarize, we're building five material new profit centers, with legs for both the medium and long-term. The reserves are secure and all the projects should be sanctioned by the end of this quarter. The gas is all sold and a combination of lighter sweeter crude and lower cost should lead to higher cash and post-tax profit margins between now and 2007. This growth will come on top of the very strong foundation of seven existing profit centers. Three of these, the North Sea, Alaska and North America gas, make up almost 80 percent of our production. Egypt, the Middle East, Asia Pacific domestic and South America comprise the remainder.

At this point I need to relate this description of the business to the way we have talked about it in previous years. In the past, we simply divided basin growth, base being defined as everything that was on production at the beginning of 1999. It was a very artificial description designed to achieve clarity as the ARCO assets came in to the portfolio. But it does not reflect how we run the business. This does. In this description, the most important changes are that all volumes in the deep water Gulf of Mexico, Asia Pacific, LNG and Trinidad are considered to be part of the build portfolio, including those on line before January 1999.

As strategy in our existing profit centers is to manage the assets for cash flow and returns , we accomplished this through rigorous focus on three areas. First, maximizing the economic flow of barrels through the system, replacing reserves consistent with lighter field depletion plans. Second, developing those barrels with a strong focus on capital productivity, making tough choices to put scarce resources to their best use and thereby avoiding over investment. And finally, operating with a goal of having best in class costs in every basin in which we operate.

Let me cover each of these in more detail. Our first objective is to maximize the economic recovery of the barrels over the life of the basin. This is accomplished through a systematic and sustained process of proved developed reserve replacement. Let me give you some examples. BP has been producing on the North Slope for 25 years. Last year our proved developed reserve replacement was 150 percent -- a great result for a mature area as we continue to develop the main reservoirs while utilizing the existing surface infrastructure to bring on Prudhoe (ph) based satellites. Our proved development reserved replacement rates on the North Slope has been more than 100 percent in the two years since the ARCO acquisition.

The U.S. onshore business is one of our most mature operating areas. This business produces over half a million barrels of oil equivalent a day, and achieves a proved developed reserve replacement of around 80 percent in 2002, similar to the average for the last three years. In both Egypt and our Pan-American joint venture in Argentina, we have replaced over 150 percent of production over the last three years. Taken together over the last three years, our track record has been to replace produce reserves in our existing profit centers at a rate of over 80 percent and we anticipate this level of replacement will continue into the foreseeable future. This underpins a forward-looking decline rate of around 3 percent. The second objective is to drive for continuous improvement in the productivity of the resources we commit in both capital and revenue costs. Our focus is to maintain long-term returns in the current profit centers while we bring on high quality growth projects for the future -- a simple measure that we use to ensure we're on track is the level of resource required for each incremental barrel of production.

As you can see on the left, we made a 30 percent improvement in productivity in 2002. Drilling is fundamental to capital productivity. In 2002, we achieved a significant improvement in drilling wells. We drilled 14 percent more efficiently as measured by dollars spent per barrel of production delivered. We make our investment choices through a global ranking process. An opportunity doesn't even get considered unless it first meets strict risk adjusted requirements for rate of return. It is then ranked against other similar opportunities. On the right, is an example of our global program, we use a similar process for our drilling programs. Each data point represents an opportunity with cumulative investment costs on the horizontal access and cumulative production rate on the vertical axis. As you move further to the right, each opportunity gets less productive than the one before. We use these comparisons to make a cutoff depicted here in red for opportunities that will either not get pursued or will be deferred to complete at a later date. The third objective is to have a best in class operating cost structure.

In 2002, we achieved a 6 percent year on year improvement in unit lifting costs which was in line with our target despite lower than anticipated volumes. At the business level, we have an industry-leading position amongst the majors. However, we don't consider that to be best in class because we're not best in class everywhere we operate. The gap in our view in this area is between 50 and 100 million dollars a year, two levers to access it. Firstly, we can only be best in class with the right portfolio. We're in the process of divesting some of our highest cost, lowest margin barrels in the North Sea, the lower 48 and Gulf of Mexico Shell. On average, these divested barrels had a lifting cost of around $7 a barrel compared with a stream average of $2.44. Secondly, we continue to transform the way we operate by aggressively pursuing best in class standards of cost both in the field and above the field.

Let me give some examples of actions we're taking in the North Sea. Over the past year, we have divested 57,000 barrels a day with average lifting cost of more than $8.50 a barrel. We are restructuring our offshore operations, introducing best operating practice and utilizing technology. For example, Optic Fibre (ph) in Norway to enhance productivity. Our goal is to transform the cost base of these assets while continuing our aim of being the safest operator in the North Sea. The net result of all of these actions should reduce North Sea lifting costs from nearly $2.50 a barrel to around $1.90 a barrel by year end 2003. Our consistent goal is to offset inflationary pressures and deliver a year on year unit cost improvement while constantly improving our performance in matters of health, safety and environment.

Finally, operating efficiency. Despite the challenges we faced last year, underlying operating efficiency has improved by around 2 1/2 percent over the last two years from 85 percent to 87 1/2 percent in 2002 -- a significant improvement, but still a ways away from best in class in our industry.

To summarize, in our existing profit centers we have the resources to underpin the future profiles, we have a rigorous focus on the level of investment and a track record of strong cost management.

Let me now cover divestments. Quality through choice is fundamental to our strategy and such choice is exercised at all parts of the lifecycle. During 2002 and so far in 2003, we have divested or agreed to divest nearly 5 1/2 billion dollars of assets, with the exception of Trinidad, which pre-dates the BP Amoco merger, and Tangu (ph), which was done to gain market access, these disposals are part of our process to continually high grade the upstream portfolio. While the disposed assets had investment opportunities, they did not compete in our portfolio and others were prepared to pay good value for them because they do compete in theirs. For the producing assets we have agreed to divest so far in 2003, we have realized around $5 a barrel for proven reserves. On the basis of our own internal discounted cash flow analysis, this equates to an effective future price of $25 a barrel. We believe this is good business.

As you can see, these are not all late-life assets in a state of decline. We make tough choices about assets at all points in the lifecycle, always seeking to balance growth and returns. Disposal of these assets allows to us generate cash and redeploy the capital into higher return opportunities elsewhere in the portfolio. We will continue to examine the portfolio for assets that don't compete and anticipate the possibility of an additional 500 to $1 billion in disposals in the remainder of 2003. Taken together these disposals should raise upstream returns by between 30 and 50 basis points over a full year at our standardized assumptions.

Let me now summarize. John has laid out the future of the upstream in terms of capital investment, production and returns. In 2003, we intend to invest between 9.8 and 10.2 billion dollars. This is higher than the amount required for reinvestment beyond 2004, when we expect investment to reduce to around $9 billion per annum.

We expect production to grow between zero and 3 percent for 2003, and over the period from 2000 to 2005 we expect growth in production capacity of between 3 and 4 percent per annum and in the period from 2003 to 2007 around 5 percent. This investment pattern is creating a longer data production profile. We are investing today for both the medium and long-term. As we implement the program, we're focused on ensuring capital efficiency does not go down through, one, the discipline of making choices and two, driving efficiencies in everything we do. And I have shown some examples of that today. Going forward, we expect finding and development costs to average around $4 a barrel, roughly in line with 2002, and more importantly, the five-year rolling average of around $3.80 a barrel.

I began by saying I was excited about the prospects of our upstream business. I hope I have conveyed some of that excitement to all of you. My enthusiasm and confidence comes from four things: Firstly we have a long track record of access and exploration success and today's announcement on Russia is the latest example of just that. Secondly, in our new profit centers, the reserves are there and we are developing a track record of delivery. Thirdly, in our existing profit centers we have the resources to underpin the future profiles, a rigorous focus on the level of investment and a track record of strong cost management. And fourthly, we're in action on the portfolio as we make choices to drive quality at every point in our business. Finally, and most importantly, we have good people who are determined to be the best in their field.

Ladies and gentlemen, thank you very much. Let me now hand over to Ralph who will take you through the gas, power and renewable segment.

Missed the best part. Thank you, Tony. And good afternoon to everyone today.

I would like to take the next few minutes to give you a brief overview of what we do in the gas, power and renewable segment. And the basic purpose of the segment is to create value from activities that are complimentary to all the other business segments, petrochemicals, upstream and downstream. We believe this integrated approach offers an opportunity for distinctive competitive performance on the one hand, while defining a boundary for the business to work within on the other. With this in mind, our strategy has three key components. First, maximize the value of the group's gas resources through marketing. This means that for today's gas production, really focus on expanding the gross margin. Do that by targeting higher value customer segments, making sure that we have the logistics and markets in place to make sure that all of our gas can naturally flow unconstrained and optimize around our asset base to deliver the lowest possible cost of goods sold.

Our marketing business has grown to around 22 BCF (ph) a day, and we currently enjoy top-tier positions in the market in both the United States, the United Kingdom. Our undeveloped gas resources, we believe the key here is to capture markets ahead of supply with a longer term aim and allowing our gas resources to move into the market with the same ease that oil does today, that's a real goal we are going to go after. Clearly this is best demonstrated by LNG and I will touch on that in a moment.

The second purpose of this segment is to grow the value of our natural gas liquids business or NGLs, as we call them. We are the number one marketer in North America with about a 13 percent market share and globally we supply in the region of 6 percent of the market, which is substantial at 8 1/2 million barrels a day. This is underpinned by our upstream asset base globally and our top core operating performance in our plans. We also provide feedback to our chemicals business, and product for our refining and marketing business. With global demand for NGLs, both as a chemical feed stock and as a clean fuel expected to grow in excess of 3 percent a year, we expect this business will also potential for further growth. Taken together, our gas marketing and NGLs business has delivered strong financial performance over the last three years. Excluding real gas (ph), which was sold in 2002, these two activities generated return on average capital employed of around 17 percent, and we actually averaged 15 percent in 2002, which proved to be a tough year for the sector as a whole.

Now, the third strategic purpose is to develop material and profitable renewables business. In renewables we continue to focus on solar, where we currently have a 17 percent share of the world market. This places us number two behind Sharp (ph) of Japan in terms of worldwide sales. While this business is an investment for the long-term, we are and will continue to watch the bottom line very, very closely. In 2002 we took steps to close our poor performing plants, while investing to expand product capacity of our Advantis (ph) high efficiency products. This year we intend to continue to consolidate our manufacturing operations and test different channels of trade to see if we can grow the gross margins through a branded offer. These are the core activities for gas, power and renewables, and I look forward to updating you on our progress in the future.

Tony spoke about growing profit centers. And I spoke about capturing markets ahead of supply. I would like to show you how these two ideas come together in the matter of LNG. This chart illustrates the progress of BP's LNG trade. The left-hand side of this chart shows the volume of BP gas supplied into existing plants or those under construction today. As shown, we expect to grow supplies to more than 1 1/2 billion cubic feet a day by 2005, resulting in a average growth of around 15 percent a year. By 2005, we should have grown our global market share to 8 percent from the 5 1/2 percent we currently have today.

The right-hand side of this chart shows our success in building markets ahead of supply. By the end of last year, we had already captured enough markets to secure with cover all of our growth for 2005. In fact, our recently announced short-term supply arrangements with Abu Dabi (ph) in Qatar were done to cover our market long position. Of particular note was our success in China last year, which has been coined by some industry observers as a triple win. BP and its partners secured long-term agreements to supply 2.6 million tons a year to Fujian (ph) province from Tangu (ph) province in Indonesia, where we have a 37.2 percent equity interest. We also gained 3 million ton a year supply agreement (inaudible) from the northwest shelf, where we have an equal 1/6 interest owner.

In addition to these two supply agreements, we also sanctioned the first phase of the Guandong (ph) LNG import terminal, in which we are the sole foreign partner. This terminal, coupled with Fujian and Guandong market capture give us a leading position in these two rapidly growing provinces which between them, account for over 16 percent of the GDP of China.

The last point to make is that market length created has a longer term purpose. If we project our supply position to 2008, you can see that we're well on our way to securing sufficient demand for one additional in Trinidad and Tangu. Capturing markets ahead of supply allows Tony and his upstream colleagues to focus on optimizing development costs in the absence of uncertainty around market, it also creates significant value by allowing us to move gas into higher margin markets -- Trinidad is a case in point. BP gas from Trinidad should grow from around 550 million cubic feet a day to 1.1 BCF a day, when trains two and three ramp up. This can grow to north of 1 1/2 billion cubic feet a day with train four by 2008.

As shown on this map, LNG from Trinidad can move to multiple markets, with a large percentage free to move to the best of these. Taken together, our three new ships, very strong downstream market positions in both the United States and Spain, and our short-term supply positions with Abu Dabi in Qatar present us with significant flexibility. BP and partners are taking a market based approach to the LNG business, instead of relying solely on the traditional point to point approach. We believe this will give us new access to performance in the LNG business.

Of course, this is just a snapshot of February 2003. Demand patterns continue to change. In the United States where replacing resources becomes increasingly more difficult, and in Europe where the liberalization process continues to progress. Whatever the outcome, BP and its partners in Trinidad are well positioned to meet the market demands of the Atlantic Basin.

Ladies and gentlemen, I hope this gives you a sense of what we do in the gas, power and renewables segment. We add value to the group's gas and NGLs, and we're in the process of building a serious renewables business, and I hope from what I said it's clear to all of you that the heart of everything we do is business marketing.

I would now like to turn the podium over to John Manzoni, who will take you through the refining and marketing segment. Thank you very much.

Thank you, Ralph.

Ladies and gentlemen, I'm delighted to talk about the refining and marketing business, and there are three main points I would like you to take away from what I have to say in the next few minutes. First of all, that rapid growth has led to a larger and stronger footprint. This has created a new platform. Second, that we have four different business models inside what we call refining and marketing, each has access to growth opportunities and we're focusing our investment into those opportunities. And third, that we built a track record of constant or expanding underlying unit gross margins over the recent period. This has been achieved by portfolio choices and also by driving productivity and that is a trend that we plan to continue.

As John said in his introduction, the recent period since 1998 has been one of rapid growth in the refining and marketing business. After a decade to the mid-'90s of a stable asset portfolio with refining throughput and marketing volumes around 2.1 million barrels a day, mergers and acquisitions since 1998 have substantially changed the shape of this part of the portfolio. Average capital employed has almost doubled as illustrated by the bars on the left hand chart in front of you. On the right, you can see that marketing volumes have increased by about 48 percent over that period. Refining throughputs have grown by about 15 percent and refining cover now stands at close to 68 percent. And we now serve nearly 13 million customers each day through our collection of powerful brands. They include ARCO, Castrol, Amoco, BP and Iral (ph).

As we grew, we also divested to improve the quality of the portfolio, and this totals about $6 billion since 1998. Actual average returns over the period in the last decade have been averaging about 5 points higher than the previous decade. The results of our portfolio actions combined with the synergy delivery associated with the various deals has resulted in continuing improvement in efficiency. While absolute costs have increased with the portfolios size, this has not been at the expense of efficiency. Costs per unit of gross margin have reduced around 18 percent over the period since 1998. Now although we anticipate the rate of efficiency improvement, that's the yellow line on this chart, slowing a little in '03 as we complete the synergy delivery from the most recent labor transaction, here the cost reduction plans are in place for this year. We have programs in place today which target cost savings of more than $300 million this year and examples of these are all across our business.

They include a significant simplification of our IT infrastructure across Europe, a move to simplify supply chain activity in the lubricants business, programs to reduce overhead costs across Europe and the United States, and better procurement practices throughout all of our businesses. Also during this year we will be designing a more fundamental intervention to reduce the transactional complexity in our system, which has resulted from the bringing together of several companies over the last few years. I see this process as making a significant difference to our cost to serve in '04 and '05 and this year we should begin to define the benefits more clearly and also to begin its implementation.

The real power of the portfolio is manifested through its brands. Where we choose to compete, we aim to occupy a number one or number two position in the relevant market segments. In Europe, we're the second largest fuels retailer overall and the largest fuels retailer in the biggest market, which is Germany. We have over 2,700 outlets in Germany today, mostly branded Aral, and this gives a gasoline market segment share of about 22 percent. And we have number one or number two positions in most of our other European markets. We are the largest automotive lubricants marketer across Europe with a 17 percent segment share. And again, the largest player in Germany.

In North America here we are the largest -- we are the second largest fuels marketer with Amoco Ultimate gasoline giving us the highest premium grade ratio. We're also a leading player in the automotive lubes. And we're continuing to develop our presence in China with our partners PetroChina and Sinopec. We've established 324 joint venture stations so far with a plan to reach about 500 by the end of this year and more than 1,400 by 2007. And we're ahead of our competition in this investment. And in India, Castrol is the leader in the automotive lubricants segment. These are very powerful market positions and I want to come back to link them with returns and gross margins.

As John has said, we think of our refining and marketing business in four distinct business models; retail, refining, lubricants and business marketing. Each of these businesses is quite different and in the interest of time, I will describe the key aspects of only three of them today; refining, retail and lubricants. Business marketing will wait for another day. I'll come back to these market facing businesses in a moment, but first, let's talk about refining. Our refining portfolio is selected through a series of lenses; refinery configuration, location, and distinctive value to BP, through integration either with Petrochemicals or with marketing. We believe that the portfolio actions we've taken using these lenses have resulted, for us, in an advantaged portfolio. And we had a disciplined approach to investment over the last few years. Our investment into clean fuels is expected to reach a peak in '03 and this year we plan to invest around $300 million on clean fuel capability across our system.

An example of this year's investment is the isummarization (ph) unit at Cherry Point Refinery in Washington State, which should give an immediate uplift to the margins available to that refinery. After that, the investment level is expected to reduce again. We believe our system will require around $800 million of base capital investment annually in steady state to maintain competitiveness and to expand the gross margin. And of course, as investment declines, we expect cash flow from our manufacturing base to increase strongly.

The average refinery size in our system is about 220,000 barrels a day, which is larger than our competitors and thus brings us unit to cost advantages. We have a track record of improving unit costs since 1998, as you can see from this chart. We see small increases in '03 due to operating a more complex plant to comply with the Clean Fuel Specifications that I've just discussed. We've also seen improving availability over the period since 1998. Availability was 96.1 percent in 2002, making our refining system top quartile and we intend to continue to drive this sort of performance.

This next chart is an expression of the quality of the portfolio over time. The bars show the improvement in the unit gross margin of our refining system at a standardized set of trading conditions against the base of 2000. This improvement is driven from a combination of four factors. First, we've been improving the operating factors in our refineries as I've just described. Second, our portfolio selection has resulted in our refining system producing higher value products. For example, the refineries acquired through Vaba (ph) have added nine percent to our upgraded capabilities.

A third factor is that the flexibility of our refineries has allowed us to continually improve the effectiveness with which we source crude oil for the system. And finally, we invest selectively in the assets to improve their operating characteristics and specifically to increase the unit gross margins. Absolute gross margins have ranged from around $3.10 a barrel to around $5.70 a barrel over the last three years. While underlying gross margins of standard conditions have expanded by over $1 a barrel from 2000 up to the end of 2002, we've planned further expansion in 2003 and beyond.

So before I move to the marketing businesses, I want to summarize refining. We've been highly focused in our investments into the refining sector and concentrated on ensuring clean fuels compatibility for our system. This investment should reach a peak in 2003 and decline from this point. Underlying returns have been increasing throughout the period, driven by improved operating factors, especially unit costs and availability. And our unit gross margins are expanding due to the portfolio and operating actions that I've described, but also by how we supply our system with crude oil.

Next to retail. Again, I want to relate the improving quality of the portfolio and the growth opportunities. The retail portfolio has grown considerably over the last few years and overall volumes sold have increased by more than 45 percent since 1998. We consider our retail portfolio as a series of individual markets and select those markets which either offer growth potential through convenience shopping, they tend to be in the metropolitan areas, or where we can have a powerful fuels brand presence and grow with the fuels market. If the markets don't meet those criteria, we divest them and utilize the funds for reinvestment into our convenience strategy in our core convenience markets. Over the last four years, we've generated about $2 billion through divestments and organically reinvested about $4 billion. And I would expect divestments to continue into the future at between four and six percent of the capital employed base as we continue to focus and high-grade our markets.

Our convenience strategy is focused on three formats for investment around the world. First, there is BP Connect. We had 486 Connect stores at the end of last year and we plan to build around 75 more this year. These are fabulous stores and they have store sales approaching one and a half times those of the average of our portfolio. Second, there is AM/PM on the West Coast of the United States. These stores have the highest (inaudible) rating of any gasoline convenience store on the West Coast and sales have been growing consistently at five percent per annum. And finally, there is Aral in Germany where we plan to increase the sales per square metered -- per square meter from 7,800 today toward (ph) our German average which lies at ()$11,300 for applying our merchandising skills. The results of this strategy are shown on this chart. We've seen a convenience growth rate of 6.6 percent per annum on a like-for-like basis since 1998 against an average market growth of three percent. And we see this differential growth continuing this year and beyond.

So in our convenience strategy we have a strong track record and we have an exciting set of future opportunities. At the same time, we must acknowledge that we have a lot to learn in convenience retailing, so there is room to travel here.

Turning to our fuels markets, here we intend to continue to roll out our brand presence and concentrate on the quality of our product offer. As I've mentioned, we enjoy the highest premium grade ratio here in the United States through Amoco Ultimate and we plan to build on this into the future. We will, in general, aim to reduce our own capital employed in the fuels markets without compromising the product offer or our brand coverage.

But it is not only portfolio and investment. We are also in action to improve the performance of our retail business through its operating factors. We have to be constantly in action here to offset a margin which, over time, would otherwise decrease as a result of the competitive forces in the marketplace. Our investment into convenience markets is showing through in the blue bars. We're getting better and better at operating our stores. And, as the portfolio contains more fully invested convenience stores, the sales per square meter in our system have increased 14 percent since the year 2000. The red line shows the average through-put press (ph) site increasing as we continue to divest the poorer sites and reinvest into bigger, more efficient sites. In 2003, it should average 4.2 million liters per annum per site. And as the yellow line shows, the unit costs are continuing to reduce. So our operating factors are all moving in the right direction.

And these portfolio and operating improvements should act to offset any natural decline or even improve the unit gross margins from our retail business. The total gross margin, and from our retail sites, comprises what we take on fuels and what we earn in the shop. We can influence the fuels gross margin by careful selection of markets. For instance, the addition of Vaba (ph) and Aral into the portfolio with its very powerful position in the German market, helped to underpin the fuels gross margin in the last year. The shop margin derives from the investment into convenience stores and is increasingly serving to underpin the total. Today, it represents about 20 percent of the unit gross margin from our retail business and we intend to grow it. Overall, the total unit gross margin from our retail system has been around 3.5 cents per liter over the last few years and has held remarkably constant as increased shop margin has offset a declining fuel margin. As we continue investment into the convenience markets, we plan to underpin and grow this further.

So to recap what I've said on retail, we will continue to drive top-line growth through focused investments into high quality sites and stores with a bias for sites with a convenience offer. We will also aim to continue expanding our unit gross margin through capital portfolio choice, that's about where we do business, through investment into convenience offers in metropolitan areas and running those stores well, and by continuing to improve the unit costs across our entire portfolio. Some of this expansion will inevitably be taken up by the market, but our track record to date has at least offset this effect.

Finally, the lubricants business. This part of the portfolio has also grown strongly over the period. Revenues in 2002 are up ten percent since 2000, as you can see from the red line on this chart. The combination of BP and Castrol has created a very powerful platform for growth. The lubes business delivered all of its target synergies a year ahead of schedule and, at the same time, continued to grow revenue throughout the period. The improved efficiency has demonstrated clearly in terms of reduced unit costs. This right hand chart shows the power of our brands. This is a business model which is founded in its brands.

Through the power of the brands, which are based on technology and technological solutions for customers, our lubricants business has grown consistently ahead of the market, thus growing market segment share. We've not only grown ahead of the competition, we have also continued to expand the unit gross margin of those volumes. This has been achieved through a combination of continuously upgrading our offer to meet our customer's needs and also by driving efficiencies through the entire supply chain. This is a powerful story of brand-led growth through carefully segmented and targeted customer groupings which offer the potential for material and profitable new offers and, hence, further revenue growth.

We've also seen success in expanding the geographic footprint of our business in countries such as China and Russia where our business is growing in excess of 20 percent per annum. Helped, I might add, in Asia, by our association with David Beckham (ph), who is a massively popular figure in that part of the world and is also associated with our brand.

And lastly but important for lubricants, we continue to work very closely with many of the auto makers to jointly create solutions for the needs of their next generation of engines.

So to summarize. We have built a platform over the last few years, we have leading market positions, and very strong brands. Each of the four business models which make up our refining and marketing business offers potential for more performance and more growth. I've shown you that we've been able to hold stable or increase unit gross margins in each of retail, refining and lubricants and we see opportunities to increase this further. We have a track record of reducing unit costs. That continues this year. We have firm plans for more than $300 million of efficiency improvements and this year we will begin a more fundamental review of how to simplify our business. And finally, we will focus growth investments into four areas; into convenience markets, into new markets such as China, we will be highly selective in refining investments for clean fuels or for operating improvements, and into our brands to drive unit margins and volume growth. And so that's how we're seeing the portfolio and opportunities for the refining and marketing business today.

Ladies and gentlemen thank you very much and with that, I will hand over to Ian Kahn.

Thank you, John. Good morning. I'm delighted to be here today for the first time talking to you about the Petrochemical segment which, during 2001 and 2002 has reset its strategy and taken a number of actions to improve performance inline with that strategy. I'm particularly pleased to inherit a team that's so committed to the safety of our operations, which has improved significantly in the last few years. As you've seen from the results, 2002 was a very successful year for Petrochemicals after a disappointing operational performance in 2001.

I'd like to start by setting 2002 in the context of the transformation of the Petrochemicals segment since the merger of BP and Amoco, which was announced in '98. This slide shows the significant progress we've made in our business since that time. The green bars show production capacity in millions of tons, as indicated by the right hand axis. By the end of 2003 we expect to have grown productive capacity by over 40 percent since 1998. While building capacity, we've also been refocusing our portfolio during a period of close to bottom of cycle conditions. This is a refreshing approach in an industry which is often known for over expansion at the top of the cycle. I'm going to overlay on the chart the progression of BP's gross margin per ton over the period, indexed to '98. BP's gross margin per ton has only been declining by an average of about three percent per annum over the period to 2002.

This is against average industry petrochemical margins which we estimate have declined by about six percent per annum over the same period. This relative stability in our margin structure is primarily due to the product we're focusing on and the shift in the mix of our portfolio as a result of our divestment program. The capacity growth and stable margin structure mean that its (ph) standard conditions, BP's gross margin dollars have been growing significantly. We have done this while simultaneously reducing our cash fixed costs, which we expect to have reduced by nearly 20 percent by the end of this year. When combined with our capacity expansion, cash fixed costs per ton have steadily been reduced on average by ten percent per annum over the last four years and we expect them to have fallen by over 40 percent by end of 2003 as shown by this next overlay.

All of this is significant. The earnings potential of the Petrochemicals segment has been materially enhanced over the last five years. We are now well placed for any improvement in demand and accompanying gross margin expansion to have a significant beneficial effect on our increment cash generation.

And we have not been expanding capacity and improving unit costs in just any Petrochemical products. We've been increasingly focusing our portfolio on seven core products, which with one major co-product, today represent about 70 percent of our capital employed and our production capacity.

Our intent is for those products to become increasingly our focus over the next four years. Let me introduce them to you.

This chart shows our seven core products. These have been selected for four reasons.

Firstly, large market segment shares. We now have a leadership position in each of these products in terms of market share. We define that as having a number one or number two global position with the exception of ethylene, which with its major co-product propylene, has regional markets, for logistics reasons.

Secondly, growth. Their growth rates are generally higher than average for Petrochemical products. Taken together, our core portfolio has typically enjoyed growth rates of two to three times GDP.

Thirdly, technology, BP has distinct technological advantage in three products, PTA, acidic acid (ph) and accrue night trial (ph). In each of which we're also the global market share leader. BP's technology is also amongst the best globally in our other core products.

In the case of PTA, which is the fundamental building block of polyester for fibers and packaging such as drinks bottle, we have a global market segment share of about 20 percent. And our technology continues to lead new expansions.

As an example in January, we've just brought on stream a new 350,000 ton PTA plant at Juhi (ph) in southern China. Driven by proprietary state-of-the-art technology, the plants achieved a 44 percent reduction in equipment requirements and 30 percent reduction of site waste creation when compared to our previous designs. It was also delivered on time and is top quintile globally in terms of cost.

And the fourth criterion, integration value. Some products are natural territory for a company like BP and there is material integration value with our other activities, such as refining and NGL (ph) production. This applies to equity and production from cracking NAFTA ethane (ph) natural gas liquids, and the leadership position we have in production of parazylene (ph) from refinery streams. Parazylene (ph) is the key feedstock for the manufacturer of PTA.

Today BP's production capacity in our core products, tosspropalyene (ph) is nearly 24 million tons as is our total Petrochemical capacity of 34 million tons. This makes BP's portfolio distinctive. Not only do we have the third largest Petrochemical's portfolio globally, but it is increasingly focused in a few core products with distinct competitive advantage and upside earnings potential, and our future plans involve targeted investment to strengthen our positions in these core products.

In addition to our investment program and extension of our technological advantage, our aim is to add material value to these positions through expanding gross margin from marketing and optimization of the value chain. Collectively through these actions we plan to deliver further improvement in our underlying returns.

I'd now like to turn to our internal plans and outlook for the segment, particularly regarding investment levels, portfolio management, and returns.

This chart shows BP's investment history in Petrochemicals for the last four years and our view of the period to 2006. The bars indicate total investments with the blue bar representing capital expenditure in BP controlled operations, and they agree about our share of investments made within all of our joint ventures. The organic line represents the proportion of our Petrochemical capital employed, which is associated with our core product portfolio.

First the investments. During the last four years we have see higher than normal investments levels. For instance in 2000 and 2001, due to one-time spend, particularly related to our practice of buyer's interest in Hurdol Kami (ph) and our investment in the Solva (ph) joint venture. These investments, plus our share in the bay back position have repositioned three of our core products, ethylene, polypropylene and HDPE (ph).

Stripping out inorganic activity, our underlying investments have averaged about $1.3 billion per annum over the last four years, a level which we believe to be appropriate for the competitive development of our leadership positions in our portfolio. You will see that from this year, we plan to return to this level including all the joint venture investments.

The projected increase in our joint venture investments over the next three years is largely associated with the world-scale Shanghai ethylene cracker complex or SECCO, in which BP has a 50 percent interest, and which will give us a strong position in the growing Chinese ethylene HDPE (ph) polypropylene and acquillonitrial (ph) markets.

When combined with our acidic acid (ph) and PTA investments, we will have a material presence in China in six out of our seven core products.

Now divestments. Over the last four years, BP has made Petrochemical divestments, certainly $1.3 billion. Today, our strategic focus on a narrower portfolio makes future planning quite straight forward.

In short, those businesses outside of our core portfolio, they're co-products and closely related activity will be reviewed for sale by 2006.

As a result of these portfolio actions, our plans suggest that about 90 percent of BP's Petrochemical capital employed will be associated with our core products by 2006.

This level of focus is not expected to result in shrinking the business over time. Over the next three years we project production capacity to grow slightly overall, with our core portfolio growing at about six percent per annum.

By 2006, we believe our Petrochemicals portfolio will be one of the most focused in the industry, in terms of high growth products, proprietary technology and market segment shares.

When these portfolio actions are combined with those in the areas of continued cost reduction, application of technology and value chain optimization, we would firstly expect that net margins would expand standardized conditions, and secondly that BP's Petrochemicals portfolio will deliver an improvement in underlying returns of three percentage points by 2006, relative to a 2002 baseline.

So in summary, I'd like to leave you with four points. Firstly our portfolio is distinctive in its margin structure, and its exposure to the upside with (inaudible) by 2003, earnings potential underscored by a projected 40 percent increase in capacity since '98, with the simultaneously almost 20 percent reduction in cash fixed costs.

Secondly, that capacity is increasingly focuses in seven core products with distinctive growth rates, proprietary technology, leadership positions and integration value with the rest of BP.

Third, through portfolio actions, we anticipate that about 90 percent of our Petrochemicals capital employed will be associated with those seven core products by 2006.

And finally, with our current plans, our Petrochemical segment is designed to deliver a three percentage point improvements in returns but standardized conditions, also by 2006.

Thank you and I'd now like to hand you back to John.

Ian, thank you very much. Now what I'd like to do is try and briefly as I did yesterday, to Russia, and then summarize where we are. There's as second hand-out on your tables, which has been titled Russia, which covers what I'm going to talk about.

The new upstream, profit centers we've talked about, some of the most attractive accessible hydrocarbon provinces in the world, that is the ones outside OPEC, which are open to international investments. But of course there is one other area that falls into that category, probably the area with the greatest potential of all, Russia, the world's largest oil and gas producer.

Now we in BP established an initial base in Russia in 1997 and having learned a great deal about doing business there, we now feel the time is right to do more. You'll recall that we entered Russia in 1997 and the end of '97 with purchase of 10 percent of Sidanco. The present ownerships and management structure of Sidanco was established early in 2001 and since then we've built an important relationship of mutual advantage with Mikhail Fridman and the other owners of Alfa-Access Renova called AAR.

In the process we're learned an enormous amount about doing business in Russia. Over the least year we've been discussing with them the merger of our interest in Sidanco and TNK and an increase in our stake in the consequentially new, newly created entity.

Now our examination has taken about a year, because we've completed a very thorough and detailed examination, including expensive physical inspection of the assets and the liabilities. We've also been discussing with AAR how best to govern the new entity so that all parities could protect their assets and not adversely shift liabilities between each other.

After that review. We reached agreement with AAR to merge, subject to the approval of regulatory authorities, our interest in Sidanco and TNK, and to create a new company, which for the moment we'll call Newco. Once created, this will be Russia's third largest oil producer. BP will purchase a 50 percent share in Newco, subject to legal and regulatory approvals. The assets and nature of Newco and the way in way the downstream adds value to production are described in your handout.

This is the first time a western company has had a significant Russian involvement in the recent past, that is the last 86 years. We'll pay $3 billion in cash at closing, $3.75 billion in equal annual payments of $1.25 billion; however in ordinary shares at the end of each three anniversaries, subsequent to the closing. The shares then will be valued using the 30-day average price, immediately proceeding those dates. The transaction assumes Newco debt of $2.1 billion. Closing should take place sometime in the summer and the effective date of the transaction is the first of January 2003.

We are taking to Newco our existing interest in Sidanco, Russia Petroleum and subject to partner discussions, our interest in Shakalin and the Moscow retail system.

As part of the agreement, AAR will retain its 50 percent interest in Newco until at least the end of 2007. The structure of the transaction is designed to put economic incentive behind this retention.

This slide shows a selection of relevant comparable valuation metrics. As you can see, the purchase is made in line with the valuation of other Russia majors, but at a considerable discount to BP.

The range of estimates on reserves is at the lower end, BP's own estimate and at the higher end, the estimate made by Miller and Lents on behalf of TNK. Incidentally this distinguished company is also gotten estimates I believe for look oil (ph) and ucos (ph).

The UK's production in 2002 would have been over 1.1 million barrels per day and BP's accounted entitlement over and above our existing interest in Sidanco would have been over 460,000 barrels per day. No separate value has been attributed to Newco's downstream assets, though these should clearly have value later. No value has been attributed to Newco's gas resources.

We believe we are not only paying fair value for a 50 percent interest in Newco, but that there is great potential to go beyond today's value as this slide shows.

That's the purpose of this transaction and that's why it's a very important and exciting step for BP.

Synergies and cost reductions come from the combination of TNK and Sidanco as well as from a continued improvement in operating performance.

The potential for production growth, which is shown in the handout is a continuation of the historic successes for TNK and Sidanco have had where confident of the reserves available for this growth.

BP will bring its extensive experience and expertise in integration and operations to deliver all this potential using the tools that Tony described. The focus on economic maximization, the management of reserves, the extension of capacity and the achievement of best-in-class operations.

The future growth options which are also described in the handout include the long-term developments of the existing resources in Russia Petroleum and the development of the large gas condensate field in Rospan.

As most of your know, pricing in Russia is two-tier, 44 percent of Newco's production is exported and gets international prices. And around 15 percent of its product from its refineries are also exported.

Domestic prices are much lower. Over a period of time, there is a chance that effective realizations may rise to more international levels as a result of increased expert capability, improved product quality and ongoing Russian economic development and reform.

So what is the financial impact on BP of this transaction?

The transaction will be accounted for by the equity method. Investor Relations will give you the details, but if I may in essence 50 percent of Newco's production on operating profits, along with our total investment will appear in our accounts, operating profit includes the amortization of our purchase price.

We estimate that BP's gearing will increase by two and three percent when the deal closes. The effects of this incremental gearing should reduce to around one percent as the share components are actually issued.

The transaction should be immediately accretive to both earnings and to return on capital employed. UK will distribute all available cash each year to its shareholders after funding its capital investment program.

We project that even at standardized assumption, that is at $16 Brent oil prices, Newco will generate sufficient cash to fund its investment program and will need no additional capital from the shareholders. This is important, because it gives our shareholders exposure to Russia through a self-financing company.

Of course, we recognize that many people regard Russia as a risky place in which to invest. We believe we've learned a great deal over the last few years, which will help us to mitigate that risk, and as I've described, to design the transaction in a way, which insures that there is a genuine continuing common interest in success.

The payment process, the pricing structure and the agreement by AAR to retain their interest all underpin our confidence that the risks are limited and manageable. So does our experience. We also and most importantly, have established a governance structure, based on principles, which shall protect the interest of our shareholders.

BP and AAR have expressly agreed to apply Western corporate governance principles, as practiced by BP. Newco will be incorporated outside Russia. The board will consist of 10 members, with five appointed by BP. The board will operate to insure that Newco strategy is enacted and will delegate operational authority with limitations to the CEO, who will be appointed by BP.

These appointments combined with an improving Russian legal system are continuing partnership with AAR, their retained interest of 50 percent and the trust that has been built up should all converge to protect our interests.

We're also determined to work to improve standards of care and safety and the environment to bring them up to the BP level, but I think that may take some considerable time, but it is a clear and agreed objective.

So this is a very exciting step, this transaction is a major step in support of our overall strategy. Newco will become the sixth new profit center and in common with the others, it offers enormous long-term potential, beyond the current activity set.

This will be greater in scale than our other new profit centers, contributing at 2002 levels 13 percent of our production. It's capable of improvement, and we believe that it rivals any other potential involvement available anywhere in the world.

I know we all believe that this is a great moment in the history of BP and of TNK, and indeed, an important milestone in the history of the industry.

It marks a step change for both companies and establishes a business, which will be able to meet the competitive challenges ahead.

This transaction makes Russia a very important element in the long-term renewal of BP. And we're very pleased to be part of Russia's future, because this is investment decision is based not only on detailed analysis, but also of many years of unique experience in a country, which is going through a process of fundamental reform, at a very encouraging rate. A country reviving its historic position in the global oil and gas industry, and a country providing important security of supply to the world.

Now if I may, I'd like to sum up and return to the slides in you main handout.

How do all the things that we've talked about contribute to our remaining target set in 2000, which as you know, is to produce underlying double-digit earning growth of standardized assumptions on average over '00 to '03. This chart illustrates delivery so far and what remains to be done in '03. We believe we'll deliver in full on this target, because we have in place sufficient capacity additions, gross margin improvement programs and cost reduction programs.

Of course these estimates for 2003 do not include the effects of acquisitions and divestitures in line with all other similar estimates in this presentation.

This is the last time I will address this particular measure. As the 10 percent annual compound growth target, reflected a period of post-merger synergy capture, it's now drawing to a close. Increasingly, this single measure no longer reflects how we measure or manage our business, although we still recognize the importance of underlying earnings growth both to you and to us.

What about the pattern of investments?

Here's a chart of capital and divestments. In 2002 our net investment was high, because of the acquisition of Veba, and you can see in '03 and '04, estimated capital spending is unusually high due to the five new profit centers upstream.

We expect divestments to continue at a level of three to $6 billion in '03, within the recent historic range. We aim to keep our gearing in the band of around 25 percent or around 35 percent as measured by debt-to-debt plus equity and that gives us some headroom if trading conditions get worse.

Then margins.

We talked, as I've explained, in terms of standardized margins. Standardized assumptions in order to see how cash flows are balanced on a consistent basis, but of course, we actually a price taker and it's important to understand how responsive our margins are to external conditions.

Now this chart, which is clearly intended for your later study, shows the way in which price realizations refining or chemical margins have moved over the last five years. And the way in which a $1 change up or down would affect replacement costs operating profit.

DUE TO LENGTH OF CALL, THIS PORTION WILL BE TRANSCRIBED OFFLINE

... two questions. First, on Russia. I assume, given your rigorous return discipline, that in your analysis and assessment of the Russian opportunity that to take into consideration the unique and additional geo-political risks that you assign some increment to your traditional hurdle rate. And I was wondering if you could clarify and comment on what that increment is.

Secondly, for John Manzoni on the downstream side, I listened very carefully now, twice, to your eloquent, articulate remarks, including commentary with respect to Vabor Synergies (ph). Yet, there appears to be a disconnect between what you said and the actual performance of the business unit, particularly with respect, potentially - at least from an outsider's perspective - to debay (ph) the contribution, which just does not appear now in the entire second half of 2002, anyway, to be coming down to the bottom line. And I was hoping that, perhaps, you could clarify the nature of that disconnect, or if my judgment is just terribly poor.

Well, Mark, thank you for those questions.

I'd like to ask John to answer your second part first, and let me come back to the first part. John?

Sure. Mark, let me try to illuminate for you. I think you're speaking into something which exemplifies the complexity, I think, that the industry is finding, this year, in particular, or for last year, in particular, which is the difference between what you might observe from looking at what I would call "refining indicator margins," and what, actually, happens inside the company. And the reason for that is the particular circumstances last year, and this is true, both globally and in Europe, which is speaking to your Vabor (ph) point. There is a divergence between what the indicator margins might lead you to believe would happen inside the refining system, and actually, what we and others have reported in terms of the performance.

And it derives from, really, two factors; the first is the withdrawal of heavy crude oil with Venezuela coming off the market (inaudible) at the back end of last year, which made the heavy crude oil at these refineries relatively more expensive. It's not picked up in the indicator margins that you are using to see what happened to the Vabor synergies (ph). And the second is that as you have a very high, rapid increase in crude price, large chunks of the bottom of the barrel from the refineries are not related to the crude price, so there is a divergence again between the products that we put out and what one might anticipate, given the crude price rise.

Those two factors speak to a - in fact, what we saw, for instance, in the fourth quarter of last year, was a lower refining margin than the fourth quarter of the prior year. And the indicated margins would indicate quite the opposite.

I don't think we're alone. I think much of the competition experienced the same thing, and indeed, have articulated the same thing.

That's one thing. I think, specifically, in Europe and to do with Vabor (ph) - in addition to the conditions that I've just described in Europe, we did have some operational issues in Northwest Europe, in particular, with one of our refineries having a crude unit down, which actually impacted our performance at the back end of last year in Northwest Europe. But, I think that was a smaller issue than the one that I've just described, which I think is a more general explanation of the issue, here.

Thanks, John. Now, Mark, I suppose all of us know that there's a limit, and I think I said it in my talk just a moment ago, about what you can do with numbers. I don't think it's possible to model things with mathematical spreadsheet precision, and I'm sure all of us know that - that we don't tend to mess around with the discount rate, because that somehow lulls people into a sense of false security. It says that if you put up the discount rate high enough, then you get a post event PB (ph), then everything's got to be all right. And that's exactly the way to reduce all forms of thinking, consideration and analysis, and to put everything into numbers and to do everything that BP never, ever does.

This is about analysis of many, many dimensions. It is about durability. It is about governance. It is about upside. It is about trying to understand what's gonna happen to realize prices. It's about the way in which we think we're gonna manage. It's about potential that we haven't even talked to you about, because we're not sure about it. It's wondering whether there is the linkage between the refining and marketing business in Russia, and our supply needs in Europe. It seems to me like they're next door to each other. But, I don't think we want to put any of that in. We want to sort of think about this over a very, very long term.

So, on the balance of all the things that you look at, you say, "we have enough ways of trying to find the path to get the right value." We know, for sure, that the one path you pick - which has to be a projection of a description of how you do things - is probably not the path that in the end will ultimately be the reality. I think we've found that, actually, in our experience and I'm sure in your experience of all the things that we've done. We have a very clear path, only to find out that actually a better path comes about as we go forward - be that in the merger of Amoco or Arco, or Burma Castrol, or the others we've done, or in the basis in which we invest in our organic activity.

I just say that because I think that it's important to understand we don't actually do things by trying to lull ourselves into a sense of false security by getting numbers which allow people not to think.

Al?

Yeah. Al Anton, Carl Forsheimer and Company (ph).

Just some questions on the Russian transaction. The first thing you mentioned, that the cash positive at reference crude price, but since more the half the crude is sold internally, and that price can sometimes be a single-digit number, I wonder if ...

Our math includes that single-digit number.

OK. All right.

OK. So, you know, if it's 44 percent of crude, it's 15 percent of product, which is not the best quality, so that does - that gets us a mixed price. And then the rest is domestic.

Very good. And the second question is allied to that, and that is with Trendnet's (ph) monopoly on exports, and the recent refusal, apparently, of a permit for a group to export through Marmansk, do you see this being a problem? Or, how do you see export capacity growing in the next three or four years?

Let me ask Tony. Tony, what do you think about this?

Well, I think there clearly is an infrastructure challenge in Russia today. There's no doubt about that. And there are a number of ways in which it can be resolved. And I believe that we will work with our new partners to find a way of increasing the content of Russian crude that gets onto the market. I mean, I can't actually give you the precise answer for that today. But, if you look at what actually happens in Newco (ph) today, 44 percent goes out as international crude onto the international markets, five percent goes into domestic sales, and the differentials there are very seasonal. They depend on - in the winter, less is able to go out through the northern ports, so the differential widens. And in the summer months the differential collapses. And then, the remaining 60-odd percent is actually refined, of which around 15 percent gets international prices. And clearly there is a lot of (inaudible) going on in Russia about how to create further opportunity to get - to realize international prices.

They apparently are playing games with the Latvians.

Well, I - you know, I - there's lot of ways in which Russian crude gets onto the market actually through trucks, barges, pipes, through refining. You know, that will continue and clearly new infrastructure needs to get put in place.

And finally with regard to the three tranches of shares to be paid, I assume that the share buyback will about offset that or ...

Well, I'm not going to comment on anything other than we've commented on at the moment, but I think I was pretty clear about the way the Board of Directors - we all think about the need to give shareholders not only value growth but growth in value today if I can contrast the two. We've done $4 billion of stock buybacks so far. We have a program now subject to market conditions for $2 billion. So I'd leave it like that if I can. Clearly these shares we're issuing are not being issued for some time. You know, they start being issued, but if we close sometime this year - let's say the middle of the year, it'll be '04, '05, and '06 (inaudible) a billion two five (ph) each issue.

Can I now go to Doug Terreson who is on the phone, and Doug, I'm sorry I didn't ask you yesterday.

That's OK, Lord Browne. Good morning. I hate to ask you another question about Russia, but I have a few. I wanted to see if you would elaborate a little bit on the key operational financial and strategic changes that have materialized over the past couple of years which make you feel obviously a lot more comfortable with the timing of your investment in Russia. And second, (inaudible) has been a pretty reliable provider of reserve estimates over the years especially in relation to some of their peers in Russia. But after having said that, you guys have used a reserve figure that's only about 60 percent of what they have provided which seems a little bit conservative but may be prudent. But either way, could you talk about the production level and/or the growth rate that the self-financing comment that you guys made applies to? Meaning, while I think you mentioned initial production net to the company of around 460,000 per day, do your projections include growth from this level without outside capital as you've mentioned? And if so, how much? That's two or three questions.

Thank you, Doug. I'm going to ask first Dick Olver just because of his experience here to talk about what's happened over the last couple of years of history in Russia which, you know, gives us any indication for the future, Dick. And then I'd like to ask Tony to talk about the reserve figures and the production level in line with Doug's question. Dick?

OK, just a couple of comments (inaudible). The first comment to make is that one of the things that we learned early in the Sadenko (ph) years was that the application of BP's expertise to disposal of crude and products actually gave a great advantage to Sadanko (ph), so higher gross margin was we were able to get from the existing production.

Lately (ph), the second issue will parlay into everything that I suspect that Tony will say, and that is that when a lot of these fields had not received the sort of attention that they might receive over a number of years, particularly of course through the difficult times that the Russian had had. And I think that once you start to apply BP's technology and ideas about what to do in these fields, then you see growth rates (inaudible) actually quite mature fields ...

OK.

... which are much higher than you might imagine. I've deliberately left off the numbers, Tony, to leave you to talk about the costs of supply and so on.

I think in terms of reserves, the only thing I'd say is that Leer and Lent (ph) have a lot of experience in Russia, and I think that what we've done is to look at this in a prudent way.

Sure.

Who knows what will happen eventually? And lastly, John, I think the only thing I'd say is the attitudes of the Russian people. I think that's changed enormously. They have an enormous desire to see a standard of governance that has not been typical. I think of course in the end there's an enormous desire to see western multiples, and this drives a lot of behavior.

Good. Thank you, Dick. (inaudible)

Doug, yes, it's always good to start with history. The new co (ph) would have grew around six percent in 2002, and we would see this growing around five percent over the next two to three years, perhaps leveling off a little bit after that. But we (inaudible) the capital (inaudible) capital in 2002 was around $650 million. That gives you some sense as to how efficient it is. It is of course because development costs are very low - less than $2 a barrel - between $1.50 and $2 a barrel. And the wedge production, which of course is all-important in this sort of mature development, is around five-and-a-half thousand dollars per daily barrel - that's what the wedge production is.

In terms of the reserves, we've done a very detailed. I mean I can't stress how much - you know, we've got reams and reams of technical due diligence on this. We've built up production skins for each and every asset over the course of the last year. So, we feel we have a very good understanding about the resource base. And we are being prudent in our view as to what it might be.

Sure.

In terms of where the production increment is coming from, there are three or four key things that will happen. The first, much of it is very simple. It's good operating practice. There are 8,000 idle wells in this new entity, so that's an access for - easy access for new production. There's a lot to do with de-bottlenecking and pump - optimizing the pumps on the surface. And then both T&K (ph) and Sadenko (ph) who last year had along with many of the other Russian companies Ukost (ph), in particular, have had very significant success with major frac (ph) programs, so we're going to be doing lots of fracs (ph). And then finally the - lot of opportunity for infield drilling programs. Though as Mike said, there's a very detailed analysis that underpins both the reserve estimate and the production profile increments that we're talking about.

Great. Thanks a lot.

Let me just add one thing. I, in my - and I've been through my own due diligence on this - I was very satisfied that the reserve estimates that we had made were consistent with those being made by BP for all of the other reserves that it has reported.

OK.

So therefore, it's internally consistent to BP. It may or may not be in - externally consistent with those in other companies who have assessed their reserves. And so rather unusually, we've given you a range. We don't like to give a range like this, but Leer and Lent is a very distinguished company. We've had a lot of experience with them. I personally have had a tremendous amount of exposure to Leer and Lent (ph), and so you don't likely brush to one side their analysis. You simply say, it's a different way of doing it, and so we are reporting it as their analysis or (inaudible) T&K)_ and our own analysis consistent with the way in which we would assess reserves in the rest of our portfolio. I think we have to leave it to people to examine that to see what it means.

So, I just say that just on the basis of why we've done this. I hope that answers your question.

It does, John. Thanks a lot.

Thanks a lot, Doug. Now, in the room here, please?

Thanks. Fred Leuffer for Bear, Stearns. I think the production profile that you presented today excludes the impact of asset sales.

It does.

But I think the asset sales could have two impacts - one, obviously they've lowered the base of reserves. But secondly, if you're selling mature properties, they should start to have an impact of flattening your underlying decline (inaudible). Can you comment a little bit, understanding that the timing of the deals will affect production, but just what it could do in terms of the growth targets that you have put out? It seems to me that they - those you stated fairly conservatively.

I won't - I keep - I don't want to sound didactic, but we don't have growth targets. Let's be clear. They are not targets. We have ranges. And I mean this in all seriousness. I know you're smiling and saying, "Well, he would say that, wouldn't he?" But actually I want to just - I want to just step back for a moment and ask (ph) the impact.

If you have a ROCE left unchecked, of course what would happen would be that we'd shrink the company to the last remaining gas station and the last remaining very, very old oil field with no capital employed. And then you get a big ROCE. So it's sort of says think about the past - not about the future.

If you have a production target left unchecked, it'll be out there and it could lead you to (inaudible) assets you shouldn't invest in or invest in (inaudible) base that (ph) actually is not the best place to invest or it may lead you to fail to hit the target, which is exactly what happened to us because when we looked at all the opportunities, we said (inaudible) target out, but actually it's the wrong thing to hit it for investors because it's wrong to sit on the assets, it's wrong to invest in the base, we have to go invest in the future. And that's what we're doing, and investing in the future is very, very important for BP because we have in our view - you may disagree with us - an unrivaled set of opportunities for the future. So, I'm very nervous about this because I believe it is a balanced set of things and then genuinely how we run the company. It's not a matter of hitting one thing after the other.

So, getting back to your question, clearly it does because these are (inaudible) declining assets than the average of the base and it will flatten out the decline curve which is not included in here. But of course it reduces the amount of production. We don't quite know how much this year because goodness knows when these asset sales very unpredictable for closing. But (inaudible) on top of that. We have a profile which comes in from Russia at some stage this year probably, which is a (inaudible) portfolio which really is larger than the asset portfolio that we are selling. So we're going to get a very interesting dynamic, and I think we want to see how all this comes about which changes the outward expression of the way in which production develops. But, yes, it will change the dynamics of the curves.

And I - we're not actually through yet, either. You know, I mean, I doubt - we'll never, of course, be through with looking at the portfolio because I come back to the point that the most important thing about the point of distinction is the quality of the assets in the market you're investing in. And it's not just at the high level - you know, big things like talking about something to do with the North Sea. It's actually the detailed analysis of exactly what there is in there with the detailed analysis of the markets and which markets we should be in.

(inaudible) you've had a chance if you don't mind. Yes, sir - behind you?

Dean Pasali (ph), Wilmington Trust. You have the number one position on the downstream of any foreign company in China. Could you comment or perhaps Tony could comment also on the potential for upstream projects over the coming three to five years in China going forward?

Sure. Can I just - if you don't mind, I might just ask John, Ian, and Tony (inaudible) this because we have a lot of petrochemicals in China.

What I'll do is reiterate our existing downstream position, which is building with our partners, PetroChina and Sydotech (ph), and it's actually a very exciting opportunity. In addition to that, which I didn't talk about, we have LNG, which is - LPG, I'm sorry, which is going extremely well - as well as LNG. LPG going extremely well into China, so we've actually got a very fast and growing position there which is actually very exciting in the downstream business.

(inaudible) petrochemicals, if I could just add that our main investments today have been in acetic acid in Chongqing in the center of the country, the (inaudible) acid plant I mentioned earlier at Zhuhai, and we're very excited with the new 50 percent share of the investment in the $2.7 billion complex near Shanghai, which we consider to be competitively significantly advantage. So quite a big program for us, too, in petrochemicals.

On the upstream, we've looked at China and (inaudible) personally over many years, and frankly we can't (ph) see upstream opportunities. What we do see, of course, is a tremendous market for gas. So our focus is actually the development of the upstream opportunities we've secured in Indonesia, for example, and in east Siberia made more - made even stronger with our transaction in Russia. We see it as - really as a market for upstream resource rather than (inaudible) upstream resource.

OK, we have some - yes, Madame, right at the back?

Yes, Tina Vital, Standard & Poor's Equity. Regarding new co (ph), given the difficulties of operating in Russia and the need to protect your investment and to have control over the operations of your investment, would you please explain what led you to an equity investment what appears to be in somewhat like a holding company versus a negotiation, perhaps, in some of the underlying - ownership in some of the underlying assets?

Thank you. Well, first, actually we think this is a particularly secure way of securing our interests given the nature of new co (ph) being a non-Russian company, being the divided interest in shares exactly, certain controls we've put in regarding the principal subsidiaries of new co (ph), the governance structure, the method of decision-making including any ultimate (inaudible) resolution with Swedish arbitration makes this quite a strong vehicle.

But I think rather more importantly than that, I think that our strategy in Russia is not to be a foreign company which plants itself down and says it wants special rights such as BSAs (ph) or special terms or special consideration in a country that's been at the oil and gas business for a very, very long time and has a high number of very, very highly skilled people and understanding of the - of the oil and gas business. We, therefore, felt that the approach, which we've always taken, to become a partner and to be a co-investor with Russian interests was the right way to go.

This is extensive - an expansive involvement. It gives us a vehicle through which we can do our investment. It also gives us the capability at the request of AAR (ph) as well as our own need to put in a significant amount of management (inaudible) CEO, some of the principal officers of the company, as well as technical experts covering specific activities that Tony's mentioned.

So I think, again, it's a matter of looking at the balance of the package that gives us comfort here in the way in which we go forward. Does that explain your question? OK.

Let's keep going. Sir, yes? Just going to keep moving forward, and then I'll turn to this side again.

John Parry (inaudible) - you used the 2.70 standardized price for natural gas. Could you talk about is that - that's - assume that's pretty compatible with your L&G plans. Can you just talk about that because there is a perception that it takes more to get it on shore. And I was just wondering if you could share that with us.

Sure. This is really with reference to Trinidad. Ralph?

In general, the cost of L&G have been falling dramatically over the last decade. And we would project that to continue to happen. We would expect L&G costs to drop by another 25 to 30 percent over the next five to seven years. For Trinidad, we've always planned at the standard assumptions and in fact our old mid-cycle (ph) assumptions for Trinidad to work. And the way I like to think about it is we can deliver Trinidad into markets here in the United States cheaper than wells out of Oklahoma if we've got this thing nailed.

Sir?

Good morning. I'm Robert Plexman from CIBC. Upstream question for you, John. Selling mature assets and focusing on the growth projects not only reduces the out (ph) cost, but also the capital required. And just looking for signs of that billion dollars you've mentioned in the past of capital that wouldn't be allocated to mature assets. I mean we know what the new projects are. That hasn't changed. But it's hard to see that $10 billion cap ex number for this year. Is that timing or are we looking at higher costs for some of the new projects? Or ...

It's purely timing, Robert. As I think Tony said, capital efficiency is in good track, S&Ds (ph) in good track, seeing federal improvements, we're drilling wells, so this is a matter of bunching and timing. And actually, as we - you're absolutely right - as we sell these more mature assets, the capital which would have gone in there will not go in there and it should level out this capital expenditure profile that we've shown you when we (inaudible) we see the timing of it all.

Anything else here? Now - yes, sir?

Thank you, John. It's Matthew Warburton from UBS. Two questions - one on Russia and one on Trinidad if I may - you mentioned in your comments about economic incentives to continue with the (inaudible) shelf structure of the new co (ph). I wonder if you could possibly elaborate on what those would be for your other partner. And obviously some joint venture do have put and call relationships at the end of the set period. I just wondered if one existed in this if a success goes. You're shaking your head, so that's a no on that one.

And finally, on Atlantic LNG (ph), obviously, there was talk last year about potential attempts by the government to redistribute the (inaudible). Given the growth there, I just wondered if there's any risk. Obviously, costs are coming down. You are getting a good resale on those assets, if there's any issue there.

OK. Well, first of all, I'd like to ask (inaudible), if he could, obviously, your first question. And then, ...

Sure.

OK. And both Ralph and Tony to the second.

One of those crucial things that ...

It's on, ...

OK. Sorry. One of those crucial things that we spent time with Freidman and his partners sorting out over recent months has been making sure that our strategic objectives and theirs are not in conflict by the way in which we construct the agreement.

Timing is of the essence here, and obviously, it's a pretty obvious point, but they have either got to decide that they're gonna be long-term investors like we are, or they've got to see the capacity for their investment decisions being made in 2003, four, five, six, and so on, somehow producing rent for them, whatever they chose to do with their investment stake.

Let me say right at the start that they have conducted themselves on the presumption that they are long-term stayers with us in this investment. There's absolutely nothing contained in the agreement by way of undertakings or expressions of intent that would give belie to that.

Secondly, we've made sure that the basis of decision making, particularly the requirement for a medium-term plan to be agreed right at the start of our new venture, ensures that we only enter on an assumption that they will commit themselves to a pattern of strategic investments and economic choices which is aligned with our own.

But, thirdly, the critical question of, "well, what happens at the end of the period in which their investment is, if you like, locked in through to the end of 2007?" Neither of us has thought or given any undertakings with regard to exit. What we have simply said is, "we will ensure that we run the company for the benefit of all the investors, and if that chooses not to be us in the future or them in the future, that the basis on which continuing investments are made will create value for prospective investors, thereafter, whoever they will turn out to be."

Let me just finish by saying there is nothing in the present arrangement which presumes the exit or change of investment activity by either us or them as part of the agreement going forward. Quite the contrary; we have structured it in such a way that either investor can continue to make long-term choices going forward, and that's why we have said we don't need any arrangements other than those that are typical in the industry, and that if one party chooses not to invest, there is a provision for sole risk investments by the other. And that's the basis on which we will ensure that this company will run to the traditional long-dated standard of our industry.

Let me pick up the Trinidad piece. I think that this goes back to John's closing remarks about the balanced approach to business. Trinidad's a great case in point where we've been working very closely with the government to establish a gas master plan that that nation develops in the way it would like to develop, and continues to prosper post the last drop of gas.

We are working closely. We're confident the train four, which is the next train to come through, will be supported by the government. Every indication is that we'll get that sanction this year.

I think that's part of the activity that we've put in to work very, very closely with the government in the way that these resources are developed.

Yeah, I've not much to add, really, other than to say that we use the principal of mutuality - basing a mutually beneficial future, and we've spent a lot of a time and have a tremendous relationship, actually, in Trinidad. We have a Trinidadian organization that's led (inaudible). I mean, we actually enjoy, I think, one of the closest relationships with any administration anywhere on the planet in Trinidad. And we expect to reach agreement on train four within the next month or so.

Yes, in the back.

Alex (inaudible), Citigroup Asset Management.

Just looking at the charts on page 12 on the upstream, I had a quick question. With the fill (ph) on capital from the build (ph) portfolio projected rising from nine to 14 percent, the overall what's done (ph) on capital in the upstream saying pretty flat over the '03 to '07 period. And the amount of cap ex isn't producing the (inaudible) return, declining over that period, and then flattening out. Just putting those things together, first, does that imply that the return on capital employed of reference (ph) conditions from mature part of the portfolio is declining over that period? And secondly, if that is the case, you know, given where commodity prices are at the moment, shouldn't we be looking at a stronger disposal program in the rest of the year than half a billion to a billion dollars?

Herein lies the problem with numbers. The identifiable capital expenditure - which I think you can get from here - of the nine billion centered (ph) for the future is 5.7 billion. It'd be slightly unrealistic for us to give you a model that said that it will drop down to that. So, we sort of put in an extra whatever it is - 3.3 billion, or thereabouts - and given it a rather average return, because we assumed that we'd also be investing again in the seventh and eighth profit center, and again bringing down returns. So, we didn't want to guild the lily and say, you know, "well, it's all over now, and, you know, these things will produce fantastic returns," and then come back and say, "well, actually, that's not true. We've got to invest some more." These are all phases.

I actually am saying that at the moment this particular phase we're going through is actually very unusual. It's a coincidence of the things we want to do. The fact we've got to - we're driving hard for gas markets, which is decidedly competitive, and winning them. So, that's Tobago and Trinidad. And also the fact that actually our competitors are in a terrible hurry where we're not the operator. We're operator of most of this stuff, but in terms of the bits that we don't operate, I'll tell you we operate ...

It's Angola where we're going.

It's Angola where we're being driven by another partner or two. So, all in all, it's a rather unusual time. It's a matter of degree.

Yeah, I understand the first part of what you said, but still, that unproductive cap ex start (ph) seems to come down over that time. I mean, what would you assume - or, not currently for that cap ex part - I mean, what would you assume would be in the change in inventory (ph) on capital for the mature part of the portfolio over that period then?

Well, it goes - turn here,

It's broadly flat.

It's broadly flat to rising, I think, as we get depletion of the old asset base. I mean, I'd put it like this: if it isn't, then we start looking at what we're going to keep and what we're going to sell. I mean, we keep high-grading the portfolio. So, it's not just an outcome. It's a management intent, I think.

Mark. Yeah. Your second go. And then, one up there and, well, yes. Mark.

I had a couple of questions for Tony. First, I wondered if you'd just give us a rough idea of what percentage of Newco's (ph) current production is under water foot (ph), or any other secondary or tertiary recovery method.

Second, in the context of your presentation, the swapping of you JDA (ph) interest Malaysia for Hess's acquired Colombian interest - it seems to be a transaction that doesn't quite fit the model too terribly well. And I wonder if you could, perhaps, comment on that.

Third and finally, on the optimization of post-tax - and I believe I heard you say that - margins, and increases and such going forward, I wondered if you help me understand how, when you have components of the new portfolio in such areas as Angola, Southeast Asia, Azerbaijan, and a tax rate implicit in the current portfolio, consistent with 34 percent overall, you're gonna get a net benefit on a post-tax basis of margin enhancement.

I'm may ask the CFO to help the last question out. Tony.

If I can remember, Mark, we had Russia first in that (inaudible).

There's tremendous diversity in this portfolio - I guess the first thing to say - from very large, very mature fields, which is (inaudible), which has been under-active water flood for a very long time, and other fields, which are still under primary depletion. If you take today's portfolio, it's probably around 75 percent is under water flood, on that sort of order.

That was the first question. The second question was to do with ...

JDA.

JDA, and I think ...

Why did we do that ...

Yeah, OK. I think this is - I mean, this is - thank you.

That's all right. I think did it, also.

He was asking me why we did it.

Of course, you know, (inaudible) different views of assets, as JDA was, that it was gonna be a long time before we got it on production. It was not gonna be material to us. We had an opportunity to sway it into a place where we have a very significant presence. We had the opportunity to realize additional barrels with no additional overhead at all, and Columbia remains an important part of the South American portfolio. It's not the biggest part of our portfolio, but we have a position in Columbia where we can exploit economies of scale in the way that I described. We control everything. We run everything. We have the infrastructure in place. So, finding opportunities to drag incremental barrels through that infrastructure that we've put in place is absolutely in line with the strategies that I outlined.

Now, the third one, which I was ...

Well, the third one - perhaps, Tony, we'll just give you a post-tax margin.

Can I just talk about the (inaudible) structure in total (ph)? Because I think it's an important point to understand.

There are a number of things going on. The first thing is, the crude mix is getting better. Lighter, sweeter crude, and the portfolio we have going forward relative to what we have today - that's a fact. It's what we've found.

The second thing that's happening is that the total unit costs - transportation, lifting (ph) costs and development costs - are all declining.

And the third thing is that production taxes over the time period that I've talked about are also declining. That is a consequence of two things. It's a consequence of our early access in to many of these placements, and it's the whole point about early access. If you get in early, you get better turns. We have better turns in Azerbaijan, enshrined in a PFC (ph), than anyone who came after us. The same is true in Angola. And the second thing is that there is a PFC (ph) effect happening over this time period, because we're in a period of cost recovery. And it's true for the time period where we are continuing to invest, and we are undergoing growth. That's why you're continuing to invest; you get cost recovery. And it is only at the latter part ...

(inaudible)

Well, there's a little of that, Mark. It's a piece of that, but it's a fact. You know, it is a fact. That's ...

If I may, I think, first of all, you have to, I believe, understand how we treat taxes. There are two types of taxes being talked about here. I think we shouldn't get them confused. One is production taxes - oil and gas take - which is attached to the margin here. The rest is the corporate tax take, which, of course, is the blended average rate for the whole corporation, which stay roughly constant.

I said it in my remarks, and it is important to distinguish between the production taxes, which are incorporated into the upstream structure, and what we talk about as the effective tax rate for the corporation as a whole, which excludes those production taxes.

And that's got to be constant.

(inaudible)

I said post-tax. I meant post-tax.

It's against the ...

It's in two pieces, two pieces.

Mark is saying production taxes are coming down. Corporate taxes are more or less of the same, so.

That's very important. OK.

Sir, at the back.

Thank you. First of all, I want to say that I've always viewed this as a price and margin business, so I would applaud your strategy now of providing parameters in terms of production profiles, as opposed to specific targets.

My question, actually, did specifically relate to the tax assumptions - reduction and otherwise - implicit in your implied improvement in per barrel profitability for your profit centers. So, Tony, thank you for your answer. I guess to simplify it, finally, can you give any kind of parameters in terms of the total anticipated improvement in per barrel profitability? What might we expect to be accounted for by some easing of the overall tax burden? Can you provide any rough parameters regarding your new profit centers?

I would say, if I may, stepping back from this, that it's small. But, in my view, it's very evident from the type and nature of now where clearly the barrels are gonna come from with some degree of uncertainty.

I don't actually think - we've sort of aimed off a bit on this, as well, saying that, you know, gross margin upstream - which is, actually, if you think about it, the gross margin is just a price minus the take in case of upstream gross margin - stays pretty constant, really, because it's very difficult to predict the ins and outs of crude quality, exactly how they price year to year. That very much depends on everything from oil scale (ph) rates to which refineries are down, and, you know, who, particularly, wants what type of product.

So, we are - we survey more for bid. But, I think if you look at the real trends - the real trends - and I think they are not just math; it's actually underpinned by what's going on - it clearly (ph) says the tax rates appear to reflect first mover advantage, which is important. And indeed, the differentials appear to reflect the fact that the, in general, the crude oils that we produce are actually of a higher quality - both adjusted for gravity and sulfur. And they appear to be in places where there isn't an adverse charge for being long-haul.

So, you can actually sort of underpin the argumentation by saying this is what you'd expect. Mathematically, I think it's a more difficult challenge to get to, because by that time you have to do a lot of very detailed assumptions.

So, I think it's there, but how much is there we don't know yet, I'd say.

Ladies and gentlemen, I'm told that lunch is now available in the Wedgwood (ph) Room, and we'd be delighted if you'd all join us for lunch. Thank you very much for coming. Thank you.

END