殼牌 (SHEL) 2004 Q4 法說會逐字稿

(Technical difficulty) Group Investor Relations for Shell. Welcome to our Q4 results presentation and annual results presentation. Before I turn it over to Jeroen, I would like to ask you to read our disclaimer, please -- take a few seconds.

And now, I'd like to turn it over to Jeroen van der Veer. Thank you very much for coming.

Thank you, David. Good afternoon, ladies and gentlemen. I'll start with an introduction. Then we have Malcolm and Peter Voser around to talk to you (ph). We'll take about half an hour, and then we'll take your questions.

2004 was a year of extremes for the group, but we are making headway. We achieved record net income and cash generation, which was largely due to high prices and margins. It was helped by strong downstream profits and operational performance. Our problems in explorations and productions are being addressed, and we have completed the reserves review. We have announced radical proposals for a much simpler, clearer, more accountable corporate structure, and are reshaping our organization and changing its culture. We are continuing to push forward our strategy of more upstream and profitable downstream.

We expect our strong performance and cash generation to enable us to pay more than $10 billion of dividends in 2005 -- subject, of course, to exchange rates. We will relaunch our share buyback program, invest more in the business and retain a strong and flexible balance sheet.

Our performance during the year reflects how we are delivering on our strategy. Record net income of $18.5 billion was 48 percent higher than in 2003. Record cash from operations of nearly $26 billion was 18 percent up, which is a significant contribution from the downstream. We generated another $7.6 billion in divestment proceeds, as we upgraded our portfolio. Our equity LNG volumes continued growing at an impressive 9 percent a year, exceeding the 10 million tons milestone. If we exclude divestment from product share and price effects and hurricanes, hydrocarbon production was about the same level as last year, and this was at the high end of our expected range. The downstream lived up to its side of our strategic equation, with record profitability of $7.5 billion, including 1.8 billion from the US, where the asset base continues to improve.

We made considerable progress in shaping our portfolio in line with our strategy. On the investment side, more than three-quarters of the $15 billion was spent on the upstream business. On the other side, with the divestments, it was the reverse. All businesses contributed, but half came from the downstream, the divestments realized at a very good value.

We have made excellent progress towards the target range we have given you for divestments, and are increasing this target range now to $12 to $15 billion of divestments over the same three-year period. Major items in the consideration (ph) are the sale of Basell, InterGen and the LPG business and the completion of the sale of the gas transmission system in the Netherlands this year.

This map shows the range of our investment in growth involve (ph) all our businesses. Let me give an example of every business -- BP, the start of the giant Kashagan development in Kazakhstan; in gas and power, the decision to build 6 LNG train in Nigeria; in OP, the retail joint venture with Sinopec in China; and in chemicals, the construction of our Nanhai petrochemical complex, also in China. As you can see, a lot of action, a lot of progress towards growing the business.

I turn now to exploration and production. Exploration and production earnings of $9.7 billion were 6 percent higher for the year and 26 (ph) percent higher for the quarter, largely reflecting high oil and gas prices. Debt-adjusted cash flow was a record $16.4 billion. Outline (ph) production of nearly 3.8 million barrels of oil equivalent a day was in the top end of our indicated range. New production exceeded field declines. In Nigeria, production reached 1 million barrels oil equivalent a day, our highest level since 1980. The three new fields were recently brought into production -- Jintan in Malaysia in September, Goldeneye in the UK in October, Holstein in the Gulf of Mexico in December. Production from the Sakhalin fields in Russia started one year early. As we made clear, production for 2005 and 2006 will remain in the range of 3.5 to 3.8 million barrels equivalent a day. 2005 will be at the low point for production, with the Andover (ph) contract in Oman and before new projects ramp up.

Now, let me turn to our proved reserves. Before we discuss the figures, let me remind you of our strengthened reserve controls. These have four important elements.

First, rigor in SEC compliance -- Shell reserves reporting guidelines have been revised to be in full compliance with SEC requirements. They so that either (ph) Shell reserves reporting guidelines will be published before the annual general meetings in June. Over 3,000 staff have been trained in the use of these guidelines. As we discussed in October, our petroleum engineers and geologists have applied this new understanding to carry out detailed reviews of our reserves.

Second, the succession of review stages for reserve bookings within EP by the group audit committee, and and finally, by the boards.

Third, the strengthened internal audit process reporting outside the line of the group audit committee.

And fourthly, what we did on strengthening the controls is the use of external experts. We have the people, processes and systems in place to assure an extensive, rigorous and thorough review of our reserves basis. However, this rigor has produced results that we did not anticipate when we produced our 2003 figures in the middle of last year.

In October, we told you that the detailed review might result in further reserve restatements. We will reduce our SEC proved reserves base at the end of 2003 by around 1.4 billion barrels of oil equivalent to nearly 13 billion barrels. Initial indications are that the financial impact will be about 1 percent of our 2000 to 2004 earnings. The changes are largely of a technical reporting nature. We have now completed the reserves review. It was detailed, rigorous and thorough. We intend to move on.

Hydrocarbons are still in the ground, and our production outlook is unchanged. As well as giving you the details of the reserves restatement, Malcolm will tell you what we are going (ph) to get those barrels into production. On current provisional information, we estimate that our organic reserves replacement ratio during 2004 was some 45 to 55 percent. This excludes what we are called (ph) year-end (ph) pricing effects and divestments. We continue to target 100 percent reserves replacement over the period 2004-2008.

I turn now to gas and power. This year was another successful year for gas and power, where we are the industry leader in LNG. If divestment proceeds are excluded from both years, earnings were 20 percent up from 2003, with higher LNG volumes and prices. Debt-adjusted cash flow of $1.2 billion was up 15 percent. The 9 percent growth in LNG volumes in 2004 benefited from the startup of the fourth Northwest shelf train (ph) and the ramp-up of the two Malaysia (indiscernible) trains. This growth will continue as expansion projects in Nigeria, Oman and Sakhalin come into production. In 2004, Sakhalin signed LNG agreements for sales to Japan and North America. Shell will supply Sakhalin gas to Mexican and US markets through the Sempra terminal in Baja, California, where we have half the capacity.

We also purchased additional gas from Nigeria LNG, supporting the decision to build a sixth train to supply European and US markets. We expect our LNG capacity to increase by 14 percent a year from 2003 to 2008. Additional LNG supply prospects are being developed, as is our capacity to import and market gas in expanding markets. We're excited with the progress with developing our Pearl gas to liquid project in Qatar, applying our technology and experience to build a world-scale plant.

Now, we turn to oil products, which had a great year. Earnings adjusted for the estimated current cost of supplies more than doubled, reflecting increased sales and operational improvements, as well as better defining and marketing margins. Crude (ph) and oil products trading was more profitable, where our skills and reach in global markets served us well in a changing business environment.

US earnings of $1.7 billion were significantly better, with continued performance improvement and portfolio rationalization. Unit earnings improved sharply, largely due to much higher refinery margins. But we also delivered better operational performance, particularly in the US, where years of continuous effort are delivering the promised results.

Elsewhere, in-plant refinery shutdowns in our US refineries fell once again, down 1 percentage point to under 6 percent, as a result of strong focus on operational excellence. The rest of the world, our worldwide refining network continued to perform very well. Two years after the acquisition of DEA, our business in Germany delivered very strong financial results, and we grew our market share. Global rollout of our differentiated fuels included the successful launch of free power (ph) in the US, where it is the best-selling premium fuel.

I turn now to chemicals. Chemicals, also a great year, with a profit of $930 million in 2004, compared with a loss of the year before. This was despite an impairment of the Basell polyolefins investment of $565 million. We continue to focus on selling our interest in Basell, and the process is on track.

Operational earnings of some $1.5 billion were more than 4 times the level in 2003, and higher than in any years since we restructured the business in 1998. Improved industry conditions resulted in better sales and margins, despite high feedstock costs. But beyond that, our own action added to profitability. Asset utilization was up 3 percent, which, as you can see, is a continuing trend. The multibillion dollar Nanhai project in China is on track, where commissioning has started towards the end of this year.

Introduction of the new downstream structure integrating OP and chemicals in a simplified global organization under the leadership of Rob Routs will help us to realize the benefits of standardized systems and drive operational improvement throughout the business. The combined downstream generated debt-adjusted cash flow of $10.5 billion in 2004, nearly double the previous year. Downstream strengths we demonstrated in 2004 is key to our strategy. We intend to continue delivering it.

Let me now hand over to Malcolm to give you more details on the reserves.

Good afternoon, ladies and gentlemen. EP performance was strong, in terms of cash generation, and production was at the top end of the range, and we also made good progress on new business milestones, but the year's reserves replacement was disappointing. And so I will first update you on the SEC proved reserves position, and then look ahead.

Jeroen showed you this slide already, with the details of our reserves control procedures. I just wanted to highlight the actions taken in retraining some 3,000 DP staff, 80 percent of them being geoscientists and petroleum engineers, and then involving many of them in the detailed reservoir-by-reservoir and often well-by-well review we have conducted since last summer. And we said we would make these changes to our controls last April, and we have done so. Of course, it is disappointing that the outcome of this increased rigor is that we have had to make further downward adjustments, but this work had to be as scrupulous as possible, so we can move on from this issue. I would stress that in general, these SEC proved reserves restatements do not impact our forward plans, in terms of production and cash generation, and they remain essentially as described on September 22nd last year, and I will come back to this.

In the second quarter last year, we announced a restated total of 14.35 billion BOE proved reserves, as at end 2003. Since last summer, our asset teams in every country have completed a thorough review of 100 percent of our proved reserves base, and in addition, we have also now conducted internal audits of some 90 percent of that base, assisted by external experts. And of the remaining 10 percent, around half is in the US, where our experience to date indicates that we have very little risk of noncompliant volumes. And that audit program is now complete. The result is that we will reduce our SEC proved reserves base at end 2003 by around 1.4 billion barrels to 12.95 billion barrels.

The group financial statements, as it says in the notes, do not yet take into account the impact of the reserves restatement, as the work is not yet finalized. But based on what we know so far, the aggregate impact over the period 2000 to '04 is expected to total some $700 million. That's equivalent to around 1 percent of income over the five-year period, which is still very much work in progress. And the finalized financial impact will be described fully with the publication of the annual report. A number of small impairments to assets associated with the reserves review are also expected, with the total currently estimated at some $20 million.

Changes since last June are almost all of a technical reporting nature, with the four main issues listed here in order of importance. And I'm going to give a couple of examples to illustrate these, and the other examples are in the handout. I should first clarify, though, why the results have changed compared with last May.

When I took over EP last March, I triggered a six-week high-level review, where we covered over 90 percent of our proved reserves base, and we used for the first time external consultants in that process. That process focused at field level, as we sought to provide as reliable figures as we could, and we believed the exercise had given us SEC-compliant results. But the process could not comprehensively address the individual well data across 1,500 fields and 12,000 wells that we have in our portfolio.

We knew we needed to retrain our staff on SEC-compliant reserves estimation procedures, but we did not anticipate the full impact that the retraining of some 3,000 staff would have. And this widespread impact became apparent only when the preliminary results of the reviews and audits came through in October. And in the end, this has led to changes in some 200 fields, 75 percent of which were adjustments smaller than 10 million barrels. And I'd like to give you now a couple of examples.

Some 50 percent of today's restatements relate to recovery factors. More than half of that has to do with gas fields in Europe, Africa and the Far East, and this will illustrate that. To comply with our more rigorous procedures, the expected decline of producing fields has to be estimated by what is known as a decline curve, which extrapolates the historical performance of wells. It is not necessarily an accurate guide to the resources that will eventually be produced, and you see here on the left, the production from a typical gas well that has been online for many years. You can see that, extrapolating from the earlier production, you would have underestimated the resources that were eventually produced quite significantly. And on the right, you see a North Sea gas well that has been in production for a shorter proportion of its total life.

Now, the blue line is based on reservoir simulation, and that is our forecast of the amount of resources we expect to produce. And that, of course, uses all the available information about the reservoir -- the well loads (ph), the seismic data and so forth -- as well as performance from similar reservoirs in other fields. But we can only report as proved the smaller figure, based on the straight-line extrapolation of the performance of the well from the early data. And we're confident that in general, we'll ultimately recover more than that proved number, but it will be several years before the decline curves reflect this, and enable us to rebook the reserve as proved.

I'll show you a second example, and this is actually a conceptual map of one of the major fields in Sakhalin. And the first thing I would stress is that the restatement of reserves here has no impact on future cash flow, and doesn't change our development plan. But as part of the 2003 reserves restatement, we've reduced the booked amounts of SEC proved oil reserves here to just 14 percent of the oil resources we expect to produce.

And there are three separate technical issues affecting the fields, and I will cover them briefly. On the left, you see the issue known as lowest known hydrocarbons, which is essentially the thickness of the oil column. And essentially, we can only use, for SEC reporting, what is actually found in the two appraisal wells, although the seismic and pressure data is very clear that the column is at least twice as big.

Second, you have the issue of the lateral extent. And you can see in red there that we are allowed to book for essentially 5.5 km, the dark red areas around the existing appraisal wells, whereas the reservoir is about 9 km long.

And, third, how much oil is in the ground that we can produce, the recovery factor? And in this field, from the start, we will inject water to maintain reservoir pressure, just as we do for over half of our North Sea oil production. But we can only count water injection for this field if the benefit had already been demonstrated in the area in a suitable analog reservoir. And as it is the first development in this area, we have to use the depletion drive of 18 percent. When you combine all those factors, you get the 14 percent that I have indicated.

There's also an example where we won't be able to make further bookings until we drill the development well shown, and we won't be able to book the reserves associated with the water injection recovery factor for some years after the production and water injection has been in place.

All of that is to explain the proved reserves bookings. The confidence in the project and its expected production are unchanged.

Moving to 2004, we will publish the year-end reserve position in our annual report on 20-F, and on current provisional information, we estimate that our organic RRR during the year with some 45 to 55 percent. This is a disappointment, but we couldn't make the reserve bookings that we had anticipated back in mid-2004. And actually, although project and drilling progress and results were basically as we expected, application of these more rigorous procedures that we couldn't book the volumes from some of the projects we had previously anticipated, even though, again, there is no change in the future production expectations. If we include the year-end pricing effect, the 2004 RRR is, as you see, 30 to 40 percent. And if we include the effect of divestments, the figure is 15 to 25 percent.

Now, concerning longer-term RRR, we continue to target an average over the five-year period '04 to '08 of some 100 percent. I remain reasonably confident that we can achieve this, although, clearly, with the disappointing 2004 results, the challenge to meet this goal over the five years has increased. It is also the case that some of the bookings from our larger projects are now not expected until the latter part of the period, for the sort of technical reporting reasons I have described earlier on that Sakhalin example. And so it is likely that 2005 reserves replacement will also be less than 100 percent.

One of the issues that impacted 2004 RRR, the bottom-line figure there, was the year-end pricing effect. And it was especially significant, as I expect you realize, for Peace River in Canada, where we have reduced proved reserves from 164 million barrels to 0, even though production continues, and in fact we see potential for producing over 1 billion barrels of oil from that field in the long term. And, were we to have the year end today, then we would not have had to de-book those reserves -- that example is in the handout.

Now, in September, I showed you this picture of our overall hydrocarbon resource base. And what is it? It's our expected economically producible resources discovered and in our acreage today, and that is the basis of our business planning. And despite the reduction to proved reserves, it is our ability to move these expected resources into production that ultimately matters for future cash flow, and that has not changed.

As I said in September, we're investing $10 billion a year to unlock 13 billion barrels of resources, with new facilities and infrastructure, that will come onstream over the next five years. And these are long-term investments in long-lived projects, and I would like to just show you a few of the highlights in regard to the progress.

First of all, in 2004, we brought nine new fields onstream. So our production for 2005 and 2006 remains in the range we have discussed before -- 3.5 to 3.8 million barrels a day -- although, again, as we have said before, 2005 is likely to be at the lower end of the range.

You can also see -- and I won't go through the details, but we are making good progress on new projects. And it is that that gives us confidence that our plan for 2009 production remains in the range 3.8 to 4 million barrels a day. And by 2009, we also expect to have taken final investment decisions on something like a 4 (ph) to 5 billion barrels to come onstream in the few years thereafter.

Of course, what's important is to build our resource base for the future. Particularly good was that we strengthened our acreage position last year, and we acquired 50,000 square kilometers in seven countries, with the potential to deliver at least 20 big cat (ph) prospects. We drilled 15 big cat prospects and found hydrocarbons in five of them in Egypt, Malaysia and three in Nigeria. And we also made discoveries in seven other countries. However, initial volumes were less than we hoped and less than in recent years, but there is still a lot of appraisal to go, so I am still hopeful. Appraisal was also positive on several material accumulations in the Gulf of Mexico, Malaysia and Kazakhstan. I would like to highlight the success we have had in extending key long-term positions.

In December, we signed the agreement with the Sultanate of Oman to extend the PDO concession for another 40 years, and PDO accounts for 90 percent of Oman's production. And that follows licenses extensions in 2003 of 19 years in Brunei, 15 years in the Barang (ph) Delta in Malaysia and 30 years in Denmark. And these countries are, of course, all crucial to our long-term future. And alongside that, I think we have been making good progress in securing new positions in our focus areas such as the Middle East.

So in September, I laid out the strategy for EP, and this hasn't changed. We are making good progress, as I have shown, in unlocking the 13 billion barrels of resources. We are on track to meet our production targets for 2009. We're increasing the resources available for EP -- not just more money but more people and in the right places. And I think our EPA business retained a sound foundation of asset positions and people. We are now, I think, at the turning point. We have taken all the steps needed to put the reserve issue behind us. This year will be the low point of our production, but we expect strong growth after that. Thank you very much.

Good afternoon, ladies and gentlemen. I'm going to focus on cash this afternoon. We manage our business such that our competitive cash performance and sound investment in growth are maintaining year-end levels consistent with the proven balance sheet management. We aim to return cash to shareholders through competitive dividends and share buybacks.

Our portfolio generates significant cash, $25.6 billion from operations in 2004. The same year, the debt-adjusted cash flow was $27 billion. On top of that, we realized more than $7.5 billion in divestment proceeds. This cash allowed us to fund our investment program, including the major upstream projects essential to our strategy. We have paid a highly competitive dividend, reduced debts by almost $5 billion and bought back almost $2 billion of shares. We come into 2005 in a very strong cash position, $8.5 billion.

This is the result, of course, of high prices and margins, but also strong operational performance in the businesses. This was particularly the case in downstream this year, where the improved asset utilization allowed us to capture the benefits of the high margin environment.

Now, ladies and gentlemen, we start 2005 in a very strong position. We will invest at least $15 billion a year, with more than $12 billion in the upstream to grow the group's business. Given our pipeline of projects and the industry environments currently, we don't expect these requirements to diminish in the coming years. Funding the required capital investment in the businesses is a priority, and we have the strength to do this.

Another key element is that we know that improving our competitive performance requires divestments to shift capital to more profitable opportunities. We also believe that, for some assets, significantly more value can be captured by selling them than from continuing to operate them. If this is the case, we simply divest.

Lastly, as you remember, we charted the $10 to $12 billion of gross divestment proceeds for 2004 through 2006. With the success of our divestment program last year, we are now increasing our divestment guidance to $12 to $15 billion for the same period. And after just one year, we are already over halfway to the top of this range.

Maintaining a strong, flexible balance sheet is a priority for us. Our cash generation capacity and huge investment programs we intend to maintain a gearing position, defined as our total debt plus other commitments such as operating leases and pensions, in the range of 20 to 25 percent. Taking into account our cash holdings surplus to operational requirements at the end of '04, our gearing position was some 16 percent. This provides us with strength and flexibility, as we move forward into 2005, to first, deliver competitive returns and growth; second, to capture opportunities in the markets; and, third, to return cash to shareholders through dividends and buybacks.

As I said at the beginning, my focus today is clearly on cash. These are my priorities going forward. We manage cash to meet the investment requirements of our industry in such a way that cash in will equal cash out over several years. We grow our dividends at least in line with inflation. We maintain a strong and flexible balance sheet, with gearing around 20 to 25 percent. We invest in line with our strategy of more upstream, a profitable downstream, with the continuing $15 billion a year planned for the coming years.

Now, let me turn over on how we are returning cash to shareholders. In '05, we expect to return a highly competitive $13 to $15 billion of cash to our shareholders. Dividends paid out to shareholders should exceed $10 billion at current rates of exchange. And we will continue our policy of increasing dividends at least in line with inflation over time. The higher figure is a consequence of having the second interim dividend for '04 in February, as announced today, followed by three quarterly dividends in 2005. This returns more than $2 billion of extra cash to our shareholders this year. With the cash surplus we generated in 2004, and are generating still in today's high-priced environment, we will relaunch our share buyback program in '05, and expect to spend $3 to $5 billion.

Clearly, continuing to return surplus cash to shareholders is a key priority for us. The financial flexibility we gain from the our strong cash position and cash generation puts us in a sound position to do so.

And now, I will hand over to you to conclude, and then we'll go for Q&A.

Ladies and gentlemen, I said at the beginning 2004 was a year of extremes. On the one hand, record net income, record cash generation, which is good; but on the other hand, the reserves restatement. But the reserves review is now completed, and we will move on. Hydrocarbons are still there, and our production outlook has not changed. The focus is now on bringing those resources into production. And, as Malcolm showed, we have the projects underway to do this. But it was be powerful performance of the downstream and the continued growth of our LNG business that really stood out in 2004.

We are ahead of schedule with restructuring our portfolio, getting excellent value for our assets. And we took radical steps on corporate structure and company culture. I expect and intend that we will deliver many more improvements. We know where we are going, and we know what we need to do. We have made clear progress in moving our strategy forward.

In 2005, we will have a clear field on which to compete -- all of our energies, all of our focus on the business, driving performance and growth. Upstream investment, where historical returns are highest, is a priority. Downstream and LNG move from strength to strength, building positions, improving operations. We shape the portfolio even further and now look to realize up to $15 billion in divestments. How we do this? We pay more to our shareholders. This year, as Peter just explained, we increased the dividend spending to more than $10 billion at current exchange rates, and expect to buy back 3 to 5 billion in shares, while maintaining a strong balance sheet.

Ladies and gentlemen, in 2005, we aim to move to one company, ending duplication, streamlining processes and improving accountability. We have come through a lot. We have much still to do. And we know we have to move quickly, more decisively, and are doing so to deliver on our strategy -- more upstream and profitable downstream.

Thank you, and now I look forward to your questions.

Before going into the questions, we also have the Executive Director for Gas and Power here today, Linda Cook, and the Executive Director Rob Routs for Downstream. So, also concentrate on some questions for them after very successfully (indiscernible).

Okay. We'll take your questions. We'll start here. If you could give your name and organization, please? Neil?

Neil Perry, Morgan Stanley. A question for Malcolm and then one for Peter. Malcolm, we used to have reserve numbers that were overstated. You're now giving us reserve numbers which, by your own admission, are understating. What do you think can be produced from your assets? Can you give us a reserve number that you think is the number that you can produce from the assets from which you have given a final investment decision? What do you think you have actually got?

And then, the question for Peter -- you mentioned, when you talked about cash capturing opportunities in the market. Can you talk about how you think you can create value through acquisition, when the oil price is between $40 and $50 a barrel, if that is your intention?

The answer to the first question is that we are not saying they are understated relative to the rules in the guidance, just for clarity. We have complied rigorously with what we understand to be the rules on the guidance.

And no, we're not going to give -- and I think we said this in September -- we are not going to start giving lots of other numbers, because this has been experience in understanding numbers and the rigor around a particular definition, and the last thing we want to do is move into other areas where there are no industry standard definitions. We have tried to give you an indication of our total resource base and, more to the point, talk about what we expect to bring into production from the assets that we have moving through the pipeline, and particularly what production we expect to result. And we think that is probably the best guidance we can give. And internally, that is what we are driving the business on, in terms of managing our business.

I think, on the acquisition, I would first say that we still consider organic growth as giving us a better yielding going forward at the current price levels. I think that is the first fundamental one.

The second one is I think, going forward, you have got assets or areas of assets which can give us, because of some synergies, some critical mass or just strengthening the position, which can give us a benefit, in terms of performance even in a high oil price on gas and oil. But I think they will go through a very tough scrutiny, in terms of profitability outlook in going forward.

So I think we are keeping the balance sheet as flexible -- or our financial framework as flexible as possible, to react when the time is right and the opportunities are right. But our key focus, as you have heard, is going to be on organic growth, in order to get into the competitive return area.

John Ripley (ph) from UBS. You talked about managing the business for cash, and in September you showed the way that you balance the business at $25. Are you still able to do that, and is that how you plan for the business? If it isn't, are you able just to talk to the moving parts in the framework that you did describe in September?

Indeed, we are still learning like we have said in September the long term. So the next few years have cash neutral position of 25. Let me just give you some numbers for 2004. As reported, we have come out around $10 a barrel at cash neutral in 2004. If you actually just for the higher spending going forward on cap rates (ph), take the rather high number on the divestments out and adjust for the buybacks, I think we were just above $20 in that sense.

So we had a very good year, strongly driven by cash performance also in downstream. And we do maintain our target of 25 -- you have seen all the plans outlined in September refreshed today. That remains our return target over the next few years.

Under the framework which I have explained, which gives us some flexibility, obviously, to return cash to shareholders as we will manage the various components in going forward. But we stick to the 25 for the time being but have had a very good year.

Tim Whittaker from Lehman Brothers. Malcolm, I calculated in 2004 your reserve life won't be much more than nine years, significantly below the competition. What do you think is the right reserve life for a company of Shell's scale?

What might you do about bringing to (ph) a higher reserve life? Is that just organic investment over time, or can we expect something more strategic?

And finally, earlier on, in your previous time you presented to us, you said 100 percent reserves replacement over the next five years. That was before the latest downgrade. So, presuming some of those reserves come back in, should we expect, therefore, more than 100 percent? Or have you essentially reduced your target, because you have got those additional reserves downgraded to put back in?

I don't know that I would sort of focus on one number and say that's the right number, but what I would say, as we have said before -- it's an R/P (ph) of around nine years, which, as you say, is where we are at the end of '04, is not where we want to be. So we are growing the resource base and bringing that resource through the funnel.

One of the things that we have stressed before it is, at the moment and for the next few years, we are in a phase where there is a lot of investment going into long-term, long-life assets -- the Kashagan's and the Sakhalin's -- and then, of course, some like Athabasca and possibly GTL that may not contribute to SEC proved reserves, but will still contribute value and production streams and so forth. So I think we've got to look at the total resource base and the total value.

Our focus remains on -- I think that is the right strategy for us. I think we see a lot of success in the integrated gas chain. We think we will grow our business in unconventionals, and I think that that will contribute to the resource base over time and grow that total resource base. I think it's going to be a combination focus on organic and from our own portfolio.

New business development, where we see a lot of success, things like GTL, which is not necessarily coming from expert exploration, but it is leveraging our technology and relationships to get us into a new and important position. And then, over time, as we have said right from the beginning, the third strand has got to be the right source of acquisitions, but in areas that match our strategy, where we can create value and where we see ourselves as a long-term competitor.

In terms of your question about have we changed the goal post, we have said 100 percent reserves replacement ratio, and we remain on that 100 percent. Yes, it's from a later starting point. But not only did we have issue and the uncertainty about timing of those rebookings -- and I gave you a couple of examples -- you also have the issue of uncertainty or of a shift, in some cases, of our understanding of the timings of the bookings we can make on existing projects. Because, as we got our heads around exactly what compliance means, it applies both to the portfolio we had at the end of '03 and the expectations of timings going forward. We stick with the 100 percent, reasonable confidence on that. And I hope, over time, over the long term, we'll find resources that we can add that will, in turn, come through to proved reserves.

Mark Tanoti (ph), Merrill Lynch. Peter, first question -- can you just maybe help us again with the math, because I am not really getting it. When you are showing debt adjusted cash flow last year, at $27 billion, you have told us your CapEx commitments and your dividends are going to be at least 26. And that's in a year, last year, where the oil price was 38 (ph) and refining margins were at cyclical highs. How does that all square with a $25 cash breakeven oil price? I'm just at a loss to see how those numbers work.

Maybe also, Malcolm, I can ask you a quick question on the E&P business. We have been at pains today (ph) to talk about reserve restatement and the issues surrounding that. But today, again, fourth-quarter results, we've seen what looks like a fairly disappointing E&P result, in terms of underlying margins. Can you talk a little about the underlying margin trends you're seeing in the actual business, in terms of what you are producing right now, and in terms of costs, cost pressures, on both a cash basis, in terms of underlying DD&A trends?

I'll take the first one. I think you have to adjust a few things in order to get to the 25. Quite clearly, 2005 is going to be a year, for example, that we will pay some 2 billion more dividends because of swapping from two times a year to four times a year. If you take what we have said in September, we have said long term, we're looking at the $3 to $3.5 billion -- $3 to $4 billion of divestment proceeds on an annual basis, and not the 7.5 that you had this year.

We normally do it or we are (ph) neutralizing for buybacks, in that sense, and we look at the cash neutral numbers. So when you actually -- at least the way I have done the math, when you take all these adjustments, at least our model comes to 25. So I can't give you any more there.

Just on underlying margin trends, let's take unit cost, operating cost, DD&A and then other factors. Unit operating costs, we said in July, probably up by about $1 in '04 -- in fact up by $1.09 -- the combination of exchange rates, industry cost pressures and accounting changes and some shift in our portfolio. I think in DD&A it's up 8 percent on the year and, again, there's exchange rates in there, and you just see the impact of new projects and investments, as in Brazil and the States. In overall margin terms, I think the other issue to keep an eye on is taxation. And clearly, we saw movement last year in Denmark, which is significant. I think, though, that going forward, people know that countries also are looking to make sure they are getting enough investment. There's a bit of a chase to make sure that they can attract investment. So I hope that that trend will not continue.

One last comment is our longer-term focus is on investing in areas with more upside. So that's why you see the investment in the oilsands, why you see that we're actually maintaining our plateau production in Europe over the next five years.

Let's take one from somebody calling in, please.

Bert van Hoogenhuyze.

In the first place, talking about the divestments you did and your CapEx plans, do you feel that in view of the divestments also in the upstream, you will still stick with your 11.5 billion CapEx (ph) in 2005? And secondly, you already elaborated on the reserve problem. Still, your terminology is indeed a bit weaker than it was in September, on average, at least. Wouldn't it be reasonable to expect, with a lower base and still the resource base there, your reserve replacement would actually have to go up, because these are technical changes which can easily be changed into actual reserves in production?

Yes. I'll just say the issue about reserves and technical changes -- I've sort of answered the question already. We expect 100 percent; I've got reasonable conference in it. I was not trying to weaken it, but I'm also acknowledging that, yes, while there maybe some element of re-bookings, as we indicated in the two examples, the decline curve analysis and the example from the Sakhalin field, you don't get that back immediately. You have to have quite a long history to demonstrate the underpinning to get those re-bookings. So I'm confident that we will get it, but the timing is not something where you can say, yes, and I can count on it in the next few years, while at the same time some of what we saw as an outlook back in the middle of the year -- the projects are same, the forecast is the same, the schedules are the same, but the timing of the booking is later than we thought. So overall, that's why we have made the same statement today.

(Multiple speakers) side, as I've said, we are looking at 15 billion at this stage for the total group. We don't see, actually, a diminishing curve on that one, and I have said that we're looking at roughly $12 billion for upstream, in that sense, and I think that is where our current plans are.

Let's go back to the floor.

Jeremy Elden from Lehman Brothers. Two quick questions -- on 2004 CapEx, your earlier guidance is 14.5 to 15 billion, excluding the minority of Sakhalin:, you delivered 13.4 excluding that. Can you give us any illustration of what the variance was? Was it project slippage, or were you so good at executing, they came in well under budget?

And, now that you have reorganized chemicals to put it within or closer to manufacturing, and let Rob run it all, can you give some description of how that complex is organized now, and what kind of synergies you're starting to find?

Malcolm will do the first part, and Rob will explain it, himself, to you.

On the CapEx, at least as far as the EP business is concerned, where I think -- of what you have indicated, that we didn't spend (indiscernible) -- no, it's actually not -- neither the savings, nor is it really slippage, in terms of the fact that all of our major projects -- the big projects, essentially, the spends, those that are in full flight, as it were, the spend was essentially as we expected.

What we have seen is that we've got a number where the front-end spend is a bit slower than we had when we made the estimate. We're actually still on schedule with the project, in terms of completion. So it's more that I think quite often happens is we try and avoid it, but engineers will tend to think they will need the money earlier than they well, even though they are meeting the milestones on the projects, which is the key thing. And there were one or two special cases where we expected to spend money to put additional funding into Nigeria, but the joint venture funding delivered as we had originally hoped, so we didn't need to put the extra funds in; we could basically do the whole program with slightly less money from our side.

If I can just add here, we also said already in October that we're going to come in below because one of the changes we also had was an accounting change, which accounted for a few hundred million dollars, which is actually a lease contract, which is not coming this year nor next year, may come in 2006. So that brought it quite a bit down already in the October announcement.

We have created a lot of excitement in the organization around oil and chemicals coming together. It was about time. (Inaudible) operating those businesses separate, and now people are starting to find more and more synergies.

Main (ph) first steps were really to get our manufacturing facilities together, and that has happened on January 1st. There is an excellent operations group that now covers both chemicals and refining, and applies the same practices to both sides of the house. (Indiscernible) turnarounds are now executed the same way, with the same methods and the same regular (ph) on both sides of the business. And that is supposed to throw off quite a bit of money.

In terms of the size of the price, let me give you an indication, without going overboard. Jeroen and I started talking about this a number of years ago, and at that time, which is now, I think, about 3, 3.5 years ago, we set a target of $300 million. And we have surpassed that, by not having the two organizations together. So in bringing it together even more, we think there is probably a hell of a lot more money on the table than what we have realized already.

Adam Sieminski from Deutsche Bank. I have one for Malcolm and one for Jeroen. Malcolm, do you sense any possibility that the SEC is going to have flexibility in the future to change their views on things like year-end pricing after this very strict interpretation that you have taken?

And then, for Jeroen, could you talk just a little bit about how Shell will be able to effectively compete over the next five years with these nascent national oil companies who seem to have fewer constraints, in terms of financial performance, than a company like Shell?

I'll be brief on will the SEC change. I think it's far from our position to offer them guidance on this subject.

(Indiscernible) your question. You are talking about the India's to China's especially. If you read the press, basically the Chinese are moving everywhere. And they take a very long-term view. They are not only in our oil industry; they even look at nuclear projects, et cetera.

What we have seen in the oil industry -- the government-to-government deals, basically -- they happened in 1974 after the oil prices went up, and they happened in 1979 and the early '80s, it happened as well. And of course, I don't know whether we are in a similar timeframe. But if you've taken the lessons from the past, it's very close to our present strategic agenda. Because governments can talk to governments, but where we can differentiate as a company like Shell is to be ahead with new technology. So basically, because usually they are state-owned companies; they are not at the front side of technology or to get quicker learnings from the whole world to apply for new projects. So you can say yes, dear government, you can do something with another government. But then your economics are worse, you get less taxes because we can apply our technology, we can do it better or faster.

Secondly is that the multinationals, and in our company, we will make sure that we have a huge capability to execute multi-billion-dollar projects basically on time, on schedule, within budget. We are not perfect, and sometimes something goes wrong, even within Shell. But there are many large projects which we do very well. And that's when government is very important, as well. Usually, with all due respect, government companies have not necessarily the same track record in that.

So this is about the classic competition in the global market. In the end, your best defense is that we have to offer better value propositions, either with technology or better learnings or project manager, or we can speed it up, so that we can demonstrate to those governments that we can do a better job. I think that's our best defense.

I'd like to take one from the operator. Operator, could you please put Fred Leuffer on the phone, please?

Just two questions. First, I was surprised to hear you say that reserve replacement is likely to be under 100 percent in '05. And I'm just curious what this says about exploration success in the past five years and cycle times. That's the first question.

The second one is that I wonder if you have a number for us on the impact of the unplanned downtime in chemicals in the fourth quarter. What was the impact on fourth-quarter earnings?

Malcolm starts, and Rob takes the question about chemicals.

Fred, indeed, we were giving guidance over the five years. I don't think it's a particular judgment on exploration success in the past five years, although possibly exploration expenditures and success before that. Cycle times do take a long time to translate exploration wells and in subsequent appraisal into proved developed reserves or proved reserves. You can see that with Sakhalin, you can see that with fields like Kashagan and so forth.

In fact, we had, I think -- we have talked before in the analyst presentation about the 7.6 billion we found over the five years from '99 to '03, and 1 billion of that is onstream now. But we do need to, I think, accelerate the speed at which we bring discoveries through the funnel, and that is very much one of our focus areas.

If you look at chemicals across the year, over the last 12 months, actually year-to-year performance and onstream time in chemicals has improved quite a bit. We had excellent performance in quarters two and three, and we had some cracker issues in the fourth quarter. First quarter, we had a number of planned turnarounds. If you have an idea of the impact, the financial impact in the fourth quarter, you have to think $80 to $90 million.

Colin Smith, from CSFB. I've got three questions. Two of them should be quick. The tax rate looked like it cropped (ph) up quite a bit in Q4. And bearing in mind Malcolm's comments about tax rates generally, could (technical difficulty) from what you think prospective (technical difficulty) tax guidance is (technical difficulty) both under your base case and, let's say, something in the $30 to $35 oil world?

The second question is, thinking about the major assets and businesses that you mentioned as being up for disposal (technical difficulty) collectively what they contributed to earnings in 2004, and also to (technical difficulty) cash as it would have appeared in your cash flow statement?

And finally, just on cash itself, that ended year end, obviously, quite a high number. Was that just reflecting the timing of disposal receipts versus ability to pay down debt, or does that represent a new way of approaching cash balances?

Well, the tax rate -- it is clearly the high-price scenario that does drive the tax slightly up. I think, at this stage, I would not like to give a new guidance out, compared to the one we have. I think I will take another couple of months to get at that, and we will come back in the first quarter to give you some guidance or some more exact guidance in a high-price scenario how our tax rate is going to move. The main factor I know (ph) coming out at this stage, the discontinued operations reporting does cause some distortion. And I would like to come back with a clear answer on the one. So better results, but it's going to be higher in going forward at those prices.

I take three as well, because that is on the cash side. I don't like to be, actually, debt free. I think that is not prudent management going forward. We have clear plans in place what we're going to do with our cash balances in 2005. I like to have some debt position and use the cash in a different way. A kind of guidance for you to go forward -- for operational reasons, we will need anything between 2 and 3 billion to have in our stock, and I think the rest we will work with it. But I think you can take it for granted that we will not drive debt to zero.

(Multiple speakers).

You asked whether, I think, the year-end cash balance, whether that included the (indiscernible) (multiple speakers).

We had, quite clearly, a ramp-up in the fourth quarter, because we had high proceeds coming in, as you have seen in our press release. And that has clearly contributed to that, whilst I have to say we also had a very strong quarter.

Yes. And what was the total earnings impacts from the divestments of 2004?

I think we put (ph) a note, actually, in the press release where you can see that. And we have issued that a total, just divestments -- I come back to that.

I think we should move onto the next question, please.

Neil McMahon, with Sanford Bernstein. Just a few questions. First of all, will the restatements today of the reserves lead to any delay in you merging the companies? And has the SEC started looking back into that again, thinking about the financial restatements of your past few years?

Secondly, just on the upstream, just trying to get an idea of progress on some of your key plans from September. You mentioned five big cat discoveries. Did you find 500 million barrels net to Shell in those discoveries? And how is the project management coming on with Bonga and Sakhalin?

And finally, what percentage of enterprise will be left in your portfolio after the divestments beyond 2006?

The restructuring of the company, which has scheduled to go through the AGMS (ph) the 28th of June, is absolutely on track. And in fact, today, because the whole aim is that we close the whole debate of reserves, and that we can file our figures to the SEC. Today is just hopeful (ph) we are on time with everything. So the whole thing is on track for the 28th of June. Malcolm?

Of the five big -- we said five big cats that had pre-drilled, of 100. What I also indicated -- so they came in, some more, some less. In total, what I said is exploration for the year did not deliver the volume we'd hoped for, or we'd had in previous years, but we have got a lot more appraisal to do. I'm not really going to go any further than that.

In terms of Sakhalin, where we really have, I think, put our A team on it and reinforced on every front, we still have some major projects, with a lot of issues to address, in terms of ensuring that we deliver as expected. I'm very pleased with the progress of the LNG side and, in fact, with the gravity platform base and the design and construction of the facility.

So we are basically on schedule. We have still got the cost management challenges there that we have flagged for quite some time, and we still have an independent scientific panel reporting on pipeline routes in the next few weeks, which will give it some prominence. But I think we've tackled all of these issues in a good way, including the appointment of the independent scientific panel.

On Bonga, I think what I feel good about is we have reduced -- six months ago, there were still a lot of technical risks on the project schedule. Now, we have installed all the risers, the gaseous (ph) risers and the production risers, which reduces the uncertainty. That was the big technical hurdle. What we're in now is just straight commission and construction hookup activity. We have two flotells (ph) on the project. I'm going there next week. We're still targeting July startup, but what I would say is the chance of being a month or two earlier is, on a project like that, far less than the chance of being a month or two late. There is a lot to do, and I think it will be sometime in the third quarter. I'll know more after I have seen it next week whether July sounds realistic. That's what all the team is targeting.

Oh, and you asked -- sorry -- about enterprise, what percentage left. I don't think that our divestments are focused on enterprise. There is sometimes a perception that what you bought wasn't good stuff. Remember, we bought it when the oil price was less than $20 a barrel. We have been very pleased. We bought it to achieve exposure to high upside, and that's what it has delivered. And some of them are excellent assets -- there's the Nalston (ph), the Pierce (ph), the Bigipira Salima (ph) and the Italian position, all very valuable, and some of the stuff in Norway. So our divestments are not particularly focused on that portfolio at all.

We'll take one, operator, from the phone, please -- Fadel Gheit of Oppenheimer, please.

Two questions, one on upstream unit profitability. Not only did share profitability per unit is much lower than Exxon and BP, but when comparing 4Q results to any of the prior three quarters, you still have lower unit profitability, despite rising oil and gas prices. My question here is, why wouldn't we see -- forget about comparing Shell to Exxon and BP. I'm comparing 4Q of Shell to first, second and third quarter. And in each of the last three quarters, you had better unit profitability than in the fourth quarter, despite the higher realization in the fourth quarter than in the first, second or third.

Okay. In the fourth quarter, there were some particular charges which amount to a few hundred million dollars, which is impacted on the unit earnings. And they particularly relate to correction accounting change on feasibility costs that had been capitalized. There are some unrecovered costs which are charges that we have essentially taken, written off in that we are not transferring them to some of the joint ventures, as we had originally anticipated. It relates to the agreements and particularly the shift in exchange rates.

(Multiple speakers). Are you talking about charges that are not disclosed?

Sorry?

Are you talking about charges that are not disclosed in your press release, or what?

No, they are indicated there, in the sense of --

Because everything that you have indicated we included in our model, and still we come short of -- the unit profitability is still lower. So is there any reason? Is it higher tax rate, lower -- much higher cost structure? It has to be either taxes or costs.

No, I think we've been fairly transparent, in the sense that we indicated the gains and the offsets on charges, and apart from that, the costs over the year. As I have said, we on operating costs were up $1.09 on the year. So I'm not sure I can help you more than that.

Now, my second question, on the reclassified reserve amount of about 6 billion down, if you were to give us a back-of-an-envelope guess-timate, if you will, of the probability of part or some or more of the reserve will be written off completely, and how much would that be?

I think the question was, do we expect to get the hydrocarbons back and produce them over time? And you combine the first restatements and the subsequent restatements.

Right.

The answer is, as we have always said, we expect essentially that the vast majority of these hydrocarbons will be producible over time.

I mean, we are talking over time like is it 90 percent over five years?

(Multiple speakers) question, please. If we can go to the far back, please? Thank you.

Stuart McCarthy (ph), JP Morgan, and a question for Malcolm. Malcolm, you stated in the presentation that, generally speaking, the reserve restatements will not affect your future production plans. So I was wondering if, more specifically speaking, you could highlight exactly where the reserve restatements do affect future plans, and perhaps in that answer, any information or details on exactly what may happen to costs would be obvious.

The reason for being just a little bit cautious in the way we phrased it -- we're not trying to be tricky, but if you take the decline curve analysis example that we have indicated, of course, it is possible that you will not see what we expect on the simulation, in which case there would be some reduction in the expected production forecast.

We have no reason, no information from any of the changes that have been of a technical nature -- there is no information to suggest a reduction in our expected production outlook. But for the sake of -- obviously, there is a lot of eyes on what we say here. And I wanted to be very clear that we cannot guarantee that we're going to get back to what we believe is the expectation. And I think that decline curve analysis shows it rather clearly. We believe the simulations, because they encompass all information we have about the reservoirs in the way I have indicated, but it is possible we will not get the response that we have modeled.

Just the decline analysis, I think, was just one of four reasons for the reserve restatement. So at half (ph) -- is it 18 (ph) percent of the reserve restatements is due to that reason? (Multiple speakers).

Well, I think we have given the breakdown in our paper is 52 percent is due to recovery factor analysis, and the major contributor to recovery factor analysis was the issue of decline curve analysis. And then I tried to also give clear other examples. The Pilton (ph) example actually illustrates the three other phenomenon. So you have seen there the proved area phenomenon, the lowest known hydrocarbons phenomenon and the recovery factor, in terms of not having a local analog to demonstrate water injection. Between that, those are the four factors. And I hope you'll see that in each case, it is reasonable to expect that there is no change in our expectations. They are around technical reporting factors.

Jonathan (ph)?

(indiscernible) from Citigroup. I just had a question, I think, relating to margin pressure. You have highlighted Oman and Brunei, the license extensions there. Have you suffered a tightening of fiscal terms as a result of those extensions?

Also, can you give a sort of indication of additional reserves that may have been booked in 2004 from those?

I'm not going to go into the commercial conditions of either of the situations. All I can say is we're pleased to continue to have both of them in our portfolio, and they continue to be important long-term positions to us, in all respects. And we will not be going into country-by-country analysis.

I am particularly pleased about the 40-year extension, but actually, in proved reserves terms at this point, it was not a particularly big contributor. It was important, but not disproportionate in any way.

It's Peter Nichol from ABN Amro. Two questions. Malcolm, to go back to your examples of the rebooking, are you basically saying that you have been booking two proven and provable (ph) reserves as SEC proved bookings or the best case (ph)?

And the second question, since I've got Colin Smith sitting in front of me, I think the question that was trying to be asked was, what is the contribution in 2004 from the major big-ticket disposals that you are expecting this year, i.e., the LPG, Basell and InterGen?

Peter, no, the answer was not to suggest that we booked all of the expectation, either in the decline curve analysis or the other one. They were both examples of where our proved has been influenced by that analysis, and where there was, I think, a lack of understanding at detail level about the importance of applying this strict interpretation of the decline curve.

In the case of the Sakhalin reservoir I showed, I think we have roughly half the proved. So we are now down to 14 percent of the expected. So no way were we booking the total expectation as proved. But in fact, that was what one where we had some external certification of the reserve number that we held before, but the more rigorous application has brought us down to that level. And that's part of this restatement.

The disposal question?

Thanks for repeating it, because acoustically I couldn't hear it beforehand. But having said that, I'm not going to disclose the numbers, because disclosing individual business numbers -- I think we are satisfied with their performance in 2004, and we will have a hard look at whenever is offered on these businesses if you actually go for a divestment, yes or no. So the money has to be right, and the multiple has to be right before we sell.

Fred Lucas, Cazenove. A few quickies on the buyback. What needs to happen to take the buyback from 3 to 5 billion? Is 5 billion a limit, and will you consider doing closed-period buybacks this year?

I think, on the limit, we gave a range of 3 to 5. I think that at this stage for 2005, what is in our plans. Once the year evolves, we will have a close look at if it's at the 3 or the 5 billion level. I think we go through that once the year progresses.

I think -- let me just be clear on the buybacks, because I heard some questions already coming. We have very few trading days actually left where we can do buybacks between now and the unification, on the 28th of June. So you will see the buybacks are more second-half-driven than, actually, first-half-driven. And so, in that sense, I think you can expect a rather cautious buyback program in the first few months.

We'll take one from the phone, please, and then we'll take one more, and I think that will be it. From the phone, Mark Gilman (ph), please?

A couple things for Malcolm. The minority piece of the 1.4 billion reserve reduction, Malcolm?

I can't give you that, Mark, at the moment.

I'm sorry. I didn't hear you.

No, I didn't give you an answer, because I didn't have it at hand.

Mark, I think it must be pretty low.

We will take it up when we come back -- not immediately in my head.

Okay, let me move on to something else. Are you suggesting that the SEC has basically, in their requirements, repealed the law of exponential declines, which is part of the industry's history, as it relates to how reservoirs perform, with respect to reserve bookings?

No, Mark, I am basically saying that the way in which our advice from external experts has been applied, and the situations in which we have applied what I showed you today, the sort of linear decline curve analysis, has basically been in accordance with all of the guidance that they have given us, in the situations where you have to adhere to this and where not.

Linda wants one (indiscernible).

Just to say the example Malcolm showed -- this is from an old petroleum engineer -- the example Malcolm showed was a gas rate plot versus cumulative production, which is not the same as the exponential, semi-log (ph) plot that you do for oil fields, which is rate versus time, which is still applicable.

Thank you, Linda. We have time for one more from the floor. There are none? Then thank you very much for coming.