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Filed by Royal Dutch Shell plc

This communication is filed pursuant to Rule 425 under The Securities Act of 1933, as amended,
and deemed filed pursuant to Rule 14d-2 of the Securities Exchange Act of 1934, as amended.

Subject Company: Royal Dutch Petroleum Company

Commission File Number: 001-3788

Date: February 4, 2005

LEGAL INFORMATION

The proposed transaction will be implemented through, among other things, an exchange offer made by Royal Dutch Shell plc, to all ordinary shareholders of Royal Dutch Petroleum Company (“Royal Dutch”). You are urged to carefully review, where applicable: (i) the Royal Dutch offer document and the prospectus which will be filed with the Dutch Authority for the Financial Markets and Euronext Amsterdam by Royal Dutch Shell plc, and (ii) the registration statement on Form F-4 (including the prospectus) and other documents relating to the exchange offer that will be filed with, or furnished to, the U.S. Securities and Exchange Commission (the “SEC”) by Royal Dutch Shell plc and the related solicitation/recommendation statement on Schedule 14D-9 that will be filed with the SEC by Royal Dutch, regarding the offer, because each of these documents will contain important information relating to the exchange offer. You may obtain a free copy of (i) these documents after they are made public in the Netherlands or filed with the SEC and (ii) other documents made public in the Netherlands or filed with, or furnished to, the SEC by Royal Dutch Shell plc, Royal Dutch, and The “Shell” Transport and Trading Company (“Shell Transport”) at the SEC’s website at www.sec.gov or the Royal Dutch website at www.shell.com These documents may also be obtained free of charge by contacting Bart van der Steenstraten, Shell International B.V., FIK Division, PO Box 162, 2501 AN The Hague, The Netherlands or the Company Secretary, The “Shell” Transport and Trading Company, Shell Centre, London SE1 7NA, United Kingdom.

CAUTIONARY STATEMENTS CONCERNING FORWARD LOOKING STATEMENTS

This document contains forward-looking statements that are subject to risk factors associated with the oil, gas, power, chemicals and renewables business as well as risks related to the proposed transaction. It is believed that the expectations reflected in these statements are reasonable, but may be affected by a variety of variables which could cause actual results or trends or reserves replacement to differ materially, including, but not limited to: the failure of the conditions to the proposed transaction being satisfied (including the failure of Royal Dutch and Shell Transport shareholders to approve the proposed transaction); the costs related to the proposed transaction; the failure of the proposed transaction to achieve the expected benefits; changes in dividend policy; the development of the trading market in Royal Dutch Shell plc shares; the accounting implications of the proposed transaction; tax treatment of dividends paid to shareholders and other factors affecting the Royal Dutch/Shell Group of Companies (the “Group”) businesses generally, including, but not limited to, price fluctuations, actual demand, currency fluctuations, drilling and production results, reserve estimates, loss of market, industry competition, environmental risks, physical risks, risks associated with the identification of suitable potential acquisition properties and targets and the successful negotiation and consummation of transactions, the risk of doing business in developing countries, legislative, fiscal and regulatory developments including potential litigation and regulatory effects arising from recategorization of reserves, economic and financial market conditions in various countries and regions, political risks, project delay or advancement, approvals and cost estimates.

Please refer to the Annual Report on Form 20-F for the year ended December 31, 2003 (as amended) for a description of certain important factors, risks and uncertainties that may affect the Group’s businesses. None of Royal Dutch Shell plc, Royal Dutch and Shell Transport undertake any obligation to publicly update or revise any of these forward-looking statements, whether to reflect new information, future events or otherwise.

THE FOLLOWING IS THE TRANSCRIPT OF A PRESENTATION MADE AVAILABLE ON WWW.SHELL.COM ON
FEBRUARY 4, 2005.

ROYAL/DUTCH SHELL
GROUP OF COMPANIES

Q4 AND FULL YEAR RESULTS 2004

PRESENTATION TO ANALYSTS

London, 3 February 2005

At 2.15 pm

ROYAL/DUTCH SHELL
GROUP OF COMPANIES
Q4 AND FULL YEAR RESULTS 2004
Presentation to Analysts
London, 3 February 2005
2.15 pm

Dave Lawrence (VP Group Investor Relations): 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 which will take a few seconds. Thank you. Now I would like to turn it over to Jeroen van der Veer. Thank you very much for coming.

Jeroen van der Veer: Good afternoon ladies and gentlemen. I shall start with an introduction. Then we have Malcolm and Peter Voser, I shall round it off and it will take about half an hour before we take your questions.

2004 – making headway

2004 was a year of extremes for the Group but we are making headway. We achieved record net income and cash generation. This was largely due to the high prices and margins but was helped by strong Downstream profits and operational performance. Our problems in Exploration and Production are being addressed and we have completed the reserves review. We have announced radical proposals for a much simpler, clearer and more accountable corporate structure, and are reshaping our organisation 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 in dividends in the year 2005, subject, of course, to exchange rates. Today we have announced that we will relaunch our share buyback programme, invest more in the business and retain a strong, flexible balance sheet.

Delivering on our strategy

Our performance during the year reflects how we are delivering on our strategy. There is record net income of $18.5 billion which is 48% higher than in 2003. There is record cash from operations of nearly $26 billion – this was 18% up – with a significant contribution from the downstream.

We generated another $7.6 billion in divestment proceeds as we upgraded our portfolio, and our equity LNG volumes continued growing at an impressive 9% a year. Exceeding 10 million tonnes milestone. If we exclude divestments, product-sharing 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.

Downstream lived up to its side of our strategic equation, both with record profitability of $7.5 billion, including $1.8 billion from the US, where the asset base continues to improve.

More upstream, profitable downstream

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 divestments it was the reverse. All businesses contributed but half came from the Downstream, realised at a very good value. We have made excellent progress towards the target range we had given you for divestment and are increasing this target range now from $12 to $15 billion of divestments over the same three year period.

Major items under consideration 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.

Investing in growth

This map shows the range of our investment in growth involving all of our businesses. Let me give you an example of every business. In EP the start of the giant Kashagan development in Kazakhstan; in Gas and Power the decision to build the sixth LNG train in Nigeria; in OP, the retail joint venture with Synopec 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.

Exploration and production: robust results

Let me turn now to exploration and production. Exploration and production earnings of $9.7 billion were 6% higher for the year and 26% higher for the quarter, largely reflecting the high oil and gas prices. Debt adjusted cash flow was a record $16.4 billion. Headline production of nearly 3.8 million barrels oil equivalent a day was in the top end of our indicated range. New production exceeded field declines.

In Nigeria, production reached a million barrels oil equivalent a day, our highest level since 1980.

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 Salym field in Russia started one year early. As we have 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 the low point for production, with the end of a contract in Oman and before new projects ramp up.

Rigorous reserves review process

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, rigour in SEC compliance. Shell reserves reporting guidelines have been revised to be in full compliance with SEC requirements. They – the 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.

Secondly, a succession of review stages for reserve bookings within EP by the Group Audit Committee and, finally, by the Boards.

Thirdly, a strengthened internal audit process reporting outside the line of the Group Audit Committee.

Fourthly, what we did on strengthening of 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 bases. However, this rigour has produced results that we did not anticipate when we produced our 2003 figures in the middle of last year.

Proved reserves restatement

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 oil equivalent to nearly 13 billion barrels. Initial indications are that the financial impact will be about 1% of our 2000-2004 earnings. The changes are largely of a technical reporting nature. We have now completed the reserves review, which was detailed, rigorous and thorough. We intend to move on.

The 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 doing 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%. This excludes what are called “year end pricing” effects and divestments. We continue to target 100% reserves replacement over the period 2004-2008.

I turn now to Gas and Power.

Gas & Power: continued LNG growth

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 up 20% from 2003 with higher LNG volumes and prices. Debt adjusted cash flow of $1.2 billion was up 15%. The 9% growth in LNG volumes in 2004 benefited from the start-up of the fourth North West Shelf train and the ramp-up of the two Malaysia Tiga 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 the sixth train to supply the European and US markets. We expect our LNG capacity to increase by 14% 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 are excited about the progress in developing our Pearl Gas to Liquids Projects in Qatar, applying our technology and experience to build a world scale plant.

Oil Products: driving performance

Now we turn to oil products, which have had a great year. Earnings, adjusted for the estimated cost of supplies, more than doubled, reflecting increased sales and operational improvements as well as better refining and marketing margins.

Crude and oil products trading was more profitable, where our skills and reach in global markets serve us well in a changing business environment. US earnings of $1.7 billion dollars were significantly better, with continued performance improvement and portfolio rationalisation. Unit earnings improved sharply, largely due to much higher refinery margins. However, we also delivered better operational performance, particularly in the US, where years of continuous effort are delivering the promised results.

Unplanned refinery shutdowns in our US refineries fell once again, down one percentage point to under 6% as a result of a strong focus on operational excellence. Elsewhere, 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.

The global roll out of our differentiated fuels included the successful launch of V-Power in the US where it is the best selling premium fuel.

I turn now to Chemicals.

Chemicals: strong operational earnings

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

Operational earnings of some $1.5 billion were more than four times the level of 2003 and higher than in any year 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 utilisation was up 3% which, as you can see, is a continuing trend. The multi-billion dollar Nanhai project in China is on track for commissioning and start-up towards the end of this year.

The introduction of the new Downstream structure, integrating OP and Chemicals in a simplified global organisation under the leadership of Rob Routs, will help us to realise the benefits of standardised 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. The Downstream strength we demonstrated in 2004 is key to our strategy. We intend to continue delivering it.

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

EXPLORATION AND PRODUCTION

Malcolm Brinded

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 in new business milestones. However, the year’s reserves replacement was disappointing, so I shall, first, update you on our SEC proved reserves position and then look ahead.

Reserves review process

Jeroen showed you this slide with the details of our reserves control procedures, and I shall just highlight the actions taken in retraining some 3,000 EP staff, 80% of them being geoscientists and petroleum engineers, and involving many of them in the detailed reservoir by reservoir, and often well by well, review we have conducted since summer last year. 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 rigour is that we have had to make further downward adjustments, but this work had to be as scrupulous as possible so that 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. They remain essentially as I described on 22 September last year, and I shall come back to this.

Year-end proved reserves restatement

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% of our proved reserves base. In addition, we have also now conducted internal audits of some 90% of that base, assisted by external experts. Of the remaining 10%, around half is in the US where our experience to date indicates that we have very little risk of non-compliant volumes and that audit programme 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 finalised. Based on what we know so far, the aggregate impact over the period 2000-2004 is expected to total some $700 million, equivalent to around 1% of income over the five-year period. This is still very much work in progress and the finalised 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 anticipated, with the total currently estimated at some $20 million.

The changes since last June are almost all of a technical reporting nature, with the four main issues listed here in order of importance. I shall give a couple of examples to illustrate these, and the other examples are in the handouts.

I should first clarify why the results have changed compared with last May. When I took over EP last March, I triggered a six-week, high-level review of over 90% 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. We believed this exercise had given us SEC compliant results.

The process could not comprehensively address individual well data across 1,500 fields and over 12,000 wells that we have in our portfolio. We knew we needed to retrain our staff on SEC compliant reserves estimation procedures. What we did not anticipate was the full impact that the retraining of some 3,000 staff would have. This widespread impact became apparent only when the preliminary results of the reviews and audits came through in October. In the end, this has led to changes in some 200 fields, 75% of which were adjustments smaller than 10 million barrels. I would like to give you now a couple of example.

Decline curves

Some 50% of today’s restatement relates to recovery factors, more than half of which is 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. You see on the left production from a typical gas well that has been on line for many years and, you can see that extrapolating from the early production you would have underestimated the resources that were eventually produced, quite significantly.

On the right, you see a North Sea gas well that has been in production for a shorter proportion of its total life. 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 log, the seismic data and so forth, as well as performance from similar reservoirs in other fields. However, we can only report as proved the smaller figure based on a straight line extrapolation of well performance from the early data. We are confident that in general, we will 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 reserves as proved.

I will 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 does not change our development plan. But as part of the 2003 Reserves Restatement, we have reduced the booked amount of SEC proved oil reserves here to just 14% of the oil resources that we expect to produce.

There are three separate technical issues affecting the field 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 we can only use for SEC reporting what is actually found in the two appraisal wells, although from the seismic and pressure data it is very clear that the column is at least twice as thick.

Secondly, 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 kilometres, the dark red areas around the existing appraisal wells, whereas the reservoir is about nine kilometres long. Thirdly, 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 benefits had already been demonstrated in the area in a suitable analogue reservoir and, as it is a first development in this area, we have to use the depletion drive of 18%. When you combine all those factors, you get the 14% that I have indicated.

This is also an example where we will not be able to make further bookings until we drill the development well shown and we will not 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.

VG 6: 2004 Reserves Replacement

Moving to 2004, we will publish the year end reserves position in our annual report and 20F. On current provisional estimation, we estimate that our organic reserves replacement ratio (RRR) during the year was some 45% to 55%. This is a disappointment, but we could not make the reserves bookings that we anticipated back in mid-2004. Although project and drilling progress and results were basically as we expected, application of the more rigorous procedures meant that we could not book the volumes from some projects that we had previously anticipated, even though again there is no change in future production expectations. If we include what is known as year end pricing effects, the 2004 RRR is 30-40%. If we also include the effect of divestments, the figure is 15-25%.

Concerning longer term RRR, we continue to target and average over the five year period 2004-2008 of some 100%. I remain reasonably confident we can achieve this, although clearly the disappointing 2004 result, 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 technical reporting reasons I described earlier on the Sakhalin example, and so it is likely that 2005 reserves replacement will also be less than 100%.

One of the issues that impacted 2004 RRR, the bottom line there, was the year end pricing effect. This was especially significant in the Peace River field in Canada, where we have reduced proved reserves from 164 million barrels to zero, even though production continues and we see potential for producing over one billion barrels of oil from that field in the long term. Were we to have had the year end today, we would not have had to de-book the reserves – that example is shown in the handout.

Unlocking the resource base

In September, I showed this picture of our overall hydrocarbon resource base, which covers the expected, economically producible resources discovered and in our acreage today, and that is the basis for our business planning.

Despite the reductions to our proved reserves, it is our ability to move these expected resources into production that ultimately matters for future cash flows, and that has not changed. As I said in September, we are investing some $10 billion a year to unlock 13 billion barrels of resources with new facilities and infrastructure that will come on stream over the next five years. These are long term investments in long life projects and I would like to show you now a few highlights in regards of the progress: in 2004, we brought nine new fields on stream. Our production for 2005 and 2006 remains in the range we discussed before 3.5 to 3.8 million barrels a day, although as I 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. This gives us confidence that our plan for 2009 production remains in the range 3.8-4.0 million barrels oil equivalent per day. By 2009, we also expect to have taken final investment decisions on something like a further five billion barrels to come on stream in the few years thereafter.

And of course what is important is to actively build our resource base for the future. Particular good news was that we strengthened our acreage position last year and we acquired 50,000 square kilometres of acreage in seven countries, with the potential to deliver at least 20 of what we call ‘big cat’ prospects. We drilled 15 big cat prospects and found hydrocarbons in five of them – in Egypt, in Malaysia and three in Nigeria. We also made discoveries in seven other countries. However, initial volumes were less than we hoped and less than in recent years but we still have 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 and agreement with the Sultanate of Oman, to extend the PDO concession for another 40 years and PDO accounts for 90% of Oman’s production. This follows licence extensions in 2003 of 19 years in Brunei, 15 years in the Baram Delta in Malaysia and 30 years in Denmark. 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 area such as in the Middle East.

Summary

In September, I laid out the strategy for EP and this has not 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 are increasing the resources available for EP business, not just more money but more people in the right places. Our EP business retains a sound foundation of assets, positions and people, and we are now at the turning point. We have taken all the steps needed to put the reserves issue behind us. This year will be the low point of our production but we expect a strong growth after that.

Thank you very much.

Financial Strategy
Peter Voser
Chief Financial Officer

Thank you Malcolm and good afternoon ladies and gentlemen. I am going to focus on cash this afternoon. We manage our business such that our competitive cash performance can fund investment and growth and maintain gearing levels consistent with a prudent balance sheet management. We aim to return cash to shareholders through competitive dividends and share buybacks.

Strong cash generation

Our portfolio generates significant cash — $25.6 billion from operations in 2004. The same year debt adjusted cash flow was $27 billion. On top of that, we realised more than $7.5 billion in divestment proceeds. This cash allowed us to fund our investment programme, including the major upstream projects essential to our strategy.

We have paid a highly competitive dividend, reduced debt by almost $5 billion and bought back almost $2 billion of shares. We come into 2005 in a very strong cash position at $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 improved asset utilisation allowed us to capture the benefits of the high margin environment. Therefore, ladies and gentlemen, we start 2005 in a very strong position.

Investing $15 billion to build the business

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 environment, currently we do not expect this requirement 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.

Raising divestment guidance

Another key element is that we know that improving our competitive performance requires divestment 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. When this is the case, we just simply divest.

Last year as you remember we targeted $10 to $12 billion of gross divestment proceeds for 2004 through to 2006. With the success of our divestment programme last year, we are now increasing our divestment guidance to $12 to $15 billion for the same period, after just one year we are already over half way to the top of that range.

Strong and flexible balance sheet

Maintaining a strong, flexible balance sheet is a priority for us. With our cash generation capacity and the future investment programme, 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%.

Taking into account our cash holdings surplus to operational requirements at the year end 2004, our gearing position was some 16%. This provides us with strength and flexibility as we move forward in 2005, to first deliver competitive returns and growth; second to capture opportunities in the market, and third to return cash to shareholders through a competitive dividend and buybacks.

Priorities for cash

As I said at the beginning my focus today is clearly on cash, and these are my priorities going forward. We manage cash to meet the investment requirements of our industry and 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%. We invest in line with our strategy of ‘more upstream and profitable downstream’ with a continuing $15 billion a year planned for the coming years.

Now let me tell you in the next slide how we are returning cash to shareholders.

$13-15 billion to shareholders in 2005

In 2005, we expect to return a highly competitive $13-15 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 2004 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 price environment, we will relaunch our share buyback programme in 2005 and expect to spend some $3-5 billion.

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

Now I will hand back to Jeroen to conclude the presentation and then we will move into Q&A.

Jeroen van der Veer: Ladies and gentlemen as I said at the beginning, 2004 was a year of extremes.

The year ahead: 2004 – a year of extremes

On the one hand, record net income and record cash generation which is good but on the other hand, the reserves restatement. The reserves review is now completed and we will move on. The 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 under way to do this. It was the powerful performance of the Downstream and the continued growth of our LNG business that really stood out in 2004.

We are ahead of the 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 what we need to do. We have made clear progress in moving our strategy forward.

2005: a stronger Shell

In 2005, we will have a clearer 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 and improving operations. We shape the portfolio even further and now look to realise up to $15 billion in divestments. While 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 we expect to buy back $3-5 billion in shares, while maintaining a strong balance sheet.

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 that we have to move quickly and more decisively. We are doing so, to deliver on our strategy ‘more upstream and profitable downstream’.

Thank you and now I look forward to your questions.

Questions & Answers

Peter Voser: Just before going to the questions we also have with us here today the Executive Director for Gas and Power, Linda Cook; and the Executive Director for Downstream, Rob Routs. You may wish to ask them some questions.

Neil Perry (Morgan Stanley): I have a question for Malcolm and then one for Peter. Malcolm, we used to have reserve numbers that were overstated and you are now giving us reserve numbers which, by your own admission, are understating what you think can be produced from your assets. Can you give us a reserve number which 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 actually got?

Then I have a question for Peter. You mentioned when you talked about cash, you mentioned 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?

Malcolm Brinded: The answer to the first question is that we are not saying that they are understated relative to the rules and the guidance – just for clarity. We have complied rigorously with what we understand to be the rules and the guidance.

No, as we said in September, we are not going to start giving lots of other numbers. This has been an experience in understanding numbers and the rigour around a particular definition. The last thing we want to do is to 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. We think that is probably the best guidance we can give. Internally, that is what we are driving the business on, in terms of managing our business.

Peter Voser: On the acquisition, I would first say that we still consider organic growth as giving us a better yield, going forward at the current price levels. That is the first, fundamental point.

The second point is that, going forward, you have assets or areas of assets, which can give us – because of some synergies – some critical mass, or just strengthen the position which can give us a benefit in terms of performance, even in a higher oil price or gas scenario. However, I think they will go through a very tough scrutiny in terms of profitability outlook, going forward.

We are keeping the balance sheet, or our financial framework, as flexible as possible, to react when the time and opportunities are right. Our key focus, as you have heard, will be on organic growth, in order to get into the competitive return area.

John Rigby (UBS): You have talked about managing the business for cash and, in September, you showed the way that you balanced the business at $25. Are you still able to do that and is that how you plan for the business? If it is not, are you able to talk to the moving parts in the framework that you described in September?

Peter Voser: Thank you for the question, John. Indeed, we are still planning, as we said in September, the long-term — the next few years — at the cash neutral position of $25.

Let me just give you some figures for 2004. As reported, we came out at around $10 a barrel as cash neutral in 2004. If you actually adjust for the higher spending, going forward, and capex, take the rather high number on the divestments out of the charts for the buyback, and I think we are just above $20 in that sense. We have therefore had a very good year, strongly driven by cash performance also in Downstream.

We maintain our target of $25. You have seen all the plans outlined in September refreshed today, and 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 manage the various components going forward. We will stick to the $25 for the time being but we have had a very good year.

Tim Whitaker (Lehman Brothers): I calculate at the end of 2004 that your reserve life will not 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 moving to a higher reserve life? Is that just organic investment over time or can we expect something more strategic.

Finally, earlier on, the previous time when you presented this, you said 100% reserves replacement over the next five years, but that was before the latest downgrade. Presuming that some of those reserves come back in, should we expect therefore more than 100%, or have you essentially reduced your target because you have those additional reserves downgraded to put back in?

Malcolm Brinded: Thank you, Tim. I do not know that I would focus on one number and say that it was the right number. What I would say – as we have said before – an R over P of around nine years which, as you say, is where we are at the end of 04, is not where we want to be. We are growing the resource base and bringing that resource through the funnel.

One of the things we stressed before is that 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 – that Kashagans and the Sakhalins. Then of course there are some, like Athabasca and possibly GTL, that may not contribute to SEC proved reserves but which will still contribute value and production streams and so forth. We have to look at the total resource base and the total value.

Our focus remains and I think that is the right strategy for us. We will see a lot of success in the integrated gas chain and we think we will grow our business in unconventionals. That will contribute to the resource base over time and grow that total resource base.

It will be a combination, with a focus on organic and from our own portfolio. In new business development we see a good deal of success with things like GTL, which is not necessarily coming from exploration but it is leveraging our technology and relationships to get us into new and important positions. Then, over time, as we have said right from the beginning, the third strand has to be the right sort of acquisition, in areas that match our strategy, where we can create value and where we see ourselves as a long-term competitor.

In answer to your question about whether we have moved the goalposts, we said 100% reserves replacement ratio, and we remain with that. Yes, it is from a later starting point but not only do we have the issue and the uncertainty about the timing of those rebookings – and I gave you a couple of examples – but we also have the issue of uncertainty or of a shift in some cases of our understanding of the timings of the bookings that we can make on existing projects. As we have got our heads around exactly what compliance means, it applies both to the portfolio that we had at the end of ‘03 and the expectations of timings, going forward.

We stick with the 100% and we have reasonable confidence in that. I hope that over time, over the long term, we will find resources that we can add that will in turn come through to prove reserves.

Mark Iannotti (Merrill Lynch): Peter, can you help us with the maths again because I am not really getting it. When you are showing just the cashflow last year at $27 billion, and you have told us your capex commitments and that your dividends will be at least 26, that was in a year – last year – where the oil price was $38 and refining margins were at cyclical highs, how does that all square with a $25 cash break-even oil price? I am at a loss to see how those numbers work.

Malcolm, could I then ask you a quick question on the E&P business? It pains me to talk about reserves restatement and the issues surrounding that but today, again, in the fourth quarter results, we have seen what looks like a fairly disappointing E&P result in terms of underlying margins. Can you talk about the underlying margin trends that you see in the actual business, in terms of what you are producing right now, and in terms of costs and cost pressures, on a cash basis in terms of underlying DD&A trends?

Peter Voser: If I could take the first question, you have to adjust a few things in order to get to the $25. Quite clearly, 2005 will be a year where we will pay some $2 billion more dividends because of swapping from two times a year to four times a year. In September we said that, long term, we are looking at a $3 to $4 billion of divestment proceeds on an annual basis, and not the $7.5 billion that you had this year. We are neutralising for buybacks in that sense when we look at the cash neutral numbers. In the way that I have done the maths, when you take all these adjustments, at least our model comes to $25. I cannot give you any more on that.

Malcolm Brinded: On the underlying margin trends, let us take unit costs, operating costs, DD&A and then other factors. The unit operating costs, as we said in July, were probably up by about $1 in 04 – in fact, they were up by $1.09. There was the combination of exchange rates, industry cost pressures and accounting changes, and some shift in our portfolio. In DD&A it is up 8% on the year and, again, there are exchange rates in there. You just see the impact of new projects and investments, as in Brazil and the States.

In overall margin terms, the other issue to keep an eye on is taxation. Clearly, we saw a movement in Denmark last year, which was significant. Going forward, people know that countries are also looking to make sure that they are getting enough investment and there is rather a chase to make sure that they can attract it, so I hope that that trend will not continue.

My last comment is that our longer term focus is on investing in areas with more upside, so that is why you see the investment in the oil sand, where you see that we are actually maintaining our plateau production in Europe over the next five years.

Bert van Hogenhurst: First, talking about the divestments you made 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 in 2005?

Secondly, already that rate and the reserve problem – still, your terminology is indeed a little weaker than it was in September on average, at least. Would it not be reasonable to expect, with a lower base and still the resource base there, that your reserve replacement would actually have to go up, because these are technical changes which can easily be changed into factual reserves and production?

Malcolm Brinded: On the issue about reserves and technical changes, I have answered the question already. We expect 100% and I have reasonable confidence in that. I was not trying to weaken it but I am also acknowledging that yes, while there may be some elements of rebooking, as we indicated in the two examples, the decline curve analysis and the example from the Sakhalin field, you do not get that back immediately. You need to have quite a long history to demonstrate the underpinning, to get those rebookings.

I am 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.’ At the same time, with some of what we saw as an outlook back in the middle of the year, the project is the same and the forecast is the same, the schedule is the same but the timing of the booking is later than we thought. Overall, that is why we have made the same statement today.

Peter Voser: On the capex investment side, as I have said, we were looking at $15 billion at this stage for the total Group and we do not see a diminishing curve on that one. I have said that we are looking at roughly $12 billion for upstream in that sense, and that is where our current plans are.

Jeremy Oldham (Lehman Brothers): I have two quick questions. On 2004 capex, your earlier guidance was $14.5 to $15 billion, and excluding the minority of Sakhalin you delivered $13.4 billion. Can you give us an illustration of what the variance was? Was it project slippage, or were you so good at executing that they came in well under budget?

Now that you have reorganised Chemicals, to put it within or close to Manufacturing and let Rob run it all, can you give some description of how that complex is organised now and what kind of synergies you are starting to find.

Malcolm Brinded: On the capex, at least as far as the EP business is concerned – of which you have indicated that we did not spend a fair chunk – it is actually neither the savings nor slippage in terms of the fact that all of our major projects, and the big projects that potentially, in those that are in full flight, the spend was essentially as we expected.

We have a number where the front end spend is a little slower than we had when we made the estimate but we are actually still on schedule with the project in terms of completion. As quite often happens, we try to avoid it, but engineers will tend to think they will need the money earlier than they will, even though they are meeting the milestones on the project, which is the key thing. 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 and we did not need to put the extra funds in. We could basically do the whole programme, with slightly less money from our side.

Peter Voser: Perhaps I could just add that we also said in October that we would come in below, because we also had an accounting change which accounted for a few hundred million dollars. This is actually a lease contract which is not coming this year but may come in 2006. That had brought it down quite a bit already in the October announcement.

Rob Routs: We have created a good deal of excitement in the organisation around Oil and Chemicals coming together and it is about time. For years, we have been operating those businesses separately and now people are starting to find more and more synergies.

The first steps were really to get the manufacturing facilities together, and that happened on 1 January. There is an excellent operations group which now covers both Chemicals and Refining and applies the same practices to both sides of the house. For instance, turnarounds are now executed in the same way with the same methods and the same regulations on both sides of the business, and that is supposed to throw off a fair amount 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 about three and a half years ago and at that time we set a target of $300 million and we have surpassed that by not having the two organisations together. Bringing them together, we think there is probably a great deal more money on the table than we had already realised.

Adam Zermansky (Deutsche Bank): I have two questions – one for Malcolm and one for Jeroen. Malcolm, do you sense any possibility that the SEC will have flexibility in the future, or change their views on things like year-end pricing and this very strict interpretation that you have taken?

Then Jeroen, could you talk just a little 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 financial performance than a company like Shell?

Malcolm Brinded: Yes, Adam, I will be brief on the question whether the SEC will change. It is far from our position to offer them guidance on this subject.

Jeroen van der Veer: I liked your question very much – you are talking about the Indias and Chinas especially. If you read the press, basically, the Chinese are moving everywhere and they take a very long-term view – not only in our oil industry, but they even look at nuclear projects and so on.

In the oil industry, we have seen the government-to-government deals, basically, They happened in 1974 after the oil prices went up, and they happened in 1979 and the early 1980s. I do not know whether we are now in a similar timeframe but, if we have learned lessons from the past, it is very close to our present strategic agenda. Governments can talk to governments but where we can differentiate, as a company like Shell, is by being ahead with new technology. Usually, they are state-owned companies and they are not at the forefront of technology, or able to learn quickly from the whole world to apply to new projects. You can say yes, dear government, you can do something with another government, but then your economics will be worse, and you will collect less taxes because we can apply our technology, we can do it better or faster.

Secondly, the multinationals – in our company, we will make sure that we have a huge capability to execute multi-billion dollar projects, basically on time, on schedule and within budget. We are not perfect and sometimes things go wrong, even within Shell, but there are many large projects which we do very well. That is where government is very important as well. Usually, with all due respects, government companies do not necessarily have the same track record in that.

This is about the classic competition in the global market. In the end, your best defence is that we have to offer better value propositions, either with technology or better learnings, or project managers, so that we can speed it up and demonstrate to those governments that we can do a better job. That is our best defence.

Fred Lufer (Bear Sterns): I have two questions. First, I was surprised to hear you say that reserve replacement was likely to be under 100% in 2005. I am curious as to what this says about exploration success in the past five years, and cycle times. That is my first question.

Secondly, do 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?

Jeroen van der Veer: Malcolm will start, and then Rob will take the question about Chemicals.

Malcolm Brinded: We were giving guidance over the five years. I do not think it is a particular judgment on exploration success in the past five years although possibly exploration expenditure and success before that. Cycle times take a long time to translate exploration, wells and then subsequent appraisal into proved, developed reserves or proved reserves. You can see that with Sakhalin and you can see that with fields like Kashagan and so forth.

In fact, we talked before in the analysts’ presentation about the 7.6 billion we found over the five years from 1999 to 2003, 1 billion of which is on stream now. However, we need to accelerate the speed at which we bring discoveries through the funnel. That is very much one of our focus areas.

Rob Routs: If you look at Chemicals across the year, over the last 12 months, the year-to-year performance in on-stream 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. In the first quarter, we had a number of planned turnarounds.

If you want an idea of the financial impact in the fourth quarter, you have to think of $80 to $90 million.

Colin Smith (CSFB): I have three questions, two of which should be quick. Tax rates look as though they cropped up a fair amount in Q4. Bearing in mind Malcolm’s comments about tax rates generally, could you confirm what you think prospective tax guidance is, both on your best case and, let us say in something in the $30 to $35 oil world.

Secondly, thinking about the major assets and business that you have mentioned as being up for disposal, can you tell us what they contributed collectively to earnings in 2004, and also to cash as it would have appeared in your cashflow statement.

Finally, just on cash itself, that ended year-end obviously at 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?

Peter Voser: On the tax rate, it is clearly the high price scenario that drives the tax slightly up. At this stage, I would not like to give a new guidance out compared to the one we have. I shall take another couple of months to get at that and then we shall come back in the first quarter to give you some more exact guidance in a high price scenario how our tax rate will move. The main factor why not coming out at this stage that the discontinued operations reporting does cause some distortion, and I would like to come back with a clear answer on that one. So bear with us but it will be higher going forward at those prices.

I shall take three as well as that is on the cash side. I do not like to be that free, it is not prudent management going forward. We have clear plans in place as to what we shall do with our cash balances in 2005. I like to have some debt position and use the cash in a different way. As kind of guidance for you to go forward, for operational reasons we will need anything between $2-3 billion to have in our stock and the rest we will work with, but you can take it for granted that we shall not drive that to zero. Is that okay? [yes]

Jeroen van der Veer: I believe you asked whether the year end cash balance included the non-representative factor of divestments.

Peter Voser: Quite clearly, we had 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 while I have to say that we also had a very strong quarter.

Jeroen van der Veer: What is the total earnings impact of the divestments in 2004?

Peter Voser: I think there is a note in the press release where you can see that, and we have issued that. I shall come back on that.

Neil McMahon (Sanford Bernstein): I have a few questions. First, will the restatement of the reserves lead to any delay in you merging the companies, and has the SEC started looking back into that again – I am thinking about the financial restatements of your past few years? Secondly, on Upstream, I want to try 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? Finally, what percentage of Enterprise will be left in your portfolio after the divestments beyond 2006?

Jeroen van der Veer: The restructuring of the company which is scheduled to go through the AGMs on 28 June is absolutely on track, and today the aim is that we close the whole debate on reserves and that we can file our figures to the SEC. We are on time with everything, so the whole thing is on track for 28 June.

Malcolm Brinded: We said we had five big cats we have pre-drilled of 100 and I also indicated that they came in some more, some less. In total, I said that our explorations for the year did not deliver the volume we had hoped for or that we have had in previous years, but we have much more appraisal to do and I shall not go any further than that.

As far as Sakhalin, where we have put our A team on it and reinforced on every front, it is still a major project with many issues to address in terms of ensuring that we deliver as expected. I am very pleased with the progress of the LNG site and with the gravity platform base, and the design and construction of the facilities. We are basically on schedule, we still have 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. However, we have tackled all of these issues in a good way, including the appointment of the independent scientific panel.

On Bonga, what I feel good about is that six months ago there was still a lot of technical risks on the project schedule. Now we have installed all the gas risers and the production risers, which reduces the uncertainty, which was the big technical hurdle. What we are in now is straight commissioning, construction, hook-up activities. We have two flow towers on the project and I am going there next week. We are still targeting July start-up but the chance of being a month or two earlier on a project like that is far less than the chance of being a month or two late. There is a lot to do and I believe that it will be sometime in the third quarter, and I shall know more after I have seen it next week whether July sounds realistic, but that is what all the team are targeting.

You asked about what percentage is left of Enterprise. I do not think that our divestments are focused on Enterprise. There is some perception that what you bought wasn’t good stuff but remember that we bought it when the oil price was less than $20 per barrel. We bought it to achieve exposure to high upside and that is what it has delivered, and some of them are excellent assets such as Nelson, Pearce, Bijupira, Salema and the Italian position all very valuable, and some of the stuff in Norway. Therefore, our divestments are not particularly focused on that portfolio at all.

Fadel Gheit (Oppenheimer & Co): I have two questions please. One is on upstream unit profitability. Not only was Shell’s profitability per unit much lower than Exxon and BP, but when comparing Q4 results to any of the prior three quarters, you still have lower unit profitability despite rising oil and gas prices. My question here is, forget about comparing Shell with Exxon and BP, and compare Q4 of Shell to first, second and third quarters. In each of the last three quarters, you had better unit profitability than in the fourth quarter despite the higher realisation in the fourth quarter than in the first, second and third?

Malcolm Brinded: In the fourth quarter, there were some particular charges which amount to a few hundred million dollars, which has impacted on the unit earnings, and they particularly relate to correction accounting change on feasibility costs that have been capitalised. There are some unrecovered costs which are charges that we have taken, written off, in that we are not transferring them to some of the joint ventures that we had originally anticipated as it relates to the agreement, particularly the shift in exchange rate.

Fadel Gheit: Are you talking about charges that were not disclosed in your press release or what?

Malcolm Brinded: No, they are indicated there.

Fadel Gheit: Everything you have indicated we have included in our model and still the unit profitability is lower. Is there any reason, is it higher tax rate, much higher cost structure? It has to be either taxes or cost?

Malcolm Brinded: No, I believe we have 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 said our operating costs were up $1.09 on the year, so I am not sure that I can help you any more than that.

Fadel Gheit: My second question is on the reclassified reserve amount of about 6 billion barrels. If you were to give us the back of an envelope guesstimate of the probability of part, some or more of the reserves that will be written off completely, how much would that be?

Malcolm Brinded: I believe the question was do we expect to get these hydrocarbons back and produce them over time, and you combined the first restatement and the subsequent restatement?

Fadel Gheit: Right.

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

Stuart McCarthy (JP Morgan): I have a question for Malcolm. You stated in the presentation that, generally speaking, the reserve restatement will not affect your future production plans. I wonder whether, more specifically speaking, you could highlight exactly where the reserve restatements do affect future plans and perhaps in that answer give us any information or details on exactly what may happen to costs?

Malcolm Brinded: The reason for being a little cautious in the way we phrased was not that we were trying to be tricky. 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 information from any of the changes that have been of a technical nature to suggest a reduction in our expected production outlook. There are many eyes on what we say here and I want it to be very clear that we cannot guarantee that we shall get back to what we believe is the expectation, and I think that that decline curve analysis shows that very clearly. We believe the simulations because they encompass all the information we have about the reservoirs in the way I have indicated, but it is possible that we shall not get the response that we have modelled.

Stuart McCarthy: The decline analysis was one of four reasons for the reserve restatement. So is 80% of the reserve restatement for that reason?

Malcolm Brinded: We have given the breakdown in the paper, it is 52% that is due to recovery factor analysis and the major contributor to recovery factor analysis was the issue of decline curve analysis. Then I tried to give other examples. The Piltun example illustrates the three other phenomena, so you have seen there the proved area phenomenon, the lowest known hydrocarbon phenomenon and the recovery factor in terms of not having a local analogue to demonstrate water injection. Those are the four factors and I hope you will 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 Wright (Citigroup): I have a question relating to margin pressure. You have highlighted the licence extensions in Oman and Brunei. Have you suffered a tightening of fiscal terms as a result of those extensions? Also can you give an indication of additional reserves that may have been booked in 2004 from those?

Malcolm Brinded: I shall not go into the commercial conditions of either of the situations. All I can say is that we are 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. We shall not be going into country-by-country analysis. I am particularly pleased about the 40-year extension but in proved reserves terms at this point, it was not a particularly big contributor – important but not disproportionate in any way.

Peter Nichol (ABN Amro): I have two questions. Malcolm, going back to your two examples of the rebooking, are you saying that you have been booking to proven and probable reserves as SEC proved bookings in the best case? Secondly, since I have Colin Smith sitting in front of me, I believe 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?

Malcolm Brinded: Peter, the answer is it 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 have been influenced by that analysis and where there was a lack of understanding at detailed level about the importance of applying the strict interpretation of the decline curve.

In the case of the Sakhalin reservoir that I showed, I believe that we have roughly halved the proved, so we are now down to 14% of the expected, so no way were we booking the total expectation as proved. In fact, that was one where we had some external certification of the reserves number that we held before but the more rigorous application has brought us down to that level and that is part of this restatement.

Peter Voser: On the disposal question, thanks for repeating it because acoustically I could not hear it beforehand. Having said that, I shall not disclose the numbers because we are not disclosing individual business numbers. We are satisfied with their performance in 2004 and we shall take a hard look at whatever is offered on these businesses if we go for a divestment, yes or no. 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?

Peter Voser: On the limit, I would give a range of $3-5 billion and at this stage for 2005 that is what is in our plans. Once the year evolves, we shall have a close look if it is as the $3 or the $5 billion level. Let me be clear on the buybacks because I have heard some questions already coming. We have very few trading dates left when we can do buybacks between now and the unification on 28 June, so you will see that the buybacks are more second half driven than first half driven. In that sense, therefore, you can expect a rather cautious buyback programme in the first few months.

Mark Gilman (The Benchmark company): I have a couple of things for Malcolm. The minority piece of the 1.4 billion reserve reduction?

Malcolm Brinded: Cannot give you that at the moment, Mark.

Mark Gilman: I am sorry, I didn’t hear you?

Malcolm Brinded: I didn’t give you an answer because I did not have it to hand.

Jeroen van der Veer: Mark, it is pretty low.

Malcolm Brinded: It is not immediately in my head.

Mark Gilman: Okay, let me move on to something else. Are you suggesting that the SEC has 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?

Malcolm Brinded: No, Mark, I am 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 linear decline curve analysis, has 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 Cook: Hello, Mark, the example that Malcolm showed – this is from an old petroleum engineer – was a gas rate plot versus QM production which is not the same as the exponential semi-log plot that you do for oil fields, which is rate versus time, which is still applicable.

David Lawrence: [No further questions] Thank you very much for coming. Goodbye.

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