Summary results

Record earnings and cash generation

Jeroen van der Veer, Chief Executive, said: “2004 was a year of extremes, with the reserves recategorisation on one hand and record net income and cash generation on the other. Our performance demonstrates our financial and operational resilience, and the quality of our people and assets. We have taken the steps necessary to close out the reserves issue, made substantial improvements to our portfolio and are reshaping the organisation. We expect to pay out at least $10 billion in dividends in 2005 and will relaunch our share buyback programme. The proposal to create Royal Dutch Shell plc reflects our commitment to regain our competitive strength.”

Segment earnings

2004 Basic earnings per share — see note 1 and note 9

2004 Second interim dividend

2004 Reported net income- see note 1

2004 CCS earnings — see note 1 and note 3

2004 ROACE — see note 1 and note 5

2004 Upstream EP earnings- see note 1

2004 Production

Reserve Restatement

Reserves Replacement Ratio (RRR) 2004

2004 Upstream GP segment earnings

2004 Downstream OP segment earnings

2004 Downstream Chemicals segment earnings

2004 Cash flow from operations

2004 Debt ratio

2004 Capital Investment

2004 Proceeds from divestments

2004 Share buy back

Update on Transaction

Outlook 2005

2005 Dividend payments

2005 Buyback program

Capital Investment

Divestments 2004-2006

Gearing

Production

Reserves Restatement as at end 2003 (financial impact see note 1)

On 28 October 2004, the Group provided early guidance that reserve audits indicated the potential for an SEC proved reserve reduction of approximately 900 million boe. At that time, some 55% of the proved reserve base had been subject to preliminary review by our internal audit teams.

The Group has now completed its proved reserves reviews and internal audits for the period 2003 and earlier, and has determined that it will restate approximately 1.4 billion boe of proved reserves. SEC proved reserves at 31 December 2003, previously reported as 14.35 billion boe, are estimated to be 12.95 billion boe.

These revisions result from a thorough review of the portfolio by asset teams and completion of the audit process that commenced mid 2004. More than 3,000 staff have been trained on SEC-compliant reserves estimation procedures, and have engaged in a detailed review of 100% of the Group’s asset base, in many cases assisted by external consultants. In addition, an extensive programme of 30 internal audits was conducted with the participation of separate external consultants. The reserve changes announced today have been agreed by the Exploration and Production Reserves Committee, with final review by the Executive Committee, Group Audit Committee and Parent Company Boards completed as of 2 February 2005.

Restated volumes are primarily a result of re-interpretation of technical data consistent with SEC definitions. Four technical issues contribute to the restatement: recovery factor analysis and interpretation accounts for approximately 52%; definition of proved area approximately 31%; lack of suitable field analogues for improved recovery approximately 8%; and interpretation of lowest known hydrocarbons accounts for approximately 6%. Non-technical issues such as project phasing and contractual issues contribute 3%, in contrast to earlier announced restatements. The proportion of proved developed reserves in this restatement is around 45%.

This announcement of a further adjustment in SEC proved reserves reflects the application of our more rigorous and detailed estimation and reporting procedures, announced in April 2004. We have completed the 2004 reserves review and based on this will publish final figures with the publication of our Annual Report and Form 20-F filings. We expect to publish details of our reserves process and guidelines prior to our Annual General Meetings in June 2005.

The proved Reserves Replacement Ratio (RRR) for 2004 is expected to be in the range 45-55% before year-end pricing impact and divestments. Including these items, the proved RRR is expected to be in the range 15-25%. The impact of year-end pricing is 14%, most of which is attributable to low year-end bitumen prices at Peace River in Canada, leading to the removal of all Peace River SEC proved reserves. The remaining year-end pricing impact is attributable to a reduction in reserve entitlements in production sharing contracts. Divestments reduce the proved RRR by 16%.

The SEC proved reserves estimates do not include petroleum reserves of around 600 million barrels associated with oil sands in Canada, which contributed 80 thousand boe per day in 2004 to production.

The Group continues to target 100% Reserves Replacement over the period 2004-2008. Most proved reserves are expected to be added in the latter part of the period as new projects are developed and brought on stream.

Upstream:

Exploration and Production; Gas and Power

     Upstream portfolio developments during the quarter were:

     Petroleum Development Oman (Shell share 34%) extended its oil concession licence in Oman to carry out petroleum operations to 2044. This concession accounts for more than 90% of Oman’s current crude oil production.

     During the fourth quarter, exploration discoveries were made in Gabon, Malaysia and Alberta, Canada and appraisal drilling was successful at Gumusut in deepwater Malaysia.

     In Ireland, planning permission was received for the development of the Corrib gas field (Shell Share 45%).

     First oil and gas was produced from Holstein (Shell share 50%) in the Gulf of Mexico, West Salym (Shell share 50%) in Western Siberia and from Goldeneye (Shell share 49%) and Howe (Shell share 60%) in the North Sea.

     The divestments of Block 18 in Angola (Shell share 50%) and the Rosetta concession in Egypt (Shell share 40%) were completed. In addition, an agreement was signed for the sale of the Schooner and Ketch gas fields in the UK and for Chinese National Offshore Oil Corporation Limited to participate in the North West Shelf (NWS) venture in Australia.

     The Australian NWS venture delivered its first LNG cargo from LNG train 4.

     The Sakhalin LNG joint venture signed a supply agreement for 1.5 million tonnes per annum (mtpa) for 22 years with Tokyo Electric Power. Malaysia Tiga LNG concluded a supply agreement with Kogas in Korea for 2.8 mtpa from 2005 to 2008 and the Australian NWS LNG partners concluded agreements with Guangdong Dapeng LNG of China for the supply of 3.3 mtpa from 2006 for 25 years and equity participation of Guangdong Dapeng LNG in part of the NWS project.

     The sale of the gas transportation business of N.V. Nederlandse Gasunie to the Dutch government for €2.8 billion (Shell has a 50% share) was agreed. Completion is expected mid 2005 contingent on Dutch parliamentary approval. Shell also divested its 16.67% interest in gas distribution companies Distrigas SA and Fluxys SA in Belgium, the majority of its gas transmission businesses in the Gulf of Mexico and part of its shareholding in Enterprise Products Partners L.P. Shell also agreed to sell a further 25% equity interest in the Altamira LNG import terminal project in Mexico, retaining capacity rights.

Downstream:

Oil Products and Chemicals

     Downstream continued implementation of the Group’s strategy for reshaping the portfolio during the quarter.

     The sales of Shell’s US Mid-Continent and Mid-West refined products pipeline systems were completed with total gross cash proceeds of just over $1 billion. The sale of the retail and commercial assets in Portugal and of the downstream assets mainland Spain were completed.

     The sale of Shell’s 64% equity share in the Rayong Refinery in Thailand was completed, reducing Shell’s consolidated debt by some $1.3 billion.

     Asset sale agreements were signed for some Oil Products businesses in the Eastern part of the Caribbean, Romania, the Netherlands and the USA. Additionally, Shell concluded the sale agreement relating to the divestment of the LPG business in Portugal. These transactions and the sale of the Canary Islands downstream assets are expected to close in 2005.

     In early 2005, the sale of the Bakersfield Refinery was announced and is expected to complete in the first quarter of 2005.

     Shell announced that it is progressing with the detailed design and engineering of its proposed world scale cracker and derivatives project in Singapore to begin construction in 2006 and start up in 2009.

     PTT PolyCanada (Shell share 50%) started up the 95,000 tonnes per annum plant for the production of polytrimethylene terephthalate (Corterra) in Montreal, Canada. Feedstock will be supplied from Shell’s Geismar petrochemicals plant in the USA.

     In July 2004, Shell and BASF announced the review of strategic alternatives regarding their polyolefins joint venture Basell (Shell share 50%). The options being reviewed by the shareholders include the sale of their stakes. To date, a number of offers for the company from both financial and strategic buyers have been received.

Exploration
and
Production

Earnings by segment

     (a) All amounts in this announcement for the Group and the Exploration and Production segment do not yet give effect to the financial impact of the additional reserves restatement announced today. The Group and Exploration and Production segment results will be restated in both the prior and current periods — see note 1 [Reserves restatement] on page 21.

     Fourth quarter segment earnings of $2,578 million were 26% higher than a year ago, mainly due to higher hydrocarbon prices.

     Earnings this quarter included divestment gains offset by charges. Divestment gains of $306 million from assets in Angola, Australia and Egypt, and a $228 million mark-to-market valuation credit related to certain UK gas supply contracts, were offset by charges including deferred tax revaluations and unrecoverable costs.

     Liquids realisations were 46% higher compared to an increase in Brent of 50% and WTI of around 55%. Outside the USA, gas realisations increased by 14%. In the USA gas realisations increased by 56%, compared to an increase in Henry Hub of 23%.

     Total hydrocarbon production for the quarter was 3,837 thousand boe per day. Excluding the impact of divestments of 55 thousand boe per day, production is 2% lower than a year ago; this reflects a 7% decrease in oil production and a 5% increase in gas production.

     Production benefited from new fields in the USA (primarily Na Kika), Malaysia (Jintan) and the UK (Goldeneye, Howe, Scoter) and the ramp-up of production (in Nigeria and Brazil) totalling some 180 thousand boe per day versus the same quarter last year. New production volumes exceeded field declines of approximately 150 thousand boe per day, mainly in the USA, the UK and Norway. Production quarter on quarter was impacted by hurricanes in the Gulf of Mexico by some 43 thousand boe per day.

     Capital investment in the fourth quarter of $2.9 billion, excluding the minority share of Sakhalin, and including exploration expense of $0.5 billion, was 13% higher than the corresponding period last year.

     Full year earnings of $9,664 million were 6% higher than a year ago, mainly due to higher hydrocarbon prices.

     Divestment gains of $608 million in 2004 were offset by $118 million mark-to-market valuation charges for certain UK gas supply contracts and a $330 million charge for the write down of various exploration assets. Other charges (including tax) of $582 million led to an overall net charge of $422 million for 2004.

     Earnings were further impacted by lower hydrocarbon production, an increase in the effective tax rate, higher depreciation, higher operating costs and exploration charges and the effect of a weaker dollar.

     The increase in the effective tax rate this year is due to the effect of higher oil and gas prices on certain production contracts and an increase in the tax burden in Denmark.

     Liquids realisations were 29% higher than in 2003 against an increase in Brent and WTI of 33-34%. Outside the USA gas realisations increased by 10%. In the USA the increase was 13%, higher than the Henry Hub increase of 4%.

     Total hydrocarbon production for 2004 was 3,772 thousand boe per day and 3% down compared to a year ago. Excluding divestments of 76 thousand boe per day, the year on year price impact on Production Sharing Contracts (PSC) and the increased effect of hurricanes in the Gulf of Mexico, production was unchanged compared to 2003; this reflected a decrease in oil production of 2% and an increase in gas production of 3%.

     Production benefited from new fields in Canada (Athabasca Oil Sands), Brazil (Bijupira Salema), the USA (mainly Na Kika and Habanero), Malaysia (Jintan) and the UK (Carrack and Scoter) and ramp up of production totalling some 221 thousand boe a day. New production volumes exceeded field declines, mainly in the USA, the UK, Oman and Norway of some 163 thousand boe per day.

     Capital investment in 2004 of $8.8 billion, excluding minority share of Sakhalin, was similar to a year ago. Exploration expenditure including signature bonuses amounted to $1.3 billion in 2004.

Gas & Power

     Fourth quarter earnings of $1,020 million compared to earnings of $266 million a year ago. The current quarter benefited from divestment gains of $564 million, 12% higher LNG sales volumes (at quarterly record of 2.76 million tonnes), improved realised LNG prices and higher dividends. LNG volumes include the start-up of Australian NWS LNG Train 4 and the continued ramp-up of Malaysia Tiga LNG volumes. Marketing and Trading earnings were better than the same period last year.

     Full year 2004 segment earnings of $2,155 million compared with earnings of $2,289 million a year ago. 2004 earnings included $748 million income from divestment gains versus $1,120 million in 2003. Strong earnings reflected a 9% increase in LNG sales volumes and higher realised LNG prices and dividends. Income from Gas-To-Liquids (GTL) increased as a result of high asset utilisation and margins at the Malaysian Bintulu plant. Midstream and Marketing and Trading income were lower and development costs increased during the year. LNG volumes benefited from the start-up of Australia NWS joint venture Train 4, Malaysia Tiga volume ramp-up and a full year of Nigeria LNG Train 3 volumes.

Oil Products

     Fourth quarter segment earnings were $1,633 million compared to $481 million a year ago.

     Fourth quarter CCS earnings were $2,297 million compared to $236 million a year ago.

     Oil Products earnings included total net gains of $416 million from divestments ($810 million) and combined charges ($394 million) related to the impairment of certain refining and retail assets and various tax, legal, severance and environmental charges.

     Outside the USA segment earnings were $1,123 million compared to $330 million a year ago. CCS earnings were $1,591 million in the fourth quarter up from earnings of $294 million a year ago. Net gains of $75 million are included in these results (2003: net charges $155 million). Refining earnings were up as a result of strong margins in Europe and Asia Pacific. Refinery intake was 1.6% lower than the prior year. Marketing earnings increased versus the prior year due to stronger retail and commercial margins. Trading profits were up versus the fourth quarter of 2003. Overall operating costs increased by $493 million due largely to the impact of a weaker US dollar on non-dollar denominated operating costs.

     In the USA segment earnings were $510 million compared to $151 million a year ago. CCS earnings were $706 million compared to a loss of $58 million in the fourth quarter of 2003. Fourth quarter 2004 earnings include net gains of $341 million (2003: net charges of $169 million). Refining earnings increased as a result of stronger Gulf Coast and West Coast refining margins. Refinery intake declined nearly 8% due to the sale of the Delaware City refinery in the second quarter of the year. Plant utilisation was up marginally and unplanned downtime was reduced. Marketing earnings declined, as the impact of higher retail and commercial margins was offset by lower Lubricants results reflecting lower volumes and margins as well as higher cost. Retail and commercial volumes declined in line with the ongoing network optimisation. Trading earnings were up versus last year.

     Full year segment earnings were $7,537 million compared to $2,860 million a year ago.

     Full year CCS earnings were $6,530 million in 2004, an increase of 107% compared to earnings of $3,147 million in 2003. Earnings included net gains of $1,038 million from divestments and $475 million charges related to the impairment of certain refining and retail assets and various tax, legal, severance and environmental charges. This compares to 2003 net charges of $427 million.

     Outside the USA segment earnings were $5,597 million compared to $2,461 million a year ago. CCS earnings were $4,844 million, 75% up from earnings of $2,768 million in 2003. Net gains of $242 million are included in these results (2003: net charges $164 million). Refining earnings were up as a result of stronger refining margins for most of the year in Europe and Asia Pacific. Refinery intake was up about 1% versus 2003. Marketing earnings increased versus the prior year due to stronger retail and commercial margins in the last half of the year. Refinery utilisation was down slightly from 81% to 80% due to higher planned maintenance downtime. Trading earnings were up over 2003. Overall operating costs increased by $1,639 million due largely to the impact of a weaker US dollar on non-dollar denominated operating costs.

     In the USA segment earnings were $1,940 million compared to $399 million a year ago. CCS earnings were $1,686 million in 2004 substantially up from earnings of $379 million in 2003. Net gains of $321 million are included in 2004 results (2003: net charges $263 million). Refining earnings increased as a result of stronger Gulf Coast and West Coast refining margins for much of the year. Refinery intake declined 2%; lost intake due to the sale of the Delaware City refinery was partially offset by higher intake at other refineries. Refinery utilisation was up nearly 2 percentage points due to lower unplanned downtime. Marketing earnings declined as a result of lower marketing margins for most of the year and reduced earnings from Lubricants due to lower volumes and margins as well as higher cost. Retail and commercial volumes declined due to ongoing portfolio rationalisation. Trading earnings were up significantly versus the prior year.

Chemicals

     Segment earnings for the fourth quarter were a loss of $200 million and after the impairment of the investment in Basell amounting to a loss of $565 million. This compared to a loss of $354 million last year, which included net charges of $417 million. Earnings reflected stronger demand and higher margins and benefited from capacity additions in 2004 (Deer Park cracker expansion and Sabina Petrochemicals butadiene plant start-up in the USA and the expansion of the EO/Glycols unit in the Netherlands). Earnings increased relative to a year ago due to improved industry margins tempered by cost of sales increases in the USA due to falling crude based feedstock prices during the fourth quarter 2004 and crude and ethylenes inventory valuation. Unplanned downtime of cracker capacity in Europe as well as a late-December unplanned shutdown at Deer Park in the USA impacted sales volumes and earnings. The weaker US dollar improved margins outside the USA, partly offset by a negative impact on costs.

     Full year segment earnings were a profit of $930 million and after the $565 million impairment of the investment in Basell. This compared with a loss of $209 million in 2003, when earnings were impacted by charges of $549 million. The improvement in earnings this year was attributable to higher operating rates and more favourable margins. Sales volumes increased by 5% reflecting higher demand and capacity additions. Asset utilisation was 3% higher on average, reflecting higher operating rates in the second and third quarter of 2004, although in the first and the fourth quarter asset performance was impacted by planned and unplanned downtime of crackers in Europe and in the USA. Margins improved for most products, reflecting price realisations that outweighed the growing cost of feedstocks.

Other Industry
and
Corporate segments

     In the fourth quarter Other industry segments (Renewables, Hydrogen and Consumer) earnings were a loss of $81 million, compared to a loss of $40 million in the same period a year ago. Corporate net costs were $305 million compared to $396 million a year ago. Positive difference in exchange results and reduced interest costs were partly offset by higher costs and taxation expenses.

     Full year losses in Other industry segments were $141 million, compared to a loss of $267 million in the same period a year ago.

     Corporate net costs were $899 million compared to $917 million a year ago.

Note

     The results shown for the fourth quarter are unaudited.

     Quarterly results for 2005 are expected to be announced on 28 April 2005 for the first quarter, 28 July 2005 for the second quarter and 27 October 2005 for the third quarter.

     This announcement contains forward-looking statements, that are subject to risk factors associated with the oil, gas, power, chemicals and renewables business. 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, trends or reserves replacement to differ materially, 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 risk, 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 recategorisation 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 Royal Dutch/Shell Group of Companies’ businesses. The Royal Dutch/Shell Group of Companies does not undertake any obligation to publicly update or revise any of these forward-looking statements, whether to reflect new information, future events or otherwise.

3 February 2005

$ million