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FORM 20-F

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 1-3788 N.V. Koninklijke Nederlandsche Petroleum Maatschappij (Exact name of registrant as specified in its charter)		Commission file number 1-4039 The “Shell” Transport and Trading Company, Public Limited Company (Exact name of registrant as specified in its charter)
Royal Dutch Petroleum Company (Translation of registrant’s name into English)
The Netherlands (Jurisdiction of incorporation or organisation) 30, Carel van Bylandtlaan, 2596 HR The Hague, The Netherlands tel. no: (011 31 70) 377 9111 (Address of principal executive offices)		England (Jurisdiction of incorporation or organisation) Shell Centre, London SE1 7NA, England tel. no: (011 44 20) 7934 1234 (Address of principal executive offices)

Securities Registered Pursuant to Section 12(b) of the Act

		Name of Each Exchange				Name of Each Exchange
Title of Each Class		on Which Registered		Title of Each Class		on Which Registered
Ordinary shares of the nominal (par) value of 0.56 Euro (€0.56) each		New York Stock Exchange*		New York Shares representing Ordinary shares of the issuer of an aggregate nominal amount of £1.50 each and evidenced by Depositary Receipts (“New York Shares”) Ordinary shares of 25p each***		New York Stock Exchange**

*Also admitted to unlisted trading privileges on the following Stock Exchanges: Boston, Cincinnati, Midwest, Pacific and Philadelphia.		**Also admitted to unlisted trading privileges on the following Stock Exchanges: Boston, Cincinnati, Midwest, Pacific and Philadelphia. ***Not for trading, but only in connection with the listing of New York Shares on the New York Stock Exchange.

Securities Registered Pursuant to Section 12(g) of the Act

Securities For Which There is a Reporting Obligation Pursuant to Section 15(d) of the Act

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report. Outstanding as of December 31, 2004: 2,081,725,000 ordinary shares of €0.56 each.		Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report. Outstanding as of December 31, 2004: 9,624,900,000 Ordinary shares of the nominal amount of 25p each.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes ü No

Indicate by check mark which financial statement item the registrants have elected to follow. Item 17    Item 18 ü

Copies of notices and communications from the Securities and Exchange Commission should be sent to:

CRAVATH, SWAINE & MOORE LLP

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Explanatory Note

Reserves Restatements

Second Reserves Restatement

The Second Half Review reflected the implementation of certain remedial actions, designed to strengthen the controls relating to the reporting of proved reserves, undertaken following the restatement of proved reserves and of the standardised measure of discounted future net cash flows contained in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as originally filed with the SEC on June 30, 2004. See “Controls and Procedures – Remedial Actions Taken in 2004” for an additional discussion of these remedial actions.

Financial Restatements

Second Financial Restatement

1	The Group converts natural gas to crude oil equivalent using a factor of 5,800 standard cubic feet per barrel.

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The following table sets forth the adjustments made to reported results to eliminate the effect of the inappropriate overstatement of unaudited proved reserves as described above under “Reserves Restatements”:

Second Financial Restatement effects
Net income										$ million
		2003				2002				2001				pre 2001
Depreciation, depletion and amortisation			(289	)			(118	)			(94	)			(112	)
Share of operating profit of associated companies			(19	)			(6	)			(2	)			(2	)
Income before taxation			(308	)			(124	)			(96	)			(114	)
Total tax			126				54				44				54
Income after taxation			(182	)			(70	)			(52	)			(60	)
Minority interest			(1	)			4				3				7
Net income			(183	)			(66	)			(49	)			(53	)

Please refer to Note 2 on pages G5 to G8 and “Supplementary information – Oil and Gas (unaudited)” on pages G49 to G61 of this Report for additional information regarding the Second Reserves Restatement.

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Cross reference sheet for Annual Report on Form 20-F

		Headings* in this Annual Report which relate to:
		N.V. Koninklijke Nederlandsche		The “Shell” Transport and Trading
		Petroleum Maatschappij		Company, Public Limited
Item number and captions		(Royal Dutch Petroleum Company)		Company
1   Identity of Directors, Senior Management and Advisers		Not applicable		Not applicable
2   Offer Statistics and Expected Timetable		Not applicable		Not applicable
3   Key Information		Selected Financial Data – Royal Dutch Discussion and Analysis of Financial Condition and Results of Operations – Royal Dutch, Group Business and Property – Risk factors		Selected Financial Data – Shell Transport Discussion and Analysis of Financial Condition and Results of Operations – Shell Transport, Group Business and Property – Risk factors
4   Information on the Company		Introduction Discussion and Analysis of Financial Condition and Results of Operations – Group Business and Property Supplementary information – Oil and Gas (unaudited)		Introduction  Discussion and Analysis of Financial Condition and Results of Operations – Group Business and Property Supplementary information – Oil and Gas (unaudited)
5   Operating and Financial Review and Prospects		Discussion and Analysis of Financial Condition and Results of Operations – Royal Dutch, Group Business and Property – Business environment, Description of activities, Research		Discussion and Analysis of Financial Condition and Results of Operations – Shell Transport, Group Business and Property – Business environment, Description of activities, Research
6   Directors, Senior Management and Employees		Royal Dutch – Control of registrant, Management Financial Statements – Note 15 to Royal Dutch, Group; Royal Dutch – Remuneration Report Business and Property – Personnel		Shell Transport – Control of registrant, Management Financial Statements – Note 13 to Shell Transport, Group; Shell Transport – Directors’ Remuneration Report Business and Property – Personnel
7   Major Shareholders and Related Party Transactions		Royal Dutch – Control of registrant, Articles of Association – Rights attaching to each class of shares Discussion and Analysis of Financial Condition and Results of Operations – Legal Proceedings		Shell Transport – Control of registrant, Memorandum and Articles of Association – Rights attaching to shares Discussion and Analysis of Financial Condition and Results of Operations – Legal Proceedings
8   Financial Information		Index to Financial Statements and Exhibits Financial Statements – Royal Dutch, Group Selected Financial Data – Royal Dutch Discussion and Analysis of Financial Condition and Results of Operations – Royal Dutch, Group		Index to Financial Statements and Exhibits Financial Statements – Shell Transport, Group Selected Financial Data – Shell Transport Discussion and Analysis of Financial Condition and Results of Operations – Shell Transport, Group
9   The Offer and Listing		Royal Dutch – Nature of trading market		Shell Transport – Nature of trading market
10 Additional Information		Royal Dutch – Articles of Association, Management, Exchange Controls and other Limitations Affecting Security Holders, Taxation Introduction – Documents on display		Shell Transport – Memorandum and Articles of Association, Management, Exchange Controls and other Limitations Affecting Security Holders, Taxation Introduction – Documents on display
11 Quantitative and Qualitative Disclosures about Market Risk		Discussion and Analysis of Financial Condition and Results of Operations – Group – Risk management and internal control, Treasury and trading risks Supplementary information – Derivatives and other Financial Instruments and Derivative Commodity Instruments		Discussion and Analysis of Financial Condition and Results of Operations – Group – Risk management and internal control, Treasury and trading risks Supplementary information – Derivatives and other Financial Instruments and Derivative Commodity Instruments
12 Description of Securities Other than Equity Securities		Not applicable		Not applicable
13 Defaults, Dividend Arrearages and Delinquencies		None		None
14 Material Modifications to the Rights of Security Holders and Use of Proceeds		None		None
15 Controls and Procedures		Discussion and Analysis of Financial Condition and Results of Operations – Controls and Procedures		Discussion and Analysis of Financial Condition and Results of Operations – Controls and Procedures
16A Audit Committee Financial Expert		Royal Dutch – Management		Shell Transport – Management
16B Code of Ethics		Royal Dutch – Management		Shell Transport – Management
16C Principal Accountants Fees and Services		Discussion and Analysis of Financial Condition and Results of Operations – Royal Dutch – Group Audit Committee; – Principal Accountants Fees and Services		Discussion and Analysis of Financial Condition and Results of Operations – Shell Transport – Group Audit Committee; Principal Accountants Fees and Services
16D Exemptions from Listing Standards for Audit Committees		Not applicable		Not applicable
16E Purchases of Equity Securities by the Issuer and Affiliated Purchasers		Royal Dutch – Purchases of Equity Securities in Royal Dutch by Royal Dutch and Affiliated Purchasers		Shell Transport – Purchases of Equity Securities in Shell Transport by Shell Transport and Affiliated Purchasers
17 Financial Statements		Not applicable		Not applicable
18 Financial Statements		Financial Statements – Royal Dutch, Group		Financial Statements – Shell Transport, Group
19 Exhibits		Index to Financial Statements and Exhibits		Index to Financial Statements and Exhibits

*	Names of the registrants and references to the Royal Dutch/Shell Group of Companies appearing in headings have been abbreviated to Royal Dutch, Shell Transport and Group, respectively. Collectively Royal Dutch and Shell Transport are referred to as the Parent Companies.

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N.V. Koninklijke Nederlandsche Petroleum Maatschappij
(Royal Dutch Petroleum Company),

The “Shell” Transport and Trading Company, Public Limited Company

List of contents		Page
Introduction
Structure of the Royal Dutch/Shell Group			vi
A.  The Parent Companies			vii
B.  Royal Dutch/Shell Group of Companies			vii
C. Presentation of information			viii
D.  Documents on display			ix
Royal Dutch/Shell Group of Companies – Business and Property
A.  Activities and major interests			1
B.  Business environment			1
C. General development of the business			3
D.  Risk factors			4
E.  Description of activities			5
1.  Exploration & Production			5
2.  Gas & Power			19
3.  Oil Products			23
4.  Chemicals			32
5.  Renewables and Hydrogen			34
6.  Research			35
F.  Personnel			36
Selected Financial Data
Royal Dutch			37
Shell Transport			37
Discussion and Analysis of Financial Condition and Results of Operations
Royal Dutch Petroleum Company			39
The “Shell” Transport and Trading Company, Public Limited Company			41
Royal Dutch/ Shell Group of Companies			42
Critical Accounting Estimates			72
Controls And Procedures			75
Principal Accountants Fees and Services			78
Legal Proceedings			79
Royal Dutch Petroleum Company
Control of Registrant			82
Nature of Trading Market			82
Articles of Association			83
Exchange Controls and Other Limitations Affecting Security Holders			86
Taxation			86
Management			87
Shares under option and share purchase plan			91
Purchases of Equity Securities in Royal Dutch by Royal Dutch and Affiliated Purchasers			93
The “Shell” Transport and Trading Company, Public Limited Company
Control of Registrant			94
Nature of Trading Market			94
Memorandum and Articles of Association			95
Exchange Controls and other Limitations Affecting Security Holders			98
Taxation			98
Management			99
Shares under option and share purchase plan			103
Purchases of Equity Securities in Shell Transport by Shell Transport and Affiliated Purchasers			105
Index to the Financial Statements and Exhibits			106
Financial Statements
Royal Dutch Petroleum Company			R1
The “Shell” Transport and Trading Company, Public Limited Company			S1
Royal Dutch/Shell Group of Companies			G1
Supplementary information
Oil and Gas (unaudited)			G49
Derivatives and other Financial Instruments and Derivative Commodity Instruments			G62
Exhibits			E1
Exhibit 8
Exhibit 23.1
Exhibit 23.2
Exhibit 23.3
Exhibit 23.4
Exhibit 23.5
Exhibit 23.6
Exhibit 23.7
Exhibit 99.1
Exhibit 99.2
Exhibit 99.3
Exhibit 99.4
Exhibit 99.5
Exhibit 99.6

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Introduction

Parent Companies

Royal Dutch/Shell Group of Companies

Group Holding Companies

Service Companies

Operating Companies

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A The Parent Companies

The “Shell” Transport and Trading Company, Public Limited Company (hereinafter referred to as “Shell Transport”) was incorporated as a public limited company on October 18, 1897, under the laws of England. Shell Transport is considered resident of England for tax purposes. The registered office of Shell Transport is at Shell Centre, London, SE1 7NA, UK, telephone number 011 4420 7934 1234.

Royal Dutch and Shell Transport do not engage in operational activities. They derive the whole of their respective incomes – except for interest income on cash balances or short-term investments – from their respective interests in the companies known collectively as the Royal Dutch/ Shell Group of Companies.

On October 28, 2004, the Royal Dutch and Shell Transport Boards announced that they had unanimously agreed to propose to their shareholders a transaction through which each Parent Company will become a subsidiary of Royal Dutch Shell plc, which will become a publicly-listed company incorporated in England and Wales and headquartered and tax resident in the Netherlands. Jeroen van der Veer was appointed Group Chief Executive with full executive authority, empowered to drive strategy implementation, operational delivery and cultural change. The Boards believe that the implementation of the transaction will strengthen the Group and deliver significant benefits in the form of clarity (one listed company, one Board, one Chairman and one Chief Executive), efficiency (streamlined decision making) and accountability (clarity in governance, reporting and responsibilities). Please refer to “Discussion and Analysis of Financial Condition and Results of Operations – Unification Proposal” for additional information on this transaction.

The agent for service for both Royal Dutch and Shell Transport in the United States is The Corporation Trust Company, Corporation Trust Center, 1209 Orange Street, Wilmington, DE 19801, USA, telephone number (302) 658-7581.

B Royal Dutch/ Shell Group of Companies

The illustration on the previous page shows the relationship between the Parent Companies and the Royal Dutch/ Shell Group of Companies.

Group Holding Companies

Royal Dutch is entitled to have its nominees elected as a majority of, and Shell Transport is entitled to have its nominees elected as the balance of, the members of the Boards of Directors of the two Group Holding Companies. Every member of the Board of Management of Royal Dutch and every Managing Director of Shell Transport is also a member of the Presidium of the Board of Directors of Shell Petroleum N.V. and a Managing Director of The Shell Petroleum Company Limited. As such, they are generally known as “Managing Directors”. They are also appointed by the Boards of Shell Petroleum N.V. and The Shell Petroleum Company Limited to a joint committee known as the Executive Committee, which considers and develops objectives and long-term plans, for the Royal Dutch/Shell Group of Companies.

Service Companies

Operating Companies

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Exploration & Production: Searches for, finds and produces crude oil and natural gas. Builds and operates the infrastructure needed to deliver hydrocarbons to market.

Gas & Power: Liquefies and transports natural gas, develops gas markets and infrastructure including gas-fired power plants and engages in the marketing and trading of natural gas and electricity. Converts natural gas to liquids to provide clean fuels.

Oil Products: Markets transportation fuels, lubricants and speciality products. Refines, supplies, trades and ships crude oil and petroleum products.

Chemicals: Produces and sells petrochemicals to industrial customers globally.

Other industry segments comprises technical consultancy services, Shell Renewables and Hydrogen.

The management of each Operating Company is responsible for the performance and long-term viability of its own operations, but it can draw on the experience of the Service Companies and, through them, of other Operating Companies.

The information contained in the list of significant Group companies, including the jurisdiction of incorporation and the Parent Companies’ proportion of ownership, filed as Exhibit 8 to this Annual Report on Form 20-F, is incorporated herein by reference.

C Presentation of information

The information given in this Report for the Royal Dutch/ Shell Group of Companies reflects the operational and financial results of Group companies throughout the world. The financial information given is an aggregation of the accounts of all Group companies (except where otherwise indicated) expressed in US dollars.

This report discloses prior year comparative amounts “as restated” to reflect:

–	the recategorisation, as not proved, of 1,371 million barrels of oil equivalent (boe) previously booked at December 31, 2003 as proved reserves following the Group’s reviews of its proved reserves inventory (with the assistance of external consultants) during the period from July 2004 to December 2004 (the Second Reserves Restatement); and
–	the restatement of the Financial Statements of the Group and each of the Parent Companies for the year ended December 31, 2003 and prior periods reflecting the impact of the Second Reserves Restatement (the Second Financial Restatement).

The Second Reserves Restatement and Second Financial Restatement were also reflected in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with US Securities and Exchange Commission (SEC) on March 7, 2005. Please refer to Note 2 on pages G5 and G8 and “Supplementary information – Oil and Gas (unaudited)” on pages G49 to G61 of this Report for additional information regarding the Second Reserves Restatement.

The companies in which Royal Dutch and Shell Transport directly or indirectly own investments are separate and distinct entities, but in this Report the collective expressions “Shell” and “Group” are sometimes used for convenience in contexts where reference is made to the companies of the Royal Dutch/ Shell Group in general. Likewise the words “we”, “us” and “our” are sometimes used in some places to refer to companies of the Royal Dutch/ Shell Group in general, and in others to those who work in those companies. These expressions are also used where no useful purpose is served by identifying the particular company or companies. The expression “Group companies” as used in this Report refers to companies in which Royal Dutch and Shell Transport either directly or indirectly have control, by having either a majority of the voting rights or the right to exercise a controlling influence. The companies in which Group companies have significant influence but not control are referred to as “associated companies”.

The expression “Operating Companies” as used in this Report refers to those Group and associated companies which are engaged in various branches of the businesses of oil, natural gas, chemicals, power generation, renewable energy and hydrogen. The term “Group interest” is used for convenience to indicate the direct or indirect equity interest held by the Group Holding Companies in a venture or partnership or company (ie, after exclusion of all third-party interests).

For information on discontinued operations, see “Discussion and Analysis of Financial Condition and Results of Operations” and Note 4 to the Financial Statements of the Group on pages G12 to G13.

The figures shown in most of the tables in this Report represent those in respect of Group companies only, without deduction of minority interests. However, where figures are given specifically for oil production (net of royalties in kind), natural gas production available for sale, and both the refinery processing intake and total oil product sales volumes of Equilon and the Motiva joint venture (following the Group’s additional share purchases in 2002, Equilon is no longer a joint venture), the term “Group share” is used for convenience to indicate not only the volumes to which Group companies are entitled (without deduction in respect of minority interests in Group companies) but also the portion of the volumes of associated companies to which Group companies are entitled or which is proportionate to the Group interest in those companies.

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Except as otherwise specified or as contained in the Financial Statements, all financial information contained in this Report is presented in accordance with accounting principles generally accepted in the United States.

The discussion and analysis in this Report contains forward-looking statements that are subject to risk factors associated with the oil, gas, chemicals, power generation and renewable resources businesses. It is believed that the expectations reflected in these statements are reasonable, but they may be affected by a variety of variables which could cause actual results or trends 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 risks, risks associated with the identification of suitable potential acquisition properties and targets and the successful negotiation and consummation of such transactions, the risks of doing business in developing countries, legislative, fiscal and regulatory developments, 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.

D Documents on display

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Royal Dutch/Shell Group of Companies – Business and Property

A Activities and major interests

Oil and gas, by far the largest of the Group companies’ business activities (which include the Group’s Exploration & Production, Gas & Power and Oil Products segments), accounted for approximately 90% of net proceeds in 2004. In fact, Group and associated companies constitute one of the largest oil and gas enterprises in the world (by a number of measures, including operating cashflow and oil and gas production). They market their oil products in more countries than any other oil company, and have a strong position, not only in the major industrialised countries, but also in the developing ones. The distinctive Shell pecten (a trademark in use since the early part of the twentieth century) and trademarks in which the word Shell appears support this marketing effort throughout the world. Taken together, Group and associated companies also rank among the world’s major chemical companies (by sales); in 2004 chemicals accounted for around 10% of the net proceeds of Group companies. The Group’s interests in power generation and renewable energy are considerably smaller, notwithstanding that the Group’s renewables business is now one of the larger global solar enterprises (by production). The Group’s various activities are conducted in more than 140 countries and territories.

The breakdown of net proceeds of Group companies by industry segment and by geographical region for the years 2002 to 2004 is set out in the following tables:

Net Proceeds by Industry Segment
(including inter-segment sales)		$ million
		2004				2003				2002
						As restateda				As restateda
Exploration & Production
Third parties			20,643				12,224				11,640
Inter-segment			19,001				20,244				14,680
			39,644				32,468				26,320
Gas & Power
Third parties			9,604				7,377				4,254
Inter-segment			1,210				850				620
			10,814				8,227				4,874
Oil Products
Third parties			207,006				159,075				132,681
Inter-segment			11,924				3,416				3,080
			218,930				162,491				135,761
Chemicals
Third parties			26,877				18,843				14,125
Inter-segment			2,620				1,974				1,082
			29,497				20,817				15,207
Corporate and Other
Third parties			1,060				843				753
Inter-segment			11				29				17
			1,071				872				770
			299,956				224,875				182,932

Net Proceeds by Geographical Area
(excluding inter-segment sales)		$ million
		2004				2003				2002
						As restateda				As restateda
Europe			94,904				70,375				62,575
Other Eastern Hemisphere			49,482				37,482				32,406
USA			102,877				75,109				54,677
Other Western Hemisphere			17,927				15,396				13,795
			265,190				198,362				163,453

a	See Note 2 to the Group Financial Statements.

B Business environment

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recovery from the Gulf of Mexico and concerns over possible supply disruptions from Nigeria and Russia and adequacy of heating oil supply ahead of the peak winter season. Crude prices eased in early November on rising global supplies and continuing mild winter in the northern hemisphere. The decline slowed in mid-December due to OPEC’s decision to cut crude output by 1 mb/d from the start of 2005 and renewed concerns over possible heating oil supply shortage, prompted by cold spells in Europe and the US. Brent and WTI crude prices ended the year 2004 at the $40 a barrel and $43 a barrel level respectively. Crude prices in 2005 will be influenced by the pace of Iraqi oil export recovery, OPEC supply policy, the rate of global economic expansion, particularly in the US and China and the severity of northern hemisphere winter.

Crude oil price conditions are evaluated based on careful assessment of short, medium and long-term drivers under different sets of assumptions, yielding a range of prices to be used in evaluation. Historical analysis, trends and statistical volatility are part of this assessment, as well as analysis of global and regional economic conditions, geopolitics, OPEC actions, supply and demand. Sensitivity analyses are used to test the impact of low price drivers (economic weakness, rapid resumption of Iraqi production, greater than expected increase in non-OPEC production) and high price drivers (greater than expected economic growth, slower than expected resumption of Iraqi production). Short-term events (such as relatively warm winters or cool summers and the resulting effects on demand and inventory levels) contribute to volatility.

The drivers of natural gas prices are more regionalised than the relatively global nature of crude oil pricing. Whilst Henry Hub prices are recognised price benchmarks in North America, the Group also produces natural gas in other areas that have significantly different supply, demand and regulatory circumstances.

For the full year 2004, Henry Hub gas prices averaged $5.87 per million British Thermal Units (Btu) compared to $5.63 per million Btu in 2003. Prices were driven by increasing demand in the face of concerns over production declines onshore United States and Western Canada. Henry Hub prices for 2005 are expected to remain high.

Natural gas prices in Continental Europe and Asia are predominantly indexed to oil prices. In 2004, Japan industry wide LNG (cif) prices averaged $5.13 per million Btu versus $4.77 per million Btu in 2003, reflecting higher oil prices. Shell LNG is primarily sold through associate companies, with prices closely related to industry averages. Realised Shell gas prices in Europe averaged $3.68 per thousand standard cubic feet in 2004 versus $3.30 per thousand standard cubic feet in 2003. Prices in both these markets are expected to remain high for 2005, reflecting a firm oil price outlook.

Excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate high-price conditions in the United States or other markets because of lack of infrastructure and difficulties in transporting natural gas. The Group is planning to increase investment in long-term projects in areas of excess supply to install needed infrastructure to produce and liquefy natural gas for transport by tanker and regasification in markets where demand is strong. Consistent with other Group investments, projects of this type are evaluated using multiple oil price conditions, including price conditions of $20 and less a barrel to assess the resilience of investments at low price conditions.

In 2004, industry refining margins averaged $8.05, $11.65, $4.50 and $2.90 a barrel in US Gulf Coast (USGC), US West Coast (USWC), Rotterdam and Singapore, compared to $5.10, $6.30 $2.70 and $1.05 a barrel a year earlier. The strong margins across the world in 2004 were underpinned in the main by exceptional product demand growth particularly in China and, to a lesser extent, the USA.

During the first half of 2004, margins in the USA and Europe also found support from low gasoline stocks in the USA ahead of the peak driving season, extensive turnaround activities and the introduction of tighter US gasoline specifications. In Singapore, margins were bolstered by a major refinery disruption in Taiwan and heavy refinery maintenance in the Far East and Arab Gulf. US margins eased during the first half of the third quarter with rising gasoline stocks as more refineries returned from turnaround to normal operations. They rebounded in the latter half of the quarter with strengthening middle distillate prices as concerns mounted over the adequacy of heating oil supply for the winter season. USGC margins were further strengthened in late September by the impacts of Hurricane Ivan, which brought a significant reduction in product stocks just before the autumn turnaround season. European margins also fell in the first half of the quarter as gasoline netbacks from trans-Atlantic exports to the US declined but recovered in mid-quarter with the start of seasonal turnaround activities. Singapore margins were well supported by strong Chinese gasoline and middle distillate demand throughout the quarter and rose to a seven year high in September on exceptional kerosene and gasoil price strength. US and European margins remained strong during the first half of the fourth quarter with seasonal turnaround activities but declined in the latter half as refineries resumed normal operations. Singapore margins also stood firm in the first half of the quarter against buoyant Chinese demand for gasoline and gasoil, and rising demand for gasoline from Australia with the start of the driving season. However margins declined in the latter half of the quarter amid slowing product import buying interest into China and a much milder-than-normal winter in Japan in the fourth quarter.

Margins in 2005 will be influenced strongly by the pace of economic expansion in the USA and China, the impact of high oil prices on product demand and the severity of northern hemisphere winter. Some upside support to margins in the Atlantic Basin is expected through seasonal refinery turnarounds in the first quarter and tightening gasoline and diesel specifications in the USA and Europe respectively.

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Petrochemicals industry conditions were favourable. Petrochemicals demand rebounded in 2004 and has shown little signs of cooling throughout the year despite the crude oil price escalation. This, together with low levels of inventories, led to an increase in operating rates relative to last year. In Europe, cracker profitability improved as strong ethylene pricing and co-products (benzene and propylene) credits supported naphtha cracker margins, while the increase of the euro exchange rate against the US dollar tempered the effect of increasing US dollar feedstock costs. In the US price increases in ethylene and co-products offset the impact of the rise in feedstock and energy prices. Even with high and volatile feedstock costs, strong demand is expected to be sustained through 2005 and the short-term outlook for petrochemicals is positive.

C General development of the business

Group and associated companies’ natural gas production available for sale through the end of 2004 has increased by 9% since 2000. Investment continues in the expansion of existing operations and in major new pipelines. Moreover, additional liquefied natural gas (LNG) projects and Gas to Liquids plants are being considered in several countries. Gas is the preferred fuel for power generation and demand for both gas and electricity is expected to grow. LNG equity sales of 10.15 million tonnes in 2004 were a record and were up 9% compared with 2003.

In 2004, we strengthened our acreage position by acquiring some 50,000 square kilometers of acreage in seven countries. We drilled 15 “big cat” exploration wells, which are wells in fields where there has been a major discovery, with discoveries in 5 of them, in Egypt, Malaysia and Nigeria. Appraisal results were positive on several material discoveries in the Gulf of Mexico, Asia and Kazakhstan. We brought various new fields on stream, including Salym in Russia, and Holstein in the Gulf of Mexico. We took final investment decisions on Nigeria LNG Limited’s (Group interest 25.6%) Train 6 in Nigeria, on Pohokura in New Zealand, and on the large Kashagan development in Kazakhstan. In Oman, agreements were signed with the government to extend the terms of Petroleum Development Oman’s (Group interest 34%) concession until 2044. Plans were announced to increase bitumen production at the Athabasca Oils Sands Project (Group interest 47%) from the current 155,000 barrels of oil per day (bopd) capacity to between 270,000 and 290,000 bopd by 2010. Construction is progressing on our major integrated gas projects in Sakhalin in Russia and on Ormen Lange in Norway. Our 2004 production was at the high end of the expected range at approximately 3.8 mmboed, and we delivered record cash flow.

Group companies continue to pursue a policy of a diversified supply base, and they trade actively in crude oil and its refined products throughout the world. Major acquisitions in 2002 in the USA, the world’s largest market, and in Germany, Europe’s largest market, have strengthened Oil Products’ competitive position and enhanced the quality of the global portfolio. This has reinforced the objective of Oil Products leading the global downstream industry. Furthermore, the Group will continue to address environmental concerns through tighter product specifications. Above all, Group companies will maintain their emphasis on innovative customer offers, portfolio optimisation and structural cost reduction. Both refining and marketing operations have ongoing initiatives to improve their health, safety and environmental performance.

In 2004, the Chemicals portfolio was strengthened with new investments, upgrades of existing facilities and business exits. In North America the joint venture butadiene extraction plant in Texas started production in the first quarter of 2004, the Deer Park OP2 cracker debottleneck was completed and the PTT Poly Canada joint venture started operations. In Europe a third reactor was added to the EO/Glycols unit at Moerdijk increasing capacity. In Asia construction continued on the Nanhai petrochemical complex in China with completion targeted for end of 2005 and the cracker and derivatives project in Singapore progressed to the initial design and engineering phase. Also in 2004, the Group exited the Solvents business in Morocco and the MEK unit at Norco was closed. The catalyst restructuring programme was completed with the sale of the catalyst regeneration business and the closure of CS Metals. Also Shell and BASF announced the review of strategic alternatives regarding their polyolefins joint venture Basell (Group interest 50%). A number of offers from both financial and strategic buyers have been received. The shareholders are continuing to review the potential options.

The Group intends to integrate the Oil Products and Chemicals businesses in order to provide opportunities to achieve cost efficiencies from shared services and common manufacturing sites, and from improved use of hydrocarbon resources on integrated sites.

In 2002, Renewables became one of the largest global solar photovoltaic (pv) players (by production) by acquiring the balance of shares in its solar joint venture with Siemens and E.On, and continued its growth in the wind energy sector with the development of two wind parks in California, Whitewater Hill and Cabazon Pass.

All the business activities described in this section are supported by research. The finding of oil and gas, the enhancement of recovery from existing fields and the engineering of offshore structures, are subjects that receive particular attention, as do the products and processes of oil refining, gas processing and chemicals manufacturing.

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D Risk factors

Prices for oil, natural gas, oil products and chemicals may fluctuate.

The Group’s operations and earnings are subject to risks related to currency fluctuations and exchange controls.

The Group’s operations and earnings are subject to risks related to the drilling and well production process and the ability to replace oil and gas reserves.

The Group’s operations and earnings are subject to risks related to the estimation of reserves.

In 2004 and 2005, the Group restated its proved reserves to correct certain errors. See “Discussion and Analysis of Financial Condition and Results of Operations – Reserves Restatements and Financial Restatements” and “Supplementary information – Oil and Gas (unaudited)” for additional information on the restatements. In connection with the restatements, a number of putative shareholder class actions and shareholder derivative suits were filed against, among others, Royal Dutch and Shell Transport, and civil and criminal investigations were commenced by authorities in the US, the UK and the Netherlands. See “Discussion and Analysis of Financial Condition and Results of Operations – Legal Proceedings” for a discussion of these matters.

The Group’s operations and earnings are subject to economic and financial market conditions.

The Group’s operations and earnings are subject to environmental risks.

The Group’s operations and earnings are subject to risks related to operational hazards, natural disasters and expropriation of property.

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The Group’s operations and earnings are subject to risk of change in legislation and fiscal and regulatory policies.

The Group’s operations and earnings are subject to the risks of doing business in politically sensitive or unstable countries.

E Description of activities

1 Exploration & Production

–	Licences (or concessions) which entitle the holder to explore for hydrocarbons and exploit any commercial discoveries. Under a licence, the holder bears the risk of exploration, development and production activities and of financing these activities. In principle, the licence holder is entitled to the totality of production minus any royalties in kind. The state or state oil company may sometimes enter as a joint-venture partner sharing the rights and obligations of the licence but usually without sharing the exploration risk. In a few cases the state oil company or agency has an option to purchase a certain share of production. The lease agreement, typical in North America, is generally the same except for treatment of royalties paid in cash (see below).
–	Production sharing contracts (PSC) entered into with a state or state oil company oblige the oil company, as contractor, to provide all the financing and bear the risk of exploration, development and production activities in exchange for a share of the production. Usually this share consists of a fixed or variable part, which is reserved for the recovery of contractor’s cost (cost oil); the remainder is split with the state or state oil company on a fixed or volume/revenue-dependent basis. In some cases the state oil company will participate in the rights and obligations of the contractor and will share in the costs of development and production. Such participation can be across the venture or be on a per-field basis.

Group companies’ exploration and production interests, including acreage holdings and statistics on wells drilled and drilling, are shown on pages 12 to 13.

Details of Group companies’ and the Group share of associated companies’ estimated net proved reserves are summarised in the following table and are set out under the heading “Supplementary information – Oil and Gas (unaudited)” on pages G49 to G61. Oil and gas reserves cannot be measured exactly since estimation of reserves involves subjective judgment. Estimates remain subject to revision. It should be noted that totals are further influenced by acquisition and divestment activities. Proved reserves are shown net of any quantities of crude oil or natural gas that are expected to be taken by others as royalties in kind but do not exclude quantities related to royalties expected to be paid in cash (except in North America and in other situations in which the royalty quantities are owned by others) or those related to fixed margin contracts. Proved reserves include certain quantities of crude oil or natural gas which will be produced under arrangements which involve Group companies in upstream risks and rewards but do not transfer title of the product to those companies.

As announced on January 9, 2004, March 18, 2004, and April 19, 2004, the Group reviewed its proved reserves inventory (with the assistance of external consultants) during the period from late 2003 to April 2004 (collectively, the First Half Review). Following the First Half Review, 4,474 million barrels of oil equivalent (boe)⁽¹⁾ previously booked at December 31, 2002 as proved reserves were recategorised as not proved (the First Reserves Restatement).

(1)	For this purpose the Group has converted natural gas to crude oil equivalent using a factor of 5,800 standard cubic feet per barrel.

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In connection with the First Reserves Restatement, Royal Dutch and Shell Transport determined, based largely upon the investigation and report to the Group Audit Committee (GAC), that there were deficiencies and material weaknesses in the internal controls relating to proved reserves bookings and disclosure controls that allowed volumes of oil and gas to be improperly booked and maintained as proved reserves. The inappropriate booking of certain proved reserves had an effect on the financial statements, mainly understating depreciation, depletion and amortisation. To eliminate the effects on the financial statements of the inappropriate reserves bookings, Royal Dutch and Shell Transport elected to restate their financial statements (the First Financial Restatement). For a discussion of the identified deficiencies and material weaknesses relating to the booking of proved reserves and of the remedial action taken to address these deficiencies, see “Discussion and Analysis of Financial Condition and Results of Operations – Controls and Procedures – Remedial Actions Taken in 2004”.

As announced on October 28, 2004, November 26, 2004 and February 3, 2005, the Group performed additional reviews of its proved reserves inventory (with the assistance of external consultants) during the period from July 2004 to December 2004 (collectively, the Second Half Review and, together with the First Half Review, the Reserves Reviews). As a result of the Second Half Review, 1,371 million barrels of oil equivalent (boe) previously booked at December 31, 2003 as proved reserves were recategorised as not proved. These changes are reflected in the restatement of proved reserves and the standardised measure of future cash flows contained in this Report (the Second Reserves Restatement and together with the First Reserves Restatement, the Reserves Restatements). The Second Reserves Restatement was also reflected in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with US Securities and Exchange Commission (SEC) on March 7, 2005.

The following tabulation of proved reserves reflects the situation after taking into account the effects of these re-categorisations, including restatement of previously reported figures. Further information on these re-categorizations and restatements is provided in “Supplementary information — Oil and Gas (unaudited)” beginning on page G49.

Proved developed and undeveloped reservesa
(at December 31)						million barrels
						2003				2002
		2004				As restated				As restated
Crude oil and natural gas liquids
Group companies			3,761				5,009				5,782
Group share of associated companies			1,127				805				858

thousand million standard cubic feet
Natural gas
Group companies			37,525				38,370				37,757
Group share of associated companies			3,041				3,188				3,308

a	Excludes oil sands.

Capital expenditure and exploration expense by
geographical areaa (oil and gas exploration and production only)						$ million
		2004				2003				2002
Europe			1,792				2,185				7,519
Africab			2,053				1,861				1,674
Asia Pacificc			447				579				537
Middle East, Russia, CISd			3,217				2,155				785
USA			1,282				1,652				2,015
Other Western Hemisphere			588				686				600
			9,379				9,118				13,130

a	Capital expenditure is the cost of acquiring property, plant and equipment, and – following the successful efforts method in accounting for exploration costs – includes exploration drilling costs capitalised pending determination of commercial reserves. In the case of material capital projects, the related interest cost is included until these are substantially complete. The amounts shown above exclude capital expenditure relating to the Athabasca Oil Sands Project. In addition, the amount shown above includes acquisitions and the costs of acquiring Enterprise Oil (“Enterprise”) in 2002 of $5.3 billion. This has been included within the amount shown for Europe.
	Exploration expense is the cost of geological and geophysical surveys and of other exploratory work charged to income as incurred, and exploratory drilling costs which were initially taken up in capital expenditure pending determination of commercial reserves but where the efforts are subsequently determined to be unsuccessful and then charged to income (with a corresponding reduction in capital expenditure). Exploration expense excludes depreciation and release of currency translation differences.
b	Excludes Egypt.
c	Excludes Sakhalin.
d	Middle East and Former Soviet Union/Commonwealth of Independent States, includes Caspian Region, Egypt and Sakhalin.

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Average production costs of Group companies
by geographical areaa		$/barrel of oil equivalent
						2003				2002
		2004				As reclassifiede				As reclassifiede
Europe			3.82				3.24				2.94
Africab			3.23				2.69				2.75
Asia Pacificc			2.89				2.05				1.96
Middle East, Russia, CISd			4.86				3.83				2.98
USA			4.26				2.93				2.67
Other Western Hemisphere			6.48				5.04				4.50
Total Group			4.04				3.19				2.83

a	Excludes oil sands.
b	Excludes Egypt.

c	Excludes Sakhalin.

d	Middle East and Former Soviet Union/Commonwealth of Independent States, includes Caspian Region, Egypt and Sakhalin.

e	Reclassified as detailed in footnote a in Note 26(c) to the Group Financial Statements.

Crude oil and natural gas liquids productiona										thousand barrels/day
		2004				2003				2002b				2001				2000
Europe
UK			275				354				402				311				378
Norway			129				143				131				89				87
Denmark			142				141				140				130				129
Italy			21				19				–				–				–
Netherlands			8				8				9				10				13
Germany			5				5				5				6				6
Others				c			1				9				1					c
			580				671				696				547				613
Other Eastern Hemisphere
Africa
Nigeria			349				314				215				250				239
Gabon			35				35				46				56				69
Cameroon			15				16				17				19				21
Others			–				–				2				3				3
			399				365				280				328				332
Middle East
Omand			246				269				319				327				326
Abu Dhabi			133				126				100				94				96
Syria			35				44				49				48				50
Russia			32				30				33				23				9
Egypte			10				11				11				14				10
Others			15				17				13				–				–
			471				497				525				506				491
Asia Pacific
Brunei			98				103				101				97				95
Australia			60				73				92				99				111
Malaysia			47				51				59				60				56
China			20				22				24				23				25
New Zealand			15				19				29				30				9
Thailand			–				14				15				16				18
Others			3				3				5				–				–
			243				285				325				325				314
Total Other Eastern Hemisphere			1,113				1,147				1,130				1,159				1,137
USA			375				414				442				411				417
Other Western Hemisphere
Canada			120				44				43				47				46
Venezuela			22				46				46				44				44
Brazil			43				11				2				2				2
Others			–	c			–	c			–				1				3
			185				101				91				94				95
Total			2,253				2,333				2,359				2,211				2,262

						million tonnes a year
Metric equivalent			113				117				118				111				113

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Data reflect continuing and discontinued operations. Production of crude oil and natural gas from discontinued operations, see Note 4 to the Group Financial Statements, was 10 thousand boe/day in 2004 (2003: 36; 2002: 40).

a	Of Group companies, plus Group share of associated companies, and including natural gas liquids (Group share of associated companies is assumed to be equivalent to Group interest). Oil sands and royalty purchases are excluded. In those countries where PSCs operate, the figures shown represent the entitlements of the Group companies concerned under those contracts.
b	The acquisition of Enterprise contributed some 180 thousand barrels of oil equivalent per day to 2002 total hydrocarbon production (9 months of production averaged over the full year). Production came mainly from assets in the UK and Norway.
c	Less than one thousand barrels daily.
d	Exceptionally, the minority interest is deducted in respect of production volumes given for Petroleum Development Oman.
e	Egypt was previously included in Africa.

Natural gas production available for salea										million standard cubic feet/day
		2004				2003				2002b				2001				2000
Europe
Netherlands			1,667				1,527				1,527				1,555				1,431
UK			984				1,002				1,148				1,196				1,118
Germany			411				437				408				428				450
Denmark			383				302				313				309				300
Norway			260				287				242				176				199
Others			34				32				29				20				17
			3,739				3,587				3,667				3,684				3,515
Other Eastern Hemisphere
Africa
Nigeria			375				352				244				219				177
			375				352				244				219				177
Middle East
Oman			471				468				786				553				459
Egypt			211				228				232				248				140
Syria			9				11				16				18				23
			691				707				1,034				819				622
Asia Pacific
Malaysia			739				706				664				580				553
Brunei			554				549				508				491				450
Australia			436				403				373				379				367
New Zealand			258				288				461				470				157
Others			145				190				119				108				98
			2,132				2,136				2,125				2,028				1,625
Total Other Eastern Hemisphere			3,198				3,195				3,403				3,066				2,424
USA			1,332				1,527				1,679				1,598				1,644
Other Western Hemisphere
Canada			449				466				473				507				478
Others			90				74				64				47				35
			539				540				537				554				513
Total			8,808				8,849				9,286				8,902				8,096

Data reflect continuing and discontinued operations. Production of crude oil and natural gas from discontinued operations, see Note 4 to the Group Financial Statements, was 10 thousand boe/day in 2004 (2003: 36; 2002: 40).

a	By country of origin from gas produced by Group and associated companies (Group share). In those countries where PSCs operate, the figures shown represent the entitlements of the Group companies concerned under those contracts.

b	The acquisition of Enterprise contributed some 180 thousand barrels of oil equivalent per day to 2002 total hydrocarbon production (9 months of production averaged over the full year). Production came mainly from assets in the UK and Norway.

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Natural gas production available for salea		million standard cubic metres/day
		2004				2003				2002b				2001				2000
Europe
Netherlands			47				43				43				44				40
UK			28				28				32				34				32
Germany			12				12				12				12				13
Denmark			11				9				9				9				8
Norway			7				8				7				5				6
Others			1				2				1					c				c
			106				102				104				104				99
Other Eastern Hemisphere
Africa
Nigeria			11				10				7				6				5
			11				10				7				6				5
Middle East
Oman			13				13				22				16				13
Egypt			6				6				7				7				4
Syria				c				c				c			1				1
			19				19				29				24				18
Asia Pacific
Malaysia			21				20				19				16				16
Brunei			16				16				14				14				13
Australia			12				11				11				11				10
New Zealand			7				8				13				13				4
Others			4				6				3				3				3
			60				61				60				57				46
Total Other Eastern Hemisphere			90				90				96				87				69
USA			38				43				48				45				46
Other Western Hemisphere
Canada			13				13				13				15				14
Others			2				2				2				1				1
			15				15				15				16				15
Total			249				250				263				252				229

Data reflect continuing and discontinued operations. Production of crude oil and natural gas from discontinued operations, see Note 4 to the Group Financial Statements, was 10 thousand boe/day in 2004 (2003: 36; 2002: 40).

a	By country of origin from gas produced by Group and associated companies (Group share). In those countries where PSCs operate, the figures shown represent the entitlements of the Group companies concerned under those contracts.

b	The acquisition of Enterprise contributed some 180 thousand barrels of oil equivalent per day to 2002 total hydrocarbon production (9 months of production averaged over the full year). Production came mainly from assets in the UK and Norway.

c	Less than one million cubic metres daily.

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Location of activitiesa,b (at December 31, 2004)

Exploration

Production

Shell Operatorc

Onshore

Offshore

Onshore

Offshore

Onshore

Offshore

Europe

Austria

l

l

l

Denmark

l

l

Germany

l

l

l

Ireland

l

l

Italy

l

l

Netherlands

l

l

l

l

l

l

Norway

l

l

l

UK

l

l

l

Africa

Angola

l

Cameroon

l

l

l

Gabon

l

l

l

l

l

Morocco

l

l

Nigeria

l

l

l

l

l

l

Asia Pacific

Australia

l

l

l

l

Brunei

l

l

l

l

l

l

China

l

l

l

l

Malaysia

l

l

l

New Zealand

l

l

l

l

l

Pakistan

l

l

l

Philippines

l

l

l

Middle East, Russia, CIS

UAE (Abu Dhabi)

l

l

Azerbaijan

l

Egypt

l

l

l

l

l

Iran

l

l

Kazakhstan

l

l

l

Qatar

l

Oman

l

l

l

Russia

l

l

l

l

l

Saudi Arabia

l

l

Syria

l

l

USA

USA

l

l

l

l

l

l

Other Western Hemisphere

Argentina

l

Canada

l

l

l

l

l

Brazil

l

l

l

Venezuela

l

l

a	Including associated companies.
b	Where an associated company has properties outside its base country, those properties are not shown in this table.
c	In several countries where “Shell Operator” is indicated, a Group interest company is operator of some but not all exploration and/or production ventures.

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Oil and gas acreagea,b,c,d (at December 31)										thousand acres								thousand acres
																										2003
										2004																Undeveloped
		Developed								Undeveloped								Developed								As restated
		Gross				Net				Gross				Net				Gross				Net				Gross				Net
Europe			8,449				3,200				14,024				4,904				10,172				3,204				15,977				5,307
Africae			6,597				2,058				15,584				8,398				6,956				2,193				18,595				10,253
Asia Pacificf			7,094				3,283				106,326				29,388				3,793				1,638				113,978				33,357
Middle East, Russia, CISg			34,753				11,152				63,469				29,882				34,729				11,062				65,106				30,079
USA			961				531				3,998				2,864				1,512				694				4,040				2,802
Other Western Hemisphere			855				529				27,236				20,421				853				529				28,094				19,835
			58,709				20,753				230,637				95,857				58,015				19,320				245,790				101,633

Number of productive wellsa,b (at December 31)
																										2003
										2004																Gas
		Oil								Gas								Oil								As restated
		Gross				Net				Gross				Net				Gross				Net				Gross				Net
Europe			1,786				478				1,445				491				1,799				468				1,432				485
Africae			1,215				396				36				12				1,380				414				43				14
Asia Pacificf			1,191				551				237				90				1,313				726				247				99
Middle East, Russia, CISg			3,795				1,198				40				38				3,673				1,145				203				129
USA			16,131				8,163				719				520				15,891				7,998				697				486
Other Western Hemisphere			117				112				329				270				116				111				322				265
			24,235				10,898				2,806				1,421				24,172				10,862				2,944				1,478

Number of net productive wells and dry holes drilleda
										2003								2002								2001								2000
		2004								As restated								As restated								As restated								As restated
		Productive				Dry				Productive				Dry				Productive				Dry				Productive				Dry				Productive				Dry
Exploration
Europe			6				2				6				3				9				4				6				4				7				3
Africae			3				1				5				–				6				4				7				1				4				1
Asia Pacificf			5				5				5				7				3				3				8				12				5				6
Middle East, Russia, CISg			7				2				7				4				5				4				6				4				8				4
USA			2				3				10				–				10				4				2				4				9				4
Other Western Hemisphere			1				2				2				5				2				2				3				3				1				2
			24				15				35				19				35				21				32				28				34				20
Development
Europe			27				–				19				1				47				–				38				–				15				–
Africae			11				–				20				1				39				–				14				–				12				–
Asia Pacificf			22				1				41				2				42				1				56				2				40				3
Middle East, Russia, CISg			150				6				149				4				83				12				90				8				98				6
USA			504				1				465				–				559				1				549				2				492				3
Other Western Hemisphere			10				1				8				–				31				–				25				–				11				1
			724				9				702				8				801				14				772				12				668				13

a	Including associated companies.
b	The term “gross” relates to the total activity in which Group and associated companies have an interest, and the term “net” relates to the sum of the fractional interests owned by Group companies plus the Group share of associated companies’ fractional interests.
c	One thousand acres equals approximately four square kilometres.
d	Excludes oil sands.
e	Excludes Egypt.
f	Excludes Sakhalin.
g	Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin.

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thousand acres																		thousand acres																thousand acres
										2002																2001																2000
										As restated																As restated																As restated
		Developed								Undeveloped								Developed								Undeveloped								Developed								Undeveloped
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
			10,417				3,259				19,752				6,930				9,570				3,031				12,616				4,581				9,399				2,973				13,951				4,920
			6,289				1,886				25,394				15,516				6,489				1,984				20,804				11,658				6,491				1,973				18,963				11,261
			3,963				1,864				118,471				40,446				3,762				1,816				115,294				41,691				3,766				1,599				85,219				37,893
			35,448				11,435				18,544				12,771				34,509				11,021				22,921				15,379				34,504				10,962				25,546				18,648
			1,557				754				4,670				3,183				1,599				702				3,931				2,609				1,967				934				4,280				2,743
			832				509				33,338				22,840				767				492				35,709				22,001				1,197				824				49,219				27,368
			58,506				19,707				220,169				101,686				56,696				19,046				211,275				97,919				57,324				19,265				197,178				102,833

										2002																2001																2000
										As restated																As restated																As restated
		Oil								Gas								Oil								Gas								Oil								Gas
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
			2,002				533				1,454				458				1,618				429				1,299				427				1,640				442				1,349				438
			1,399				446				42				13				1,614				550				45				15				1,663				565				47				16
			1,317				726				205				95				1,242				588				199				91				1,162				542				199				77
			3,456				1,085				179				115				3,210				1,031				131				91				3,085				990				86				66
			15,686				8,294				945				686				16,717				8,511				956				658				17,870				8,870				1,044				627
			112				110				314				259				86				86				298				251				338				193				274				230
			23,972				11,194				3,139				1,626				24,487				11,195				2,928				1,533				25,758				11,602				2,999				1,454

Number of wells drillinga,b (at December 31, 2004)
		Exploration								Development								Total
		Gross				Net				Gross				Net				Gross				Net
Europe			6				2				10				4				16				6
Africac			1				–				4				1				5				1
Asia Pacificd			2				1				5				2				7				3
Middle East, Russia, CISe			2				1				35				11				37				12
USA			8				5				16				9				24				14
Other Western Hemisphere			8				5				12				11				20				16
			27				14				82				38				109				52

a	Including associated companies.
b	See Note b on page 12.
c	Excludes Egypt.
d	Excludes Sakhalin.
e	Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin.

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(b) Major oil and gas interests

Europe

Germany A Group company holds a 50% interest in the Brigitta & Elwerath Betriebsfuehrungsgesellschaft (BEB) joint venture (50:50). Exploration and production licences are awarded under the terms of Germany’s Federal Mining Law. Most licences are awarded to more than one company and are governed by joint ventures. Operatorship is normally awarded to the party holding the highest equity share. BEB is involved in some 30 joint ventures with varying interests and is the main operator in Germany. Further German interests include the 43% Group share in the outside-operated Deutsche Offshore Konsortium. Royalties are determined by the individual German states on a yearly basis and are different for the production of natural gas and oil. Royalty incentives are given for the development of tight gas reservoirs. Activities include production activities, gas storage, the operation of two large sour gas treatment plants, numerous compression stations and some 3,000 km of pipelines.

Ireland Shell E&P Ireland Ltd. (Group interest 100%) is the operator for the Corrib Gas Project (Shell equity 45%), currently under development, and has further exploration interests in four licences offshore Ireland, of which three are operated and one is non-operated. In October 2004, planning permission was granted for a proposed gas terminal at Bellanboy Bridge, County Mayo to bring Corrib gas ashore.

Italy Shell Italia E&P S.p.A. (Group interest 100%) was part of the Group’s 2002 acquisition of Enterprise Oil. The main assets are onshore in southern Italy and include various interests in producing assets (Monte Alpi, Monte Enoc and Cerro Falcone which are operated by Eni on behalf of the JV partners), development projects (including Tempa Rossa, managed by Total) and nearby exploration prospects.

Netherlands The Group share of natural gas and crude oil in the Netherlands is produced by Nederlandse Aardolie Maatschappij B.V. (NAM), (Group interest 50%) in a 50:50 joint venture. An important part of NAM’s gas production is from its very large onshore Groningen gas field in which the Dutch state has a 40% financial interest (through the wholly state-owned company EBN). NAM’s production of oil and gas is covered by production licences. Government participation in development and production varies between 0% and 50%, depending mainly on the legislation applicable when the licences were granted and whether the participation covered gas or oil. Production is preceded by an exploration licence, the duration of which, since 1997, varies with the work programme that has to be submitted with the application for a licence. In practice, this means a period of about three to ten years, which can be shortened by the authorities when the exploration effort falls short of the licence or permit programme. Upon making a commercial discovery, a production licence is granted. Production licences with respect to onshore fields, that were originally granted as onshore concessions under former legislation, are not currently limited in time but the duration of the licences with respect to offshore fields and licences granted under the new Mining Act (both relating to offshore and onshore) vary with the estimated production period – normally a period of 15 to 45 years.

Norway As part of the Group’s acquisition of Enterprise in 2002, various assets owned by Enterprise Oil Norway AS (EONAS) were acquired. EONAS was brought under the ownership of A/S Norske Shell (Group interest 100%) in March 2003. A/S Norske Shell holds an interest in a number of production licences, seven of which encompass producing oil and gas fields. A/S Norske Shell also holds an interest in several potential development assets, including Ormen Lange and Skarv. The development decision for the major Ormen Lange gas development discovered in 1997 was taken by the joint venture in 2003, involving an onshore plant/terminal and pipelines for transportation to the markets in the UK and continental Europe. Of the exploration licences acquired through Enterprise, the majority have been divested, farmed out or relinquished. During 2004, Shell divested its interest in the producing Murchinson Field (Norwegian sector). Shell International Pipelines Inc. (Group interest 100%) holds interests in gas transportation and processing systems, pipelines and terminals. The licence period for these assets expires in the period from 2010 to 2020.

United Kingdom Shell UK Limited (Group interest 100%) is one of the largest integrated oil and gas exploration and production companies operating in the UK (by production volumes). Shell operates most of its interests in the UK Continental Shelf on behalf of a 50:50 joint venture. Most of Shell UK’s production comes from the North Sea. Natural gas comes from associated gas in mixed oil and gas fields in the northern sector of the North Sea and gas fields in the southern sector of the North Sea. Crude oil comes from the central and northern fields, which include Brent, Nelson and Shearwater. Shell UK also has interests as a non-operator partner principally in the Atlantic margin, West of Shetlands (Schiehallion/Loyal) fields. Licences issued before August 20, 1976 were valid for an initial period of six years. Following successful exploration, these were extended for a further 40 years in respect of half the original licence area. Licences issued between August 20, 1976 and June 13, 1980 were valid for an initial period of four years followed by a second

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period of three years. In cases of successful exploration, these licences were extended for a further 30 years after relinquishment of two-thirds of the acreage. From June 14, 1980, licences were granted for an initial period of six years (nine years for deepwater), and in successful cases extended for a further 30 years (40 years for deepwater) in respect of no more than half the licence area. Licences issued since July 1988 carry an additional requirement that if, after 12 years of the 30-year period, no field development has been approved, the licence must be surrendered. No royalty is payable on production from fields for which development approval was granted after April 1982; royalties for other fields was abolished with effect from January 2003. With effect from April 2002, a new oil tax on companies operating in the British North Sea was enacted, raising the marginal corporate tax rate from 30% to 40%. Production under older licences is also subject to Petroleum Revenue Tax. The overall effective tax rate changes annually, falling over time as the relative share of production from older licences declines. As part of the acquisition of Enterprise in 2002, various assets owned by Enterprise Oil UK Limited were acquired. During 2003 and 2004 a number of non-core assets were divested, including interests in the producing fields Kittiwake, Mallard, Montrose, Arbroath, Magnus, East Foinaven, Alba, Orion, Indefatigable, Scott and Telford.

Africa

Cameroon Pecten Cameroon Company (PCC) (Group interest 80%) has a 40% working interest in a PCC operated property (Mokoko-Abana), 24.5% interest in a non-operated property (Rio del Rey) and a 25% interest in exploration licences with the state oil company (SNH) and another partner.

Gabon Shell Gabon (Group interest 75%) has interests in eight onshore concessions/ exploitation permits, five of which (Rabi/Kounga, Gamba/ Ivinga, Toucan, Totou and Bende) are operated by the company. The Rabi/Kounga concession was transferred to a PSC with effect from January 1, 2003; it expires in 2022 and includes an option for a five-year extension. The Gamba/ Ivinga concession expires in 2042. The Toucan concession expires in 2023 while the Totou/ Bende concession expires in 2020. The other three concessions (Avocette, Coucal and Atora) expire between 2010 and 2018. Production in Gabon is dominated by the Rabi field, which is operated by Shell Gabon, which holds a 42.5% equity interest in the field. Shell Gabon’s portfolio also includes three exploration permits, one around the Gamba/ Ivinga concession and two near the Rabi, Toucan and Avocette fields (Awoun and Ozigo). The Kenguerie Marin permit offshore Libreville held by Shell Gabon was relinquished in 2003. Two Group companies, Shell Offshore North Gabon B.V. (SONG) and Shell Offshore Gabon B.V. (SOSG), hold three permits in ultra-deepwater areas in the north and south. In 2003 SOSG relinquished four offshore licences (Panga, Douka, Astrid and Anton).

Morocco Two Group companies, Shell Exploration et Production du Maroc GmbH (SEPM), and Shell Deepwater Exploration Morocco GmbH (SDEM) have interests in two exploration licences offshore Morocco. SEPM is operator of and has a 60% paying interest in five deepwater “Rimella” blocks A-E. Partners are Repsol YPF (26.7%) and Wintershall (13.3%) during 2004. The exploration licence is for an initial period of five years (effective January 2001). SDEM is operator and has a 51.46% equity interest (68.62% paying interest) in Cap Draa offshore concession. Other partners are Wintershall AG (15.69%) and Energy Africa Morocco Ltd (15.69%).

Nigeria The Shell Petroleum Development Company of Nigeria Ltd. (SPDC) (Group interest 100%) is the operator of a joint venture (Group interest 30%) with the Nigerian National Petroleum Corporation and two other companies. The venture’s onshore oil and gas mining leases expire in 2019 and offshore leases expire in 2008. In late 2004, the government of Nigeria revoked some SPDC licences. Discussions on this continue into 2005. SPDC expects to retain the majority of the value in the licences. The licences in question are undeveloped and contain no proved reserves.

Shell Nigeria Exploration & Production Company (SNEPCO) (Group interest 100%) operates under a PSC (30-year term) with a 55% working interest in deepwater block OPL-212 and OPL-219. SNEPCO also has a 49.81% interest in deepwater blocks OML-125 and OPL-211 (Agip operated), and a 43.75% interest in deepwater block OPL-209 (ExxonMobil operated).

Shell Nigeria Offshore Prospecting Limited (SNP) (Group interest 100%) has a 35% working interest in block OPL250 (PSC, ChevronTexaco operated).

Shell Nigeria Ultra Deep Limited (SNUD) (Group interest 100%) has a 100% interest in block OPL245 (PSC).

Shell Nigeria Exploration Properties Alpha Ltd. (SNEPA) (Group interest 100%) operates under a 100% working interest in deepwater block OPL322 (40% Shell equity, 50% PSC with NNPC, 10% PSC with indigenous operator Dajo Oil).

Somalia Shell Somalia B.V. holds a 50% working interest and operatorship of Blocks M3-M7, where operations are currently suspended due to force majeure conditions.

Asia Pacific

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operator on behalf of six joint-venture participants of the NWS gas/condensate and oil fields. Gas and condensate are produced from the North Rankin and Goodwyn facilities to an onshore treatment and LNG facility on the Burrup peninsula. Woodside is also the operator of the producing Laminaria and Corallina fields situated in the Timor Sea. In 2005, SDA announced its divestment of non-operated stakes in the Laminaria and Corallina fields. Together with Woodside, Shell also has interests in significant liquid-rich gas fields in the Timor Sea (notably Greater Sunrise) as well as the Browse basin. SDA is also a non-operating participant in the Gorgon Joint Venture in the Carnarvon basin (operator Chevron Texaco Australia Pty Ltd), with interests ranging from 12.5% to 28.57% in gas fields in the Greater Gorgon area, situated West of Barrow Island.

Bangladesh In June 2004, a Group company divested a 37.5% interest in the Sangu field development area. Another Group company divested a 45% interest in exploration Block 5, a 22.5% interest in Block 7, and a 45% interest in Block 10.

Brunei A Group company is a 50% shareholder in Brunei Shell Petroleum Company Sendirian Berhad (the other 50% shareholder being the Brunei government). The company, which has long-term oil and gas concession rights both onshore and offshore Brunei, sells most of its natural gas production to Brunei LNG Sendirian Berhad (Group interest 25%). A Group company has a 35% share in the non-operated Block B Joint Venture (BBJV) concession where gas is produced from the Maharaja Lela Field.

China Group companies hold a 30% interest in the offshore South China Sea Xijiang producing field. Shell holds 100% of the contractor’s interest in the Changbei Petroleum Contract with China National Petroleum Corporation (CNPC), to assess the development potential of the Changbei gas field in the Ordos Basin of western onshore China.

Malaysia Group companies have 19 PSCs with the state oil company Petronas. In many of these contracts Petronas Carigali Sendirian Berhad (PCSB), a 100% Petronas subsidiary, is the sole joint venture partner. Shell is the operator, with a 50% working interest, of eight non-associated producing gas fields and the operator, with a 37.5% working interest, of a further two non-associated producing gas fields. The majority of the gas is supplied to Malaysian LNG Sendirian Berhad (Group interest 15% in MLNG Dua & Tiga plants) for deliveries of liquefied natural gas to customers mainly in Taiwan, Japan and Korea. Regarding oil production and exploration, Shell has a 40% equity stake in the non-operated Baram Delta PSC and exploration interests in the deepwater SK-E block and inboard blocks SK-307, SK-308 and SK-312. Shell operates five producing fields in Sabah waters of which Kinabalu (80% equity share) is the largest. Group companies also have PSCs for exploration and production in Blocks SB-301, SB-303, SB-G and SB-J offshore Sabah. A Group company operates an exploration licence offshore Peninsular Malaysia (PM-303), where Shell also holds a 50% interest in Blocks PM-301 and PM-302, which are operated by a Joint Operating Company with PCSB.

New Zealand Group companies have a 83.75% interest in the production licence for the offshore Maui gas field. In addition, Group companies have a 50% interest in the onshore Kapuni gas field and a 48% interest in the undeveloped Pohokura gas field. The gas produced is sold domestically, mainly under long-term contracts. Group companies also have interests in other exploration licence areas in the Taranaki Basin. All of these interests are operated by Shell Todd Oil Services Ltd, a service company (Group interest 50%).

Pakistan A Group company (Group interest 100%) holds a 28% non-operated interest in the Bhit and Badhra Development and Production Leases. These leases were excised from the Kirthar Exploration Licence which was relinquished in 2003. Another Group company (Group interest 100%) holds 47.5% of an operated deepwater licence offshore of Pakistan that was acquired in April 1998. The Group originally held a 95% interest in this licence, which was reduced following a farm-out of 50% of the Group interest in 2003.

Philippines Group companies hold a 45% interest in the deepwater PSC for block SC-38. The SC-38 interest includes an exploration area and a production licence, the latter relating to the Malampaya and San Martin fields. Current production is gas and condensate from the Malampaya field via a platform located offshore north west of the island of Palawan. Condensate is exported via tankers at the platform and gas is transported via 504 km pipeline to an onshore gas plant in Batangas, on the main island of Luzon. Gas is sold to three combined-cycle gas turbine power plants. In addition to SC-38, Shell currently holds a 50% interest in the deepwater exploration acreage of GSEC-99 north east of Palawan Island.

Thailand In January 2004, a Group company was sold, which held a 75% interest in the onshore S1 concession, containing the producing Sirikit oil field, and a 100% interest in the non-producing offshore Block B6/27.

Middle East, Russia, CIS (including Sakhalin, Egypt and Caspian region)

Azerbaijan A Group company holds a 25% interest in the non-operated Inam licence, offshore of Azerbaijan.

Egypt Shell Egypt (Group interest 100%) participates as operator in five exploration concessions (the West Sitra concession was acquired and the Rosetta concession was divested in 2004) and in four development leases (the Rashid lease was divested in 2004). All concessions and leases are granted on the basis of PSCs. Included in Shell Egypt’s portfolio is an 84% interest in the North-eastern Mediterranean

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deepwater concession. Shell Egypt has a 50% interest in Badr Petroleum Company (Bapetco), a joint venture company with the Egyptian General Petroleum Corporation (the Egyptian national oil company). Bapetco executes the operations for those producing fields where Shell has formal operatorship.

Iran A Group company (Group interest 100%) has a 70% interest in an agreement with the National Iranian Oil Company (NIOC) to develop the Soroosh and Nowrooz fields in the northern Gulf. This Group company is currently operating the development with a view to handing over operatorship to NIOC once full production has been reached.

Kazakhstan A Group company currently holds a 16.67% interest in the North Caspian PSC in respect of some 6,000 sq. kms offshore in the Kazakhstan sector of the Caspian Sea. Development of the giant Kashagan field (declared commercial in 2002) is ongoing. Oil and gas discoveries have also been made at Kalamkas, Aktote, Karain, and Kashagan SW and all are being further appraised. Shell holds a 50% interest in Arman Joint Venture, a small onshore producing company.

Oman A Group company has a 34% interest in Petroleum Development Oman (PDO), which is the operator of an oil concession expiring in 2044, (after an extension during 2004) or at such a later date as the government and the 40% concession-owning company Private Oil Holdings Oman Ltd. (in which a Group company has an 85% shareholding) may agree.

Gas Investment and Services Company Ltd. (GISCO) (Group interest 85%) holds a gas operating agreement which appoints PDO as the operator for any gas discovered in central Oman until 2024, with provisions for extension upon agreement with the government. The first major central Oman gas project involves the supply of gas to customers in the Sur area of north-east Oman, the largest of which is Oman LNG (Group interest 30%). The GISCO funded investment in the Central Oman Gas project is repaid at December 31, 2004 by the Government of the Sultanate of Oman. The management of the Operating Agreement is therefore the sole activity and source of income of Gisco after December 31, 2004.

Qatar In July 2004, Shell signed a Development Production Sharing Agreement with the Qatar government to build a world-scale Gas to Liquids plant, with Shell as the 100% investor. Condensate-rich gas will be supplied from two platforms in the giant North Field located some 50 km offshore. The project start up is planned for 2009.

In February 2005, the Group and Qatar Petroleum signed a Heads of Agreement for the development of a large-scale LNG project (Qatargas 4, Group interest 30%). The project comprises the integrated development of upstream gas production facilities to produce 1.4 billion cubic feet per day of gas and substantial quantities of associated liquids from Qatar’s North field, a single LNG train yielding approximately 7.8 million tonnes per annum of LNG for a period of 25 years and shipping of the LNG to the intended markets in North America and Europe. LNG deliveries are expected to commence around 2010-2012.

Russia Shell Sakhalin Holdings, B.V. (Group interest 100%) holds a 55% interest in Sakhalin Energy Investment Company Ltd. (SEIC). SEIC continues seasonal oil production from the Molikpaq facility on the Piltun-Astokhskoye field, offshore Sakhalin Island. Full development of the Piltun Satokhskoye oil field and Lunskoye gas field, including an LNG plant in the south of Sakhalin Island, continued during 2004. Salym Petroleum Development (Group interest 50%) continued to develop the Salym fields in Western Siberia during 2004. Shell holds a 5.425% interest in the Caspian Pipeline Company which manages a pipeline running from Western Kazakhstan to the Black Sea.

Saudi Arabia Shell is conducting an exploration programme in the Rub Al-Khali area in the south of the Kingdom. Shell will lead the project and has a 40% interest, with Total and Saudi Aramco holding 30% each.

Syria A registered branch of Syria Shell Petroleum Development B.V. (Group interest 100%) holds undivided participating interests ranging from 62.5% to 66.67% in three Production Sharing Contracts that expire between 2008 and 2014 (Deir Ez Zor, Fourth Annex and Ash Sham, which were each amended in 2004 to include deep and lateral formations). In addition, Group companies are parties to a gas utilisation agreement for the collection, processing and sharing of natural gas from designated fields for use in Syrian power generation and other industrial plants.

USA

Affiliates of SEPCo hold a 51.8% interest in a USA-based exploration and production limited liability company, Aera Energy LLC, holding exploration and production assets in California. This venture is accounted for using the equity method of accounting.

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Other Western Hemisphere

Brazil Shell Brasil Ltda (Group interest 100%) has interests in 16 deepwater exploration blocks – five operated (BS-4, BC-10, BM-ES-10, BM-S-31, and SM-170) and 11 non-operated (BC-2, BM-FZA-1, BM-S-8, BM-C-14, BM-C-25, BM-S-17, BM-S-19, SM-320, SM-322, CM-103, CM-151 and ES-M-525). Shell is in the process of withdrawing from three of these non-operated blocks (BC-2, BMC-14 and BMS-17) and formalisation is pending regulatory filings and approval in Brazil. Group interest in these blocks ranges from 15% to 100%. Shell Brasil also operates and has an 80% interest in the Bijupirá & Salema operations, offshore of Rio de Janeiro. Production from the fields commenced in August 2003. The Group retains an interest in the producing offshore Merluza gas field through Pecten Victoria Inc (Group interest 100%). The field is operated by Petrobras.

Canada Shell Canada Ltd (Group interest 78%) is a significant producer of natural gas, natural gas liquids, bitumen, synthetic crude and sulphur. The majority of its gas production comes from the Foothills region of Alberta (Shell Canada’s approximate interest is 85%) and the Sable gas fields offshore of Nova Scotia (Shell Canada’s interest is 31% in the Sable offshore fields and 34% in the onshore gas plant). Exploration rights in Canada are generally granted for terms ranging from one to nine years. Subject to certain conditions, exploration rights can be converted to production leases, which may be extended as long as there is commercial production pursuant to the lease.

Shell Canada produces heavy oil through thermal recovery in the Peace River area (Shell Canada’s interest is 100%) and recently completed a new oil sands mining project in the Athabasca oil sands area of Northern Alberta. Shell Canada holds a 60% interest in the Athabasca Oil Sands Project (AOSP) under a joint venture agreement to develop and produce synthetic crude from Shell’s Athabasca oil sands leases. The AOSP is comprised of the following:

–	the Muskeg River mine, which has a capacity of 155,000 barrels of bitumen per day and is located 75km north of Fort McMurray, Alberta. The mine uses trucks and shovels to excavate the oil sands, as well as advanced extraction technologies to separate the bitumen from the sand.
–	the Scotford upgrader, which is adjacent to Shell Canada’s existing Scotford refinery north of Fort Saskatchewan, Alberta. The Scotford upgrader processes bitumen from the Muskeg River mine into a range of synthetic crude oils and is operated by Shell Canada.

The production of bitumen and synthetic crude is considered under the SEC’s regulations to be mining activity rather than oil and gas activity.

Venezuela Shell Venezuela S.A. (Group interest 100%) holds an Operating Service Agreement (expiring in 2013) with a state oil company, Petroleos de Venezuela (PDVSA), to develop and produce the Urdaneta West Field in Lake Maracaibo.

2 Gas & Power

Processing Liquefied natural gas (LNG) plants
Location, Group interest in plants(a) and capacity(b)
(at December 31, 2004)
								100%
				Group				capacity
				interest				million tonnes
				%				per annum
Nigeria		Bonny			26				9.6
Oman		Qalhat			30				6.6
Brunei		Lumut			25				7.2
Australia		Karratha			22				11.7
Malaysia (Dua and Tiga)		Bintulu			15				14.6

(a)	Percentage rounded to nearest whole percentage point where appropriate.
(b)	As reported by the joint ventures.

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Liquefied natural gas sales volumes (Shell equity share) (million
tonnes)
		2004				2003				2002				2001				2000
Malaysia			1.9				1.5				2.3				2.3				2.3
Australia			2.0				1.8				1.7				1.7				1.7
Brunei			1.8				1.8				1.7				1.7				1.7
Oman			2.1				2.1				1.9				1.7				0.7
Nigeria			2.4				2.1				1.5				1.5				1.1
Total			10.1	5			9.3				9.1				8.9				7.5

Europe

Denmark A/S Dansk Shell (Group interest 100%) continued to develop its natural gas marketing business in 2004.

Germany BEB Erdgas und Erdöl GmbH, a joint venture with ExxonMobil in which a Group company holds a 50% economic interest, is a major producer of gas in Germany, and also one of the country’s gas transmission companies. The natural gas marketing activities of this company have been split and are operated by separate independent Shell and ExxonMobil organisations effectively from April 2004. A wholly-owned Group company, Shell Energy Deutschland GmbH, was established for this purpose in 2004. Group companies have indirect (through BEB Erdgas und Erdöl GmbH) minority shareholdings in gas transmission and distribution companies. In 2004, the Group completed the sale of its indirect interests in Verbundnetz Gas AG (5.3%) and Avacon AG (1.4% through BEB Erdgas und Erdöl GmbH).

Greece The Group holds a 24% interest in Attiki Gas Supply Company S.A., a local gas distribution company currently with some 10,000 customers (mainly residential, but also some commercial and small industrial). Other shareholders are Cinergy Global Power Inc. (25%) and Attiki Gas Distribution Company S.A. (held 100% by Public Gas Corporation of Greece S.A.) (51%). Attiki Gas Supply Company S.A. holds a distribution licence to develop the distribution system infrastructure and to distribute gas to small industrial, commercial and residential customers in the Attiki area.

Italy Shell Italia SpA (Group interest 100%) launched a natural gas marketing business in 2004.

Netherlands N.V Nederlandse Gasunie (Group interest 25%), a large marketer of Dutch gas by most key measures, including volume. In November 2004, the Group announced a Heads of Agreement for the restructuring of the ownership in Nederlandse Gasunie, under which the Group’s interest in Gasunie’s gas transportation business will be transferred to the Dutch State. Upon completion of this transaction (pending government approval), expected mid-2005, the Dutch state will make a total net payment of €2.78 billion (Group share 50%).

Shell Energy Europe B.V., a wholly-owned Group company, continued to develop gas and power activities throughout Europe and to provide advice and assistance to the Group’s gas and power businesses in Europe. In 2004, the company started selling gas to a number of European wholesale customers.

Spain Shell España, S.A. (Group interest 100%) continued to develop its natural gas marketing business selling in the wholesale as well as in the industrial and commercial market.

United Kingdom Shell Gas Direct Ltd (Group interest 100%), a gas marketing company, generally maintained its market share during 2004 selling in the industrial and commercial market.

Other European Countries Wholly-owned Group companies in other European countries continue to seek opportunities to develop the gas and power business.

Other Eastern Hemisphere

The Group has a 28.6% interest in the Gorgon joint venture that is considering development of an LNG and domestic gas project on Barrow Island off Western Australia. A wholly owned Group company is also involved in a number of licences in the Timor Sea between the Northern Territory and Timor Leste with opportunities for both domestic gas and LNG export.

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Brunei Gas is liquefied and sold to customers in Japan and Korea by Brunei LNG Sendirian Berhad (Group interest 25%). In March 1993 the company’s main contract, to supply LNG to three power and gas utilities in Tokyo and Osaka, was extended for a further 20 years at an increased sales quantity of some 5.5 million tonnes a year. In 2004, the total sales quantity was some 7 million tonnes, to both Japan and Korea. The LNG continues to be delivered in a fleet of seven LNG vessels owned by Brunei Shell Tankers Sendirian Berhad (Group interest 25%), as well as a larger vessel owned by Brunei Gas Carriers Sendirian Berhad (Group interest 10%) which was brought into service in June 2002.

China In a 50:50 joint venture with China Petroleum and Chemical Corporation (Sinopec), Shell is developing its first Coal gasification plant in Dongting, China. Construction completion is expected by early 2006.

The Group is in the process of finalising joint venture arrangements with the Hangzhou Gas Group and Hong Kong China Gas for supply of gas to industrial and commercial customers in Hangzhou, China.

India The Group holds a 100% interest in three companies – Shell Hazira Gas Private Ltd., Hazira Port Private Ltd. and Hazira LNG Private Ltd., all of which are located in the State of Gujarat. Hazira Port Private Ltd. and Hazira LNG Private Ltd. are constructing a port and LNG terminal at Hazira in Gujarat. The initial maximum capacity of this terminal is 2.5 mtpa and may be expanded in the future. The terminal is being commissioned and will be ready for operations in the first half of 2005. Shell Hazira Gas Private Ltd., will use these facilities to import LNG and to market and supply regasified LNG to customers in Gujarat and North West India. A 26% interest in all the three companies has been sold to Total Gaz Electricite Holdings France, subject to defined conditions precedent.

Iran A Project Framework Agreement for the Persian LNG project (Group interest 25%) was signed during the year which takes the project into the next stage of design.

Japan In a joint venture with Tokyo Gas, the Group is engaged in marketing and sales of natural gas to industrial and commercial customers in the greater Tokyo area of Japan.

Malaysia Exports of LNG from Sarawak by Malaysia LNG Sendirian Berhad (MLNG Satu) began in January 1983 to two Japanese customers. The Group’s 15% shareholding in MLNG Satu reverted to Petronas in 2003 under a sale arrangement contained in the original joint venture agreement. Group companies continue to supply gas to MLNG Satu.

Three liquefaction trains (Group interest 15%) came onstream at the end of 1995 (MLNG Dua), with customers in Japan, South Korea and Taiwan. Group companies operate fields supplying gas to MLNG Dua. Construction of a third expansion to the Bintulu facilities, the 7.4 million tonnes per year two-train MLNG Tiga Project (Group interest 15%), was essentially completed and operations commenced in 2003.

Adjacent to the LNG facilities is a Gas to Liquids plant, operated by Shell MDS (Malaysia) Sendirian Berhad (Group interest 71.8%). This plant has the capacity to convert approximately three million cubic metres per day of natural gas into some 12,500 barrels per day of high-quality middle distillates and other products using Shell-developed technology. First commercial production from the plant began during 1993 using feedstock from offshore gas fields. The plant was de-bottle-necked during 2003, including the introduction of a new generation proprietary catalyst, resulting in an increased design capacity of 14,700 barrels per day. A full range of liquid and wax products is being sold into specialty markets in Asia Pacific, the USA and Europe.

Nigeria A LNG plant owned by Nigeria LNG Limited (NLNG) (Group interest 25.6%) started up in October 1999. The plant currently produces some 9.6 million tonnes of LNG per year from three LNG trains for export under long-term contracts to customers in Europe. In the first quarter of 2002, the shareholders of NLNG committed to the “NLNG Plus” project, a further two-train expansion (Trains 4&5), to supply US and European markets. These trains are expected to commence operation in 2005. In addition, a decision was taken during 2004 to proceed with the construction of a sixth LNG train at the site. These projects will increase NLNG’s production capacity to approximately 22 million tonnes a year of LNG and 5 million tonnes per year of natural gas liquids. NLNG currently has operational control of 12 LNG vessels and this will rise to a total of 24 vessels by 2008. In 2004, a Shell Company (together with other venture partners) committed to proceed with the West Africa Gas Pipeline Project (Group interest 18.8%). This project is planned to supply gas from Nigeria to the neighbouring states of Ghana, Benin and Togo and is scheduled to become operational in 2007.

Within Nigeria, Shell is operating a gas sales and distribution company, Shell Nigeria Gas (Group interest 100%), to supply gas to a number of industrial and commercial customers in the south of the country.

Oman The LNG plant owned by Oman LNG L.L.C. (Group interest 30%) commenced operations in April 2000. The annual capacity of the plant is some 6.6 million tonnes per annum. The majority of the LNG is sold to Korea and Japan on long-term contracts with remaining volumes sold to customers on short-term sales agreements. During 2004, Oman LNG secured a 36.8% equity interest in the Qalhat LNG S.A.O.C. project. The Qalhat LNG project will have a single LNG train with a capacity of 3.3 mtpa. Construction is expected to be completed around end 2005 and first cargo expected in early 2006.

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Qatar In July 2004, Qatar Shell GTL (Group interest 100%) signed a Development and Production Sharing Agreement with the State of Qatar for the construction of a 140,000 barrels per day Gas to Liquids plant in Ras Laffan, Qatar. Two appraisal wells were successfully tested in 2004. The final investment decision is expected in 2006, with first sales by the end of the decade.

In February 2005, the Group and Qatar Petroleum signed a Heads of Agreement for the development of a large-scale LNG project (Qatargas 4, Group interest 30%). The project comprises the integrated development of upstream gas production facilities to produce 1.4bcf/d of gas and substantial quantities of associated liquids from Qatar’s North field, a single LNG train yielding approximately 7.8 million tonnes per annum of LNG for a period of 25 years and shipping of the LNG to the intended markets in North America and Europe. LNG deliveries are expected to commence around 2010-2012.

Russia Shell Sakhalin Holding, B.V. (Group interest 100%) holds a 55% interest in Sakhalin Energy Investment Company Ltd. (SEIC). SEIC continues seasonal oil production from the Molikpaq facility on the Piltun-Astokhskoye field, offshore Sakhalin Island. Full development of the Piltun Satokhskoye oil field and Lunskoye gas field continued during 2004. The final investment decision for this phase of the development, including a two-train LNG plant with 9.6 million tonnes per year capacity, was announced on May 15, 2003. The first LNG cargo is scheduled to be delivered in late 2007; target markets for the LNG include Asia Pacific and the west coast of North America.

USA and Canada

Shell US Gas & Power (Group interest 100%) implemented extensive restructuring during 2004 including the sale of a number of offshore gas pipelines in the Gulf of Mexico, a partial sell down of the equity position in Enterprise Product Partners L.P., and the sale of its equity position in Tenaska Gateway Partners Ltd. power plant in Texas. The divestments are part of the Group’s ongoing programme of portfolio rationalisation.

The focus of the business on LNG in the USA has increased, including existing LNG import capacity rights at the Cove Point and Elba Island terminals as well as the continued evaluation of various options to expand its LNG import capabilities. In February 2005, Shell received a Record of Decision from the US Maritime Administration approving the issuance of a licence for the Gulf Landing LNG terminal in the Gulf of Mexico.

Other Western Hemisphere

Brazil In 1997, Group companies acquired a minority interest in Companhia de Gas de Sao Paulo (Comgas), a Brazilian natural gas distribution company in the state of São Paulo. In 1999, a joint venture was formed with BG International that successfully bid for the final and controlling block of Comgas (current total Group interest is 18.2%).

In 1997, Group companies acquired a minority interest in Transportadora Brasileira Bolivia Brasil S.A. (Br), interconnected to Gas Transboliviano S.A.. (Bol), constituting the Brazilian side of the Bolivia-Brazil pipeline with around 1,400 miles in total pipeline network covering five Brazilian states (current total Group interest is 7%).

In 1998, an interest between 22% and 50% across four companies was acquired in an integrated pipeline and power station project in Cuiaba, western Brazil; the pipeline also crosses through eastern Bolivia. In 2000, Group companies, jointly with Prisma Energy (formerly Enron), acquired the Transredes interests in the Cuiaba pipeline and power plant. In 2003, Group interest across all four companies constituting the Cuiaba project became 50%. The Cuiaba gas-fired power plant (480MW) became commercially operational in 2002.

Mexico In 2003, Shell won a competitive tender to deliver gas through an LNG receiving terminal at Altamira, now under construction, to CFE (state power company). Group interest in the terminal is 50% after a 25% equity interest was sold to Total S.A in 2004, and a further 25% equity interest was sold to Mitsui which was completed in January 2005. Group interest in the marketing company which holds the capacity rights in the terminal is 75% with the remaining 25% held by Total. The terminal is located in the port of Altamira, Tamaulipas, on Mexico’s Gulf coast. The facility is expected to start operations in late 2006 supplying up to 5 billion cubic metres per annum of natural gas for 15 years from the new LNG re-gasification terminal under the tender contract, ramping up from an initial 3 billion cubic metres per annum.

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Shell secured 50% capacity rights in the LNG receiving terminal on the West Coast of Mexico at Baja California to be built and owned by Sempra Energy. Initial capacity of the terminal will be 7.5mtpa (100%), which is expected to start up in 2008. Initial supplies will come from the Sakhalin LNG Project in Russia, according to agreements reached during 2004.

Venezuela In 2002, a Group company signed Framing and Preliminary Development Agreements covering a 30% interest in the Mariscal Sucre LNG (MSLNG) scheme. While these agreements expired in May 2004, Petroleos de Venezuela S.A.(PDVSA), Mitsubishi and Shell, sponsors of MSLNG, remain in discussions on progressing development of the offshore Norte de Paria fields for LNG export and supply of gas to the Venezuelan market.

LNG Supply and Shipping

InterGen

3 Oil Products

(a) Overview

The Oil Products business operates the world’s largest single branded retail network with over 46,000 service stations. Convenience retailing offers a wide range of products and services to customers worldwide. In addition, the Oil Products business serves industrial and commercial customers; from small family-run businesses through to multinational companies. Lubricants, fuels and other speciality products are supplied to industrial sectors as diverse as mining, automotive manufacturing, food processing and steel-making. Underpinning Shell’s marketing strength is the Shell brand. The Shell brand is one of the most recognised and reputable in the world. The Shell Global Brand tracker is run annually, measuring in a structured and objective way the health of the Shell brand across the world, and enables Shell companies to assess their competitive strength and brand appeal. The latest study confirmed Shell’s global lead in terms of Brand preference — it is the most preferred brand in more markets than any of our competitors. The reach of the brand, with a Shell presence in over 140 countries and territories provides the opportunity to combine the operational and cost benefits of global operations with a strong brand affiliation.

The range of innovative products and services offered to customers has been further expanded, drawing upon extensive research and development. Differentiated fuels are currently offered in over 40 countries. We continue to develop and introduce products such as low-sulphur fuels, lead replacement fuel and LPG with improved environmental performance. Shell has been actively pursuing GTL (Gas to Liquids) technology for many years. With the world’s first commercial GTL plant of its type (low temperature Fischer-Tropsch) operating in Malaysia, the company has competitive advantages in the development and manufacture of GTL products. GTL Fuel is an important building block of Shell’s transportation fuels strategy, providing a route towards sustainable mobility.

USA

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Shell Oil Products US and Motiva both market petroleum and other products directly and through independent wholesalers and retailers and have the exclusive rights to use the “Shell” brand on refined oil product sales in those areas of the USA where each company is authorised to conduct its respective business. In addition, Shell Oil Products US and Motiva had the exclusive rights to use the “Texaco” brand on refined oil product sales in their respective areas through to June 2004, and have the non-exclusive rights through to June 2006.

Starting in 2002, Shell Oil Products US and Motiva planned to reduce the number of service stations in the overall network by around 30%, to some 15,000 sites. Through the fourth quarter of 2004, some 79% of the site rationalisation programme was complete. Furthermore, a programme is underway to re-brand Texaco branded sites to the Shell brand, which was largely completed by the end of 2004. Through the fourth quarter of 2004, over 6,100 sites had been rebranded from the Texaco to the Shell brand. At year end 2004, about 100 sites remained to be rebranded.

The purchase of Pennzoil-Quaker State Company (PQS) was completed in October 2002. This acquisition made the Group a leader (by market share) in both passenger car motor oil and diesel engine oil in the USA and aligns with the Group’s strategy to become a leader in the global lubricants market.

During 2004, the Group completed a number of transactions to sell its non-strategic assets. These transactions included the sale of the company’s mid-continent refined products pipeline system to Magellan Midstream Partners L.P. and the sale of the company’s midwest refined products pipeline system to Buckeye Partners L.P. The Group received proceeds from the two transactions totalling just over $1 billion.

In May 2004, Motiva completed the sale of its Delaware refinery to the Premcor Refining Group Inc. During 2004, Shell announced that it would keep its Bakersfield, California refinery (previously announced for closure) operating through to March 31, 2005, subject to regulatory approval. During 2004, the company conducted an extensive sale process to market the refinery to potential buyers. In January 2005, Shell Oil Products US announced it had reached an agreement to sell the refinery to a newly formed subsidiary of Flying J Inc. subject to regulatory approvals and certain closing conditions. The sale was completed on March 15, 2005.

Canada

Europe

Middle East and Asia Pacific

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The sale of the Group’s 64% equity share in the Rayong Refinery in Thailand was completed in the fourth quarter of 2004, reducing the Group’s consolidated debt by some $1.3 billion.

Africa

South and Central America

Global Businesses

Shell Aviation is a world leader in the marketing of aviation fuels and lubricants and in the operation of airport fuelling. Every day at over 1,100 airports in 90 countries, Shell Aviation fuels some 20,000 aircraft and supplies over 21 million gallons (80 million litres) of fuel. In 2004, Shell Aviation was voted the world’s best ‘Jet Fuel Marketer’ in the Armbrust Survey. Shell has won the coveted Armbrust Aviation award five times in the last eight years.

Shell Marine Products is a global sales and marketing business, supplying marine fuels, lubricants and related services to the marine industry. The business supplies around 20 different types of marine fuel to power diesel engines, steam and gas turbine vessels, together with around 100 different types of marine lubricants blended to provide optimum protection in the toughest environments. The business serves more than 15,000 customer vessels ranging from large ocean-going tankers to small fishing boats.

Shell Gas LPG markets LPG to around 30 million customers in over 50 countries and territories, supplying LPG for domestic purposes (heating, cooking, etc), commercial (restaurants), agriculture and industry. In some markets, LPG is becoming increasingly popular as an automotive fuel. Typically, LPG is distributed in cylinders and small/ large bulk tanks.

As a result of an unsolicited approach from an interested buyer, the Group has decided to explore its strategic options with regard to its downstream global LPG distribution and marketing business. The review is ongoing and progress will depend on the conclusions of the review. Meanwhile work that was already underway to structure LPG into a stand-alone global operation will be accelerated.

The Group announced in the fourth quarter of 2004 the signing of a Sale and Purchase Agreement with Repsol YPF relating to the divestment of Shell Gas (LPG) business in Portugal. The divestment of the Shell Gas (LPG) Portugal’s subsidiaries and shareholdings, includes the assets of two LPG filling plants, more than two million cylinders, supply, distribution and customer contracts covering mainland Portugal and the islands of Madeira and Azores. The sale is subject to regulatory approval and completion is expected in the first half of 2005. The Group also announced in the fourth quarter of 2004 the sale of its LPG interest in Cote d’Ivoire. It is expected that this transaction will also be completed in the first half of 2005.

Shell Lubricants is a global leader in finished lubricants. Shell lubricants companies operate in over 120 countries worldwide, manufacturing and marketing some of the most recognised (by market share) lubricants brands including Shell Helix, Pennzoil, Shell Rotella, Shell Rimula and Quaker State. Shell’s high quality lubricants are used across the transport sector in passenger cars, trucks, coaches, airplanes and ships. They also deliver superior lubrication solutions to the manufacturing, food processing, mining and agriculture industries. In addition, through the Jiffy Lube fast lube network Shell Lubricants provide car maintenance and service to some 30 million customers in the USA and are growing this business in developing markets such as China.

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Shell Global Solutions provides business and operational consultancy, technical services and research and development expertise to the energy industry worldwide. Shell Global Solutions has an extensive network of offices around the world, with primary commercial centres now operating in the USA, Europe and Asia Pacific.

In 2004 Global Solutions supported the Group’s business activities in downstream manufacturing, downstream marketing, Gas & Power, and production, and successfully serviced refining, chemicals, gas, power, metals, and motor-sport customers in Europe, the USA, the Middle East and Asia Pacific.

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Refining^a

Cost of crude oil processed or consumed		$ per barrel
(including upstream margin on crude supplied by Group and associated
exploration and production companies)
		2004				2003				2002				2001				2000
			37.22				26.75				24.35				23.56				27.50

Operable crude oil distillation capacityb		thousand barrels/calendar dayc
		2004				2003				2002				2001				2000
Europe			1,835				1,808				1,809				1,400				1,395
Other Eastern Hemisphere			1,050				1,072				1,108				1,155				1,099
USA			1,032				1,073				1,075				689				222
Other Western Hemisphere			350				361				395				398				372
			4,267				4,314				4,387				3,642				3,088

Crude oil processedd										thousand barrels/stream day
		2004				2003				2002				2001				2000
Europe			1,687				1,712				1,701				1,309				1,337
Other Eastern Hemisphere			942				916				870				933				899
USA			950				974				996				624				196
Other Western Hemisphere			364				347				314				361				355
			3,943				3,949				3,881				3,227				2,787
Group share of associated companies			451				515				473				480				1,117

Crude oil distillation unit intake as percentage
of operable capacitye										%
		2004				2003				2002				2001				2000
Europe			94				96				94				95				97
Other Eastern Hemisphere			91				89				84				90				85
USA			91				89				91				91				88
Other Western Hemisphere			93				90				86				91				98
Worldwide			92				92				90				92				92

Refinery processing intakea										thousand barrels/stream day
		2004				2003				2002				2001				2000
Crude oil			3,946				3,949				3,881				3,227				2,787
Feedstocks			216				218				203				173				136
			4,162				4,167				4,084				3,400				2,923
Europe			1,770				1,776				1,761				1,358				1,394
Other Eastern Hemisphere			962				956				941				1,018				971
USA			1,055				1,079				1,064				663				198
Other Western Hemisphere			375				356				318				361				360
			4,162				4,167				4,084				3,400				2,923

						million tonnes a year
Metric equivalent			204				204				201				166				147

a	Data reflect continuing and discontinued operations. Refinery processing intake relating to discontinued operations, (see Note 4 to the Group Financial Statements) was 267 thousand barrels/stream day in 2004 (2003: 269; 2002: 283).

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Refinery processing outturng										thousand barrels/stream day
		2004				2003				2002				2001				2000
Gasolines			1,542				1,575				1,537				1,242				957
Kerosines			424				418				400				369				320
Gas/Diesel oils			1,297				1,312				1,287				1,068				974
Fuel oil			414				378				355				339				316
Other products			557				550				546				417				350
			4,234				4,233				4,125				3,435				2,917

Group share of Equilon and Motiva volumes
(not included above)		thousand barrels/stream day
		2000
Refinery processing intake			656

a	For 2000 Equilon (now Shell Oil Products US) and Motiva were reported as Associated companies. The Group share of refinery processing intake of Equilon and Motiva was reported separately. The basis of reporting from 2002 has been changed to reflect only those activities relating to the Oil Products business; previously the volumes of the Mobile refinery in Alabama, a refinery owned by Chemicals, was included within the US volumes. The 2001 figures have been restated on a similar basis. Furthermore, from 2002 the US reported volumes include 100% of Shell Oil Products US and 50% of Motiva; the 2001 figures have been restated in accordance with the ownership interests prevailing at that time.
b	Group average operating capacity for the year and excluding mothballed capacity.
c	One barrel daily is equivalent to approximately 50 tonnes a year, depending on the specific gravity of the crude oil.
d	Including natural gas liquids; includes processing for others and excludes processing by others.
e	Including crude oil and feedstocks processed in crude oil distillation units, and based on calendar-day capacities.
f	Including crude oil and natural gas liquids plus feedstocks processed in crude oil distillation units and in secondary conversion units.
g	Excluding “own use” and products acquired for blending purposes.

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Oil sales^a,b,c,d

Product volumese		thousand barrels/day
		2004				2003				2002				2001				2000
Europe
Gasolines			576				616				647				531				510
Kerosines			220				194				190				164				178
Gas/Diesel oils			934				936				950				776				718
Fuel oil			179				184				177				174				192
Other products			203				207				209				207				212
			2,112				2,137				2,173				1,852				1,810
Other Eastern Hemisphere
Gasolines			337				315				332				328				334
Kerosines			168				166				142				132				124
Gas/Diesel oils			511				489				476				460				452
Fuel oil			168				180				188				200				203
Other products			136				138				149				138				138
			1,320				1,288				1,287				1,258				1,251
USA
Gasolines			1,372				1,343				1,239				737				189
Kerosines			258				212				221				138				31
Gas/Diesel oils			430				430				401				266				82
Fuel oil			209				189				105				65				17
Other products			247				218				173				111				114
			2,516				2,392				2,139				1,317				433
Other Western Hemisphere
Gasolines			293				296				317				315				306
Kerosines			73				72				74				80				81
Gas/Diesel oils			249				243				246				252				275
Fuel oil			85				86				92				100				107
Other products			44				52				49				54				128
			744				749				778				801				897
Export sales
Gasolines			182				193				251				202				455
Kerosines			114				154				155				154				128
Gas/Diesel oils			274				213				222				194				204
Fuel oil			208				181				196				168				204
Other products			130				138				198				197				192
			908				879				1,022				915				1,183
Total product sales
Gasolines			2,760				2,763				2,786				2,113				1,794
Kerosines			833				798				782				668				542
Gas/Diesel oils			2,398				2,311				2,295				1,948				1,731
Fuel oil			849				820				758				707				723
Other products			760				753				778				707				784
			7,600				7,445				7,399				6,143				5,574

Sales by product as percentage of total product sales																		%
		2004				2003				2002				2001				2000
Gasolines			36.3				37.1				37.7				34.4				32.2
Kerosines			10.9				10.7				10.6				10.9				9.7
Gas/Diesel oils			31.6				31.1				31.0				31.7				31.0
Fuel oil			11.2				11.0				10.2				11.5				13.0
Other products			10.0				10.1				10.5				11.5				14.1
			100.0				100.0				100.0				100.0				100.0

a	Data reflect continuing and discontinued operations. Oil product sales related to discontinued operations (see Note 4 to the Group Financial Statements) were 221 thousand barrels/day in 2004 (2003: 234; 2002: 262).
b	For 2000 the sales volumes include the Group share of Equilon (now Shell Oil Products US) and Motiva volumes.

c	From 2001 the basis of reporting reflect only those activities which relate to the Oil Products business; previously some volumes handled by other businesses were included. Reported volumes from 2001 in the USA include Shell Oil Products US and Motiva sales to third parties and are in accordance with the ownership interests prevailing at the time.

d	Sales figures exclude deliveries to other companies under reciprocal purchase and sale arrangements which are in the nature of exchanges. Sales of condensate and natural gas liquids are included.

e	By country of destination, except where the ultimate destination is not known at the time of sale, in which case the sales are shown as export sales.

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Total oil sales volumesa,b														thousand barrels/day
Oil products by geographical area
		2004				2003				2002				2001				2000
Europe
Germany			772				785				789				454				421
UK and Republic of Ireland			311				313				317				319				263
France			275				283				299				306				294
Netherlands			191				180				191				204				213
Others			563				576				577				569				619
			2,112				2,137				2,173				1,852				1,810
Other Eastern Hemisphere
Australia			215				190				194				203				207
Others			1,105				1,098				1,093				1,055				1,044
			1,320				1,288				1,287				1,258				1,251
USA			2,516				2,392				2,139				1,317				433
Other Western Hemisphere
Canada			287				276				263				267				346
Brazil			170				168				191				203				216
Others			287				305				324				331				335
			744				749				778				801				897
Export sales			908				879				1,022				915				1,183
Total oil products			7,600				7,445				7,399				6,143				5,574
Crude oil			5,160				4,769				5,025				4,461				3,279
Total oil sales			12,760				12,214				12,424				10,604				8,853

						million tonnes a year
Metric equivalent			627				611				621				530				444

Group share of Equilon and Motiva volumesa
(not included above)		thousand barrels/day
						2000
Total oil products sales							1,508

a	By country of destination, except where the ultimate destination is not known at the time of sale, in which case the sales are shown as export sales.
b	Data reflect continuing and discontinued operations. Oil product sales related to discontinued operations (see Note 4 to the Group Financial Statements) were 221 thousand barrels/day in 2004 (2003: 234; 2002: 262).

Net product proceeds		$ million
by product		2004				2003				2002				2001				2000
Gasolines			55,594				44,830				38,861				30,455				27,046
Kerosines			16,308				10,826				9,170				8,710				7,877
Gas/ Diesel oils			48,304				35,344				28,077				25,735				25,211
Fuel oil			9,688				8,424				6,591				5,900				6,752
Other products			15,279				13,834				11,420				9,845				10,470
Total oil products			145,173				113,258				94,119				80,645				77,356
by geographical area
Europe			44,010				35,618				30,228				25,077				26,189
Other Eastern Hemisphere			25,725				19,957				16,801				17,371				18,278
USA			46,500				34,533				26,200				17,199				5,068
Other Western Hemisphere			15,116				12,751				10,836				12,118				14,226
Export sales			13,822				10,399				10,054				8,880				13,595
Total oil products			145,173				113,258				94,119				80,645				77,356

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Average net product proceeds														$ per barrel
by product		2004				2003				2002				2001				2000
Gasolines			55.03				44.46				38.22				39.50				41.20
Kerosines			53.52				37.18				32.12				35.70				39.69
Gas/Diesel oils			55.04				41.90				33.52				36.19				39.79
Fuel oil			31.17				28.14				23.82				22.85				25.52
Other products			54.95				50.30				40.21				38.14				36.51
Total oil products			52.19				41.68				34.85				35.96				37.92
by geographical area
Europe			56.93				45.67				38.11				37.09				39.52
Other Eastern Hemisphere			53.30				42.45				35.77				37.83				39.93
USA			50.48				39.56				33.55				35.78				31.98
Other Western Hemisphere			55.51				46.64				38.18				41.47				43.34
Export sales			41.57				32.41				26.95				26.59				31.40
Total oil products			52.19				41.68				34.85				35.96				37.92

(b) Trading

In 2004, Shell Trading opened the Shell Trading Russia B.V. branch office, so as to be better positioned to participate in the increasing opportunities for local trade and the international export of crude oil and oil products in the Commonwealth of Independent States.

(c) Shipping

Oil tankersa (at December 31)		number of ships																				million deadweight tonnes
Owned/demise-hired		2004				2003				2002				2001				2000				2004				2003				2002				2001				2000
VLCCs (very large crude carriers over 160,000 dwt)			5				7				7				7				8				1.5				2.1				2.1				2.1				2.3
Large range (45,000 to 160,000 dwt)			11				13				16				16				16				0.7				0.9				1.3				1.3				1.3
Medium range (25,000 to 45,000 dwt)			5				5				5				6				5				0.2				0.2				0.2				0.2				0.1
General purpose (10,000 to 25,000 dwt)/Specialist)			2				3				2				2				1				0.1				0.1				0.1				0.1				0.1
			23				28				30				31				30				2.5				3.3				3.7				3.7				3.8
Time-charteredb
VLCCs (very large crude carriers over 160,000 dwt)			1				1				1				–				–				0.3				0.3				0.3				–				–
Large range (45,000 to 160,000 dwt)			19				15				18				17				9				1.7				1.3				1.5				1.5				0.7
Medium range (25,000 to 45,000 dwt)			8				13				15				7				8				0.3				0.5				0.6				0.3				0.3
General purpose (10,000 to 25,000 dwt)/Specialist)			12				10				6				7				1				0.2				0.2				0.1				0.1				0.1
			40				39				40				31				18				2.5				2.3				2.5				1.9				1.1
Total oil tankers			63				67				70				62				48				5.0				5.6				6.2				5.6				4.9
Owned/demise-hired under construction or on order (oil)			3				–				–				–				–				0.3				–				–				–				–

Gas carriersa (at December 31)		number of ships																				thousand cubic metres
		2004				2003				2002				2001				2000				2004				2003				2002				2001				2000
Owned/demise-hired (LNG)e			6				5				4				2				–				797				662				522				253				–
Time-chartered (LNG)e			1				–				–				–				2				145				–				–				–				253
Owned/demise-hired (LPG)			1				1				1				1				1				60				59				59				59				59
Time-chartered (LPG)			2				2				3				2				2				136				136				145				113				155
Total gas carriers			10				8				8				5				5				1,138				857				726				425				467
Owned/demise-hired under construction or on order (LNG)			–				1				2				4				–				–				135				277				556				–

a	Oil tankers, ocean going articulated tug barges and gas carriers of 10 kdwt and above which are owned/chartered by Shell companies where the Shell equity shareholding is at least 50%.
b	Time-chartered oil tankers include Consecutive Voyage Charters.
c	Contracts of affreightment are not included.
d	Owned/demise hired newbuilding contracts not in service but due for delivery post December 31, 2004.
e	LNG carriers reported in Gas & Power sector.

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4 Chemicals

Group companies currently produce a number of base chemicals and petrochemicals. They are major suppliers of base chemicals such as lower olefins and aromatics, and first-line derivatives such as styrene monomer, propylene oxide, solvents, detergent intermediates, and ethylene oxide.

The Chemicals portfolio also includes CRI/Criterion, Inc. (CRIC), which changed its name from CRI International Inc. with effect from January 1, 2005 (Group interest 100%), and several ventures including Basell NV, Infineum, Saudi Petrochemical Company (SADAF), and CNOOC and Shell Petrochemicals Company Ltd. (CSPCL) (each, described below). In 2004, CRIC sold its global catalyst regeneration business and ceased operations of its spent catalyst reclamation business. CRIC remains a major catalyst manufacturer in the global refinery and petrochemical markets (by market share).

Basell, a 50:50 joint venture between Group companies and BASF, produces and markets polypropylene, polyethylene, advanced polyolefin materials and polyolefin catalysts, and also develops and licenses technology for polyolefin processes. Including its own joint ventures, Basell has manufacturing operations in 20 countries and its products are sold in more than 120 countries. In 2004, Basell sold its 50% share in the Compagnie Industrielle des Polyethylenes de Normandie (CIPEN) linear low density polyethylene plant in Notre-Dame-de-Gravenchon, France.

Shell and BASF announced a review of strategic alternatives regarding Basell in July 2004 and the investment is currently held for sale. A number of offers from both financial and strategic buyers have been received. The shareholders are continuing to review the potential options for exit. Options being considered include the sale of the companies’ stakes or an equity transaction.

Infineum, a 50:50 joint venture between Group companies and ExxonMobil with manufacturing locations in 8 countries, formulates, manufactures and markets high-quality fuel, lubricants, and specialty additives and components. SADAF, a 50:50 joint venture between Group companies and Saudi Basic Industries Corporation (SABIC) produces base and intermediate chemicals for global markets. CSPCL, a 50:50 joint venture between Group companies and CNOOC Petrochemicals Investment Ltd., will produce a range of petrochemicals, intended primarily for the Chinese markets. Construction of the $4.3 billion Nanhai petrochemicals complex in southern China is targeted for commissioning towards the end of 2005. In February 2005, Shell Chemicals Limited and Qatar Petroleum signed a Letter of Intent for the development of a world-scale ethane based cracker and derivatives complex in Ras Laffan Industrial City, Qatar.

At December 31, 2004, Group companies had major interests in chemical manufacturing plants, as described below and on the following pages.

Sales

Net proceeds by main product categorya																		$ million
		2004				2003				2002				2001				2000
Base chemicals			11,536				7,447				4,895				4,495				5,017
First-line derivatives			9,211				7,189				5,869				5,502				5,667
Other			742				550				726				619				4,521
			21,489				15,186				11,490				10,616				15,205

Net proceeds by geographical areaa																		$ million
		2004				2003				2002				2001				2000
Europe			7,873				5,617				3,994				3,734				5,506
Other Eastern Hemisphere			4,530				3,092				2,324				1,642				1,912
USA			6,159				4,369				3,548				3,419				5,531
Other Western Hemisphere			616				486				379				283				522
Total chemical products net proceeds			19,178				13,564				10,245				9,078				13,471
Non-chemical products			2,311				1,622				1,245				1,538				1,734
Total net proceeds			21,489				15,186				11,490				10,616				15,205

Sales volumes by main product categoryb														thousand tonnes
		2004				2003				2002				2001				2000
Base chemicals			14,184				13,165				10,031				8,760				7,909
First-line derivatives			9,499				9,779				9,595				8,849				8,219
Other			477				164				1,767				1,269				4,160
			24,160				23,108				21,393				18,878				20,288

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Ethylene capacity – Group and associated companiesc
		2004				2003				2002				2001				2000
Nominal capacity (thousand tonnes/year)			6,701				6,203				6,023				5,586				5,215
Utilisation (%)			87				90				92				87				94

a	Excluding proceeds from associate companies and chemical feedstock trading.
b	Excluding volumes sold by associate companies, chemical feedstock trading and by-products.
c	Data includes Group share of capacity entitlement (offtake rights) that may be different from nominal Group equity interest.

Europe

Luxembourg Catalyst Recovery Europe S.A. (Group interest 100%) was divested in 2004 as part of CRIC’s decision to exit its global catalyst regeneration business.

France At Berre l’Etang, Shell Pétrochimie Méditerranée S.A.S. (SPM) (Group interest 100%), owns and operates a refinery as well as petrochemicals units, manufacturing oil products, aromatics, butadiene, solvents, and diisobutylene. SPM also operates additives units on behalf of Infineum, polypropylene and polyethylene units on behalf of Basell, an ethylene/ propylene cracker on behalf of Société du Craqueur de l’Aubette S.N.C. (a 50:50 joint venture between SPM and Basell), and several polymer units on behalf of third party companies. Basell also manufactures low-density polyethylene at Fos sur Mer.

Germany Shell Deutschland Oil GmbH (SDO) (Group interest 100%) operates manufacturing plants in Harburg (hydrocarbon solvents), Godorf (benzene, toluene), Wesseling (ethylene, propylene, benzene, toluene, xylenes, methanol), and Heide (ethylene, propylene, benzene, toluene, xylenes, hydrocarbon solvents and chemical solvents). By virtue of the Group’s share interest (32.25%) in the relevant manufacturing company, Shell Chemicals Europe B.V. (SCE) is entitled to a proportion of the production of propylene and methyl tertiary butyl ether from plants in Karlsruhe. Due to the Group’s share interest (37.5%) in a company in Schwedt, SCE receives propylene, benzene, toluene, and xylenes. Kataleuna GmbH Catalysts, a CRIC company, manufactures catalyst at its Leuna, Germany plant. Basell manufactures ethylene, propylene, and polyolefins at its Wesseling site.

Netherlands Shell Nederland Chemie B.V. (SNC) (Group interest 100%) manufactures solvents, methyl tertiary butyl ether, brake fluids, glycol ethers units and urethanes (polyols) at the Pernis facility. SNC operates at Pernis, a polypropylene plant owned by Basell and several derivatives on behalf of third party companies.

SNC manufactures lower olefins, benzene, ethyl benzene, ethylene oxide, and styrene monomer/ propylene oxide (SM/PO) at the Moerdijk facility and operates a SM/PO plant owned by Ellba CV, a 50:50 joint venture between Group companies and BASF. Using the Group’s “SMPO process”, Ellba simultaneously produces styrene monomer, primarily used in the production of polystyrene, and propylene oxide, a chemical building block in a series of products from industrial foams to surfactants, solvents, additives and lubricants.

Shell Chemicals Europe B.V. (SCE), is responsible for all chemicals sales, supply chain management, and the procurement of feedstocks and process chemicals for chemical products across Western Europe other than in respect of chemicals joint ventures in which Group companies have an interest.

United Kingdom Shell U.K. Oil Products Ltd. (as an agent for Shell U.K. Ltd.) operates the plants of Shell Chemicals U.K. Ltd. (SCUK) (Group interest 100%) at Stanlow, which produce propylene, benzene, toluene, and higher olefins and derivatives. In Carrington, Basell manufactures polypropylene and low-density polyethylene, and operates SCUK’s plants to produce derivatives from ethylene oxide and propylene oxide and a third party’s unit. SCUK also owns NEODOL ethoxylates assets operated by ICI Chemicals & Polymers Ltd. at Wilton. SCE has indirect rights to an ethylene oxide supply from Dow’s Wilton facility. At Fife in Scotland, ExxonMobil owns and operates an ethylene plant in which, under a processing rights agreement, SCUK is entitled to 50% of the output.

Other Eastern Hemisphere

China CNOOC and Shell Petrochemicals Company Ltd. (CSPCL) is a 50:50 joint venture between Group companies and CNOOC Petrochemicals Investment Ltd. (CPIL). CPIL shareholders include China National Offshore Oil Corporation (CNOOC) (90%) and the Guangdong Investment & Development Company (10%). CSPCL will produce a range of petrochemicals, including ethylene, propylene, styrene monomer, propylene oxide, mono-ethylene glycol, polypropylene, high-density polyethylene, low-density polyethylene, and butadiene. This complex is targeted for commissioning towards the end of 2005 and is expected to produce 2.3 million tonnes per annum of petrochemical products. CNOOC and Shell Petrochemicals Marketing Company Ltd. (CSPMCL), also a 50:50 joint venture between Group companies and CPIL, coordinate pre-marketing services until CSPCL begins operations.

Saudi Arabia The Saudi Petrochemical Company (SADAF), a 50:50 joint venture between Group companies and Saudi Basic Industries Corporation (SABIC), owns and operates a one million tonnes per year ethylene cracker and downstream plants capable of producing 3.6 million tonnes per year of crude industrial ethanol, ethylene dichloride, caustic soda, styrene, and methyl tertiary butyl ether. The

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marketing arms of both partners handle local and international marketing of SADAF products. The Group’s marketing effort is co-coordinated by Shell Trading (M.E.) Private Ltd. (Group interest 100%) located in Dubai, United Arab Emirates.

Singapore Group companies own a 50% and 30% equity interest in two Sumitomo-managed joint ventures, Petrochemical Corporation of Singapore (Private) Ltd. (PCS) and The Polyolefin Company (Singapore) Pte. Ltd. (TPC), respectively. PCS owns and operates two ethylene crackers with a total capacity of one million tonnes a year of ethylene and 500,000 tonnes a year of propylene. Ethylene Glycols (Singapore) Pte. Ltd. (Group interest 70%) owns and operates an ethylene oxide/ glycols plant. Seraya Chemicals (Singapore) Pte. Ltd. (SCSL) (Group interest 100%) owns and operates a SM/PO plant, and operates a SM/PO plant owned by Ellba Eastern Pte Ltd., a 50:50 joint venture between the Group and BASF.

USA

Basell manufactures advanced polyolefins at Bayport, Texas; Jackson, Tennessee; and Lake Charles, Louisiana. Infineum has manufacturing facilities at Argo, Illinois; Baytown, Texas; Bayway, New Jersey and Belpre, Ohio. CRIC catalyst manufacturing locations are at Martinez, Pittsburgh, and Azusa, in California; Michigan City, Indiana and Willow Island, West Virginia.

Sabina Petrochemicals LLC, a joint venture owned by SCLP (62%), BASF Corporation (23%) and ATOFINA Petrochemicals, Inc. (15%) started production in the first quarter of 2004 at its 410,000 tonnes per year butadiene extraction facility in Port Arthur, Texas.

Other Western Hemisphere

PTT Poly Canada, L.P., a 50:50 joint venture (limited partnership pursuant to the Civil Code of Quebec, Canada) between SCCL and Investissements Petrochimie (2080) Inc., a subsidiary of the Société Générale de Financement du Québec, has built a world-scale polytrimethylene terephthalate (PTT) plant near Montreal, Quebec, Canada. The 95,000 tonnes per year plant started production in late 2004. The joint venture markets PTT under the trademark CORTERRA™ Polymers, with its main use in carpet and textile fibres.

Basell operates the isopropyl alcohol plant at Sarnia on behalf of Shell Chemicals Canada Ltd. Basell also owns and operates polypropylene units at Varennes, Quebec, and at Sarnia.

Criterion Catalysts & Technologies Canada Inc, a CRI/Criterion company, manufactures catalyst at its Medicine Hat, Alberta plant.

Puerto Rico Shell Chemical Yabucoa Inc. (SCYI) (Group interest 100%) owns and operates a 77,000-barrel per day refinery producing feedstock for the Deer Park, Texas and Norco, Louisiana chemical plants. The facility also produces gasoline, diesel, jet fuel and residual fuels, primarily for use in Puerto Rico.

5 Renewables and Hydrogen

Shell Solar moved into the top five global players (by production) with the acquisition of Siemens Solar in April 2002, and remained a leading player in 2004. The company manufactures solar photovoltaic products in Europe, the USA and Asia. Sales operations based in over 75 countries around the world provide customers with solar solutions to their energy requirements working through a network of distributors, dealers and Shell owned outlets. The main customer segments for the Shell Solar business are grid-connected residential, commercial and large installations, off-grid and rural.

Shell WindEnergy is focusing on developing and operating wind farms and selling green electricity, building on its strengths in project management, financing and engineering design. Business development activity is concentrated in Europe and North America. In 2004 the company entered into two joint ventures (with Goldman Sachs and Entergy) operating windparks in the US, and further progressed its offshore portfolio in Europe. Shell WindEnergy’s total capacity now amount to 740MW, making it one of the World’s 10 largest suppliers of wind energy.

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Shell Hydrogen is developing projects with the aim of introducing hydrogen as a commercial product into relevant transportation and stationary markets. The main milestone for 2004 was the opening of the first hydrogen dispenser at a Shell retail site in Washington DC. This is the first integrated hydrogen/ gasoline retail station in the US. Additionally the first IPO of a Shell Hydrogen venture took place as Quest Air Inc. was listed on the Toronto and the London AIM stock exchanges. Another Shell Hydrogen venture, HERA Hydrogen Storage Systems Inc., closed a second round of financing. HydrogenSource LCC, a developer of fuel cell processing systems, was dissolved due to a shift in market demands for these products.

6 Research

Research and development expenditure														$ million
		2004				2003				2002				2001				2000
Total (including depreciation)			553				584				472				387				389

Exploration & Production

Shell’s Exploration & Production R&D has two laboratory locations in Rijswijk, the Netherlands and Houston, Texas, USA. In-house capabilities are used in the research, development and application of proprietary exploration and production technologies in conjunction with service industry and/or academic capabilities where applicable.

Primary technology focus areas are: enhanced sub-surface imaging, complex reservoir performance modelling, improving recovery efficiency, recovery of unconventional hydrocarbons, enhanced well construction, reducing the unit technical cost of onshore and offshore processing facilities, enabling the development of ultra-deepwater fields and upgrading produced hydrocarbons.

Gas & Power

Oil Products

Key drivers in process research have been the need to achieve best-in-class performance in terms of reliability and availability, supply chain optimisation, cost reduction and further reduction in energy consumption and CO₂ emissions. Catalyst development has contributed to increased margin generation. Environmentally focused programmes provide solutions ranging from soil remediation techniques to explosion hazard assessments.

A strategic programme aimed at developing break-through options in sustainable energy and sustainable mobility is pursued, covering new routes from biomass to bio-fuels and a new approach to CO₂ sequestration by mineralisation. The further development of the coal gasification, catalytic partial oxidation and gas to liquids technology continues to be an area of focus across the business.

Chemicals

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F Personnel

Employees by segmenta (average numbers)														thousands
		2004				2003				2002				2001				2000
Exploration & Production			17				17				17				14				13
Gas & Power			2				2				2				2				2
Oil Products			78				82				75				58				58
Chemicals			8				9				9				9				14
Corporate and Other			9				9				8				7				8
			114				119				111				90				95

Employees by geographical areaa (average numbers)															thousands
			2004				2003				2002				2001				2000
Europe
	Netherlands			10				11				11				10				10
	UK			8				8				9				10				10
	Others			26				27				26				18				21
				44				46				46				38				41
Other Eastern Hemisphere				30				28				27				24				24
USA				26				30				23				12				14
Other Western Hemisphere				14				15				15				16				16
				114				119				111				90				95

Employees by segmenta (at year-end)														thousands
		2004				2003				2002				2001				2000
Exploration & Production			17				17				17				15				13
Gas & Power			2				2				2				2				2
Oil Products			76				82				80				58				58
Chemicals			8				9				9				9				10
Corporate and Other			9				9				8				7				7
			112				119				116				91				90

Employee emoluments														$ million
		2004				2003				2002				2001				2000
Remuneration			8,125				7,477				6,096				4,651				4,560
Social law taxes			695				660				518				395				390
Pensions and similar obligations			526				538				(201	)			(580	)			(577	)
			9,346				8,675				6,413				4,466				4,373

a	Excludes employees of associated companies such as those in Brunei, Germany, Oman and USA. Includes 50% of the employees of Shell Expro in the UK and of NAM in the Netherlands and 30% of Shell Petroleum Development Nigeria.

Staff are represented by collective labour agreements, unions and staff councils in many countries where the Group has operations. Labour relations are generally constructive and supportive of the activities in the Group.

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Selected Financial Data

Royal Dutch (Netherlands GAAP)															per €0.56 ordinary sharea
							2003				2002				2001				2000
			2004				As restated				As restated				As restated				As restated
Net assets – €				19.63				18.29				18.49				20.35				19.63
Total assets – €				19.63				18.30				18.49				20.36				19.64
Basic earnings – €b				4.31				3.15				2.96				3.30				3.91
	from continuing operations			3.94				3.14				2.90				3.29				4.06
	from discontinued operations			0.37				0.01				0.06				0.01				(0.15	)
Diluted earnings – €b				4.30				3.15				2.96				3.30				3.91
	from continuing operations			3.93				3.14				2.90				3.29				4.06
	from discontinued operations			0.37				0.01				0.06				0.01				(0.15	)
Dividends declared – €				1.79	c			1.76				1.72				1.66				1.59
Dividends – equivalent payment in US dollars				2.23	c			2.06				1.80				1.50				1.40

a

Following the redenomination from guilders into euros in May 2002, the authorised share capital of Royal Dutch as set forth in its Articles of Association consists of 3,198,800,000 ordinary shares, par value €0.56 each, and 1,500 priority shares, par value €448 each. The number of ordinary shares and priority shares issued and paid up at the end of 2000 was 2,144,296,352 ordinary shares and 1,500 priority shares, at the end of 2001 was 2,126,647,800 ordinary shares and 1,500 priority shares, at the end of 2002 was 2,099,285,000 ordinary shares and 1,500 priority shares, and at the end of 2003 were 2,083,500,000 ordinary shares and 1,500 priority shares, and at the end of 2004 was 2,081,725,000 ordinary shares and 1,500 priority shares. The issued and paid-up share capital at the end of 2000 was €1,216,979,748b, at the end of 2001 was €1,206,969,043, at the end of 2002 was €1,176,271,600, at the end of 2003 was €1,167,432,000 and at the end of 2004 was €1,166,438,000.

b

The basic earnings per share amounts shown are related to profit after taxation and after deducting the 4% cumulative preference dividend on priority shares. The 2004 calculation uses a weighted-average number of 2,023,212,126 shares of 2003: 2,036,687,755, (2002: 2,057,657,737; (2001: 2,095,731,261; 2000: 2,128,592,305). The basic earnings per share number has been restated to exclude shares held by Group companies for stock options and other incentive compensation plans (see Note 23 to the Group Financial Statements). For the purpose of the calculation, shares repurchased under the buyback programme are deemed to have been cancelled on purchase date.

	The diluted earnings per share are based on the same profit figures. For this calculation, weighted-average number of shares is increased by 2,283,163 for 2004 (2003: 674,120; 2002: 442,580; 2001: 1,124,897; 2000: 1,394,975). These numbers relate to stock options schemes as mentioned above.

c	Includes interim dividend of €0.75 ($0.90) made payable in September 2004 and a second interim dividend of €1.04 ($1.33) made payable in March 2005. This together will constitute the total dividend for 2004, subject to finalization by the General meeting of Shareholders to be held on June 28, 2005.

Shell Transport (UK GAAP)														per 25p Ordinary sharea
						2003				2002				2001				2000
		2004				As restated				As restated				As restated				As restated
Net assets – pence			187.1				173.1				161.2				169.3				164.9
Total assets – pence			198.2				183.1				170.7				178.5				173.9
Adjusted basic earnings – continuing operations (pro forma) – pence			37.9				30.7				26.0				29.2				36.8
Adjusted basic earnings – discontinued operations (pro forma) – pence			3.6				0.1				0.5				0.1				(1.4	)
Adjusted basic earnings (pro forma) – penceb			41.5				30.8				26.5				29.3				35.4
Adjusted diluted earnings – continuing operations (pro forma) – pence			37.9				30.7				26.0				29.2				36.7
Adjusted diluted earnings – discontinued operations (pro forma) – pence			3.6				0.1				0.5				0.1				(1.4	)
Adjusted diluted earnings (pro forma) – pence b			41.5				30.8				26.5				29.3				35.3
Dividends declared – pence			16.95	c			15.75				15.25				14.80				14.60

a	The authorised share capital of Shell Transport as set forth in its Memorandum of Association consists of £2,500,000,000 divided into 9,948,000,000 Ordinary shares of 25 pence each and 3,000,000 First Preference shares of £1 each and 10,000,000 Second Preference shares of £1 each.
b	Adjusted earnings includes Shell Transport’s share of earnings retained by companies of the Royal Dutch/Shell Group. A reconciliation between this Adjusted earnings per share measure and Shell Transport’s earnings per share is provided on page S2. The basic earnings per share amounts shown are calculated after deducting 5.5% and 7% cumulative dividend on First and Second Preference shares respectively. The calculation uses a weighted-average number of shares of 9,480,407,909 (2003: 9,528,797,724; 2002: 9,608,614,760; 2001: 9,758,574,437; 2000: 9,882,388,055). The basic earnings per share calculation has been restated to exclude shares held by Group companies for

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	share options and other incentive compensation plans (see Note 23 to the Group Financial Statements). The same earnings figure is used in the basic and diluted earnings per share calculation. For the diluted earnings per share calculation the weighted-average number of shares is increased by 4,772,177 for 2004 (2003: 2,722,083; 2002: 4,661,292; 2001: 12,602,362; 2000: 17,170,048). These numbers relate to share option schemes as mentioned above.
c	Includes an interim dividend of 6.25p paid on September 15, 2004, and a second interim dividend of 10.7p paid on March 15, 2005.

	The number of issued and paid up Ordinary shares, First Preference shares and Second Preference shares of Shell Transport at the end of 2000-2004 inclusive was:

Shell Transport										Number of issued shares
		2004				2002-2003				2001				2000
Ordinary share			9,624,900,000				9,667,500,000				9,748,625,000				9,943,509,726
First Preference			2,000,000				2,000,000				2,000,000				2,000,000
Second Preference			10,000,000				10,000,000				10,000,000				10,000,000

The amount of issued and paid up share capital of Shell Transport at the end of 2000-2004 inclusive was:

Issued and paid up capital (£)
		2004				2002-2003				2001				2000
			2,418,225,000				2,428,875,000				2,449,156,250				2,497,877,432

Shell Transport										per New York Sharea
		2004				2003				2002				2001				2000
Dividends and tax credits – equivalent payment in US dollars			1.89				1.62				1.44				1.29				1.24

a	One New York Share or American Depositary Receipt (ADR) = six 25p Ordinary shares.

Under the provisions of the UK/USA Double Taxation Conventions, US resident holders of American Depositary Receipts (New York Shares) receive a tax credit (currently 10/90 of the net dividend) concurrently with their dividend – less a deduction for UK withholding tax at 15% or the value of the tax credit, whichever is the lower. US portfolio shareholders are subject to tax on the gross dividend (net dividend plus tax credit) with credit for the UK withholding tax. Effective for dividends paid after March 31, 2003, under the new UK/USA Convention, there is no longer any deemed credit for UK withholding tax and the amount subject to taxation in the US is the actual amount of dividend paid.

The payment of future dividends on shares of Royal Dutch and Shell Transport will depend upon the Group’s earnings, financial condition (including its cash needs), future earnings prospects and other factors. Following the completion of the transaction described below under “Discussion and Analysis of Financial Condition and Results of Operations – Overview – Unification Proposal”, Royal Dutch Shell plc, consistent with Royal Dutch’s and Shell Transport’s historical dividend policy, has announced it will seek to increase dividends at least in line with inflation over time. Additional information on dividends is given under Discussion and Analysis of Financial Condition and Results of Operations – Overview – Financial Framework (page 47), Royal Dutch Petroleum Company – Articles of Association (page 83) and The “Shell” Transport and Trading Company, Public Limited Company – Memorandum and Articles of Association (page 95).

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Discussion and Analysis of Financial Condition and Results of Operations

Royal Dutch Petroleum Company (Netherlands GAAP)

Translated into euros, Royal Dutch’s share in the net income of the Royal Dutch/Shell Group of Companies for the years 2004, 2003 and 2002 respectively amounts to €8,712 million, €6,411 million (as restated) and €6,076 million (as restated). The dividends distributed from Group companies to Royal Dutch for the years 2004, 2003 and 2002 were respectively €3,842 million, €2,868 million and €3,317 million. When interest income has been added and administrative expenses deducted, after-tax net income for the year 2004 amounted to €8,713 million compared with €6,418 million for 2003 and €6,091 million for 2002.

Royal Dutch’s 60% interest in the Group net assets, expressed in US dollars, has been translated into a euro amount at the year-end rate ($1 = €0.7333 at December 31, 2004). The amount thus obtained, which appears in the Balance Sheet on page R3, should be regarded as a reflection of the US dollar value of Royal Dutch’s interest in the Group’s assets and liabilities. Consequently, changes in the US dollar/euro rate lead to translation effects in the Royal Dutch Financial Statements. The movements in the value of the US dollar, between $1 = €0.7928 at December 31, 2003 and $1 = €0.7333 at December 31, 2004, led to a negative translation effect of €2,998 million, compared with a negative translation effect of €6,445 million in 2003. These effects are dealt with separately from the “Translation effect arising from movements in US dollar/euro rate”, as shown in Note 6 on pages R6 to R7. The translation effects are dealt with in the Balance Sheet items “Investments in companies of the Royal Dutch/Shell Group” and “Investment reserves”.

As further described in Note 3 to the Royal Dutch’s Financial Statements, the Group Financial Statements and the Financial Statements of each of the Parent Companies have been restated for prior periods included in this report.

The Discussion and Analysis of Financial Condition and Results of Operations of the Royal Dutch/Shell Group of Companies is an integral part of the Discussion and Analysis of Financial Condition and Results of Operations for Royal Dutch Petroleum Company.

Share buyback and cancellation of shares

The General Meeting of Shareholders renewed the authorisation of the Board of Management, with effect from July 1, 2004, and for a period of 18 months, for the acquisition by Royal Dutch, with due observance of statutory provisions and for its own account, of shares in its capital up to a maximum of 10% of the issued capital. Such shares can be acquired on the stock exchange or otherwise at a price between an amount equal to the par value of the shares and an amount equal to 110% of the opening price quoted for shares of Royal Dutch at Euronext Amsterdam on the day of the acquisition or, in the absence of such a price, the last previous price quoted there.

In 2004, Royal Dutch purchased 9,100,000 ordinary shares on the market under its share buyback programme at an average price of €41.31 and at a total cost, including expenses, of €375.9 million. These purchases represented 0.44% of Royal Dutch’s share capital as at December 31, 2003. As of March 29, 2005, a further 4,880,000 shares had been repurchased at an average price of €46.94 at a total cost of €229 million.

It will be proposed to the General Meeting of Shareholders to be held on June 28, 2005 to cancel the shares acquired by Royal Dutch in the period between the General Meetings in 2004 and 2005.

Since the beginning of the programme until March 29, 2005 a total number of 74,776,352 ordinary shares has been acquired by Royal Dutch, of which, as of March 29, 2005 62,571,352 shares have been cancelled.

Share Options

Interim Dividend

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2005, the Supervisory Board and Board of Management of Royal Dutch announced a second interim dividend in respect of the financial year 2004 of €1.04 per ordinary share to be payable as from March 15, 2005.

International Financial Reporting Standards

With effect from January 1, 2005, Royal Dutch will also prepare its consolidated Financial Statements under International Financial Reporting Standards.

Unification Proposal

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The “Shell” Transport and Trading Company, Public Limited Company

Shell Transport’s earnings for the year 2004 amounted to £3,939.3 million (£2,939.1 million in 2003 (as restated); £2,544.7 million in 2002 (as restated)). The amount available for distribution (inclusive of distributions from companies of the Royal Dutch/Shell Group) was £1,735.5 million in 2004 (£1,362.4 million in 2003 (as restated); £1,404.0 million in 2002 (as restated)).

Shell Transport’s net assets at December 31, 2004 were £17,664.5 million, in comparison with £16,481.5 million (restated) at the end of 2003. Of these two amounts, £17,452.6 million and £16,200.6 million (restated) respectively represented Shell Transport’s share in the net assets of companies of the Royal Dutch/Shell Group.

As further described in Note 3 and Note 14 to the Shell Transport Financial Statements, the Group Financial Statements and the Financial Statements of each of the Parent Companies have been restated for all comparative periods included in this Report.

Share buyback

Share Options

Interim Dividend

International Financial Reporting Standards

With effect from January 1, 2005, Shell Transport intends to prepare its Financial Statements under International Financial Reporting Standards.

Unification Proposal

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Royal Dutch/Shell Group of Companies

Summarised Financial Data (US GAAP)
Income data														$ million
						2003				2002				2001				2000
		2004				As restateda				As restateda				As restateda				As restateda
Sales proceeds
Oil and gas			308,660				243,566				202,861				149,005				161,219
Chemicals			27,780				19,459				14,659				13,767				15,658
Other			1,082				864				767				589				481
Gross proceeds			337,522				263,889				218,287				163,361				177,358
Sales taxes, excise duties and similar levies			72,332				65,527				54,834				40,908				41,122
Net proceeds			265,190				198,362				163,453				122,453				136,236
Earnings by industry segment
Exploration & Production			8,957				8,590				6,641				7,882				9,902
Gas & Power			2,069				2,271				747				1,199				92
Oil Products			6,281				2,821				2,485				1,919				3,371
Chemicals			930				(209	)			565				127				1,031
Other industry segments			(141	)			(267	)			(110	)			(287	)			(12	)
Total operating segments			18,096				13,206				10,328				10,840				14,384
Corporate			(847	)			(820	)			(684	)			(216	)			(706	)
Minority interests			(626	)			(353	)			(175	)			(360	)			(357	)
Income from continuing operations			16,623				12,033				9,469				10,264				13,321
Income from discontinued operations, net of tax b			1,560				25				187				37				(508	)
Cumulative effect of a change in accounting principle, net of tax			–				255				–				–				–
Net income			18,183				12,313				9,656				10,301				12,813

Assets and liabilities data (at December 31)																		$ million
Total fixed and other long-term assets			130,963				125,946				111,476				80,729				76,836
Net current assets/(liabilities)			1,184				(10,813	)			(13,546	)			(2,750	)			3,778
Total debt			14,422				20,127				19,691				5,820				7,427
Parent Companies’ interest in Group net assets			84,576				72,497				60,276				56,142				57,616
Minority interests			5,309				3,415				3,568				3,466				2,897
Capital employedc			104,307				96,039				83,535				65,428				67,940

Cash flow data																		$ million
Cash flow provided by operating activities			25,587				21,719				16,283				16,905				18,278
Capital expenditure (including acquisitions)			12,734				12,252				21,027				9,598				6,128
Cash flow used in investing activities			5,643				8,252				20,633				9,080				1,490
Dividends paid			8,754				6,548				7,189				9,627				5,501
Cash flow used in financing activities			12,792				12,586				53				11,562				9,125
Increase/(decrease) in cash and cash equivalents			6,507				396				(5,114	)			(4,761	)			7,388
Other statistics
Total debt ratioc			13.8%				21.0%				23.6%				8.9%				10.9%
a  See Note 2 to the Group Financial Statements.
b  Income from discontinued operations comprises:

$ million
		2004				2003				2002				2001				2000
Earnings by industry segment
Exploration & Production			358				78				85				29				(31	)
Gas & Power			86				19				27				27				21
Oil Products			1,256				39				142				51				(689	)
Chemicals			–				–				–				–				–
Other industry segments			–				–				–				–				–
Corporate			(52	)			(98	)			(67	)			(104	)			(119	)
Minority interests			(88	)			(13	)			–				34				310
			1,560				25				187				37				(508	)

c

The debt ratio is defined as short-term plus long-term debt as a percentage of capital employed. Capital employed is Group net assets before deduction of minority interests plus short-term and long-term debt. Management of the Group believes that the debt ratio calculated on this basis (rather than the ratio of total debt to shareholders equity) is useful to investors because it takes account of all amounts of capital employed in the business. Management uses this measure to assess the level of debt relative to the capital invested in the business. The derivation of capital employed from Group net assets is shown in the table above.

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Capital investment							$ million
			2004				2003				2002				2001				2000
Capital expenditurea
	Exploration & Production			8,387				8,129				13,064				6,847				3,720
	Gas & Power			1,357				1,021				471				313				288
	Oil Products			2,404				2,367				7,653				1,462				1,258
	Chemicals			366				470				680				685				726
	Other			220				265				494				291				136
				12,734				12,252				22,362				9,598				6,128
Exploration expenses (excluding depreciation and release of currency translation differences)				1,123				1,059				997				885				834
New equity investments in associated companies				681				758				684				704				605
New loans to associated companies				377				225				605				370				556
Other investments				–				–				–				224				414
Total capital investment*				14,915				14,294				24,648				11,781				8,537
*comprisingb
	Exploration & Production			9,868				9,337				14,151				8,191				4,979
	Gas & Power			1,633				1,511				953				963				835
	Oil Products			2,466				2,405				7,968				1,527				1,571
	Chemicals			705				599				998				760				978
	Other			243				442				578				340				174
				14,915				14,294				24,648				11,781				8,537

a	Includes the acquisitions in 2002 of Enterprise Oil, Pennzoil-Quaker State, the outstanding shares in DEA and in Equilon. The payment of $1.3 billion relating to DEA was made in 2003.
b	In 2004 new loans to associated companies were allocated to the relevant business segment. Prior years have been reclassified accordingly.

Quarterly income data																																																						$ million
																																						2003																				2002
																		2004																				As restateda																				As restateda
		Q4				Q3				Q2				Q1				Year				Q4				Q3				Q2				Q1				Year				Q4				Q3				Q2				Q1				Year
Gross proceeds			95,628				87,941				79,045				74,908				337,522				67,313				64,879				63,594				68,103				263,889				59,280				58,099				53,999				46,909				218,287
less: Sales taxes, excise duties and similar levies			19,204				18,011				17,423				17,694				72,332				17,699				16,244				16,395				15,189				65,527				15,377				14,151				12,896				12,410				54,834
Net proceeds			76,424				69,930				61,622				57,214				265,190				49,614				48,635				47,199				52,914				198,362				43,903				43,948				41,103				34,499				163,453
Cost of sales			65,634				57,689				51,094				47,261				221,678				41,392				40,897				39,683				43,175				165,147				36,120				36,593				34,573				28,372				135,658
Gross profit			10,790				12,241				10,528				9,953				43,512				8,222				7,738				7,516				9,739				33,215				7,783				7,355				6,530				6,127				27,795
Operating profit			6,650				10,113				7,493				7,677				31,933				4,151				4,800				4,676				7,696				21,323				4,214				5,117				4,220				4,308				17,859
Income from continuing operations			3,098				5,281				3,898				4,346				16,623				1,946				2,385				2,535				5,167				12,033				2,242				2,555				2,272				2,400				9,469
Income from discontinued operations			1,173				76				49				262				1,560				(119	)			34				38				72				25				33				51				52				51				187
Cumulative effect of change in accounting principle, net of tax			–				–				–				–				–				–				–				–				255				255				–				–				–				–				–
Net income			4,271				5,357				3,947				4,608				18,183				1,827				2,419				2,573				5,494				12,313				2,275				2,606				2,324				2,451				9,656

a	See Note 2 to the Group Financial Statements.

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US dollar exchange ratesa																	€1 = $
					Averageb				High				Low				Period end
Year:
	1999					1.0588
	2000					0.9209
	2001					0.8909
	2002					0.9495
	2003					1.1411
	2004					1.2478
Month:
2004			February							1.2848				1.2426
			March							1.2431				1.2088
			April							1.2358				1.1802
			May							1.2274				1.1801
			June							1.2320				1.2006
			July							1.2437				1.2032
			August							1.2368				1.2025
			September							1.2417				1.2052
			October							1.2783				1.2271
			November							1.3288				1.2703
			December							1.3625				1.3224
2005			January							1.3476				1.2954
			February							1.3274				1.2773
As at March 29, 2005																		1.2913

£1 = $
					Averageb				High				Low				Period end
Year:
	1999					1.6146
	2000					1.5138
	2001					1.4382
	2002					1.5084
	2003					1.6450
	2004					1.8356
Month:
2004			February							1.9045				1.8182
			March							1.8680				1.7943
			April							1.8564				1.7674
			May							1.8369				1.7544
			June							1.8387				1.8090
			July							1.8734				1.8160
			August							1.8459				1.7921
			September							1.8105				1.7733
			October							1.8404				1.7790
			November							1.9073				1.8323
			December							1.9482				1.9125
2005			January							1.9058				1.8647
			February							1.9249				1.8570
As at March 29, 2005																		1.8752

a	Exchange rates are based upon the noon buying rate in New York City for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York.
b	Calculated by using the average of the exchange rates on the last business day of each month during the year.
c	The euro-to-US dollar exchange rates prior to the fixing of the euro conversion rate in January 1999 are derived from guilders-per-US dollar exchange rates and the fixed guilders-per-euro conversion rate of 2.20371.

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Overview

Over time, and across the commodity price cycle, the Group has achieved higher earnings, cash-flow and returns on investment in the Exploration & Production business compared with the other businesses, and sees significant growth potential in demand for natural gas. The downstream businesses continue to offer attractive returns and growth potential in certain business lines and geographies, and provide useful balance in the portfolio to reduce exposure to commodity price movements. The Group’s core competencies include the application of technology, financial and project management skills to large oil and gas projects; the ability to develop and manage a diverse and international business portfolio; and the development of customer focused businesses built around the strength of the Shell brand.

Strategy

Reshaping our portfolio

Raising our operational performance

Creating the culture and organisation to deliver

Market overview

World economy

While the outlook for 2005 is positive, there are some risks that could affect the rate of global economic growth. These risks include the decline in the US dollar, a rise in protectionism, geopolitical uncertainties and financial turbulence in emerging markets such as China.

Oil and natural gas prices

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Oil demand growth in 2005 is expected to be lower than in 2004 but still above the average level for the past decade. Crude prices in 2005 will be influenced by the rate of global economic growth, particularly in the USA and China. Other factors affecting prices will include the pace of Iraqi oil export recovery, OPEC supply policy and the severity of the northern hemisphere winter. Disruption to supply as a result of political and security issues would lead to price volatility and upward pressure on prices.

Henry Hub natural gas prices in the USA increased from $5.62 per million British thermal unit (Btu) in 2003 to $5.87 per million Btu in 2004. In 2005 Henry Hub prices are expected to reflect supply and demand in the USA where the development of domestic supply, demand levels from weather conditions and the rate of economic growth will be important. Prices in other markets are expected to remain largely linked to oil prices.

General industry factors

The refining and marketing environment is characterised by intensifying competition from industry consolidation and new entrants and changing and increasingly complex patterns of supply and demand. A fundamental shift in the pattern of demand is taking place as traditional markets in Western Europe and the USA see demand growth slowing while markets in Asia Pacific are experiencing significant growth. In 2004, a shortage of capacity relative to growing demand led to strong refining margins.

The business environment for chemicals has become more positive but remains cyclical. The central driver of growth in the business remains the overall pace of global economic activity.

Industry Segments

In 2004, the Group took the final investment decision on several significant Exploration & Production projects. These included the Kashagan development in Kazakhstan and the Pohokura gas project in New Zealand. In Oman agreements were signed with the government to extend the terms of Petroleum Development Oman’s (PDO) concession until 2044. Plans were announced to increase bitumen production at the Athabasca Oil Sands Project (Group interest 47%) from the current 155,000 barrels a day capacity to between 270,000 and 290,000 barrels a day by 2010.

Volatility in oil prices is one of the key risks in the Exploration & Production business. We believe that the oil pricing structure has shifted to a higher price environment driven by global demand growth and the increased cost of the investment needed to supply that demand. Cost increases are another key risk to the business. These risks are managed through a focus on improving asset integrity and reliability, further work to maximise the value from the creation of a global business organisation and improved project management.

Gas & Power

Earnings in 2004 reflected the increase in natural gas prices and LNG sales volumes. The Group continues to invest in LNG projects and expects to increase its LNG capacity by an average of 14% per year in the period from 2003 through 2008.

One of the principal challenges and risks in the Gas & Power business is to ensure the development of assets in each part of the LNG value chain are aligned with market growth. This risk is being managed by the development of a portfolio of supply, shipping and LNG import facilities in the key markets. Other challenges, on which there is a clear focus in the business, include ensuring that capital projects are delivered on schedule and within budget and that new business development opportunities are secured in an increasingly competitive environment.

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Oil Products

In 2004, there were stronger refining conditions globally and increases in refining and marketing margins. The increases in margins across the world reflected exceptional product demand growth particularly in China and, to a lesser extent, the USA.

The key challenges in Oil Products are volatility in refining margins and maintaining a competitive cost structure.

We expect that the creation of one downstream organisation, integrating the Oil Products and Chemicals businesses, will help to optimise refining and chemicals facilities, standardise our processes and improve services to customers. Work will continue to sell or improve underperforming assets. This will be underpinned by a focus on improving operational performance and delivering cost reductions. This will position us for future growth in selected markets where we see the greatest opportunities. In particular, we intend to focus on the Asia Pacific markets where we believe there is significant potential for growth. By the end of the decade the downstream business expects to have a greater percentage of its capital employed in Asia Pacific, compared to year end 2004.

Chemicals

In response to these challenges, the Group has maintained its focus on reducing costs, asset restructuring and closing under-performing assets and is shifting the portfolio to growth areas in Asia Pacific and the Middle East. This is underpinned by the overall chemicals strategy of producing bulk chemicals and first line derivatives to supply large industrial customers through simplified, standardised global business processes.

The Group intends to integrate the Oil Products and Chemicals businesses in order to provide opportunities to achieve cost efficiencies from shared services and common manufacturing sites, and from improved use of hydrocarbon resources on integrated sites.

Financial framework

Following the completion of the transaction described below under “-Unification Proposal”, Royal Dutch Shell plc, consistent with Royal Dutch’s and Shell Transport’s historical dividend policy, has announced it will seek to increase dividends at least in line with inflation over time. The base for the 2005 financial year will be the dividend paid by Royal Dutch in respect of the financial year ending December 31, 2004. With the adoption of quarterly dividends in 2005, Royal Dutch and Shell Transport will pay dividends in respect of the first quarter of 2005. Royal Dutch Shell plc will take these dividends into account when determining the dividends which will be declared for the remainder of the year. In 2004 the dividends paid out to shareholders exceeded $7.1 billion. As a result of the transition to the payment of quarterly dividends, the Group expects to return at least $10 billion cash to shareholders from dividends during 2005, subject to exchange rates. Given the strong cash and debt position from 2004, the share buyback program was relaunched on February 3, 2005, with the return of surplus cash to shareholders for the year 2005 expected to be in the range of $3 to $5 billion, assuming high oil prices.

Capital investment of some $15 billion (excluding contribution of the Group’s minority partners in Sakhalin) on average is required each year to grow the capital base in light of expected dividend payments, taking into account an expected $13 to $15 billion of divestments over the period 2004 to 2006. After dividends and capital investment, the priority for using cash generated is to maintain a prudent balance sheet. Both the medium and long-term focus will remain on improving the underlying operational performance in order to continue to deliver consistently strong cash flows.

Over the past 20 years the Brent crude oil price has averaged around $20 a barrel and over the past five years the price averaged approximately $27 a barrel. We expect that crude oil prices in 2005 will be influenced by developments in the key oil producing countries, the pace of Iraqi crude export recovery, and by the rate of the global economic recovery, particularly in the USA and China. Natural gas prices in the USA are expected to remain well above pre-2000 levels, due to higher demand resulting from a more general recovery of the global economy, while prices in other major markets are expected to retain an oil-price linkage.

The Group uses a range of prices for crude oil to test opportunities on the downside and look at the upside of potential projects. The Group plans for the medium term at $25 a barrel, screens for resilience to price downside at $20 a barrel, and tests for response to price

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upside at a range of higher prices. This method is applied to understand the composition of projects in the portfolio and how these respond over a broad range of prices or margins. The crude oil price outlook for 2005 will likely be impacted by developments in the Middle East and Venezuela.

Crude oil reference price conditions are determined after careful assessment of short, medium and long-term drivers of oil and gas prices under different sets of assumptions, yielding a range of prices to be used in evaluation. With regard to 2004, crude oil prices were higher than the conservative expectations of our reference price conditions. Historical analysis, trends and statistical volatility are part of this assessment, as well as analysis of global and regional economic conditions, geopolitics, OPEC actions, supply and demand. Sensitivity analyses are used to test the impact of low price drivers (economic weakness, rapid resumption of Iraqi production, greater than expected increase in non-OPEC production) and high price drivers (greater than expected economic growth, slower than expected resumption of Iraqi production). Short-term events (such as relatively warm winters or cool summers and the resulting effects on demand and inventory levels) contribute to volatility.

As described in Note 3 to the Group Financial Statements under the heading “Accounting Policies – Revenue Recognition” on page G9, the Group reports certain buy/sell contracts for feedstock, principally crude oil, and finished products mainly in the Oil Products segment on a gross basis in the Statement of Income. These contracts are entered into with the same counterparty either concurrently or in contemplation of one another. However, they are separately invoiced and settled and there is no legal right of offset. If these contracts were required to be reported net, it is estimated that net proceeds and cost of sales for 2004 would be reduced by approximately $25 billion (this reduction of around 10% would be indicative of the impact for 2003 and 2002) with no impact on net income.

Unification Proposal

On October 28, 2004, the Group also announced changes to the senior management structure which took immediate effect. Jeroen van der Veer was appointed Group Chief Executive. The Committee of Managing Directors was abolished and the Executive Committee was formed. Members of the Executive Committee are Peter Voser, Chief Financial Officer; Malcolm Brinded, Executive Director of Exploration & Production; Linda Cook, Executive Director of Gas & Power; and Rob Routs, Executive Director of Oil Products and Chemicals who all report to the Group Chief Executive, who chairs the Executive Committee.

Reserves Restatements and Financial Restatements

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reserves” within the applicable rules of the SEC (which in many cases is the date on which the volumes were initially booked as proved reserves). 12% of the volumes de-booked had been in the proved developed reserves category and 88% had been categorised as proved undeveloped reserves. The First Reserves Restatement was reflected in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as originally filed with the US Securities and Exchange Commission (SEC) on June 30, 2004.

On February 3, 2005, as a result of reservoir level reviews conducted during July 2004 through December 2004 of substantially all of the Group’s proved reserves volumes reported as at December 31, 2003, (collectively, the Second Half Review), the Group announced that it would remove from proved reserves an additional approximately 1.37 billion boe of oil and gas that were reported as at December 31, 2003 (1.15 billion boe previously reported at December 31, 2002) and further restate the unaudited oil and gas reserves disclosures contained in the supplementary information accompanying the Financial Statements (the Second Reserves Restatement, and together with the First Reserves Restatement, the Reserves Restatements) to give effect to the removal of these volumes as of the earliest date on which they did not represent “proved reserves” within the applicable rules of the SEC (which in many cases is the date on which the volumes were initially booked as proved reserves). 43% of the volumes de-booked had been categorised as proved developed reserves and 57% had been categorised as proved undeveloped reserves. The Second Reserves Restatement is reflected in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with the SEC on March 7, 2005.

Please refer to “Supplementary information – Oil and Gas (unaudited)” on pages G49 to G61 for additional information regarding the First Reserves Restatement and the Second Reserves Restatement.

In view of the inappropriate overstatement of unaudited proved reserves information resulting in the First Reserves Restatement, it was determined to restate the Financial Statements of the Group, and each of the Parent Companies, for the year ended December 31, 2002 and prior periods (the First Financial Restatement) to reflect the impact of the First Reserves Restatement on those Financial Statements (as announced on April 19, 2004). As part of the First Financial Restatement, the Financial Statements were also restated to correct an inappropriate departure from US GAAP relating to certain exploratory drilling costs, to correct an inappropriate departure from US GAAP (for 2002 only) for certain gas contracts, to correct an error in the calculation of earnings per share of the Parent Companies and to reflect a change in accounting principle relating to inventories. The First Financial Restatement also included a separate presentation of the Group Financial Statements under US GAAP and Netherlands GAAP, and a reconciliation of the differences between the presentations. This discussion and analysis is based on the US GAAP Group Financial Statements. The First Financial Restatement was reflected in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as originally filed with the SEC on June 30, 2004.

In view of the inappropriate overstatement of unaudited proved reserves information resulting in the Second Reserves Restatement, it was determined to restate the Financial Statements of the Group and each of the Parent Companies for the year ended December 31, 2003 and prior periods (the Second Financial Restatement and together with the First Financial Restatement, the Financial Restatements) to reflect the impact of the Second Reserves Restatement on those Financial Statements (as announced on February 3, 2005). The Second Financial Restatement is reflected in this Report and also in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with the SEC on March 7, 2005.

Investigation and report to the Group Audit Committee; management changes

Following an interim report to the GAC dated March 1, 2004, which was presented to the Parent Company Boards on March 2, 2004, Sir Philip Watts, Chairman of the Committee of Managing Directors and Walter van de Vijver, Chief Executive of Exploration & Production, submitted their resignations on March 3, 2004 from all director and officer positions within the Group and the Parent Companies. Following acceptance of the final report to the GAC by the members of the Supervisory Board of Royal Dutch and the non-executive Directors of Shell Transport, Judith Boynton stepped aside as Group Chief Financial Officer and as Group Managing Director and Managing Director of Shell Transport on April 18, 2004. She remained with the Group in an advisory capacity reporting to the Chief Executive Jeroen van der Veer. Ms Boynton left the Group, by mutual agreement, effective December 31, 2004.

Jeroen van der Veer, President and Managing Director of Royal Dutch, succeeded Sir Philip Watts as Chairman of the Group’s Committee of Managing Directors; Lord Oxburgh was appointed non-executive Chairman of Shell Transport and Chairman of Conference; and Malcolm Brinded was appointed Chief Executive of Exploration & Production, a Managing Director of Shell Transport and Vice-Chairman of the Committee of Managing Directors. Malcolm Brinded resigned from his position as a Managing Director of Royal Dutch. On June 23, 2004 Peter Voser was appointed Group Chief Financial Officer and a Director of Shell Transport with effect from October 4, 2004. Linda Cook was appointed a Managing Director of Royal Dutch on August 1, 2004.

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Summary of Group Results

Earnings (US GAAP)						$ million
						2003				2002
		2004				As restateda				As restateda
Income from continuing operations			16,623				12,033				9,469
Income from discontinued operations			1,560				25				187
Cumulative effect of a change in accounting principle			–				255				–
Net income			18,183				12,313				9,656
Change from previous year			+48%				+28%				-6%

a	See Note 2 to the Group Financial Statements.

2004 compared to 2003

Exploration & Production earnings were $9,315 million, 4% higher than in 2003. Production in 2004 was broadly unchanged compared to 2003, excluding the impact of divestments, price effects and hurricanes in the Gulf of Mexico. The decline in production in mature areas was largely offset by the start of production in new fields. Hydrocarbon prices were higher in 2004 compared with 2003 with Brent crude prices averaging $38.30 a barrel compared with $28.85 in 2003 and West Texas Intermediate prices averaging $41.50 a barrel in 2004 compared with $31.05 in 2003. Prices reflected the effect of strong US and Chinese demand, geopolitical uncertainty, in a number of producer countries, disruptions to production as a result of the hurricanes in the Gulf of Mexico; and lower OPEC spare production capacity. The benefits of higher oil and gas prices were offset by lower hydrocarbon production, higher costs and depreciation, and an increase in the overall effective tax rate.

Earnings in Gas & Power were $2,155 million, 6% lower than in 2003. Earnings in 2003 included gains of $1,120 million mainly related to divestments (Ruhrgas), whereas divestment gains in 2004 were $772 million. Earnings in 2004 reflected a 9% increase in LNG volumes and an 8% increase in LNG prices.

Oil Products earnings increased by 164% compared with 2003 to $7,537 million, benefiting significantly from higher refining margins, and increased trading earnings. These results included divestment gains of $1,038 million and net charges of $403 million.

Earnings in Chemicals were $930 million, including a $565 million write-down in the carrying amount of Basell (Chemicals). This impairment followed the announcement in 2004 of a review of strategic alternatives regarding this joint venture. In 2003 a loss of $209 million for Chemicals included $478 million in asset restructuring and impairment charges. The improvement in earnings from 2003 was due to volume growth and higher margins.

The results discussed above include income from discontinued operations of $1,560 million in 2004, including gains on the disposal of such operations which are described in Note 4 to the Group Financial Statements.

Capital investment¹ in 2004 was $14.9 billion compared with $14.3 billion in 2003. Gross proceeds from divestments were $7.6 billion and cashflow from operating activities was $25.6 billion, an increase of 18% from 2003. At the end of 2004, the debt total ratio² was 13.8% compared with 21.0% in 2003. Cash and cash equivalents were $8.5 billion compared with $2.0 billion in 2003.

It is expected that at least $10 billion, subject to exchange rates, will be returned to shareholders in dividends in 2005. The share buyback programme was relaunched on February 3, 2005.

In view of the inappropriate overstatement of unaudited proved reserves information, it was decided to restate the Financial Statements of the Group, and each of the Parent Companies, for prior periods (the Financial Restatements) to reflect the impact of the Reserves Restatements on those Financial Statements (as announced on April 19, 2004 and February 3, 2005). See Explanatory Note on page ii.

See pages 75 and 76 regarding “Investigation and report to the Group Audit Committee; management changes” for additional detail regarding the Group Audit Committee’s investigation arising out of the Reserves Restatements.

All Group financial information contained in this section is presented in accordance with accounting principles generally accepted in the United States. The restatements described above are reflected in prior period information where applicable.

1	Capital investment is capital expenditure, exploration expense and investments in associated companies.

2	The total debt ratio is defined as short-term plus long-term debt as a percentage of capital employed. Capital employed is Group net assets before deduction of minority interests, plus short-term and long-term debt.

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2003 compared to 2002

Exploration & Production earnings were 33% higher than 2002 at $8,923 million. Total hydrocarbon production³ fell by 1% to 3.9 million barrels of oil equivalent (boe) per day. Oil and oil sands production increased by 1% while gas production fell by 5%. Hydrocarbon prices were generally higher in 2003 compared with 2002 (Brent crude prices averaged $28.85 a barrel compared with $25.05 in 2002) as a result of the conflict in Iraq, OPEC behaviour, lower inventories worldwide and cold weather in Europe and North America. The Group’s total proved reserves at the end of 2003 were 12,979 billion barrels of oil equivalent. (More detailed information on reserves is available on pages 53 and 54.)

Earnings in Gas & Power were at a record level at $2,289 million, benefiting from the sale of the Group’s shareholding in Ruhrgas, higher prices and record LNG volumes.

An improved business environment and higher refining and marketing margins in all regions helped Oil Products earnings to increase by 9% to $2,860 million.

Business conditions remained difficult in Chemicals which showed a loss of $209 million. These results reflected asset impairment and restructuring charges totaling $478 million.

Total capital investment¹ was $14.3 billion, compared with $14.2 billion (excluding major acquisitions) in 2002. Proceeds from asset disposals in 2003 were $4.5 billion; this generated $2.0 billion of after-tax income, all of which was offset by net charges for impairment, restructuring and various other items including tax credits, resulting in a net charge of $104 million. At the end of the year the debt ratio² was 21.0%. Cash and cash equivalents amounted to $2.0 billion.

Exploration & Production

Earnings (US GAAP)						$ million
						2003				2002
		2004				As restateda				As restateda
Net proceeds (including inter-segment sales)			39,644				32,468				26,320
Purchases (including change in inventories)			(2,658	)			(1,535	)			(1,050	)
Exploration			(1,823	)			(1,475	)			(1,052	)
Depreciation			(7,457	)			(7,316	)			(5,556	)
Operating expenses			(9,320	)			(7,174	)			(6,686	)
Operating profit of Group companies			18,386				14,968				11,976
Group share of operating profit of associated companies			2,438				1,857				1,316
Operating profit			20,824				16,825				13,292
Other income/(expense)			166				72				73
Taxation			(12,033	)			(8,307	)			(6,724	)
Income from continuing operations			8,957				8,590				6,641
Income from discontinued operations, net of tax			358				78				85
Cumulative effect of a change in accounting principle			–				255				–
Segment earnings			9,315				8,923				6,726

a  See Note 2 to the Group Financial Statements.

2004 compared to 2003

Earnings included divestment gains of $740 million, of which $330 million relates to divestment gains from discontinued operations and relates to divestments of operations in Angola, Bangladesh, Egypt and Thailand. The balance of the $740 million relates to divestment gains in countries where there is continued investment in operations and which do not qualify as discontinued operations under US GAAP.

3	Includes oil sands.

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Compared with 2003, costs and depreciation were higher mainly as a result of exchange rates movements and higher activity in our growth areas. The increase in the effective tax rate was mainly driven by the impact of higher hydrocarbon prices, an increase in the tax burden in Denmark and lower tax credits than in 2003.

Write-offs of exploration properties, rights and concessions in 2004 of some $300 million due to unsuccessful drilling were in line with similar write-offs in 2003. Earnings in 2003 included a credit of $255 million resulting from a change in accounting for asset retirement obligations.

Prices

The Group’s overall realised oil prices were $35.61 a barrel up from $27.50 in 2003. In the USA realised oil prices averaged $36.15 a barrel compared with $27.24 a year earlier and outside the USA, realised prices averaged $35.53 compared with $27.54 in 2003. Realised oil prices differ from published crude oil prices because the quality, and therefore price, of actual crude oil produced differs from the quoted blends. In general, the Group produces crude oil of a lower quality than the quoted blends. The Group’s overall realised gas prices averaged $3.59 per thousand standard cubic foot compared with $3.30 in 2003.

Production

Oil production was 5% lower in 2004 than in 2003, mainly due to field declines in the USA, Norway and Oman, as well as lower production from fields in the UK. Production was also affected by lower entitlements from PSC operations as a result of higher oil prices.

Natural gas production was approximately the same as in 2003. Additional production from new fields, as well as high demand towards the end of the year, were offset by field declines in the USA and the UK, the effect of divestments, Gulf of Mexico hurricanes and lower entitlements from PSCs.

Various new fields started production during the year, including Jintan and Serai in Sarawak, Malaysia and Goldeneye, Scoter and Howe in the UK. In the Gulf of Mexico, production began at the Holstein, Llano and Glider fields. Oil production from the West Salym field in Russia also began, a year earlier than planned.

A number of fields increased production over the year. These included the Bijupirá-Salema field in Brazil, the Na Kika and Habanero fields in the USA, the EA field in Nigeria and the Athabasca Oil Sands Project in Canada. These increases, along with production from new fields, added 221 thousand boe per day of production.

Capital investment and portfolio actions

The final investment decision was taken for the Kashagan project in Kazakhstan (Group interest 16.7%) which is expected to start production in 2008. The development of the Pohokura gas field in New Zealand (Group interest 48%) was agreed and the field is expected to produce its first gas in 2006. Planning permission was granted for the terminal that will receive gas from the offshore Corrib development in Ireland (Group interest 45%).

In Oman agreements were signed with the government to extend the terms of Petroleum Development Oman’s (PDO) concession for 40 years, until 2044. PDO (Group interest 34%) produces from 100 fields in the concession area. A Heads of Agreement was signed with the Libyan National Oil Company to establish a long-term strategic partnership that could open up opportunities to develop Libya’s gas and LNG business.

Plans were announced to increase bitumen production at the Athabasca Oil Sands Project (Group interest 47%) from 155,000 barrels a day capacity now to between 270,000 and 290,000 barrels a day by 2010. This will involve work to expand the Muskeg River mine and to add a third hydro-conversion unit to the Scotford Upgrader. The cost of these projects is expected to be about $4 billion and, subject to regulatory approval, work is expected to start in 2006.

5	For this purpose, the Group has converted natural gas to crude oil equivalent using a factor of 5,800 standard cubic feet per barrel.

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In 2004, good progress was made on the Sakhalin project in eastern Russia. The main concrete construction work of the base substructure for the Lunskoye offshore gas production platform was completed. This massive project remains on schedule for late 2007 but there are significant cost pressures in what is one of the largest single foreign investment projects in Russia.

Divestments included the sale of upstream assets in Angola, Thailand, Bangladesh, Egypt and the UK. In addition, an agreement was reached to sell the Schooner and Ketch fields in the UK.

Exploration

The Group made significant additions to its overall acreage positions with new exploration licences in the UK, Brazil, the Gulf of Mexico and Norway and additional oil sands acreage was acquired in Canada.

Reserves

During 2004, a total of 212 million boe was added to proved developed and undeveloped reserves by Group companies (a reduction of 151 million barrels of oil and natural gas liquids and an increase of 2,108 thousand million standard cubic feet of natural gas), including 417 million boe from organic activities (which includes all activities other than purchases and sales of minerals in place). The net addition to proved developed and undeveloped reserves (calculated before production) consisted of reductions of 218 million boe from revisions and 205 million boe from acquisitions and divestments and additions of 15 million boe from improved recovery and 620 million boe from extensions and discoveries. There was a net addition of 414 million boe to proved developed reserves and a net reduction of 202 million boe to proved undeveloped reserves. During the same period, the Group share of proved developed and undeveloped reserve additions by associated companies was 39 million boe (20 million barrels of oil and natural gas liquids and 108 thousand million standard cubic feet of natural gas). The Group share of net additions to proved developed and undeveloped reserves by associated companies consisted of a reduction of 10 million boe from acquisitions and divestments and additions of 2 million boe from revisions, 46 million boe from improved recovery and 1 million boe from extensions and discoveries. There was a net addition of 33 million boe to proved developed reserves and a net reduction of 6 million boe to proved undeveloped reserves. The most significant 2004 additions arose from new sales agreements covering gas volumes to be produced from the Sakhalin development in Russia, a concession extension in Oman and taking the final investment decision for the Kashagan field in Kazakhstan. The high level of year-end prices adversely affected proved reserve entitlements that are determined on the basis of production sharing arrangements, and the ability to book proved reserves associated with a heavy oil project in Canada (Peace River). The gas volumes booked for the Sakhalin project following new sales agreements will be produced after the start of gas production from the Lunskoye field in Sakhalin, currently expected in 2007. The oil volumes booked in the Kashagan field will be produced following field start-up in 2008. The volumes booked following the concession extension are expected to be produced after 2012. The rest of the reserves additions during 2004 are expected to be produced over time as development activities continue and/or production facilities are expanded or upgraded. The most significant movement from proved undeveloped to proved developed reserves is the result of installing compression facilities in the Groningen field, the Netherlands.

At December 31, 2004, after taking account of Group companies’ 2004 net additions to proved developed and undeveloped reserves of 212 million boe and production of 1,222 million boe, total proved reserves for Group companies of 10,231 million boe was 12% lower than at December 31, 2003. At the same date, after taking into account the Group’s share of associated companies’ net additions of 39 million boe and production of 126 million boe, the Group’s share of total proved developed and undeveloped reserves of associated companies of 1,652 million boe was 22% higher than December 31, 2003.

For the three years ended December 31, 2004, Group companies had net additions to proved reserves of 1,838 million boe and total production of 3,812 million boe, which resulted in a 19% decline in total proved reserves from December 31, 2001 to December 31, 2004. For the same period, the Group’s share of net additions to proved reserves by associated companies was 475 million boe and the Group’s share of production by these companies was 390 million boe, which resulted in a 40% increase in the Group’s share of proved reserves of associated companies. These changes in proved reserves include the effect of transferring a company in the Middle East from Group to associated company status as at December 31, 2004.

As at December 31, 2004, the Group’s proved developed and undeveloped reserves (excluding proved reserves of associated companies) were equivalent to 8.4 years of production (based on 2004 production).

The rate at which the Group (and associated companies) are developing proved reserves over a particular period may not necessarily be indicative of the rate at which hydrocarbon resources are being discovered for a number of reasons, including the technical nature of the definition of proved reserves and the differing time periods needed to develop proved reserves in different regions and under differing

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geologic, economic and regulatory conditions. However, the current level of reserves replacement by the Group and associated companies is clearly a concern and reflects the exploration strategy in the late 1990s and the Group’s relatively low investment in the post 1998 period. Exploration has since been refocused and investment levels have increased. The Group considers it vital to improve reserves replacement in the coming years.

Outlook and strategy

We believe that crude prices in 2005 will be influenced by the pace of Iraqi oil export recovery, OPEC supply policy, the rate of global economic expansion, particularly in the USA and China, and the severity of the northern hemisphere winter.

Natural gas prices in the USA will be affected by weather conditions and the rate of economic growth. Prices in other markets are expected to remain linked to oil prices.

We believe that growing global energy demand and the increased upstream investment required to meet that demand means that oil prices have shifted to a higher level for the medium term.

Crude oil price conditions are evaluated based on careful assessment of short, medium and long-term drivers of oil and gas prices under different sets of assumptions, yielding a range of prices to be used in evaluation. Historical analysis, trends and statistical volatility are part of this assessment, as well as analysis of global and regional economic conditions, geopolitics, OPEC actions, supply and demand. Sensitivity analyses are used to test the impact of low price drivers (economic weakness, rapid resumption of Iraqi production, greater than expected increase in non-OPEC production) and high price drivers (greater than expected economic growth, slower than expected resumption of Iraqi production). Short-term events (such as relatively warm winters or cool summers and the resulting effects on demand and inventory levels) contribute to volatility.

The Group strategy is focused on improving our basic underlying strengths in operational performance and project delivery, and replenishing our portfolio. The Group will work towards this by adding new acreage, pursuing an aggressive exploration programme, investing in organic growth, opening up new positions and making selective focused acquisitions.

The strategy seeks to position the Group in four strategic areas: existing oil; new material oil; integrated gas and unconventional oil. To deliver this strategy, capital investment in Exploration & Production will be increased to some $10 billion a year (excluding investment by our minority partners in Sakhalin).

The Group will seek to sustain long-term production from existing assets where the Group has significant positions and can benefit from higher prices (such as in the USA and the UK). Investments in new material oil projects such as Kashagan in Kazakhstan and offshore Nigeria also form a key part of the Group’s strategy.

The Group believes that natural gas demand will continue to grow at a faster rate than oil demand, therefore the Group will look for more integrated gas positions to take advantage of this growth, extending its leadership position in LNG, including equity capacity, and securing emerging opportunities in Gas to Liquids production. The Group’s major presence across the value chain from exploration to the production and supply of natural gas enables the Group to maximise the value from projects such as Sakhalin. The Group intends to build on its existing strength in unconventional oil technology and the success of the Athabasca Oil Sands Project, and look for more of these opportunities.

The Group will continue to focus on reducing costs through improving management of the supply chain, and standardising processes globally. Ensuring improved and consistent project delivery is a key priority. The Group will be providing additional resources in Exploration & Production through redeployment and external recruitment.

The Group’s production forecast for 2005 to 2006 remains in the range of 3.5 to 3.8 million boe a day. After that the Group expects production to grow and reach between 3.8 and 4.0 million boe a day by 2009. The Group’s longer term production aspiration is some 4.5 to 5.0 million boe a day by 2014.

Divestments will be made in areas where the Group sees little growth potential or strategic fit. The Group expects to deliver around $5 billion of upstream divestments and swaps between 2004 and 2006. Following the successful divestments of 2004, more emphasis will be given to swaps. Focused acquisitions will be considered, especially those which provide price and exploration upside, which fit the strategic themes the Group targets and where the Group can see clear scope for long term value growth.

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2003 compared to 2002

Hydrocarbon prices were generally higher in 2003 compared with 2002, as a result of the conflict in Iraq, OPEC behaviour, lower inventories worldwide and cold weather in Europe and North America. In 2003, the Group’s realised oil prices for the world outside the USA averaged $27.54 a barrel compared with $23.68 in 2002, while US realised oil prices averaged $27.24 a barrel compared with $22.72 in 2002. US realised gas prices averaged $5.61 per thousand standard cubic feet in 2003 compared with $3.31 in 2002. Outside the USA, realised gas prices averaged $2.71 per thousand standard cubic feet in 2003, representing a 26% increase from the 2002 price of $2.15 per thousand standard cubic feet. Overall, levels of realised crude oil and gas prices in 2003 increased segment earnings (after taxes) by approximately $3.5 billion compared to 2002.

Partially offsetting the favourable impact of hydrocarbon prices on earnings was a decline of 1% in hydrocarbon production to 3.9 million barrels of oil equivalent per day (boe/d)⁷.

Oil production, (excluding oil sands production) decreased by 1% to 2.3 million boe/d, mainly as a result of field declines in the USA and North Sea, operational performance problems in the UK, various divestments, lower entitlements in PSC countries relating to higher oil prices and the shutdown of operations in Nigeria’s northern swamps. The shutdown in Nigeria was during disturbances between rival groups which lasted most of the year and operations were able to resume in late 2003. Operational performance problems in the UK were at the Shearwater platform and the Brent Field. Shearwater was shut down between March and June as a result of a well failure. Production ceased from the whole of the Brent Field in September following an accident on Brent Bravo. The Brent Delta restart was a few days after. Brent Bravo recommenced production on November 11 followed by Brent Alpha two days later. Brent Charlie remained shut for further repair and maintenance work into the first part of 2004. The decrease in oil production was partly offset by production from several new fields, mainly in Nigeria (EA), Brazil (Bijupirá-Salema), the UK and the USA; higher OPEC quotas (Nigeria and Abu Dhabi); and an additional quarter of production from ex-Enterprise Oil assets.

Natural gas production decreased by 5% to 1.5 million boe/d as a result of field declines in the USA, various divestments and lower entitlements due to the effect of higher gas prices in PSC countries. In addition there was a reduction in economic entitlement to gas production from certain properties in the Middle East. These were partly offset by higher production for LNG, higher demand due to colder weather in northwest Europe and new fields in Pakistan and the USA.

During 2003, production of synthetic crude oil commenced from the Athabasca Oil Sands Project, which added 46,000 boe/d to overall hydrocarbon production, with 78,000 boe/d in the fourth quarter.

The cost of production start-up in new growth areas, mainly the oil sands in Canada, and restructuring costs related to the implementation of a new global business operating model adopted at the end of the year, led to higher operating expenses in 2003. Costs were also negatively impacted by the decline of the US dollar against the euro, sterling and other currencies.

Results in 2003 reflected asset impairments of $508 million, mainly in the UK and South America (primarily as a result of lower production outlooks for these areas) and the write-off of various exploration properties of some $300 million, primarily in Ireland and Brazil. In both of these countries, new information from 2003 exploratory work confirmed lower than expected volume projections.

Capital investment and portfolio actions

The largest proportion of investment in 2003 was made in maintaining and developing the heartlands. These are areas where we already have a strong presence and where we saw ongoing opportunities for growth. They include North America, northwest Europe, Nigeria, Oman, Malaysia, Brunei and Australia. Developments included the new EA field in Nigeria, which came on stream in 2003, and two major agreements in the North Sea to bring Norwegian gas to the UK.

2003 also saw the development of a number of significant projects which are expected to deliver long-term value to the Group. The Athabasca Oil Sands Project achieved fully-integrated operations in 2003, which marked a key step in developing unconventional resources. The project continued to increase production throughout the year and when operating at full capacity, is expected to add some 4% to our global oil production. Agreement was reached to create the first world-scale Gas to Liquids plant in Qatar, establishing a presence in a new market. The Group’s leading position in LNG was maintained through a range of investments in Nigeria, Oman, Malaysia and Australia, as well as a commitment to the Sakhalin II project in the far east of Russia. Investment in deepwater projects

6	Includes oil sands.

7	For this purpose, the Group has converted natural gas to crude oil equivalent using a factor of 5,800 standard cubic feet per barrel.

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continued, with key projects in the Na Kika field in the Gulf of Mexico, Bonga in Nigeria and Bijupirá-Salema in Brazil. An additional commitment was made in Russia with the $1 billion project (Group interest 50%) to develop the Salym field in western Siberia.

Licence extensions were secured in Denmark, Brunei and Malaysia during the year, confirming our long-term commitment to these areas. In Saudi Arabia we signed an agreement to lead a group of companies to explore for natural gas in the South Rub Al Khali (Empty Quarter). The exploration work programme will start in the short term, and if successful, will be followed by investments that take into account the size of the commercial discovery.

We continued to achieve exploration and appraisal successes in the Gulf of Mexico, although the overall track record there continues to be mixed. Further significant new discoveries were made in Nigeria, Malaysia and Angola. A final investment decision was taken for the Kashagan project in Kazakhstan in the first quarter of 2004.

During 2003 we sold mature Exploration & Production assets in the USA (Michigan and the Gulf of Mexico shallow water). In the UK, a number of assets from the former Enterprise Oil portfolio were sold. In 2003, the total production impact of these divestments was about 21,000 boe/d on an annual basis. Overall proceeds (after-tax) of total divestments amounted to some $1 billion. During the first quarter of 2004 the divestments of the upstream assets in Thailand and various UK upstream assets were completed. In April 2004, an agreement was reached for the sale of the Group’s 50% interest in offshore Block 18 in Angola. Divestments of non-strategic assets are expected to continue as a means of improving returns on the portfolio.

Reserves

During 2003, net additions to proved developed and undeveloped reserves by Group companies (calculated before production) totalled 610 million boe (a reduction of 10 million barrels of oil and natural gas liquids and an addition of 3,595 thousand million standard cubic feet of natural gas). The net addition consisted of reductions of 548 million boe from revisions and 151 million boe from acquisitions and divestments and additions of 132 million boe from improved recovery, 1,177 million boe from extensions and discoveries. There was a net addition of 863 million boe to proved developed reserves and a net reduction of 253 million boe to proved undeveloped reserves.

During the same period, the Group’s share of net additions to proved reserves by associated companies was 58 million boe (35 million barrels of oil and natural gas liquids and 128 thousand million standard cubic feet of natural gas). The net addition consisted of a reduction of 117 million boe from acquisitions and divestments and additions of 63 million boe from revisions, 15 million boe from improved recovery and 97 million boe from extensions and discoveries. There was a net addition of 144 million boe to proved developed reserves and a net reduction of 86 million boe to proved undeveloped reserves.

At December 31, 2003, after taking account of Group companies’ 2003 net additions to proved developed and undeveloped reserves of 610 million boe and production of 1,277 million boe, total proved reserves for Group companies of 11,625 million boe was 5% lower than at December 31, 2002. At the same date, after taking into account the Group’s share of associated companies’ net additions of 58 million boe and production of 131 million boe, the Group’s share of total proved developed and undeveloped reserves of associated companies of 1,355 million boe was 5% lower than December 31, 2002.

For the three years ended December 31, 2003, Group companies had net additions to proved reserves of 3,000 million boe and total production of 3,817 million boe, which resulted in a 7% decline in total proved reserves from December 31, 2000 to December 31, 2003. For the same period, the Group’s share of net additions to proved reserves by associated companies was 328 million boe and the Group’s shares of production by these companies was 404 million boe, which resulted in a 5% decline in the Group’s share of proved reserves of associated companies.

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As at December 31, 2003, the Group’s proved developed and undeveloped reserves (excluding proved reserves of associated companies) were equivalent to 9.1 years of production.

During 2002, a total of 1,016 million boe was added to proved developed and undeveloped reserves by Group companies (950 million barrels of oil and natural gas liquids and 384 thousand million standard cubic feet of natural gas), including 450 million boe from organic activities (which includes all activities other than purchases and sales of minerals in place). During the same period, the Group share of proved developed and undeveloped reserve additions by associated companies was 379 million boe (287 million barrels of oil and natural gas liquids and 534 thousand million standard cubic feet of natural gas). The most significant 2002 organic addition arose from taking the final investment decision for Plutonia, Angola. This field was subsequently divested in 2004. In addition, reserves additions were made in the UK, Norway, Italy, Brazil and Russia as a result of the purchase of Enterprise Oil in the UK. The Russian assets were subsequently divested in 2003. Production of the ex-Enterprise Oil assets in Brazil commenced during 2003. The rest of the reserves additions during 2002 are expected to be produced over time as development activities continue and/ or production facilities are expanded or upgraded.

During 2002, net additions to proved developed and undeveloped reserves by Group companies (calculated before production) totalled 1,016 million boe (an addition of 950 million barrels of oil and natural gas liquids and 384 thousand million standard cubic feet of natural gas). The net addition consisted of reductions of 8 million boe from revisions and additions of 147 million boe from improved recovery, 311 million boe from extensions and discoveries and 566 million boe from acquisitions and divestments. There was a net addition of 1,194 million boe to proved developed reserves and a net reduction of 178 million boe to proved undeveloped reserves.

During the same period, the Group’s share of net additions to proved reserves by associated companies was 379 million boe (287 million barrels of oil and natural gas liquids and 534 thousand million standard cubic feet of natural gas). The net addition consisted of 197 million boe from revisions, 5 million boe from improved recovery, 57 million boe from extensions and discoveries and 120 million boe from acquisitions and divestments. There was a net addition of 185 million boe to proved developed reserves and a net addition of 194 million boe to proved undeveloped reserves.

At December 31, 2002, after taking account of Group companies’ 2002 net additions to proved developed and undeveloped reserves of 1016 million boe and production of 1,312 million boe, total proved reserves for Group companies of 12,292 million boe was 2% lower than at December 31, 2001. At the same date, after taking into account the Group’s share of associated companies’ net additions of 379 million boe and production of 133 million boe, the Group’s share of total proved developed and undeveloped reserves of associated companies of 1,428 million boe was 21% higher than December 31, 2001.

For the three years ended December 31, 2002, Group companies had net additions to proved reserves of 3035 million boe and total production of 3,733 million boe, which resulted in a 5% decline in total proved reserves from December 31, 1999 to December 31, 2002. For the same period, the Group’s share of net additions to proved reserves by associated companies was 174 million boe and the Group’s shares of production by these companies was 418 million boe, which resulted in a 15% decline in the Group’s share of proved reserves of associated companies.

As at December 31, 2002, the Group’s proved developed and undeveloped reserves (excluding proved reserves of associated companies) were equivalent to 9.4 years of production.

Gas & Power

Earnings (US GAAP)						$ million
						2003				2002
		2004				As reclassifieda				As reclassifieda
Net proceeds (including inter-segment sales)			10,814				8,227				4,874
Purchases (including change in inventories)			(8,700	)			(6,460	)			(3,754	)
Depreciation			(263	)			(116	)			(116	)
Operating expenses			(1,520	)			(1,141	)			(915	)
Operating profit of Group companies			331				510				89
Group share of operating profit of associated companies			1,384				871				729
Operating profit			1,715				1,381				818
Other income/(expense)			783				1,343				124
Taxation			(429	)			(454	)			(195	)
Income from continuing operations			2,069				2,270				747
Income from discontinued operations, net of tax			86				19				27
Segment earnings			2,155				2,289				774

a	See Note 2 to the Group Financial Statements.

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2004 compared to 2003

Total sales volume (Group share) for the year increased by 9% to a record 10.15 million tonnes. This increase reflected the start of production from the fourth train in the North West Shelf Venture in Australia (Group interest 22%), increased production from the Malaysia Tiga project (Group interest 15%) and the effect of a full year’s production from the third train of Nigeria LNG (Group interest 26%).

Capital investment and portfolio actions

The final investment decision was taken on Nigeria LNG Train 6 (Group interest 26%) which is expected to start production in 2007 with a capacity of 4mtpa of LNG and 1mtpa of natural gas liquids. This will give Nigeria LNG a total capacity of 22mtpa of LNG and 5mtpa of natural gas liquids.

In Australia, train 4 of the North West Shelf Venture started production, giving the venture a capacity of 12mtpa of LNG and 5mtpa of natural gas liquids.

Progress was made in LNG marketing during 2004. New long-term contracts were signed for the Australian North West Shelf Venture to supply 0.6mtpa of LNG to the Chubu Electric Company of Japan and 0.5mtpa to the Kansai Electric Power Company from 2009. An agreement was also reached to supply 3.5mtpa for 25 years to China’s first LNG terminal in Guangdong. The Malaysia Tiga LNG project signed an agreement to supply 2.8mtpa to Kogas in Korea between 2005 and 2008.

Sakhalin Energy (Group interest 55%) finalised a number of agreements to supply LNG from the Sakhalin II project. A total of 5mtpa has now been sold under long-term contracts, including contracts to supply Japanese customers: Toho Gas (up to 0.3mtpa for 20 years); Tokyo Electric (1.5mtpa over 22 years); and Kyushu Electric Power Company (0.5mtpa over 20 years). In a pioneering agreement Shell Eastern Trading Ltd agreed to buy 37 million tonnes of LNG from Sakhalin over a 20 year period to supply a new import terminal in Baja California, Mexico. This will be the first time that Russian natural gas will be sold into the North American market.

Shell signed an agreement for 50% of the capacity of a new LNG import terminal in Baja California, Mexico. The terminal is designed to have a capacity of 7.5mtpa and is expected to be operational from 2008. The capacity will be used to supply LNG from Sakhalin and other Shell projects to the Mexican and US natural gas markets. Shell also leads a joint venture (Group interest 50%) that is building a 3.3mtpa LNG import terminal on Mexico’s east coast at Altamira (Group capacity 75%).

Another Shell joint venture announced plans to develop a 7.5mtpa offshore LNG import terminal in the Long Island Sound in the USA (Group capacity 100%). If regulatory approval is given, the terminal, called Broadwater Energy, could start operation in 2010. Permits for the Gulf Landing offshore LNG import terminal in the Gulf of Mexico were received in early 2005 and the Hazira terminal in India is on target to receive its first cargo in 2005.

Shell also acquired an 11% indirect interest in the Qalhat LNG project in Oman with a total capacity of 3.3mtpa. First deliveries are expected in 2006.

An integrated development and production sharing agreement was signed between Shell and Qatar Petroleum to develop the Pearl GTL plant at Ras Laffan in Qatar, for which a final investment decision is expected to be taken in 2006. When fully operational, the plant will have the capacity to produce 140,000 barrels per day of GTL products including transport fuels. The fuels can be used in conventional diesel engines and produce very low emissions and therefore have the potential to reduce pollution in major cities. A number of GTL Fuel trials were carried out in London, California and Shanghai.

We sold a number of our assets in 2004 with a net divestment gain of $772 million, including interests in Distrigas SA and Fluxys SA in Belgium, Verbundnetz Gas and Avalon AG in Germany and, in the USA, Tenaska Gateway Partners Ltd, part of our holding in Enterprise Products Partners L.P., and the majority of our gas transmission business in the Gulf of Mexico. InterGen (Group interest 68%) reduced its interests in a number of power plants across the world. In November 2004, we announced a Heads of Agreement for restructuring the ownership in Nederlandse Gasunie, under which the Group’s interest in Gasunie’s gas transportation business will be transferred to the Dutch state. On completion of this transaction, expected in mid-2005 pending government approval, the Dutch state will make a total net payment of €2.78 billion (Group share 50%).

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Outlook and strategy

Gas & Power’s strategy is to maintain its leadership position in the industry by accessing and creating value from new natural gas resources. Over the past five years Shell associate projects have delivered eight new LNG trains overall. The Group has delivered an average of 13% growth per annum in the LNG volumes sold from 1999 to 2004.

The Group intends to invest selectively in power generation assets that help it deliver value from Shell gas positions. The Group expects that its investment in Gas to Liquids (GTL) will open up new markets for natural gas and the planned Pearl GTL project in Qatar has the potential to deliver considerable value.

The Group’s investment decisions will be made in an integrated way that allows the Group to optimise its presence throughout the gas value chain. Examples of this approach include the Nigeria LNG plant expansions, partially enabled as a result of the Group’s success in gaining access to the key North American LNG market. The Sakhalin project similarly benefits from the Group’s ability to secure customers both in the traditional Asian markets and in North America through our Baja California terminal capacity.

The Group intends to increase capital investment in Gas & Power over the coming years. The Group expects its equity share of LNG capacity to increase by an average of 14% per year from 2003 through 2008. This increase is expected to come from projects already under construction including in Oman, Nigeria and Sakhalin. The Group also believes there will be significant potential for further growth from additional expansions and new facilities beyond this period.

2003 compared to 2002

Marketing and trading results in North America improved due to a stronger trading performance than in 2002. Additionally, gains from a number of other asset sales and an accounting adjustment (to reverse mark to market accounting due to bringing tolling agreements on to the balance sheet) were partially offset by impairments of $315 million. These impairments related to the carrying amount of InterGen (an associated company, Group interest 68%) due to poor power market conditions, mainly in the US merchant power segment, and to the Cuiaba power assets in South America (Group interest 50%) in light of a reappraisal of the commercial outlook. Net proceeds and purchases were higher in 2003 compared with 2002 due to higher trading volumes and gas prices.

Capital investment and portfolio actions

The agreement to develop the Sakhalin II project in Russia, and the commercial agreement for the Gas to Liquids (GTL) project in Qatar, were the key developments in the Gas & Power business during 2003.

A range of other developments during the year supported the continued growth in our LNG business. In North America, where industry-wide indigenous gas supplies are struggling to meet demand, there was a growing market for imported LNG. Access was gained to the East Coast gas market as a result of the reopening of the Cove Point LNG import terminal in Maryland, USA, where we have one-third of the capacity. In addition we won a tender to deliver gas through a receiving terminal at Altamira for the power market in Mexico; the Group interest in this project was reduced to 75% in the first quarter of 2004. The Group also announced a joint project (50% output contracted) which plans to construct an LNG receiving terminal at Baja California, Mexico to supply Mexico and the USA. The Group aims to supply this terminal with LNG from associate projects in Asia Pacific, including the Sakhalin II project and Gorgon (Group interest 29%) in Western Australia. The Group also announced plans to build a new offshore LNG import terminal in the Gulf of Mexico, which will have the capacity to deliver one billion cubic feet of natural gas per day into the US pipeline network.

The Group further strengthened its leadership position in LNG with growth in equity capacity, through expanding associate LNG facilities in Nigeria (Group interest 26%) and Malaysia (Group interest 15%). LNG sales contracts were signed by Malaysian LNG Tiga (Group interest 15%) to supply up to two million tonnes per year to Korea, and by Nigeria LNG to supply 3.6 million tonnes per year

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to the USA and Europe from trains 4 and 5. In support of growing LNG supply and trading activities, the Group took delivery of a further new LNG vessel, bringing the total number to five at the end of 2003 with a sixth vessel delivered in the first quarter of 2004. Following the end of the original 20-year joint venture agreement, Shell exited the Malaysia LNG Satu company. Shell continues to hold a 15% stake in each of Malaysia LNG Dua and Malaysia LNG Tiga. In Oman, Shell committed to participation in the new Qalhat LNG train under construction at the Oman LNG plant.

InterGen (an associated company, Group interest 68%) completed six further power plants in Australia, Mexico, Turkey and the USA and also announced dilution of its interests in projects in Australia, Turkey and the USA. Overall the total generating capacity at the end of 2003 was 10.5GW (InterGen net equity interest).

In Europe, restructuring of Group operations continued with the establishment of Shell Energy Europe, which is designed to grow the Group’s pan-European transport, marketing and trading gas business. The Group also sold its indirect interests in Ruhrgas, its direct interest in Thyssengas and interests in other gas transport companies in Germany.

Oil Products

Earnings (US GAAP)						$ millions
						2003				2002
		2004				As reclassifieda				As reclassifieda
Net proceeds (including inter-segment sales)			218,930				162,491				135,761
Purchases (including change in inventories)			(192,802	)			(142,432	)			(118,446	)
Gross margin			26,128				20,059				17,315
Depreciation			(3,056	)			(2,717	)			(2,262	)
Operating expenses			(15,920	)			(14,167	)			(12,044	)
Operating profit of Group companies			7,152				3,175				3,009
Group share of operating profit of associated companies			1,749				910				554
Operating profit			8,901				4,085				3,563
Other income/(expense)			71				(62	)			(57	)
Taxation			(2,691	)			(1,202	)			(1,021	)
Income from continuing operations			6,281				2,821				2,485
Income from discontinued operations, net of tax			1,256				39				142
Segment earnings			7,537				2,860				2,627

a	See Note 2 to the Group Financial Statements.

2004 compared to 2003

Earnings from discontinued operations in 2004 were $1,256 million. This included net gains of $881 million relating to divestments in Latin America, Europe, and the USA, in line with the Group’s strategy of increasing profitability through greater focus on core assets.

Gross margin (calculated as net proceeds minus purchases) increased by $6,069 million, primarily driven by strong refining margins in all regions. Marketing margins increased outside of the USA while within the USA margins declined. Higher refining margins were a result of exceptional demand for oil products in the USA and China, lower oil stocks in the USA and lower refinery availability in the Atlantic basin. The disruption caused to supplies by hurricanes in the Gulf of Mexico also affected prices during the autumn.

Operating expenses were $1,753 million higher in 2004, an increase of 12.4% over 2003. Approximately 90% of the increase in operating expenses was related to businesses outside the USA. Higher operating expenses were offset by strong margins. Operating expenses as a percentage of gross margin, decreased from 71% in 2003, to 61% in 2004. The weakening US dollar contributed 59% of the increase in operating expenses since a large percentage of Oil Products operating expense is incurred outside the USA. The remainder of the increase in operating expenses reflects higher costs associated with refinery maintenance activity, portfolio restructuring, pension funding and provisions for environmental and legal settlements. Increased divestment gains largely offset these higher operating cost.

There was increased income from associated companies of $839 million due to higher refining margins in all regions for the reasons described above.

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Depreciation in 2004 increased by $339 million compared to 2003 primarily due to higher impairment provisions on certain refining and marketing assets. The impairment of the refining assets mainly reflects expected weak local market conditions and prices for the refineries product slates. The marketing assets are held for sale and were written down to expected net realisable value.

Potential risks to future earnings centre around the level of refining and marketing margins. Earnings will also be impacted by the level of refinery availability.

Capital investment and portfolio actions

An agreement was reached with Sinopec to build a network of 500 service stations in Jiangsu province in China. The joint venture will provide an initial investment of about $200 million and expects the network to be operational within three years. Other developments in the Asian markets included the award of a licence to conduct downstream fuels business activities in Indonesia and the construction of Shell’s first retail station in India.

The rebranding of the retail network in USA and Europe continued. In the USA, more than 12,000 sites have either been rebranded from Texaco to Shell or upgraded to the new Shell image and style. Shell is the leading brand of gasoline in the USA, having a greater market share and higher volume of sales than any other brand.

Work continued to extend our presence in the premium fuels market including the launch of V-Power in the USA, which is now the best selling premium gasoline in the USA. A V-Power diesel blend, with a Gas to Liquids component, was successfully launched in Germany and the Netherlands.

In line with the Group’s strategy of restructuring its portfolio and focussing on selected markets, several divestments were made. The sale of the retail and commercial assets in Portugal and of the assets onshore in Spain were completed. In the first quarter of 2005 the Group completed the sale of the offshore assets in Spain. The Group will continue to operate in Spain through its LPG, Lubricants, Aviation and Marine business. A portion of the Group’s ownership of Showa Shell in Japan was sold, reducing the Group’s interest from 50% to approximately 40%. The sale of the Group’s interest in the Rayong refinery in Thailand was completed. The Delaware City refinery and the Great Plains and Midwest product pipelines in the USA were sold. The Group announced that it was considering options for the LPG business including the possibility of a sale.

Outlook and strategy

A key element in the strategy is the creation of one downstream organisation that integrates the Oil Products and Chemicals businesses. The Group believes this will help to optimise our refining and chemicals facilities, standardise its processes and improve services to customers. At the same time, work will continue over the next two years to sell or improve underperforming assets. This will be underpinned by a focus on improving operational performance and delivering cost reductions.

The Group intends to continue to improve its delivery to customers through more streamlined business processes for ordering, pricing and payment. The Group will also look to build on the success of differentiated fuels. These fuels have been an important driver of value in the business, with differentiated fuels, such as V-Power, now available in more than 40 markets around the world.

The Group believes the downstream integration will provide a platform for future growth in selected markets where we see the greatest opportunities. In particular, the Group intends to focus on Asian markets where there is significant potential for growth. By the end of the decade the Group expects to significantly increase its capital employed in Asia.

2003 compared to 2002

Gross margin (calculated as net proceeds minus purchases) increased by $2,744 million, driven primarily by increasing refining and marketing margins in all regions. Higher refining margins resulted from a number of exceptional and non-sustainable events with global impact. These included disruptions to supply from Venezuela, an extended Japanese nuclear power generator shutdown and widespread refinery disruptions in the USA resulting from the August power blackout. This contrasted with an environment in 2002 when industry refining margins were at 10-year lows. Marketing margins in 2003 benefited early in the year from the decline in crude prices following

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the conflict in Iraq and throughout the year from the weakening of the US dollar. Oil products’ specification changes in the USA may impact overall supply and demand balances, resulting in an uncertain margin outlook for 2004.

Increased operating expenses of $2,123 million negatively impacted 2003 earnings. Approximately 75% of this increase was related to businesses outside the USA. This represents an increase in operating expenses as a percentage of gross margin from 70% in 2002, to 71% in 2003. The weakening US dollar contributed almost 50% of this increase, as a large percentage of Oil Products’ operating expenses is incurred outside the USA. The remainder of the increase reflects higher costs associated with refinery maintenance activity, portfolio restructuring, pension funding and provisions for environmental and legal settlements.

There was increased income from associated companies of $356 million predominantly in the USA from the Group’s share of Motiva Enterprises. A 75% increase in US Gulf Coast refining margins and a 2 percentage point improvement in refining utilisation in the USA contributed to the increase in earnings.

Depreciation in 2003 increased over 2002 by $455 million, due primarily to portfolio actions taken during the year. Charges were higher partly due to the decision taken to close the Bakersfield refinery in the USA as a result of declining local crude supply ($213 million). Additionally, depreciation charges increased due to the full-year consolidation of Pennzoil-Quaker State (acquired in the fourth quarter, 2002).

Capital investment and portfolio actions

In 2003 further progress was made on integrating assets from the 2002 PQS acquisition with savings delivered through the closure of seven lube-oil-blend plants and two base oil plants, and the reduction in personnel of over 900 by the end of 2003. Similar progress was made in connection with the Texaco downstream assets in the USA. At the end of 2003, over 4,200 sites had been rebranded from Texaco to Shell and personnel levels were reduced by over 2,000 as business structures have been simplified. In Germany, assets from the 2002 acquisition of DEA were fully integrated into the Group’s business in this key market, with over 600 retail sites rebranded to Shell by the end of 2003.

Also in 2003, and providing further support to the strength of our marketing businesses, the Group announced an expansion of our relationship with Sainsbury’s in the UK to provide joint fuel and convenience retailing at 100 Shell sites. In Australia, the Group reached an agreement with retailer Coles Myer to operate Shell retail sites across the country providing improved service and choice for customers. Under the Group’s differentiated fuels strategy, premium fuels continued to be launched in key markets, including V-Power in Germany.

The Group continued to actively manage our portfolio resulting in the sale of a range of assets, including several non-strategic onshore crude pipelines in the USA and the liquefied petroleum gas (LPG) business in Brazil. In 2003, the Group completed the sale of our interest in the Excel Paralubes base oil plant and sold a number of retail sites in Germany in order to meet the regulatory requirements for the DEA acquisition. Shell Gas Italia announced the planned sale of its non-automotive LPG interests to Liquigas. The Group also announced its intention to sell AB Svenska Shell in Sweden. In 2004, the Group determined not to pursue sale of AB Svenska Shell.

Chemicals

Earnings (US GAAP)						$ million
		2004				2003				2002
Net proceeds (including inter-segment sales)			29,497				20,817				15,207
Purchases (including change in inventories)			(24,363	)			(16,952	)			(12,035	)
Depreciation			(544	)			(678	)			(401	)
Other cost of sales			(2,452	)			(2,234	)			(1,518	)
Operating expenses			(893	)			(1,065	)			(815	)
Operating profit of Group companies			1,245				(112	)			438
Group share of operating profit of associated companies			94				(165	)			213
Operating profit			1,339				(277	)			651
Other income/(expense)			(15	)			(43	)			(13	)
Taxation			(394	)			111				(73	)
Segment earnings			930				(209	)			565

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2004 compared to 2003

The improvement in earnings this year was attributable to improved industry conditions leading to higher operating rates and more favourable margins. Sales volumes of chemical products increased by 5% reflecting higher demand and additional capacity. Asset utilisation was 3% higher on average, reflecting higher operating rates in the second and third quarter of 2004, although in both the first and the fourth quarter cracker availability in Europe and in the USA was reduced by both planned and unplanned downtime. The improvement in operating rates was driven primarily by the recovery in the petrochemicals industry which led to strong demand growth. The more favourable margins (defined as proceeds less cost of feedstock, energy and distribution per tonne of product sold) were mainly due to a 35% increase in unit proceeds from higher price realisations, which outweighed the increased cost of chemical feed stocks.

The impairment of Basell followed the announcement in 2004 of a review of strategic alternatives regarding this joint venture, and the reduction of the carrying amount of the Group’s investment in Basell at December 31, 2004 to its currently expected net realisable value.

Capital investment and portfolio actions

The Group continued to finance the ongoing construction at the Nanhai petrochemicals plant in southern China (Group interest 50%). The project is on schedule to be commissioned towards the end of 2005. The Group also announced the next phase in the development of its chemicals facilities in Singapore involving detailed design and engineering work. Subject to the final investment decision, the project will include modifications and additions to the existing Bukom refinery and a new world-scale ethylene cracker.

In North America, production started at two joint venture manufacturing facilities. PTT PolyCanada started production of Corterra, a product used in the manufacture of textiles and carpets. The production of butadiene, used in the manufacture of rubber and plastics products, started at the Sabina Petrochemicals plant in the USA. The cracker expansion at Deer Park in Texas, which added 550,000 tonnes of ethylene capacity to the existing plant, became operational at the end of the first quarter of 2004. In the Netherlands, a new ethylene oxide reactor began operations and the ethylene glycol plant was expanded, increasing production by over 20%.

Shell and BASF announced the review of strategic options for the Basell joint venture. Options being considered include the sale of the companies’ stakes or an equity market transaction. The global catalyst regeneration business was divested and operations at CS Metals ceased.

Outlook and strategy

Asia and in particular China continues to be one of the strongest drivers of petrochemical demand growth. Over the next two years, the petrochemicals industry in China will see production commence at three large new petrochemicals plants, including Shell’s Nanhai project. In the Middle East, the petrochemicals industry has a number of new investments that are being developed and that are expected to start production towards the end of the decade.

We will continue to focus on our cracker and first-line derivatives portfolio and delivering bulk petrochemicals to large industrial customers. The integration of the Oil Products and Chemicals businesses is expected to provide further opportunities to achieve cost efficiencies from shared services and common manufacturing sites, and from improved use of hydrocarbon resources on integrated sites. In the short term, our strategic priorities will be the successful completion and start-up of the Nanhai petrochemicals complex, and the strengthening of our asset base in North America and Europe. In the medium term, we continue to develop further growth options to shift our portfolio towards growth markets.

2003 compared to 2002

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relating to environmental and litigation provisions and a loss on the sale of a minority interest in a divested business, which was partly offset by various tax credits.

The impairments reflect changes in the assessment of future returns relative to the value of our assets. The impairment of our equity investment in the Basell joint venture reflected a reassessment of the outlook for the business. The factors contributing to this reassessment were the continued vulnerability of the business to weak economic conditions and anticipated changes in the industry and competitive landscape. In Catalysts, the Group streamlined the business portfolio to focus on high-performance catalysts and took an asset impairment in CS Metals, as anticipated benefits from a prototype technology did not meet performance expectations.

Earnings for 2002 included $62 million of charges for asset rationalisation, mainly related to plant closures. Earnings benefited from a tax credit of $102 million associated with the reassessment of the Group’s ability to utilise prior year tax losses upon the formation of Shell Chemicals Europe B.V.

Setting aside the effects of the factors described above, earnings in 2003 were $185 million lower. Sales volumes, including traded products, increased by 19% from a year ago benefiting from capacity additions and volumes from new units. However, there was a decline in overall Chemicals unit margins (defined as proceeds less cost of feedstock energy and distribution per tonne of product sold). This was due to high and volatile feedstock and energy costs and surplus capacity, particularly in the USA. Fixed costs were higher, reflecting planned increases in capacity and higher than normal asset maintenance activity, project expenses, increased costs for benefits including pensions, as well as the adverse impact of the weaker US dollar.

Capital investment and portfolio actions

Investment was primarily in ongoing projects, including those related to regulatory compliance, maintenance and upgrading of existing facilities. There was also investment to finance the ongoing construction of the Nanhai petrochemicals complex in China. Initial milestones were met with the completion of project financing and the start of construction of the Nanhai plant. The new polymer polyols plant at Pernis in the Netherlands marked the latest step in a long-term strategy to strengthen the Group’s position as a supplier to manufacturers of polyurethane foams. In the Gulf Coast region of the USA, the Group completed a project to improve the quality of heavy olefin feed.

The Group invested to upgrade and improve existing plants to ensure their ongoing efficiency and competitiveness. The Group made significant progress in improving and expanding cracker capacity in Texas, which became operational at the end of the first quarter of 2004. Improvements include upgrading existing equipment with new control systems and nitrogen oxide reduction technology. The Group also began work to upgrade the Aubette steam cracker at the Berre complex in the south of France to improve integration with the adjacent refinery and reduce sulphur dioxide emissions.

The Group continued to actively manage our portfolio with ongoing reviews of plant viability and the closure or mothballing of under-performing assets. Operations ceased at the Bayer-Shell Isocyanates joint venture. The charges associated with closures and the asset restructurings and impairments described above adversely impacted our current year earnings but the overall effect on returns over time is expected to be positive.

Other industry segments and corporate

Earnings (US GAAP)		$ millions
										2003								2002
		2004								As reclassifieda								As reclassifieda
		Other								Other								Other
		industry								industry								industry
		segments				Corporate				segments				Corporate				segments				Corporate
Income from continuing operations			(141	)			(847	)			(267	)			(819	)			(110	)			(684	)
Income from discontinued operations, net of tax			–				(52	)			–				(98	)			–				(67	)
Segment earnings			(141	)			(899	)			(267	)			(917	)			(110	)			(751	)

a	See Note 2 to the Group Financial Statements

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2004 compared to 2003

Corporate is a non-operating segment consisting primarily of interest expense on Group debt and certain other non-allocated costs of the Group. Corporate net costs were $899 million compared with $917 million in 2003.

Renewables

Shell Solar was also the system supplier and prime construction contractor for the world’s largest grid-connected Solar PV power plant, comprising of 33,500 modules, with an output of 5 megawatts. The power generated from this solar park is sufficient to meet the electricity demand of about 1,800 households.

The Wind business in the USA saw the Colorado Green and Brazos wind parks coming into full production. The White Deer wind park was put into a joint venture with Entergy, and shareholdings in the Whitewater Hill, Cabazon Pass and Rock Rover assets were sold, as had been previously planned. Wind production was affected by lower than expected wind speeds and lower availability mainly due to transmission upgrading at Whitewater Hill and Cabazon Pass.

Shell Hydrogen continued to work with governments and vehicle manufacturers to develop projects to support the viability of hydrogen as a transport fuel. These included the opening of an integrated hydrogen station in Washington DC and the launch of the hydrogen “lighthouse project” concept. These are large-scale demonstration projects to create mini-networks of hydrogen fuelling stations in specific cities or regions, the first of which will be developed in New York jointly with General Motors.

2003 compared to 2002

The sale of the main forestry operations was completed in 2003.

In Corporate, the loss of $917 million in 2003 compares with a loss of $751 million in 2002. This increase was due to higher net difference in exchange effects on financing arrangements and increased interest charges due to higher average debt, partly offset by net tax credits.

Liquidity and capital resources

2004 compared to 2003

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Outlook

Because the contribution of Exploration & Production to earnings is larger than the Group’s other businesses, changes affecting Exploration & Production, particularly changes in realised crude oil and natural gas prices and production levels, have a significant impact on the overall Group results. While Exploration & Production benefits from higher realised crude oil and natural gas prices, the extent of such benefit (and the extent of a detriment from a decline in these prices) is dependent on the extent to which the prices of individual types of crude oil follow the Brent benchmark, the dynamics of production sharing contracts, the existence of agreements with governments or national oil companies that have limited sensitivity to crude oil price, tax impacts, the extent to which changes in crude oil price flow through into operating costs and the impacts of natural gas prices. Therefore, changes in benchmark prices for crude oil and natural gas only provide a broad indicator of changes in the earnings experienced in any particular period by Exploration & Production.

In Oil Products, our second largest business, changes in any one of a range of factors derived from either within or beyond the industry can influence margins in the short or long term. The precise impact of any such change at a given point in time is dependent upon other prevailing conditions and the elasticity of the oil markets. For example, a sudden decrease in crude oil and/or natural gas prices would in the very short term lead to an increase in combined refining and marketing margins until responding downward price corrections materialise in the international oil products markets. The converse arises for sudden crude or natural gas price increases. The duration and impact of these dynamics is in turn a function of a number of factors determining the market response, including whether a change in crude price affects all crude types or only a specific grade, regional and global crude oil and refined products stocks, and the collective speed of response of the industry refiners and product marketers to adjust their operations. It should be noted that commonly agreed benchmarks for refinery and marketing margins do not exist in the way that Brent crude oil prices and Henry Hub natural gas prices in the USA serve as benchmarks in the Exploration & Production business.

In the longer term, reserve replacement will affect the ability of the Group to continue to maintain or increase production levels in Exploration & Production, which in turn will affect the Group’s cash flow provided by operating activities and net income. The field decline rate for Exploration & Production’s existing business is approximately 6 to 8% per year. The Group will need to take measures to maintain or increase production levels and cash flows in future periods, which measures may include developing new fields, continuing to develop and apply new technologies and recovery processes to existing fields, and making selective focused acquisitions. The Group’s goal is to offset declines from production and increase reserve replacements. However, volume increases are subject to a variety of risks and other factors, including the uncertainties of exploration, project execution, operational interruptions, reservoir performance and regulatory changes. The Group currently expects overall production to decrease in 2005 and then to increase beginning in 2006 as additional production from new projects begins to come on stream.

The Group has a diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of Exploration & Production and the associated cash flow provided by operating activities. As a result of its financial strength and debt capacity, the risk associated with delay or failure of any single project would not have a significant impact on the Group’s liquidity or ability to generate sufficient cash flows for operations and fixed commitments.

It is the Group’s intention to continue to divest and, where appropriate, make selective focused acquisitions as part of active portfolio management. However, the Group does not generally expect that the purchase and sale of assets in the normal course of business will have a significant adverse effect on cash flow provided by operating activities. The number of divestments will depend on market opportunities and are recorded as assets held for sale where appropriate.

The Group manages its portfolio of businesses to balance cash flow provided by operating activities against uses of cash over time based on conservative assumptions relating to crude oil prices relative to average historic crude oil prices. From 1984 through 2004, the Brent crude oil price has averaged around $20 a barrel, from 1994 through 2004 it averaged approximately $23 a barrel and from 1999 through 2004 the price averaged approximately $27 a barrel.

Financial condition and liquidity

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Total debt at the end of 2004 amounted to $14.4 billion and the Group’s total debt ratio¹ decreased from 21.0% in 2003 to 13.8% in 2004. The current level of the debt ratio falls below the medium-term gearing objective of the Group, which establishes a target gearing² of between 20% and 25% (inclusive of certain off-balance sheet obligations of a financing nature). The total debt outstanding (excluding capital leases) at December 31, 2004 will mature as follows: 42% in 2005, 17% in 2006, 18% in 2007, 1% in 2008 and 22% in 2009 and beyond.

The Group currently satisfies its funding requirements from the substantial cash generated within its business and through external debt. The Group’s external debt is principally financed through two commercial paper programmes, which are issued on a short-term basis (generally for up to six months), and a euro medium term note programme, each guaranteed jointly and severally by The Shell Petroleum Company Limited and Shell Petroleum N.V.. Each of the two commercial paper programmes and the medium term note programme are for up to $10 billion in value. Other than described below, these programmes do not have committed support from a bank as the Group considers the costs involved in securing such support are unnecessary given the Group’s current credit rating.

The debt programmes consist of:

	(a)	a Global Commercial Paper Programme, exempt from registration under section 3(a)(3) of the US Securities Act 1933, that assigns the use of the proceeds from the programme to the funding of ‘current transactions’ of the issuer, with maturities not exceeding 364 days;
	(b)	a section 4(2) Commercial Paper Programme which can be used to finance non-current transactions. The maximum maturity of commercial paper issued under the programme has been limited to 397 days; and
	(c)	a euro medium term note programme.

The Group expects to be able to continue to utilise these facilities in circumstances where it is not in possession of undisclosed price sensitive information which would impact the prospective purchasers of the relevant debt security. The Group will also evaluate other debt issuance options.

The Group currently maintains $2.5 billion of committed bank facilities, as well as internally-available liquidity (some $1 billion), to provide back-up coverage for commercial paper maturing within 30 days. Aside from this facility and certain borrowing in local subsidiaries, the Group does not have committed bank facilities as this is not considered to be a cost effective form of financing for the company given its size, credit rating and cash generative nature.

The maturity profile of the Group’s outstanding commercial paper is actively managed to ensure that the amount of commercial paper maturing within 30 days remains consistent with the level of supporting liquidity. The committed facilities, which are with a number of international banks, are renewed on an annual basis. The Group expects to be able to renew these facilities on commercially acceptable terms. The Group expects that commercial paper borrowings in 2005 could range up to $5.0 billion.

While the Group is subject to restrictions, such as foreign withholding taxes, on the ability of subsidiaries to transfer funds to their parent companies in the form of cash dividends, loans or advances, such restrictions are not expected to have a material impact on the ability of the Group to meet its cash obligations.

The Group is of the opinion that it has sufficient working capital for its present requirements, that is at least the next 12 months from the date of this report.

Credit ratings

Capital investment and dividends

1	The total debt ratio is defined as short-term plus long-term debt as a percentage of capital employed. Capital employed is Group net assets before deduction of minority interests, plus short-term and long-term debt.

2	Gearing is defined as the ratio of debt to capital employed (or debt/ (debt & equity))

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Exploration & Production expenditures of $9.9 billion (2003: $9.3 billion) accounted for more than half the total capital investment. Gas & Power accounted for $1.6 billion (2003: $1.5 billion). Oil Products investment amounted to $2.5 billion (2003: $2.4 billion). Chemicals investment was $0.7 billion (2003: $0.6 billion). Investment in other segments was $0.2 billion (2003: $0.4 billion).

Capital investment of some $15 billion (excluding contribution of the Group’s minority partners in Sakhalin) on average is required each year to grow the capital base in light of expected dividend payments, taking into account an expected $13 to $15 billion of divestments over the period 2004 to 2006. After dividends and capital investment, the priority for using cash generated is to maintain a prudent balance sheet. Both the medium and long-term focus will remain on improving the underlying operational performance in order to continue to deliver consistently strong cash flows.

Capital investment (excluding the contribution of the Group’s minority partners in Sakhalin) in 2005 is estimated to be $15 billion, with Exploration & Production continuing to account for the majority of this amount. The Parent Companies have announced the relaunch of their share buyback programmes, with a return of surplus cash to shareholders in 2005 in the range of $3 to $5 billion, assuming continued high oil prices. It is expected that the Group companies’ investment programme will be financed largely from internally generated funds.

The aim of the Royal Dutch/ Shell Group of Companies is to provide per share increase in dividends at least in line with inflation of the currencies of the Parent Companies’ base countries over a period of years. Upon completion of the transaction described under “— Unification Proposal”, Royal Dutch Shell will declare its dividend in euro. In setting the level of the dividend, consistent with Royal Dutch and Shell Transport’s historical dividend policy, the Royal Dutch Shell Board will seek to increase dividends at least in line with inflation over time.

Guarantees and other off-balance sheet obligations

Guarantees at December 31, 2003 were $3.4 billion (2002: $4.1 billion). At December 31, 2003, $1.8 billion were guarantees of debt of associated companies, $0.7 billion were guarantees for customs duties and other tax liabilities and $0.9 billion were other guarantees. Guarantees of debt of associated companies mainly related to InterGen ($1.2 billion) and Nanhai ($0.4 billion).

Contractual obligations

$ billion
						Within 1 year				2/3 years				4/5 years				After 5 years
		Total				(2005)				(2006/2007)				(2008/2009)				(beyond 2009)
Long-term debta			9.2				1.2				4.4				0.7				2.9
Capital leasesb			1.2				0.1				0.1				0.1				0.9
Operating leasesc			9.9				1.7				2.2				1.5				4.5
Purchase obligationsd			203.6				75.0				37.7				26.6				64.3
Other long-term contractual liabilitiese			0.9				0.2				0.4				0.1				0.2
Total			224.8				78.2				44.8				29.0				72.8

a	The total figure is comprised of $8.0 billion of long-term debt (debentures and other loans, and amounts due to banks and other credit instruments), plus $1.2 billion of long-term debt due within one year. The total figure excludes $0.7 billion of long-term capitalised lease obligations. See Note 16 to the Group Financial Statements.
b	Includes executory costs and interest. See Note 17 to the Group Financial Statements.
c	See Note 17 to the Group Financial Statements.
d	Includes any agreement to purchase goods and services that is enforceable, legally binding and specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the purchase. The amounts include $5.5 billion of purchase obligations associated with financing arrangements, which are disclosed in Note 17 to the Group Financial Statements. Raw materials and finished products account for 91% of total purchase obligations.
e	Includes all obligations included in “Long-term liabilities – Other” on the Statement of Assets and Liabilities of the Group that are contractually fixed as to timing and amount. In addition to these amounts, the Group has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans estimated to be $1.4 billion in 2005 (see Note 21 to the Group Financial Statements) and obligations associated with asset retirements (see Note 24 to the Group Financial Statements).

The table above excludes interest expense related to long-term debt estimated to be $0.4 billion in 2005, $0.7 billion in 2006/2007 and $0.6 billion in 2008/2009 (assuming interest rates with respect to variable interest rate long-term debt remain constant and there is no change in aggregate principal amount of long-term debt other than repayment at scheduled maturity as reflected in the table).

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2003 compared to 2002

Within cash flow used in investing activities ($8.3 billion), capital expenditure, acquisitions and new investments in associated companies decreased from $22.3 billion to $13.2 billion. The purchases in 2002 of Enterprise Oil, Pennzoil-Quaker State and Equilon increased the 2002 figure by $8.9 billion. The lower total cash used in investing activities also reflected an increase of $2.9 billion in proceeds from sales of assets, including the Group’s interest in Ruhrgas, to $4.5 billion.

Other Matters

The Group’s approach to internal control includes a number of general and specific risk management processes and policies. Within the essential framework provided by the Statement of General Business Principles, primary control mechanisms include strong functional leadership, adequate resourcing by competent staff, and self-appraisal processes in combination with strict accountability for results. These mechanisms are underpinned by established Group policies, standards and guidance material that relate to particular types of risk, structured investment decision processes, timely and effective reporting systems and active performance monitoring.

Examples of specific risk management mechanisms include:

–	regular review of significant risks by the Executive Committee and the Group Audit Committee;
–	a common health, safety and environment (HSE) policy, a common requirement for HSE management systems, and external certification of the environmental component of such systems for major installations;
–	a financial control handbook that establishes standards for the application of internal financial controls;
–	arrangements for the management of property, liability and treasury risks; and
–	a business control incident reporting process that enables monitoring and appropriate follow-up actions for incidents arising as a result of control breakdowns. Lessons learned from these incidents are used to improve the Group’s overall control framework.

In the context of reserves, examples of specific risk management mechanisms include:

–	oversight of the process for approving the booking of proved reserves by the Global Exploration & Production Reserves Committee (the Reserves Committee);
–	Group guidelines for booking proved reserves that conform fully with applicable SEC rules and guidance and clarify criteria for booking and de-booking proved reserves (and the distinctions between regulatory requirements and the Group’s internal reserves classifications);
–	training of reserves guidelines users;
–	responsibility on the local Chief Reservoir Engineer for ensuring that reserves bookings and de-bookings are compliant with SEC rules and that any booking and debooking decisions are only made with appropriate, auditable documentation and after completion of the appropriate challenge processes;
–	business and financial responsibility on the local Regional Technical Director and Regional Finance Manager, respectively, for the decisions of their Chief Reservoir Engineer;

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–	responsibility for booking and de-booking decisions with the Chief Financial Officer of Exploration & Production and the Director of Technology of Exploration & Production, working together with the Group Reserves Co-ordinator and the other members of the Reserves Committee;
–	approval by the Group’s Executive Committee of the reserves bookings and de-bookings taken by Exploration & Production; and
–	final review by the Group Audit Committee.

A formalised self-appraisal and assurance letter process is in place. Annually, the management of every business unit provides assurance as to the adequacy of governance arrangements, risk and internal control management, HSE management, financial controls and reporting, treasury management, brand management and information management. Country Chairs also provide assurance regarding compliance with the Statement of General Business Principles and other important topics. As part of this process business integrity concerns or instances of bribery or illegal payments are to be reported. Assurance letter results including any material qualifications are reviewed by the Group Audit Committee and support representations made to the external auditors.

In addition to these structured self-appraisals, the assurance framework relies on objective appraisals by internal audit. The results of internal audit’s risk-based reviews of Group operations provide the Group Audit Committee with an independent view regarding the effectiveness of risk and control management systems.

These established review, reporting and assurance processes enable the Conference (a meeting of the Executive and Non-Executive Directors) to regularly consider the overall effectiveness of the system of internal control and to perform a full annual review of the system’s effectiveness.

Taken together, these processes and practices provide confirmation to the Group Holding Companies that relevant policies are adopted and procedures implemented with respect to risk and control management.

As discussed below under “Controls and Procedures” the Parent Companies determined, based largely on the investigation and report to the Group Audit Committee, that there were deficiencies and material weaknesses in the internal controls relating to proved reserve bookings and disclosure controls that allowed volumes of oil and gas to be improperly booked and maintained as proved reserves, which also had an effect on the Financial Statements.

Property and liability risks

Treasury and trading risks

The Group has Treasury Guidelines applicable to all Group companies and each Group company is required to adopt a treasury policy consistent with these guidelines. These policies cover financing structure, foreign exchange and interest rate risk management, insurance, counterparty risk management and derivative instruments, as well as the treasury control framework. Wherever possible, treasury operations are operated through specialist Group regional organisations without removing from each Group company the responsibility to formulate and implement appropriate treasury policies.

Each Group company measures its foreign currency exposures against the underlying currency of its business (its functional currency), reports foreign exchange gains and losses against its functional currency and has hedging and treasury policies in place which are designed to manage foreign exchange exposure so defined. The functional currency for most upstream companies and for other companies with significant international business is the US dollar, but other companies usually have their local currency as their functional currency.

The financing of most Operating Companies is structured on a floating-rate basis and, except in special cases, further interest rate risk management is discouraged.

Apart from forward foreign exchange contracts to meet known commitments, the use of derivative financial instruments by most Group companies is not permitted by their treasury policy.

Specific Group companies have a mandate to operate as traders in crude oil, natural gas, oil products and other energy related products, using commodity swaps, options and futures as a means of managing price and timing risks arising from this trading. In effecting these transactions, the companies concerned operate within procedures and policies designed to ensure that risks, including those relating to the default of counterparties, are minimised. The Group measures exposure to the market when trading. Exposure to substantial trading losses is considered limited with the Group’s approach to risk.

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Other than in exceptional cases, the use of external derivative instruments is generally confined to specialist oil and gas trading and central treasury organisations which have appropriate skills, experience, supervision and control and reporting systems.

Supplementary information on derivatives and other financial instruments and derivative commodity instruments is given on pages G62 to G74 of this report.

Pension funds

Environmental and decommissioning costs

The costs of prevention, control, abatement or elimination of releases into the air and water, as well as the disposal and handling of waste at operating facilities, are considered to be an ordinary part of business. As such, these amounts are included within operating expenses. An estimate of the order of magnitude of amounts incurred in 2004 for Group companies, based on allocations and managerial judgment, is $1.4 billion (2003: $1.3 billion).

Expenditures of a capital nature to limit or monitor hazardous substances or releases, include both remedial measures on existing plants and integral features of new plants. Whilst some environmental expenditures are discrete and readily identifiable, others must be reasonably estimated or allocated based on technical and financial judgments which develop over time. Consistent with this, estimated environmental capital expenditures made by companies with major capital programmes during 2004 were $0.7 billion (2003: $0.7 billion). Those Group companies are expected to incur environmental capital costs of at least $0.5 billion during 2005 and 2006.

It is not possible to predict with certainty the magnitude of the effect of required investments in existing facilities on Group companies’ future earnings, since this will depend amongst other things on the ability to recover the higher costs from consumers and through fiscal incentives offered by governments.

Nevertheless, it is anticipated that over time there will be no material impact on the total of Group companies’ earnings. These risks are comparable to those faced by other companies in similar businesses.

At the end of 2004, the total liabilities being carried for environmental clean-up were $907 million (2003: $972 million). In 2004, there were payments of $244 million and increases in provisions of $161 million. The Group introduced US accounting standard FAS 143 (Asset Retirement Obligations) with effect from January 1, 2003 (see Note 24 to the Group Financial Statements on page G29). The fair value of the obligations being carried for expenditures on decommissioning and site restoration, including oil and gas platforms, at December 31, 2004 amounted to $5,894 million (2003: $4,044 million).

Employees

Research and development costs

Foreign exchange volatility

International Financial Reporting Standards

With effect from the first quarter of 2005, the Group will release its quarterly (unaudited) results under IFRS, including comparative data for 2004, together with reconciliations to opening January 1, 2004 and to 2004 data previously published in accordance with

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accounting principles generally accepted in the United States (US GAAP). The 2005 Financial Statements of the Group or, subject to completion of the transaction described under the heading “— Unification Proposal” on page 48, of its successor, will be prepared under IFRS, with appropriate reconciliations to US GAAP.

The total impact on net assets at transition on January 1, 2004 is expected to be a reduction of $4.7 billion, mainly resulting from the recognition of unrecognised gains and losses on post-retirement benefits at the date of transition of $4.9 billion. This will have no impact on the actuarial position or funding of the pension funds, which continue to be well funded.

There have been various amendments during 2004 to International Accounting Standards 32 and 39 relating to the accounting for financial instruments. In order to complete its review of the potential impact the Group is applying the option to continue with its existing policy (under which derivatives defined under US GAAP, other than those meeting the normal purchases and sales exception, are already recognised on the balance sheet at fair value) for 2004 and to implement any changes to accounting policy arising from these standards with effect from January 1, 2005.

The adoption of IFRS will have no impact on the financial framework, the Group’s strategy or the Group’s cash. However net income will differ resulting from the IFRS requirements to expense stock options, to capitalise major inspection costs, to provide for additional impairments and to reverse previous impairments where applicable and (mainly as a consequence of the transition adjustment) there will be an impact on pension costs. However, as stated above there will be no impact on the actuarial position of funding of the pension funds, which continue to be well funded.

Cautionary statement

Critical Accounting Estimates

Estimation of oil and gas reserves

Oil and gas reserves are key elements in the Group’s investment decision-making process. They are also an important element in testing for impairment. Changes in proved oil and gas reserves will also affect the standardised measure of discounted cash flows presented in “Supplementary information – Oil and Gas (unaudited)” (see pages G49 to G61) and changes in proved oil and gas reserves, particularly proved developed reserves, will affect unit-of-production depreciation charges to income.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, ie, prices and costs as of the date the estimate is made. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Estimates of oil and gas reserves are inherently imprecise, require the application of judgment and are subject to future revision. Accordingly, financial and accounting measures (such as the standardised measure of discounted cash flows, depreciation, depletion and amortisation charges, and decommissioning provisions) that are based on proved reserves are also subject to change.

Proved reserves are estimated by reference to available reservoir and well information, including production and pressure trends for producing reservoirs and, in some cases, subject to definitional limits, to similar data from other producing reservoirs. Proved reserves estimates are attributed to future development projects only where there is a significant commitment to project funding and execution and for which applicable governmental and regulatory approvals have been secured or are reasonably certain to be secured. Furthermore, estimates of proved reserves only include volumes for which access to market is assured with reasonable certainty. All proved reserve

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estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans. In general, changes in the technical maturity of hydrocarbon reserves resulting from new information becoming available from development and production activities have tended to be the most significant cause of annual revisions.

In general, estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and depleted. As a field goes into production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions.

As announced on January 9, 2004, March 18, 2004, April 19, 2004, October 28, 2004, November 26, 2004 and February 3, 2005 the Group reviewed its proved reserves (with the assistance of external consultants) during the period from late 2003 to December 2004. These reviews lead to the First Reserves Restatement, which was reflected in the 2003 Annual Report and Accounts and the Annual Report on Form 20-F, as filed with the SEC on June 30, 2004, and to the Second Reserves Restatement which was reflected in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with the SEC on March 7, 2005. As at December 31, 2003, after giving effect to the First Reserves Restatement and the Second Reserves Restatement, the proportion of the Group’s total proved reserves that was categorised as proved developed reserves was 57%, the remaining 43% being proved undeveloped reserves.

As noted above, changes in the estimated amounts of proved reserves can have a significant impact on the standardised measure of discounted cash flows presented under “Supplementary information – Oil and Gas (unaudited)” beginning on page G60. The First Reserves Restatement and the Second Reserves Restatement resulted in a 17% reduction in the standardised measure as at the end of 2002. Apart from the effects of the Reserves Restatements, however, revisions to proved reserves have had a relatively modest impact on standardised measure compared to changes in prices and costs, sales and transfers and income tax. A summary of changes to the standardised measure is given on page G60.

Changes to the Group’s estimates of proved reserves, particularly proved developed reserves, also affect the amount of depreciation, depletion and amortisation recorded in the Group’s financial statements for fixed assets related to hydrocarbon production activities. These changes most often result from production and revisions. However, the Reserves Restatements also affected proved developed reserves. A reduction in proved developed reserves will increase depreciation, depletion and amortisation charges (assuming constant production) and reduce net income.

Exploration costs

A proposed amendment to FASB Statement no.19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” has been issued. If enacted this would result in the continued inclusion, on a prospective basis, of the cost of certain exploratory wells in tangible fixed assets beyond 12 months which do not meet the current requirements given above if both sufficient reserves have been found to justify completion as a producing well, and sufficient progress is being made towards assessing the reserves and the economic and operating viability of the project. (See Note 3 to the Group Financial Statements). This would result in lower write-offs if proved reserves are ultimately determined, with a consequential increase in depreciation, depletion and amortisation of future periods.

Recoverability of assets

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Estimates of future cash flows are based on management estimates of future commodity prices, market supply and demand, product margins and, in the case of oil and gas properties, the expected future production volumes. Other factors that can lead to changes in estimates include restructuring plans and variations in regulatory environments. Expected future production volumes, which include both proved reserves as well as volumes that are expected to constitute proved reserves in the future, are used for testing asset recoverability because the Group believes this to be the most appropriate indicator of expected future cash flows, used as a measure of fair value. Estimates of future cash flows are risk weighted and consistent with those used in Group companies’ business plans. A discount rate based on the Group’s risk free rate is used in impairment testing, adapted where required to specific local circumstances. Changes in the discount rate can result from inflation rates, individual country risks and currency risks. The Group reviews the discount rate to be applied on an annual basis but the risk free rate has been stable in recent years.

Asset impairments have the potential to significantly impact net income. For example, in recent years there have been significant charges in 2003 ($1,376 million pre-tax) and the changes in estimates that most precipitated those impairments were in relation to future production outlooks and economic conditions, and portfolio actions (particularly in Oil Products due to the announced closure of the Bakersfield refinery). This resulted in certain asset-specific impairments in Exploration & Production (totalling $698 million), Oil Products, Chemicals and other industry segments. There were also significant write-downs in the carrying amounts of certain associated companies in 2003 as a result of a reassessment of future business conditions. These comprised Basell in Chemicals ($286 million after tax) and InterGen ($200 million) and Cuiaba ($115 million) in Gas & Power.

As described above, the Group has a portfolio of assets across a number of business lines and geographic regions. The factors that influence estimated future cash flows from assets also vary depending on the nature of the business activity in which those assets are used and geographical market conditions impacting the businesses in which assets are used. This wide business and geographic spread is such that it is not practicable to determine the likelihood or magnitude of impairments under different sets of assumptions. The assumption on future oil prices tends to be stable because the Group does not consider short-term increases or decreases in prices as being indicative of long term levels. At the end of 2004 the estimated oil and gas prices used for asset recoverability testing were lower than prices prevailing in the market at that time.

Provisions and liabilities

Other provisions and liabilities are recognised in the period when it becomes probable that there will be a future outflow of funds resulting from past operations or events which can be reasonably estimated. The timing of recognition requires the application of judgment to existing facts and circumstances, which can be subject to change.

Estimates of the amounts of provisions and liabilities recognised are based on current legal and constructive requirements, technology and price levels. Because actual outflows can differ from estimates due to changes in laws, regulations, public expectations, technology, prices and conditions, and can take place many years in the future, the carrying amounts of provisions and liabilities are regularly reviewed and adjusted to take account of such changes.

In relation to decommissioning and restoration costs, the estimated interest rate used in discounting the cash flows is reviewed at least annually. The interest rate used to determine the balance sheet obligation at December 31, 2004, was 6%.

As further described in Note 28 to the Group Financial Statements, the Group is subject to claims and actions. The facts and circumstances relating to particular cases are evaluated in determining whether it is “probable” that there will be a future outflow of funds and, once established, whether a provision relating to a specific litigation is sufficient. Accordingly, significant management judgment relating to contingent liabilities is required since the outcome of litigation is difficult to predict. Despite this uncertainty, actual payments related to litigation during the three years ended December 31, 2004 have not been material to the Group’s financial condition or results of operations.

Notwithstanding the possibility of outcomes outside expected ranges, in recent years the Group’s experience has been that estimates used in determining the appropriate levels of provisions have been materially adequate in anticipating actual outcomes.

A change in estimate of a recognised provision or liability would result in a charge or credit to net income in the period in which the change occurs (with the exception of decommissioning and restoration costs as described above).

Employee retirement plans

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The amounts reported for the Group’s employee retirement plans are disclosed in Note 21 to the Group Financial Statements, and are calculated in line with Statement of Financial Accounting Standards No. 87 (FAS 87). These calculations require assumptions to be made of future outcomes, the principal ones being in respect of increases in remuneration and pension benefit levels, the expected long-term return on plan assets and the discount rate used to convert future cash flows to current values. The assumptions used vary for the different plans as they are determined in consultation with independent actuaries in the light of local conditions. The assumptions are reviewed annually. Expected rates of return on plan assets are calculated based on a projection of real long-term bond yields and an equity risk premium which are combined with local inflation assumptions and applied to the actual asset mix of each plan. The amount of the expected return on plan assets is calculated using the expected rate of return for the year and the market-related value at the beginning of the year. Discount rates used to calculate year-end liabilities are based on prevailing AA long-term corporate bond rates at year end. Weighted average values for the assumptions used are contained in Note 21 to the Group Financial Statements. The main change in 2004 was a 0.5% reduction in the discount rate used to calculate year-end liabilities reflecting lower long-term interest rates.

Pension cost under FAS 87 primarily represents the increase in actuarial present value of the obligation for benefits earned on employee service during the year and the interest on the obligation in respect of employee service in previous years, net of the expected return on plan assets. The FAS 87 calculations are sensitive to changes in the underlying assumptions. A change of one percentage point in the expected rate of return on plan assets would result in a change in pension cost charged to income of approximately $500 million (pre-tax) per annum. FAS 87 generally reduces income volatility because unexpected changes in the amounts of plan assets and liabilities (actuarial gains and losses) are amortised over the average remaining employee work life.

The trustees manage the pension funds and set the required contributions from Group companies based on independent actuarial valuation rather than the FAS 87 measures.

Controls And Procedures

In making the evaluation, the Companies have considered matters relating to the Reserves Restatements, including action taken during 2004 to identify deficiencies and enhance the effectiveness of disclosure controls and procedures. The Executive Committee noted the implementation of a number of structural enhancements designed to address improvement needs identified by a special report to the Group Audit Committee. Further steps will be taken through the course of 2005 to embed, sustain and build upon the enhancements made to date.

Except as described below, there has not been any change in the internal controls over financial reporting of the Group or either Parent Company that occurred during the period covered by this report that has materially affected, or is reasonably likely to affect, such internal controls over financial reporting.

Investigation and Report to the Group Audit Committee; Management Changes

Following an interim report to the GAC dated March 1, 2004, which was presented to the Parent Company Boards on March 2, 2004, Sir Philip Watts, Chairman of the Committee of Managing Directors and Walter Van de Vijver, Chief Executive of Exploration & Production, submitted their resignations on March 3, 2004 from all director and officer positions within the Group and the Parent Companies. Following acceptance of the final report to the GAC by the members of the Supervisory Board of Royal Dutch and the non-executive Directors of Shell Transport, Judith Boynton stepped aside as Group Chief Financial Officer and as Group Managing Director

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and Managing Director of Shell Transport on April 18, 2004. She remained with the Group in an advisory capacity reporting to the Chief Executive Jeroen van der Veer. Ms Boynton left the Group, by mutual agreement, effective December 31, 2004.

Jeroen van der Veer, President and Managing Director of Royal Dutch, succeeded Sir Philip Watts as Chairman of the Group’s Committee of Managing Directors; Lord Oxburgh was appointed non-executive Chairman of Shell Transport and Chairman of Conference; and Malcolm Brinded was appointed Chief Executive of Exploration & Production, a Director of Shell Transport and Vice Chairman of the Committee of Managing Directors. Mr. Brinded resigned from his position as a Managing Director of Royal Dutch. On June 23, 2004, Peter Voser was appointed Group Chief Financial Officer and a Director of Shell Transport with effect from October 4, 2004. Linda Cook was appointed a Managing Director of Royal Dutch on August 1, 2004.

Deficiencies relating to reserves reporting

–	the Group’s guidelines for booking proved reserves were inadequate in several respects, including (i) containing inconsistencies with the SEC’s rules and published guidance relating to proved reserves and (ii) failing to clearly and sufficiently impart these requirements and guidance to users of the guidelines;
–	there was a lack of appropriate resources and a confusion of roles and responsibilities with respect to the Group Reserves Co-ordinator and the Group Reserves Auditor;
–	the Group’s Committee of Managing Directors and the Parent Company Boards were not provided with appropriate information to inform disclosure judgments;
–	there were weaknesses in the finance function whereby the Chief Financial Officers of the businesses did not have direct reporting responsibility to the Group Chief Financial Officer;
–	there were unclear lines of responsibility for booking proved reserves;
–	there was a lack of understanding at various levels of the Group of the meaning and importance of disclosure obligations under the SEC’s rules and published guidance relating to proved reserves; and
–	there was a control environment that did not emphasise the paramount importance of the compliance element of proved reserves decisions.

Remedial Actions Taken in 2004

–	Global Reserves Committee. The Group established the Global Exploration & Production Reserves Committee (the “Reserves Committee”) in order to improve consistency of standards and their application across the Group’s operations globally and strengthen the oversight of the process for approving the booking of proved reserves.
–	Group Reserves Guidelines. The Group’s guidelines for booking proved reserves have been revised with the assistance of independent petroleum engineers and counsel to ensure that these guidelines conform fully with applicable SEC rules and guidance, clarify the criteria for booking and de-booking of proved reserves (and the distinctions between regulatory requirements and the Group’s internal reserves classifications) and improve their utility for all users. It is expected that future revisions of the guidelines will occur

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	only as necessary and as early as possible in the year to allow engineers to understand the implications well in advance of the submission of reserves volumes at year-end.

–	Training Reserves Guidelines Users. In 2004, the Group began, and in early 2005 completed training approximately 3,000 employees in the use of the revised Group Reserves Guidelines.
–	Overhaul of the office of Group Reserves Co-ordinator. Given the technical and compliance elements of reserves determinations, the Group Reserves Co-ordinator will no longer report to business planning or strategy executives in Exploration & Production but to the Director of Technology. More staff have been and will be employed to resource the vital function of the Group Reserves Co-ordinator who will also regularly use independent petroleum engineers as deemed necessary, including for the systematic training of engineers in the field. The Group Reserves Co-ordinator is responsible for the revision and ongoing maintenance and application of the Group’s Guidelines, and as such is responsible for identifying and resolving difficult areas of interpretation with the Reserves Committee and the Group Reserves Auditor as well as for identifying training needs and facilitating training sessions from both a technical and regulatory perspective. The Group Reserves Co-ordinator also has an obligation to liaise with internal legal staff on disclosure judgments on the basis of technical compliance and/or materiality.
–	Overhaul of the office of Group Reserves Auditor. The Group Reserve Auditor function has been assigned additional employees so that the audit cycle of the Group’s reserves can be made more frequent and each audit can be made more rigorous. The Group Reserves Auditor and his or her staff now report to the Group Chief Internal Auditor to increase the independence of the Group Reserves Auditor function. The Group Reserves Auditor also regularly uses independent external petroleum engineers to complement and develop in-house expertise.
–	Clarification of roles and responsibilities of the Group Reserves Auditor and the Group Reserves Co-ordinator. The roles of the Group Reserves Auditor and Group Reserves Co-ordinator have been redefined to make clear that they must retain a respectful separation and independence so as to allow the Group Reserves Auditor to challenge the Group Reserves Co-ordinator and Exploration & Production reserve booking decisions more effectively as parts of the Group internal audit function.
–	Removal of reserves from scorecards. Scorecards are used internally to gauge the performance of the Group’s businesses against identified goals for purposes of management evaluation and for calculating management bonuses. Reserves bookings have been removed from performance scorecards of individuals associated with the reserves assurance process, including senior executives.
–	Improved visibility and accounting of reserves issues by senior management and Directors. The Group’s Executive Committee (prior to October 2004, the Group’s Committee of Managing Directors) collectively approve the reserve bookings and de-bookings taken by Exploration & Production. Following this approval, a review of the overall outcome is considered by the Group Audit Committee.
–	Enhanced accountability of Business CFOs to the Group CFO. The Chief Financial Officers of the businesses now report directly to the Group Chief Financial Officer. This reorganisation is designed to improve the ability of the Group Chief Financial Officer to have effective oversight of financial issues relating to the business units. It also enables the Group Chief Financial Officer, in turn, to inform colleagues and directors of important disclosure issues, as required.
–	Strengthening of line responsibilities for reserve reporting. The line authorities and accountabilities for reserve reporting have been reinforced as follows:

	–	to clarify that the local Chief Reservoir Engineer is responsible for ensuring that reserves bookings and de-bookings are compliant with SEC rules and requiring that any booking and de-booking decisions are only made with appropriate, auditable documentation and after completion of the appropriate challenge processes;
	–	to place business and financial responsibility on the Regional Technical Director and Regional Finance Manager, respectively, for the decisions of their Chief Reservoir Engineer;
	–	to clarify that responsibility for booking and debooking decisions rests with the Chief Financial Officer of Exploration & Production and the Director of Technology of Exploration & Production, working together with the Group Reserves Co-ordinator and the other members of the Reserves Committee;
	–	to provide for the approval of these decisions by the Group’s Executive Committee; and
	–	finally, to provide for final review by the Group Audit Committee.

–

Enhancement of the Legal Function. To improve the ability of the senior management to benefit from appropriate legal advice, provision has been made for the Group Legal Director to have the ability to attend meetings of the Group’s Executive Committee, the Conference and the Parent Company Boards. Similarly, the General Counsel of the various businesses, who attend the executive committee meetings of those businesses, have been expressly given the task of identifying disclosure issues for consideration at a higher level. All lawyers at the Group level and the Parent Companies, including the Corporate Secretaries of the Parent Companies, now report to the Group Legal Director, except to the extent inappropriate under applicable legal and fiduciary requirements or governance codes when they report directly to the Parent Company Boards. The legal function has been given responsibility for

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	actively identifying training needs in areas of disclosure, reporting obligations and corporate governance and devising training programs to address those needs.

–	Enhancement of the Disclosure Committee. The role of the Group’s existing Disclosure Committee has been enhanced and the Committee is now chaired by the Group Legal Director. The Disclosure Committee has also been given regular access to the Group’s Executive Committee to assess the adequacy of disclosures and ensure the awareness and approval of the Group’s Executive Committee of those disclosures. In carrying out its responsibility to ensure accuracy, completeness and consistency with other disclosures, the Disclosure Committee will be asked to provide a second level of control over the substantive content of disclosures.
–	Reduction of Job Rotation. The Group examines the tenure of individuals in key functions. While it is important for numerous reasons to expose people to different experiences within the Group, it is accepted that the period of rotation of certain positions should be extended and, upon rotation, complete and detailed handover notes should form the basis for a formal transfer.
–	Document Retention Policy. A consistent policy has been prepared to be put into place. Following implementation, this policy will be disseminated throughout the Group.
–	Promoting Communication and Compliance. Group-wide communications have taken place, and will continue, in which the Group’s senior management emphasises to all employees that integrity and compliance concerns must be raised with the internal audit or legal functions, and must be investigated thoroughly and openly, regardless of who is involved. This policy will be communicated forcefully and frequently. Moreover, a working group of senior executives has been formed to evaluate ways to enhance the effectiveness of the Group’s compliance efforts and to promote consistent communication of compliance requirements throughout the Group. A Group Compliance Officer was appointed in January 2005.

Principal Accountants Fees and Services

Group						$ million
										2002
		2004				2003				As restated
Audit fees			42				32				27
Audit-related feesa			13				11				17
Tax feesb			9				7				6
All other feesc			6				6				12

a	Fees for audit-related services such as employee benefit plan audits, due diligence assistance, assurance of non-financial data, operational audits, training services and special investigations.
b	Fees for tax compliance, tax advice and tax planning services.

c	Primarily non-audit IT system review services.

The following table sets forth the fees paid by Royal Dutch to KPMG Accountants N.V., Royal Dutch’s registered independent public accountants for each of the years for which audited financial statements appear in this Report:

Royal Dutch

€ thousand

2004

2003

2002

Audit fees

190

245

140

Audit-related fees

–

–

–

Tax fees

–

–

–

All other fees

–

–

–

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The following table sets forth the fees paid by Shell Transport to PricewaterhouseCoopers LLP, Shell Transport’s registered independent public accountants for each of the years for which audited financial statements appear in this Report:

Shell Transport						£ thousand
		2004				2003				2002
Audit fees			155				129				31
Audit-related feesd			16				32				23
Tax fees			–				–				–
All other fees			–				–				–

d	Fees for all other non-audit services relate to advice in respect of the financial reporting and disclosure impact of developments in accounting policies and business activities of the Royal Dutch/ Shell Group on the financial statements of Shell Transport, including proposed developments in International Financial Reporting Standards.

The Group Audit Committee approved 54% of the aggregate fees set forth in the tables above in the rows entitled “Audit-related fees,” 84% of the aggregate fees set forth in the tables above in the rows entitled “Tax fees” and 100% of the aggregate fees set forth in the tables above in the rows entitled “All other fees”. The Group Audit Committee approves services to be provided by the external auditors KPMG and PricewaterhouseCoopers in accordance with the procedures described under the headings “Royal Dutch – Management – Group Audit Committee” and “Shell Transport – Management – Group Audit Committee” on pages 89 and 101.

Legal Proceedings

The reasons for this determination can be summarised as follows:

–	While the majority of the cases have been consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York, there are many cases pending in other jurisdictions throughout the U.S. Most of the cases are at a preliminary stage. In many matters, little discovery has been taken and the courts have yet to rule upon motions on substantive legal issues. Consequently, management of the Group does not have sufficient information to assess the facts underlying the plaintiffs’ claims; the nature and extent of damages claimed, if any; the reasonableness of any specific claim for money damages; the allocation of potential responsibility among defendants; or the law that may be applicable. Additionally, given the pendency of cases in varying jurisdictions, there may be inconsistencies in the determinations made in these matters.
–	There are significant unresolved legal questions relating to claims asserted in this litigation. For example, it has not been established whether the use of oxygenates mandated by the 1990 amendments to the Clean Air Act can give rise to a products liability based claim. While some trial courts have held that it cannot, other courts have left the question open or declined to dismiss claims brought on a products liability theory. Other examples of unresolved legal questions relate to the applicability of federal preemption, whether a plaintiff may recover damages for alleged levels of contamination significantly below state environmental standards, and whether a plaintiff may recover for an alleged threat to groundwater before detection of contamination.
–	There are also significant unresolved legal questions relating to whether punitive damages are available for products liability claims or, if available, the manner in which they might be determined. For example, some courts have held that for certain types of product liability claims, punitive damages are not available. It is not known whether that rule of law would be applied in some or all of the pending oxygenate additive cases. Where specific claims for damages have been made, punitive damages represent in most cases a majority of the total amounts claimed.
–	There are significant issues relating to the allocation of any liability among the defendants. Virtually all of the oxygenate additives cases involve multiple defendants including most of the major participants in the retail gasoline marketing business in the regions

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	involved in the pending cases. The basis on which any potential liability may be apportioned among the defendants in any particular pending case cannot yet be determined.

For these reasons, management of the Group is not currently able to estimate a range of reasonably possible losses or minimum loss for this litigation; however, management of the Group does not currently believe that the outcome of the oxygenate-related litigation pending as of December 31, 2004 will have a material impact on the Group’s financial condition, although such resolutions could have a significant effect on periodic results for the period in which they are recognised.

A $490 million judgment in favour of 466 plaintiffs in a consolidated matter that had once been nine individual cases was rendered in 2002 by a Nicaraguan court jointly against SOC and three other named defendants (not affiliated with SOC), based upon Nicaraguan Special Law 364 for claimed personal injuries resulting from alleged exposure to dibromochloropropane (DBCP) – a pesticide manufactured by SOC prior to 1978. This special law imposes strict liability (in a predetermined amount) on international manufacturers of DBCP. The statute also provides that unless a deposit (calculated as described below) of an amount denominated in Nicaraguan cordobas is made into the Nicaraguan courts, the claims would be submitted to the US courts. In SOC’s case the deposit would have been between $19 million and $20 million (based on an exchange rate between 15 and 16 cordobas per US dollar). SOC chose not to make this deposit. The Nicaraguan courts did not, however, give effect to the provision of Special Law 364 that requires submission of the matter to the US courts. Instead, the Nicaraguan court entered judgment against SOC and the other defendants. Further, SOC was not afforded the opportunity to present any defences in the Nicaraguan court, including that it was not subject to Nicaraguan jurisdiction because it had neither shipped nor sold DBCP to parties in Nicaragua. At this time, SOC has not completed the steps necessary to perfect an appeal in Nicaragua and, as described below, the Nicaraguan claimants have sought to enforce the Nicaraguan judgment against SOC in the U.S. and in Venezuela. SOC does not have any assets in Nicaragua. In 2003, an attempt by the plaintiffs to enforce the Nicaraguan judgment described above in the United States against Shell Chemical Company and purported affiliates of the other named defendants was rejected by the U.S. District Court for the Central District of California, which decision is on appeal before the Ninth Circuit Court of Appeals. Enforcement of the Nicaraguan judgment was rejected because of improper service and attempted enforcement against non-existent entities or entities that were not named in the Nicaraguan judgment. Thereafter, SOC filed a declaratory judgment action seeking ultimate adjudication of the non-enforceability of this Nicaraguan judgment in the U.S. District Court for the Central District of California. This district court denied motions filed by the Nicaraguan claimants to dismiss SOC claims that Nicaragua does not have impartial tribunals, the proceedings violated due process, the relationship between SOC and Nicaragua made the exercise of personal jurisdiction unreasonable, and Special Law 364 is repugnant to U.S. public policy because it violates due process. A finding in favour of SOC on any of these grounds will result in a refusal to recognize and enforce the judgment in the United States. Several requests for Exequatur were filed in 2004 with the Tribunal Suprema de Justicia (the Venezuelan Supreme Court) to enforce Nicaraguan judgments. The petitions imply that judgments can be satisfied with assets of Shell Venezuela, S.A., which was neither a party to the Nicaraguan judgment nor a subsidiary of SOC, against whom the Exequatur was filed. The petitions are pending before the Tribunal Suprema de Justicia but have not been accepted. As of December 31, 2004, five additional Nicaraguan judgments had been entered in the collective amount of approximately $226.5 million in favour of 240 plaintiffs jointly against Shell Chemical Company and three other named defendants (not affiliated with Shell Chemical Company) under facts and circumstances almost identical to those relating to the judgment described above. Additional judgments are anticipated (including a suit seeking more than $3 billion). It is the opinion of management of the Group that the above judgments are unenforceable in a U.S. court, as a matter of law, for the reasons set out in SOC’s declaratory judgment action described above. No financial provisions have been established for these judgments or related claims.

Since 1984, SOC has been named with others as a defendant in numerous product liability cases, including class actions, involving the failure of residential plumbing systems and municipal water distribution systems constructed with polybutylene plastic pipe. SOC fabricated the resin for this pipe while the co-defendants fabricated the raw materials for the pipe fittings. As a result of two class action settlements in 1995, SOC and the co-defendants agreed on a mechanism to fund until 2009 the settlement of most of the residential plumbing claims in the United States. Financial provisions have been taken by SOC for its settlement funding needs anticipated at this time. Additionally, claims that are not part of these class action settlements or that challenge these settlements continue to be filed primarily involving alleged problems with polybutylene pipe used in municipal water distribution systems. It is the opinion of management of the Group that exposure from this other polybutylene litigation pending as of December 31, 2004, is not material. Management of the Group cannot currently predict when or how all polybutylene matters will be finally resolved.

In connection with the recategorisation of certain hydrocarbon reserves that occurred in 2004, a number of putative shareholder class actions were filed against Royal Dutch, Shell Transport, Managing Directors of Royal Dutch during the class period, Managing Directors of Shell Transport during the class period, and the external auditors for Royal Dutch, Shell Transport and the Group. These actions were consolidated in the United States District Court in New Jersey and a consolidated complaint was filed in September 2004. The parties are awaiting a decision with respect to defendants’ motions to dismiss asserting lack of jurisdiction with respect to the claims of non-United States shareholders who purchased on non-United States securities exchanges and failure to state a claim. Merits discovery has not begun. The case is at an early stage and subject to substantial uncertainties concerning the outcome of the material factual and legal issues relating to the litigation, including the pending motions to dismiss on lack of jurisdiction and failure to state a claim. In addition, potential damages, if any, in a fully litigated securities class action would depend on the losses caused by the alleged wrongful

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conduct that would be demonstrated by individual class members in their purchases and sales of Royal Dutch and Shell Transport shares during the relevant class period. Accordingly, based on the current status of the litigation, management of the Group is unable to estimate a range of possible losses or any minimum loss. Management of the Group will review this determination as the litigation progresses.

Also in connection with the hydrocarbon reserves recategorisation, putative shareholder class actions were filed on behalf of participants in various Shell Oil Company qualified plans alleging that Royal Dutch, Shell Transport and various current and former officers and directors breached various fiduciary duties to employee participants imposed by the Employee Retirement Income Security Act of 1974 (“ERISA”). These suits were consolidated in the United States District Court in New Jersey and a consolidated class action complaint was filed in July 2004. Defendants’ motions to dismiss have been fully briefed. Some document discovery has taken place. The case is at an early stage and subject to substantial uncertainties concerning the outcome of the material factual and legal issues relating to the litigation, including the pending motion to dismiss and the legal uncertainties with respect to the methodology for calculating damage, if any, should defendants become subject to an adverse judgment. The Group is in settlement discussions with counsel for plaintiffs, which it hopes will lead to a successful resolution of the case without the need for further litigation. No financial provisions have been taken with respect to the ERISA litigation.

The reserves recategorisation also led to the filing of shareholder derivative actions in June 2004. The four suits pending in New York state court, New York federal court and New Jersey federal court demand Group management and structural changes and seek unspecified damages from current and former members of the Boards of Directors of Royal Dutch and Shell Transport. The suits are in preliminary stages and no responses are yet due from defendants. Because any money “damages” in the derivative actions would be paid to Royal Dutch and Shell Transport, management of the Group does not believe that the resolution of these suits will have a material adverse effect on the Group’s financial condition or operating results.

The United States Securities and Exchange Commission (SEC) and UK Financial Services Authority (FSA) issued formal orders of private investigation in relation to the reserves recategorisation which Royal Dutch and Shell Transport resolved by reaching agreements with the SEC and the FSA. In connection with the agreement with the SEC, Royal Dutch and Shell Transport consented, without admitting or denying the SEC’s findings or conclusions, to an administrative order finding that Royal Dutch and Shell Transport violated, and requiring Royal Dutch and Shell Transport to cease and desist from future violations of, the antifraud, reporting, recordkeeping and internal control provisions of the US Federal securities laws and related SEC rules, agreed to pay a $120 million civil penalty and undertook to spend an additional $5 million developing a comprehensive internal compliance program. In connection with the agreement with the FSA, Royal Dutch and Shell Transport agreed, without admitting or denying the FSA’s findings or conclusions, to the entry of a Final Notice by the FSA finding that Royal Dutch and Shell Transport breached market abuse provisions of the UK’s Financial Services and Markets Act 2000 and the Listing Rules made under it and agreed to pay a penalty of £17 million. The penalties from the SEC and FSA and the additional amount to develop a comprehensive internal compliance program have been paid by Group companies and fully included in the Income Statement of the Group.

The United States Department of Justice has commenced a criminal investigation, and Euronext Amsterdam, the Dutch Authority Financial Markets and the California Department of Corporations are investigating the issues related to the reserves recategorisation. Management of the Group cannot currently predict the manner and timing of the resolution of these pending matters and is currently unable to estimate the range of reasonably possible losses from such matters.

Group companies are subject to a number of other loss contingencies arising out of litigation and claims brought by governmental and private parties, which are handled in the ordinary course of business.

The operations and earnings of Group companies continue, from time to time, to be affected to varying degrees by political, legislative, fiscal and regulatory developments, including those relating to the protection of the environment and indigenous people, in the countries in which they operate. The industries in which Group companies are engaged are also subject to physical risks of various types. The nature and frequency of these developments and events, not all of which are covered by insurance, as well as their effect on future operations and earnings, are unpredictable.

Under existing provisions, the Group will bear the costs of legal proceedings against certain officers, members and former members of the Boards of the Parent and Holding Companies, except if the member concerned is ruled to be seriously at fault by a court of law or a judgment is given against the member or officer. Over the year 2004, the Group advanced a total of $12,048,441 (certain amounts have been converted at the average £/$ exchange rate for 2004) for litigation costs for former Board members under these provisions.

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Royal Dutch Petroleum Company

Control of Registrant

On October 28, 2004, the Royal Dutch and Shell Transport Boards announced that they had unanimously agreed to propose to their shareholders a transaction through which each Parent Company will become a subsidiary of Royal Dutch Shell plc, which will become a publicly-listed company incorporated in England and Wales and headquartered and tax resident in the Netherlands. Please refer to “Discussion and Analysis of Financial Condition and Results of Operations – Unification Proposal” for additional information on this transaction.

Ordinary shares and priority shares

Royal Dutch has 1,500 issued priority shares. As announced on June 17, 2004, a proposal to abolish the priority shares has been put forward to the General Meeting of Shareholders 2005. It is intended that the proposal will be effected through a buyback of the priority shares at their nominal value. As at March 29, 2005, each member of the Supervisory Board and of the Board of Management is the holder of six priority shares. The Royal Dutch Priority Shares Foundation holds the other priority shares. The Board of the Foundation consists of all members of the Supervisory Board and the Board of Management of the Company. Priority shares represent certain special rights, which include:

–	determining of the number of members of the Supervisory Board and the number of Managing Directors, provided that the Supervisory Board should consist of at least five members and the Board of Management of at least two members;
–	drawing-up of a binding nomination consisting of two persons for filling vacancies on the Supervisory Board and the Board of Management;
–	granting of consent required for amendment of the Articles of Association or for dissolution of Royal Dutch; and
–	granting of consent required for the assignment of priority shares.

Apart from the priority shares, which can be considered an anti-takeover measure, Royal Dutch does not have any measures which exclusively or almost exclusively exist for the purpose of preventing a takeover. Furthermore, the Company does not have any measures which specifically prevent a bidder, if it has acquired 75% of the shares in the capital of the Company, appointing or dismissing members of the Board of Management and subsequently amending the Articles of Association of the Company. In the event of a hostile takeover attempt, the Board of Management and the Supervisory Board are authorised to exercise all powers attributed to them in the interest of Royal Dutch and its shareholders.

The above-mentioned rights are exercised by the meeting of holders of priority shares. At this meeting one vote may be cast for each priority share, but no one may cast more than six votes in all.

Nature of Trading Market

Royal Dutch ordinary shares are issuable in bearer or registered form.

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Royal Dutch shares of New York Registry may be transferred on the books of Royal Dutch and exchanged for bearer shares, for shares of Hague Registry or for shares of New York Registry of other denominations at JPMorgan Chase Bank (c/o JPMorgan Service Center, PO Box 43013, Providence, RI 02940-3013) as Transfer Agent and Registrar. The Transfer Agent maintains “drop facilities” at the offices of Securities Transfer and Reporting Services (STARS), 100 William Street, Galleria, New York, NY 10038, where stock certificates and related instruments may be received and redelivered. Besides being listed and traded on the New York Stock Exchange, Royal Dutch shares of New York Registry are also admitted to unlisted trading privileges on the following stock exchanges: Boston, Cincinnati, Midwest, Pacific and Philadelphia.

Royal Dutch ordinary shares other than those of New York Registry are predominantly in bearer form.

At March 29, 2005, there were outstanding 516,033,488 shares of New York Registry representing approximately 24.8% of the ordinary share capital of Royal Dutch, held by approximately 16,939 holders of record.

The following tables set forth the high and low prices for Royal Dutch €0.56 par value ordinary shares on Euronext Amsterdam and for Royal Dutch shares of New York Registry on the New York Stock Exchange for the periods specified:

Period
		Euronext								New York
		Amsterdam								Stock Exchange
		High				Low				High				Low
		€				€				$				$
2000			75.90				51.51				65.69				50.44
2001			73.48				43.72				64.15				39.75
2002			63.20				39.21				57.30				38.60
2003			44.58				33.35				52.70				36.69
2004			44.03				36.59				57.79				45.79

Period
		Euronext								New York
		Amsterdam								Stock Exchange
		High				Low				High				Low
		€				€				$				$
2003
1st Quarter			44.58				33.35				46.88				36.69
2nd Quarter			42.15				36.56				49.81				40.56
3rd Quarter			42.09				37.45				46.79				42.84
4th Quarter			41.85				37.01				52.70				43.95
2004
1st Quarter			42.43				36.59				54.00				45.79
2nd Quarter			43.94				38.02				53.24				47.48
3rd Quarter			43.63				39.96				53.82				48.94
4th Quarter			44.03				41.17				57.79				51.63

Period
		Euronext								New York
		Amsterdam								Stock Exchange
		High				Low				High				Low
		€				€				$				$
2004
September			43.63				41.21				53.82				50.47
October			44.03				41.17				55.06				51.63
November			43.67				42.10				57.79				53.50
December			43.50				41.79				57.74				55.32
2005
January			44.70				41.84				58.73				55.37
February			48.29				44.66				63.77				57.95
March (through March 29)			49.33				45.90				65.11				59.10

Articles of Association

General

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foundation of, participation in and management and financing of limited liability and other companies or undertakings which are engaged in one or more branches of the oil, natural gas, chemical industry, in mining, power generation and distribution, renewables or in one or more other industries. Royal Dutch is further entitled in general to do all that is necessary for the attainment of its object or that is connected therewith in the widest sense.

Managing Directors and members of the Supervisory Board

(a)	A Managing Director or member of the Supervisory Board shall not vote in respect of a proposal, arrangement or contract in which he is materially interested.
(b)	A Managing Director shall not vote in respect of any matter regarding compensation to himself or to any of the other Managing Directors. Each of the Managing Directors receives a remuneration, which shall be fixed by the Supervisory Board. The maximum aggregate remuneration of the members of the Supervisory Board is fixed by the General Meeting of Shareholders for division by the Supervisory Board among its members.
(c)	The Managing Directors are empowered to exercise all powers of Royal Dutch to borrow money subject to the authorisation of the Supervisory Board being required for contracting loans that will mature in more than one year. The aforementioned authorisation of the Supervisory Board is embedded in the Company’s Articles of Association which may only be varied by the Company’s General Meeting of Shareholders.
(d)	The Managing Directors and members of the Supervisory Board are not required to hold shares of Royal Dutch in order to be qualified.

Rights attaching to each class of shares

Annual accounts consisting of a balance sheet, profit and loss account and notes to these documents, prepared by the Board of Management and reflecting the reservation of such amounts as the Board of Management, with the approval of the Supervisory Board, determines, are to be submitted each year by the Supervisory Board to a General Meeting of Shareholders for adoption.

Out of the profit which is available for distribution, there shall first be distributed on each priority share an amount equal to 4% of its par value. The balance of profit available for distribution then remaining is distributed to the holders of ordinary shares, unless the General Meeting of Shareholders resolves that the whole or part of such profit be carried forward to the following year. Shares acquired and held by Royal Dutch in its own capital are not included in the profit distribution calculation and no distributions are made thereon.

The Board of Management, with the approval of the Supervisory Board, may pay interim dividends on the ordinary shares and priority shares. On the recommendation of the Board of Management and the Supervisory Board, the General Meeting of Shareholders may resolve that a dividend or interim dividend on shares shall be payable in shares of Royal Dutch.

The right to claim payment of a dividend becomes forfeited upon the expiration of six years from the date on which the dividend was first made obtainable, at which time it reverts to Royal Dutch.

(b) Voting rights

(c) Rights to share in the company’s profits

(d) Liquidation rights

(e) Redemption provisions

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(f) Sinking fund provisions

(g) Liability to further capital calls

(h) Discriminating provisions

(i) Pre-emptive rights

The resolutions of the Board of Management and the Supervisory Board referred to above may only be passed by unanimous vote of all the Managing Directors and all of the members of the Supervisory Board present or represented at the meeting.

Holders of priority shares have no preferential right in the event of an issue of new shares.

Changing the rights of holders of shares

General Meetings of Shareholders

General Meetings of Shareholders may be held as often as the Board of Management or the Supervisory Board deem advisable, and may also be held when holders of ordinary shares representing at least one-tenth of the issued share capital address to the Board of Management and to the Supervisory Board a written request to convene a general meeting, specifying the subjects to be discussed. If such request is not acted upon so as to enable the meeting to be held within six weeks, the persons making the request may be empowered by the President of the District Court in The Hague to convene the meeting themselves.

The Agenda for a General Meeting of Shareholders is to be specified in the notice of convocation of the meeting. No other business may be transacted at the meeting.

An absolute majority of the votes cast is required for the adoption of resolutions, except in those cases where Dutch law or the Articles of Association prescribe a larger majority. An absolute majority of the votes cast is required for the appointment of persons to office, provided that, if after two polls such majority has not been obtained, another poll is to be taken between the two persons obtaining the

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highest number of votes in the second poll, after which in the event of an equality of votes, the election is to be decided by the drawing of lots.

Limitations on rights to own shares

Provisions, which would delay, defer or prevent a change of control

Threshold for disclosure of share ownership

Changes in capital

Exchange Controls and Other Limitations Affecting Security Holders

There is no legislative or other legal provision currently in force in the Netherlands or arising under the constituent documents of Royal Dutch restricting remittances to non-resident holders of Royal Dutch’s securities.

Taxation

For Royal Dutch shareholders resident in any country other than the United States and the Netherlands, the availability of a whole or partial exemption or refund of the Dutch withholding tax is governed by the tax convention, if any, between the Netherlands and the country of the shareholder’s residence.

Taxation on capital gains

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Succession duty and gift taxes

A gift of shares of a Dutch company by a person who is not a resident or a deemed resident of the Netherlands is generally not subject to Dutch gift tax.

Management

The Supervisory Board is a separate body which does not include the Managing Directors. Members of the Supervisory Board are appointed by the General Meeting of Shareholders from the persons nominated by the meeting of holders of priority shares. Each year, one of the members of the Supervisory Board retires by rotation but is eligible for re-election. Further, a member of the Supervisory Board retires after having served on the Supervisory Board for a period of 10 years or retires effective on the first day of July following the initial April 1 on which the member is 70 years of age.

Nominations for the appointment of a Managing Director or a member of the Supervisory Board shall be made by a meeting of holders of priority shares and may also be made by one or more holders of ordinary shares representing in the aggregate at least 1% of the issued share capital, if approved by the meeting of holders of priority shares. Each such nomination shall contain the names of at least two qualified persons. Shareholders cast all of their votes on either of the two qualified persons. Votes cast at a General Meeting of Shareholders in favour of the election of other persons are void.

If a vacancy occurs on the Board of Management when there are still at least two Managing Directors in office, or on the Supervisory Board when there are still at least five members in office, the Board of Management shall notify the Chairman of the meeting of holders of priority shares, which meeting shall decide, after consulting the Supervisory Board and the Board of Management, whether the vacancy is to be filled. If it is resolved to fill the vacancy, the appointment shall be made at the next General Meeting of Shareholders. If there are not at least two Managing Directors or at least five members of the Supervisory Board still in office, a General Meeting of Shareholders shall be held within three months after that situation has arisen in order to fill the vacancy.

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The Managing Directors, members of the Supervisory Board and officers of Royal Dutch at March 29, 2005, were:

Biographies

Aad Jacobs ø

Maarten van den Bergh + #

Wim Kok #

Jonkheer Aarnout Loudon + #

Professor Hubert Markl +

Christine Morin-Postel ø

Lawrence Ricciardi ø

Jeroen van der Veer

Linda Cook

Rob Routs

Company Secretary, Royal Dutch

Key to Committee membership

ø  Group Audit Committee

+ Remuneration and Succession Review Committee

# Social Responsibility Committee

Nominations

Relationships between members of the Board of Management, members of the Supervisory Board and officers

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There are no family relationships between any Managing Director, member of the Supervisory Board or officer and any other Managing Director, member of the Supervisory Board or officer.

Share ownership

		Stock options				Ordinary shares
Supervisory Board
Aad Jacobs			–				–
Maarten van den Bergha			37,950				4,000
Wim Kok			–				–
Aarnout Loudon			–				75,000
Hubert Markl			–				–
Christine Morin-Postel			–				–
Lawrence Ricciardi			–				10,000
Managing Directors
Jeroen van der Veer			467,100				13,330
Linda Cook			337,725				217
Rob Routs			277,466				–

Excluding shares under the Deferred Bonus Plan, which will be released in principle three years after deferral.

a	No options are granted to members of the Supervisory Board, but options may be outstanding to members who have formerly been a Managing Director.

Managing Directors’ share interests in Royal Dutch under the Deferred Bonus Plan

Deferred Bonus Plan

Number of deferred

Total number of

bonus and

Deferred

Market price

Average market

deferred bonus and

dividend shares

bonus shares

of deferred

Dividend

price of dividend

dividend shares

under award as at

awarded

bonus shares

shares accrued

shares paid

under award as at

January 1, 2004

during the yeara

at awardb

during the yearc

during the yeard

December 31, 2004

€

€

Jeroen van der Veere

2003 awarde

11,695

–

36.66

503

41.71

12,198

2002 awardf

3,710

–

60.09

159

41.71

3,869

Awards made in 2002 and 2003 refer to the portion of the annual bonus deferred in respect of 2001 and 2002 and their related accrued dividends. In 2004 there was no opportunity for Managing Directors of Royal Dutch to defer any of their 2003 bonuses into the Deferred Bonus Plan, as the 2003 bonuses were nil.

Due to his appointment as Executive Director of Shell Transport in 2004 Malcolm Brinded’s deferred bonus plan interests have been reported in the Shell Transport 2004 Annual Report and Accounts.

a	Representing the proportion of the annual bonus that has been deferred and converted into notional share entitlements (deferred bonus shares), which will not result in beneficial ownership until they are released. The value of these deferred bonus shares is also included in the annual bonus figures in the Emoluments of the Managing Directors of Royal Dutch table on page R19.
b	The market price is based on the average share price over a period of five trading days prior to and including the day on which the share awards are made.
c	Representing dividends paid during the year on the number of shares equal to the deferred bonus shares awarded.
d	The market price shown is the average at the date of the 2003 final and 2004 interim annual dividends paid during the year: €41.08 and €42.34, respectively.
e	During the period January 1, 2005 to March 29, 2005, the total number of shares under award of the 2003 award of Jeroen van der Veer increased by 268 dividend shares as a result of the second 2004 interim dividend pay-out. This leads to a total of his award of 12,466.
f	The 2002 award of Jeroen van der Veer was released on February 16, 2005, including 1,934 additional matching shares. The award was subject to Dutch withholding tax and the net number of shares delivered to him was 2,818. The share price at the date of release was €45.58.

Group Audit Committee

In February, 2004, the Group Audit Committee established two discrete sub-committees to review and report to the Boards of either Royal Dutch or Shell Transport (as appropriate) on matters that are Parent Company specific. For Royal Dutch such matters include the supervision of the risk management and internal control systems, the Company’s financing and its financial reporting. The sub-committee will also supervise the company’s policy on tax planning as well as compliance with the recommendations and observations of the company’s independent auditors and the relations with the company’s independent auditors (including their independence, remuneration and non-audit services). It determines the extent of the independent auditors’ involvement in the content and publication

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of financial reports other than the annual accounts, assesses the sub-committee will assess the performance of the independent auditors, advises (together with the Board of Management) the Supervisory Board on the nomination of the independent auditors for the appointment by the General Meeting of Shareholders and provides recommendations on their remuneration and provision of non-audit services.

The Group Audit Committee is also responsible for the approval of all services to be provided by the external auditors KPMG and PricewaterhouseCoopers. This includes both audit and, to the extent permitted under applicable regulations, non-audit services. Under the guidelines adopted by the Group Audit Committee, certain specified categories of services may be contracted without pre-approval so long as the fee value for each contract does not exceed $500,000. These include permitted non-audit services such as tax compliance work, regulatory compliance work, certain advice on the tax treatment of proposed transactions, expatriate tax returns except where the expatriate has a financial reporting oversight role, among others. Other services must be specifically pre-approved. For urgent matters, the chairman of the Group Audit Committee is authorised to approve auditor engagements subject to review at the next Group Audit Committee meeting. Under the guidelines, permitted services must not present a conflict of interest. In addition, certain types of services will not normally be approved, including certain buy-side diligence services where it is likely to result in the audit firm later auditing its own work, advice on alternative deal structures for merger and acquisition transactions (although certain tax advice on deal structures proposed by the Group may be permitted), carve out accounting services and system assurance reviews and other internal control reviews, unless part of audit work.

Membership of the Group Audit Committee as at March 29, 2005 is shown in the table below.

Appointed by the Supervisory Board of Royal Dutch
Lawrence Ricciardi		Chairman of the Committee
Christine Morin-Postel
Aad Jacobs

Appointed by the Board of Shell Transport
Sir Peter Burt
Luis Giusti
Nina Henderson

The membership of the Royal Dutch sub-committee comprises those Supervisory Board members appointed to the Group Audit Committee. For purposes of the U.S. Sarbanes-Oxley Act, Aad Jacobs, a supervisory director of Royal Dutch, and a member of the Group Audit Committee, qualifies as an “audit committee financial expert” (as defined). In addition, each of Mr Jacobs and Sir Peter Burt, a director of Shell Transport and member of the Group Audit Committee and the Shell Transport Audit sub-committee, qualifies under Dutch and UK corporate governance requirements as a director with “appropriate and recent relevant financial experience”.

During 2004 there were a total of 23 meetings of the Group Audit Committee. Attendance at these meetings is shown in the table below.

Attendance
Members		Attendance
Lawrence Ricciardi		21
Sir Peter Burt		19
Luis Giusti		17
Nina Henderson		23
Aad Jacobs		23
Christine Morin-Postela		3

a	Christine Morin-Postel was appointed a member during the year and attended all meetings following her appointment.

A copy of the revised terms of reference of the Group Audit Committee (including the Royal Dutch sub-committee) can be found on the Shell website (www.shell.com/investor).

Remuneration and Succession Review Committee

Social Responsibility Committee

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Current membership of the Social Responsibility Committee is shown in the table below.

Appointed by the Supervisory Board of Royal Dutch
Maarten van den Bergh
Wim Kok
Jonkheer Aarnout Loudon

Appointed by the Board of Shell Transport
Dr Eileen Buttle		Chair of the Committee
Teymour Alireza
Sir Mark Moody-Stuart

During 2004 the committee met three times. Attendance at these meetings is shown in the table below.

Attendance
Members		Attendance
Dr Eileen Buttle		3
Teymour Alireza		3
Maarten van den Bergh		2
Wim Kok		3
Jonkheer Aarnout Loudon		3
Sir Mark Moody-Stuarta		1

a	Sir Mark Moody-Stuart was appointed a member during the year and was unable to attend one of the two meetings held following his appointment.

The Group’s core values of honesty, integrity and respect for people have been embodied for more than 25 years in the Group’s Statement of General Business Principles, which since 1997 have included a commitment to support fundamental human rights and to contribute to sustainable development. The principles apply to all Shell employees. The Group’s Statement of General Business Principles is publicly available on the Shell website (www.shell.com/sgbp).

The Shell Report, which reviews how Group companies are living up to the Group’s Statement of General Business Principles and contributing to sustainable development, is published annually and will be available at www.shell.com/shellreport following its publication at the end of May 2005.

Code of Ethics

Compensation of Directors and officers

Shares under option and share purchase plan

As of March 29, 2005, an aggregate amount of 57,848,833 issued and outstanding ordinary shares of Royal Dutch were the subject of options under such plans.

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The number of ordinary shares of Royal Dutch under option at March 29, 2005, and the option prices of the ordinary shares at the dates the options were granted, per share and in total, were as follows:

Plan
Exercise pricea
		Number of shares				Average				Total				Term
		under option				per share								(expiration dates)
Shell Petroleum N.V			22,174,593				€49.75			€	1,103,109,694				10 years
															(10/12/07 – 04/11/14)
The Shell Petroleum Company Limited			10,940,818				€50.04			€	547,505,061				10 years
															(10/12/07 – 06/05/14)
Shell Oil Company			2,767,069			$	53.07			$	146,860,574.11				10 years
															(01/03/10 – 21/12/10)
Shell Petroleum Inc.			21,950,292			$	50.19			$	1,101,632,366.88				10 years
															(01/03/10 – 07/05/14)
Shell Solar Employment Services Inc.			16,061			$	47.08			$	756,204.36				10 years
															(25/05/11 – 07/05/14)

a	Euro-denominated exercise prices prior to the fixing of the euro conversion rate in January 1999 are derived from the quotient of guilder prices and the fixed guilders-per-euro conversion rate of 2.20371.

Two Group companies, one in the Netherlands (Shell Petroleum N.V.) and one in the United Kingdom (The Shell Petroleum Company Limited) have restricted stock plans under which grants are made on a highly selective basis to senior staff. The Executive Directors (including the Chief Executive) are not eligible to participate in the Restricted Stock Plans. A maximum of 250,000 Royal Dutch ordinary shares (or equivalent value in Shell Transport Ordinary shares) can be granted under the plans in any year. Shares are granted subject to a three-year restriction period and the number of the shares awarded is based on the fair market value at the start of the restriction period. The shares, together with additional shares equivalent to the value of the dividends payable over the restriction period, are released to the individual at the end of the three-year period. The total number of outstanding ordinary shares of Royal Dutch under the restricted stock plans as of March 29, 2005 is 189,699.66, of which 13,304.66 shares relate to dividend shares up to date.

Two Group companies, one in the Netherlands (Shell Petroleum N.V.) and one in the United Kingdom (The Shell Petroleum Company Limited) have long-term incentive plans under which shares are awarded conditionally once a year to Executive Directors and selected senior executives. The plan allows for a maximum grant with a face value of two times base pay. The value of shares conditionally awarded will reflect competitive market practice. Release may occur three years after grant. The entire award is expected to be released only in cases of exceptional performance. The total number of outstanding ordinary shares of Royal Dutch conditionally awarded under the long-term incentive plans as of March 29, 2005 is 313,463.66, of which 18,883.66 shares relate to dividend shares up to date. None of the shares will result in beneficiary ownership until they are released.

The Global Employee Share Purchase Plan enables employees to make contributions, which are applied quarterly to purchase ordinary shares of Royal Dutch or Shell Transport at current market value. If the acquired shares are retained in the plan until the end of the twelve-month cycle the employee receives an additional 15% share allocation. In the USA a variant of this plan is operated where contributions are applied to buy Royal Dutch Shares at the end of the twelve-month cycle. The purchase price is the lower of the market price on the first or last trading day of the cycle reduced by 15%. Executive Directors are not eligible to participate in the Global Employee Share Purchase Plan. At March 29, 2005, Group companies held 15.901 Royal Dutch ordinary shares in connection with this plan.

No issue of new shares is involved under any of the plans mentioned above.

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Purchases of Equity Securities in Royal Dutch by Royal Dutch and Affiliated Purchasers

(c) Total Number of

(d) Maximum Number

(a) Total

Shares (or Units)

(or Approximate US Dollar Value)

Number of

Purchased as Part of

of Shares (or Units) that May

Shares (or Units)

(b) Average Price Paid Per

Publicly Announced Plans

Yet Be Purchased Under the

Period

purchased1

Share (or Units)

or Programs2

Plans or Programs3

Month #1 January 1st to 31st

$2 billion

Month #2 February 1st to 29th

$2 billion

Month #3 March 1st to 31st

$2 billion

Month #4 April 1st to 30th

$2 billion

Month #5 May 1st to 31st

7,460,000

$49.87

7,460,000

$1.4 billion

Month #6 June 1st to 30th

542,000

$50.26

542,000

$1.3 billion

Month #7 July 1st to 31st

870,000

$51.18

870,000

$1.3 billion

Month #8 August 1st to 31st

11,445,000

$50.01

11,445,000

$0.4 billion

Month #9 September 1st to 30th

950,000

$51.68

950,000

$0.3 billion

Month #10 October 1st to 31st

$0.3 billion

Month #11 November 1st to 30th

$0.3 billion

Month #12 December 1st to 31st

$0.3 billion

Total

$0.3 billion

1	All purchases made through announced plans.
2	On April 29, 2004 Royal Dutch and Shell Transport jointly announced the implementation of a share buyback program, with no expiration date. The maximum amount of the plan, including purchases of shares for the hedging of employee share options granted by companies within the Royal Dutch/ Shell Group of Companies, was $2 billion for the year 2004. The maximum amounts under the plan for purchases of shares in future years was to be determined in future years. On October 28, 2004 following the announcement of the proposed transaction described under the heading “Discussion and Analysis of Financial Condition and Results of Operations – Unification Proposal”, purchases under the program were suspended. On 3 February 2005, the buyback program was re-launched, in a maximum amount of up to $5 billion for the year 2005. The maximum amounts under the plan for purchases of shares in future years will be determined in future years based on a variety of factors, including debt levels and competing demands for cash in the years concerned. The unimplemented commitments in relation to 2004 have expired.
3	Total value of remaining potential purchases of both Royal Dutch Petroleum and The “Shell” Transport and Trading Company, p.l.c. stock by these companies and other members of the Royal Dutch/ Shell Group of Companies as at the end of each month

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The “Shell” Transport and Trading Company, Public Limited Company

Control of Registrant

On October 28, 2004, the Royal Dutch and Shell Transport Boards announced that they had unanimously agreed to propose to their shareholders a transaction through which each Parent Company will become a subsidiary of Royal Dutch Shell plc, which will become a publicly-listed company incorporated in England and Wales and headquartered and tax resident in the Netherlands. Please refer to “Discussion and Analysis of Financial Condition and Results of Operations – Unification Proposal” for additional information on this transaction.

Nature of Trading Market

American Depositary Receipts representing New York Shares are listed and traded on the New York Stock Exchange and are also admitted to unlisted trading privileges on the Boston, Cincinnati, Midwest, Pacific and Philadelphia Stock Exchanges. The depositary receipts are issued, cancelled and exchanged at the office of The Bank of New York, 101 Barclay Street, New York, NY 10286, as depositary under a deposit agreement between Shell Transport and the depositary and the holders of receipts.

Each New York Share represents six 25p Ordinary shares of Shell Transport deposited under the deposit agreement. At March 29, 2005, there were outstanding 80,158,786 New York Shares representing approximately 5.00% of the Ordinary share capital of Shell Transport, held by 2,000 holders of record.

At March 29, 2005 there were 3,121,170 Ordinary shares of 25p each representing approximately 0.03% of the Ordinary share capital of Shell Transport held by 901 holders of record registered with an address in the United States.

The following tables set forth the high and low closing sales prices for Shell Transport’s registered Ordinary shares (of 25p nominal value) on the London Stock Exchange and for Shell Transport’s New York Shares (of £1.50 nominal value) on the New York Stock Exchange for the periods specified:

Period
London										New York
		High				Low				High				Low
		£				£				$				$
2000			6.27				4.12				54.06				40.00
2001			6.38				4.30				53.65				38.72
2002			5.41				3.70				47.03				34.59
2003			4.40				3.32				45.19				32.28
2004			4.51				3.46				51.70				39.12

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Period
London										New York
		High				Low				High				Low
		£				£				$				$
2003
1st Quarter			4.23				3.32				41.25				32.28
2nd Quarter			4.40				3.70				43.18				35.81
3rd Quarter			4.15				3.69				40.25				37.30
4th Quarter			4.17				3.63				45.19				37.50
2004
1st Quarter			4.19				3.46				46.17				39.12
2nd Quarter			4.19				3.47				46.36				39.85
3rd Quarter			4.35				3.87				47.15				42.58
4th Quarter			4.51				4.05				51.70				44.37

Period
London										New York
		High				Low				High				Low
		£				£				$				$
2004
September			4.35				4.04				47.15				43.96
October			4.51				4.05				48.50				44.37
November			3.51				4.24				51.03				46.92
December			4.48				4.26				51.70				49.49
2005
January			4.67				4.39				52.70				49.78
February			4.97				4.65				57.34				52.52
March (through March 29)			5.08				4.73				58.72				53.40

At March 29, 2005, there were 350 First Preference shares of £1 each representing approximately 0.01% of the issued shares of the class held by two holders of record registered with an address in the United States of America. At March 29, 2005, there were 1,225 Second Preference shares of £1 each representing approximately 0.01% of the issued shares of the class held by 6 holders of record registered with an address in the USA. (Reference is made to Note 9 on page S11 for additional information on the Preference shares).

Memorandum and Articles of Association

General

Directors

(1)	a Director shall not vote or be counted in the quorum in respect of any matter in which he is materially interested including any matter related to his own compensation;
(2)	the Directors may exercise Shell Transport’s power to borrow provided that the borrowings of Shell Transport and its subsidiaries (if any) shall not without the consent of an ordinary resolution of shareholders of Shell Transport exceed the nominal amount of the issued and paid-up share capital of Shell Transport (these powers relating to borrowing may only be varied by special resolution of shareholders);
(3)	Directors over age 70 must retire at each Annual General Meeting, but are eligible for re-election; and
(4)	Directors are not required to hold shares of Shell Transport to be qualified.

Rights attaching to shares

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Transport’s Ordinary shares are entitled to receive such dividends as may be declared by the shareholders in general meeting, rateably according to the amounts paid up on such shares, provided that the dividend cannot exceed the amount recommended by the Directors.

Shell Transport’s Board of Directors may pay holders of Ordinary shares such interim dividends as appear to it to be justified by Shell Transport’s financial position. If authorised by an ordinary resolution of the shareholders, the Board of Directors may also make payment of a dividend in whole or in part by the distribution of specific assets (and in particular of paid-up shares or debentures of any other company).

Any dividend unclaimed after 12 years from the date the dividend was due for payment will be forfeited and will revert to Shell Transport.

The holders of Ordinary shares have unrestricted rights to participate in distributions of dividend and capital subject to the rights of the holders of the First Preference shares and Second Preference shares as described below.

The First and Second Preference shares (the Preference shares) confer on the holders the right to a fixed cumulative dividend and rank in priority to Ordinary shares. The fixed dividend on the First Preference shares is payable at the rate of 5.5% per annum and the fixed dividend on the Second Preference shares is payable at the rate of 7% per annum. On a winding-up or repayment the Preference shares also rank in priority to the Ordinary shares for the nominal value of £1 per share (plus a premium, if any, equal to the excess of the daily average price for the respective shares quoted in the London Stock Exchange Daily Official List for a six month period preceding the repayment or winding-up) but do not have any further rights of participation in the profits or assets of Shell Transport.

(b) Voting rights and General Meetings of Shareholders

A poll may be demanded by any of the following:

–	the chairman of the meeting;
–	at least five shareholders entitled to vote at the meeting;
–	any shareholder or shareholders representing in the aggregate not less than one-tenth of the total voting rights of all shareholders entitled to vote at the meeting; or
–	any shareholder or shareholders holding shares conferring a right to vote at the meeting on which there have been paid-up sums in the aggregate equal to not less than one-tenth of the total sum paid up on all the shares conferring that right or such shares with a nominal value of not less than £3,000.

A proxy form will be treated as giving the proxy the authority to demand a poll, or to join others in demanding one.

The necessary quorum for a general meeting is ten persons carrying a right to vote upon the business to be transacted, whether present in person or by proxy.

Matters are transacted at General Meetings of Shareholders by the proposing and passing of resolutions of which there are three kinds:

–	an ordinary resolution, which includes resolutions for the election of Directors, the approval of financial statements, the payment of dividends, the appointment of auditors, the increase of authorised share capital or the grant of authority to allot shares;
–	a special resolution, which includes resolutions amending Shell Transport’s Memorandum and Articles of Association, disapplying statutory pre-emption rights or changing Shell Transport’s name; and
–	an extraordinary resolution, which includes resolutions modifying the rights of any class of Shell Transport’s shares at a meeting of the holders of such class or relating to certain matters concerning Shell Transport’s winding up.

An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum.

Special and extraordinary resolutions require the affirmative vote of not less than three-fourths of the persons voting at a meeting at which there is a quorum.

In the case of an equality of votes, whether on a show of hands or on a poll, the chairman of the meeting is entitled to cast the deciding vote in addition to any other vote he may have.

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Annual General Meetings must be convened upon advance written notice of 21 days. Other meetings must be convened upon advance written notice of 21 days for the passing of a special resolution and 14 days for any other resolution. The notice must specify the nature of the business to be transacted. The Board of Directors may if they choose make arrangements for shareholders who are unable to attend the place of the meeting to participate at other places.

Under English law, the Directors must convene an extraordinary general meeting of a company on the requisition of members holding not less than one-tenth of such paid-up capital of the company as carries the right of voting at general meetings of the company.

Preference shares do not have voting rights unless their dividend is in arrears or the proposal concerns a reduction of capital, winding-up, an alteration of the Articles of Association or otherwise directly affects their class rights.

Major shareholders have no differing voting rights.

(c)  Rights in a winding-up

–	after the payment of all creditors including certain preferential creditors, whether statutorily preferred creditors or normal creditors; and
–	subject to the rights attached to the First and Second Preference shares (see “Dividend rights and rights to share in the company’s profits” on pages 95 and 96) and to any special rights attaching to any other class of shares, of which there are currently none, is to be distributed among the holders of Ordinary shares according to the amounts paid-up on the shares held by them. This distribution is generally to be made in cash. A liquidator may, however, upon the adoption of an extraordinary resolution of the shareholders, divide among the shareholders the whole or any part of Shell Transport’s assets in kind.

(d) Redemption provisions

(e) Sinking fund provisions

(f)  Liability to further calls

(g)	Discriminating provisions

Variation of rights

Limitations on rights to own shares

Change of control

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Threshold for disclosure of share ownership

(i)	withdrawal of right to attend and vote at general meetings;
(ii)	no transfer shall be registered in respect of the shares; or
(iii)	no dividend shall be paid in respect of the shares.

Capital changes

New York Shares (American Depositary Receipts)

Exchange Controls and other Limitations Affecting Security Holders

Taxation

There is generally no withholding tax on UK dividends.

The USA and UK have concluded a new tax treaty which came into force on March 31, 2003. There was a one-year phase-in period, ending April 30, 2004, for the new Tax Treaty. For dividends received between May 1, 2003 and April 30, 2004 qualifying shareholders can either elect to report their dividends under the old Tax Treaty or make no election in which case the dividends will be treated in line with the new treaty. If an election is made, all the provisions of the former treaty will apply.

The former Double Taxation Convention between the UK and the USA provided for the payment to qualifying US residents of an amount equal to the relevant UK tax credit, less UK income tax at the rate of 15% on the sum of the dividend and the tax credit. With a tax credit of 10/90ths the withholding tax at 15% would be more than the tax credit. In such a case the payment was treated as being reduced to zero. The shareholder was, however, able to treat the amount of the withholding tax as a tax credit that could, subject to certain limitations, be applied against that shareholder’s US income tax liability.

Under the new tax treaty there is no UK tax credit and offsetting withholding tax with the result that the cash amount of the dividend is the gross dividend and there is no possibility of claiming a credit for UK tax against the US tax liability.

The entitlement to a tax credit of a shareholder who is resident neither in the UK nor in the USA depends upon such double tax arrangements as exist between the UK and the country of the shareholder’s residence.

Taxation on Capital Gains

Inheritance Tax

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part of the business property of a permanent establishment of the individual in the UK, or, in the case of a shareholder who performs independent personal services, pertain to a fixed base situated in the UK.

Stamp Duty Reserve Tax

Management

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The Directors, Managing Directors, and officers of Shell Transport at March 29, 2005 were:

Teymour Alireza#

Malcolm Brinded CBE FREng

Sir Peter Burt FRSEøS

Dr Eileen Buttle CBE#

Luis Giustiø

Mary R. (Nina) Hendersonø+

Sir Peter Job KBE+S

Lord Kerr of Kinlochard GCMG+S

Sir Mark Moody-Stuart KCMG#

Peter Voser

Company Secretary, Shell Transport

Key to Committee membership

ø	Group Audit Committee
+	Remuneration and Succession Review Committee
#	Social Responsibility Committee

s	Shell Transport Nomination Committee

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Directors offering themselves for election or re-election

Arrangements and/or relationships between Directors and officers

Share ownership

		Share Optionsa				25p Ordinary shares
Managing Directors
Malcolm Brindedb			1,313,550				444,423	c
Peter Voser			800,000				257,779	c
Non-executive Directors
Teymour Alireza			–				29,093
Sir Peter Burt			–				10,000
Dr Eileen Buttle			–				3,400
Luis Giusti			–				2,400
Nina Henderson			–				9,000
Sir Peter Job			–				3,570
Lord John Kerr of Kinlochard			–				10,000
Sir Mark Moody-Stuart			806,000				600,000
Lord Oxburgh			–				6,438

a	Additional information is included in the “Remuneration Report – Stock options” on page S23.
b	Excluding 10,741 Royal Dutch ordinary shares as per March 29, 2005, resulting from his participation in the Deferred Bonus Plan for Group Managing Directors in 2003 through the deferral of part of his 2002 bonus.
c	Includes awards under Long Term Incentive Plan.

Group Audit Committee

In February 2004, the Group Audit Committee established two discrete sub-committees to review and report to the Boards of either Shell Transport or Royal Dutch (as appropriate) on matters that are Parent Company specific. For Shell Transport such matters include the monitoring of the integrity of the Company’s financial statements, the regular review of the internal financial controls and corporate internal control and risk management systems and relations with the external auditor (including recommendations in relation to their appointment and removal, remuneration, effectiveness, and independence).

The Group Audit Committee is also responsible for the approval of all services to be provided by the external auditors KPMG and PricewaterhouseCoopers. This includes both audit and, to the extent permitted under applicable regulations, non-audit services. Under the guidelines adopted by the Group Audit Committee, certain specified categories of services may be contracted without pre-approval so long as the fee value for each contract does not exceed $500,000. These include permitted non-audit services such as tax compliance work, regulatory compliance work, certain advice on the tax treatment of proposed transactions, expatriate tax returns except where the expatriate has a financial reporting oversight role, among others. Other services must be specifically pre-approved. For urgent matters, the chairman of the Group Audit Committee is authorised to approve auditor engagements subject to review at the next Group Audit Committee meeting. Under the guidelines, permitted services must not present a conflict of interest, in addition, certain types of services will not normally be approved, including certain buy-side diligence services where it is likely to result in the audit firm later auditing its own work, advice on alternative deal structures for merger and acquisition transactions (although certain tax advice on deal structures proposed by the Group may be permitted), carve out accounting services and system assurance reviews and other internal control reviews, unless part of audit work.

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Membership of the Group Audit Committee as at March 29, 2005 is shown in the table below:

Appointed by the Board of Shell Transport
Sir Peter Burt
Luis Giusti
Nina Henderson

Appointed by the Supervisory Board of Royal Dutch
Aad Jacobs
Lawrence Ricciardi		Chairman of the Committee
Christine Morin-Postel

The membership of the Shell Transport Audit sub-committee comprises those Shell Transport directors appointed to the Group Audit Committee. For purposes of the U.S. Sarbanes-Oxley Act, Aad Jacobs, a supervisory director of Royal Dutch and a member of the Group Audit Committee, qualifies as an “audit committee financial expert” (as defined). No director of Shell Transport that is a member of the Group Audit Committee currently so qualifies, although Sir Peter Burt, a director of Shell Transport and member of the Group Audit Committee and the Shell Transport Audit sub-committee, qualifies under Dutch and UK corporate governance requirements as a director with “appropriate and recent relevant financial experience”, as does Mr Jacobs.

During 2004 there were a total of 23 meetings of the Group Audit Committee. Attendance at these meetings is shown in the table below.

Attendance
Members		Attendance
Lawrence Ricciardi		21
Sir Peter Burt		19
Luis Giusti		17
Nina Henderson		23
Aad Jacobs		23
Christine Morin-Postela		3

a	Christine Morin-Postel was appointed a member during the year and attended all meetings following her appointment.

A copy of the revised terms of reference of the Group Audit Committee (including the Shell Transport Audit sub-committee) can be found on the Shell website (www.shell.com/investor).

Non-audit services (Code Provision C.3.7)

Remuneration and Succession Review Committee

Social Responsibility Committee

Current membership of the Social Responsibility Committee is shown in the table below.

Appointed by the Board of Shell Transport
Dr Eileen Buttle		Chair of the Committee
Teymour Alireza
Sir Mark Moody-Stuart

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Appointed by the Supervisory Board of Royal Dutch
Maarten van den Bergh
Wim Kok
Jonkheer Aarnout Loudon

During 2004 the committee met three times. Attendance at these meetings is shown in the table below.

Attendance
Members		Attendance
Dr Eileen Buttle		3
Teymour Alireza		3
Maarten van den Bergh		2
Wim Kok		3
Jonkheer Aarnout Loudon		3
Sir Mark Moody-Stuarta		1

a	Sir Mark Moody-Stuart was appointed a member during the year and was unable to attend one of the two meetings held following his appointment.

Shell companies have long been open about the values and principles which guide them, and the Group’s Statement of General Business Principles has been publicly available since 1976. The latest revision in 1997 followed extensive internal and external consultation and now includes commitments to support fundamental human rights and to contribute to sustainable development.

The Shell Report 2004 which reviews how Group companies are living up to the Group’s Business Principles and contributing to sustainable development will be available at www.shell.com/shellreport following its publication at the end of May 2005.

Code of Ethics

Compensation of Directors and officers

Reference is made to the information given in the Remuneration section on pages S21 to S25 relating to Directors’ emoluments and service contracts (for Managing Directors) and letters of appointment (for non-executive Directors).

Shares under option and share purchase plan

As of March 29, 2005, an aggregate amount of 168,728,057 issued and outstanding Ordinary shares of Shell Transport were the subject of options under such plans.

The number of Ordinary shares of Shell Transport under option at March 29, 2005, and the option prices of the Ordinary shares at the date the options were granted, per share and in total, were as follows:

Plan

Option price

Number of shares

Average

Term

under option

per share

Total

(expiration dates)

Shell Petroleum N.V.

52,650,356

4.48

235,730,297

10 years

(10/12/07 – 04/11/14

)

The Shell Petroleum Company Limited

116,077,201

4.54

526,485,829

10 years

(10/12/07 – 06/05/14

)

Two Group companies, one in the Netherlands (Shell Petroleum N.V.) and one in the United Kingdom (The Shell Petroleum Company Limited) have restricted stock plans under which grants are made on a highly selective basis to senior staff. Group Managing Directors are not eligible to participate in the Restricted stock plans. A maximum of 250,000 Royal Dutch ordinary shares (or equivalent value in Shell Transport Ordinary shares) can be granted under the plans in any year. Shares are granted subject to a three-year restriction period and the number of the shares awarded is based on the fair market value at the start of the restricted period. The shares, together with

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additional shares equivalent to the value of the dividends payable over the restriction period, are released to the individual at the end of the three-year period. The total number of outstanding Ordinary shares of Shell Transport under the restricted stock plans as of March 29, 2005 is 852,177, of which 46,110 shares relate to dividend shares.

Two Group companies, one in the Netherlands (Shell Petroleum N.V.) and one in the United Kingdom (The Shell Petroleum Company Limited) have long-term incentive plans under which shares are awarded conditionally once a year to Group Managing Directors and selected senior executives. The plan allows for a maximum grant with a face value of two times base pay. The value of shares conditionally awarded will reflect competitive market practice. Release may occur three years after grant. The entire award is expected to be released only in cases of exceptional performance. The total number of outstanding Ordinary shares of Shell Transport conditionally awarded under the long-term incentive plans as of March 29, 2005 is 1,181,187, of which 53,933 shares relate to dividend shares up to date. None of the shares will result in beneficiary ownership until they are released.

The Global Employee Share Purchase Plan enables employees to make contributions, which are applied quarterly to purchase Royal Dutch or Shell Transport Ordinary shares at current market value. If the acquired shares are retained in the Plan until the end of the twelve-month cycle the employee receives an additional 15% share allocation. In the USA a variant of the plan is operated where contributions are applied to buy Royal Dutch shares at the end of the twelve-month cycle. The purchase price is the lower of the market price on the first or last trading day of the cycle reduced by 15%. Group Managing Directors are not eligible to participate in the Global Employee Share Purchase Plan. At March 29, 2005, 25,816 Shell Transport Ordinary shares were held by Group companies in connection with this Plan.

Shell Sharesave Scheme

At March 29, 2005 there were 10,233,483 issued and outstanding Ordinary shares of Shell Transport under the option to such employees pursuant to the rules of those schemes at prices between £3.55 and £5.66.

No issue of new shares is involved under any of the plans or schemes mentioned above.

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Purchases of Equity Securities in Shell Transport by Shell Transport and Affiliated Purchasers

(c) Total Number of

(d) Maximum Number

(a) Total

Shares (or Units)

(or Approximate US Dollar Value)

Number of

Purchased as Part of

of Shares (or Units) that May

Shares (or Units)

(b) Average Price Paid Per

Publicly Announced Plans

Yet Be Purchased Under the

Period

purchased1

Share (or Units)

or Programs2

Plans or Programs3

Month #1 January 1st to 31st

$2 billion

Month #2 February 1st to 29th

$2 billion

Month #3 March 1st to 31st

$2 billion

Month #4 April 1st to 30th

$2 billion

Month #5 May 1st to 31st

34,175,000

$7.22

34,175,000

$1.4 billion

Month #6 June 1st to 30th

2,000,000

$7.22

2,000,000

$1.3 billion

Month #7 July 1st to 31st

3,500,000

$7.25

3,500,000

$1.3 billion

Month #8 August 1st to 31st

39,515,000

$7.23

39,515,000

$0.4 billion

Month #9 September 1st to 30th

3,200,000

$7.56

3,200,000

$0.3 billion

Month #10 October 1st to 31st

$0.3 billion

Month #11 November 1st to 30th

$0.3 billion

Month #12 December 1st to 31st

$0.3 billion

Total

$0.3 billion

1	All purchases made through announced plans.
2	On April 29, 2004 Royal Dutch and Shell Transport jointly announced the implementation of a share buyback program, with no expiration date. The maximum amount of the plan, including purchases of shares for the hedging of employee share options granted by companies within the Royal Dutch/ Shell Group of Companies, was $2 billion for the year 2004. The maximum amounts under the plan for purchases of shares in future years was to be determined in future years. On October 28, 2004 following the announcement of the proposed transaction described under the heading “Discussion and Analysis of Financial Condition and Results of Operations — Unification Proposal”, purchases under the program were suspended. On 3 February 2005, the buyback program was re-launched, in a maximum amount of up to $5 billion for the year 2005. The maximum amounts under the plan for purchases of shares in future years will be determined in future years based on a variety of factors, including debt levels and competing demands for cash in the years concerned. The unimplemented commitments in relation to 2004 have expired.
3	Total value of remaining potential purchases of both Royal Dutch Petroleum and The “Shell” Transport and Trading Company, p.l.c. stock by these companies and other members of the Royal Dutch/ Shell Group of Companies as at the end of each month

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Index to the Financial Statements and Exhibits

(A) Financial Data*		Page
Royal Dutch Petroleum Company:
Report of the Registered Independent Public Accounting Firm			R1
Financial Statements
Profit and Loss Account			R2
Statement of Appropriation of Profit			R2
Earnings per share			R2
Balance Sheet			R3
Statement of Cash Flows			R3
Notes to the Financial Statements			R4
Remuneration Report			R13
The “Shell” Transport and Trading Company, Public Limited Company:
Report of the Registered Independent Public Accounting Firm			S1
Financial Statements
Profit and Loss Account			S2
Earnings per 25p Ordinary share			S2
Balance Sheet			S2
Statement of Total Recognised Gains and Losses			S3
Statement of Retained Profit			S3
Statement of Cash Flows			S3
Notes to the Financial Statements			S5
Directors’ Remuneration Report			S16
Royal Dutch/Shell Group of Companies:
Report of the Registered Independent Public Accounting Firms			G1
US GAAP Financial Statements
Statement of Income			G2
Statement of Comprehensive Income and Parent Companies’ interest in Group net assets			G2
Statement of Assets and Liabilities			G3
Statement of Cash Flows			G4
Notes to the Financial Statements			G5
Report of the Registered Independent Public Accounting Firms			G39
Netherlands GAAP Financial Statements
Statement of Income			G40
Statement of Comprehensive Income and Parent Companies’ interest in Group net assets			G40
Statement of Assets and Liabilities			G41
Statement of Cash flows			G42
Notes to the Netherlands GAAP Financial Statements			G43
Supplementary information – Oil and Gas (unaudited)			G49
Reserves			G49
Standardised measure of discounted future cash flows			G60
Supplementary Information – Derivatives and other Financial Instruments and Derivative Commodity Instruments			G62

(B) Exhibits			E1
1.1  Articles of Association of Royal Dutch (incorporated by reference to Exhibit 1.1 to the Annual Report on Form 20-F (Commission Files 1-3788 and 1-4039) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on March 31, 2003)
1.2  Memorandum and Articles of Association of Shell Transport (incorporated by reference to the Report of Foreign Issuer on Form 6-K (Commission File No. 1-4039) of Shell Transport furnished to the Securities and Exchange Commission on June 21, 2002)
4.1  Adjustment Agreement between Royal Dutch and Shell Transport dated July 5, 1907, and certain amendments thereto (incorporated by reference to Exhibit 4.1 to the Annual Report on Form 20-F (Commission File Nos. 1-3788 and 1-4039) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on March 31, 2003)
4.2  Shell Petroleum N.V. Stock Option Plan, as amended (incorporated by reference to the Post-Effective Amendment No. 1 to Registration Statement on Form S-8 (Registration No. 333-7590) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on June 28, 2001)
4.3  Shell Petroleum Company Limited Stock Option Plan (1967), as amended (incorporated by reference to the Post-Effective Amendment No. 1 to Registration Statement on Form S-8 (Registration No. 333-7590) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on June 28, 2001)
8    Significant Group companies as at December 31, 2004			E2
23.1 Consent of KPMG Accountants N.V., The Hague			E3
23.2 Consent of PricewaterhouseCoopers LLP, London			E4
23.3 Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E5
23.4 Consent of KPMG Accountants N.V., The Hague			E6
23.5 Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E7
23.6 Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E8
23.7 Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E9
99.1 Section 302 Certification of Royal Dutch			E10
99.2 Section 302 Certification of Royal Dutch			E11
99.3 Section 302 Certification of Shell Transport			E12
99.4 Section 302 Certification of Shell Transport			E13
99.5 Section 906 Certification of Royal Dutch			E14
99.6 Section 906 Certification of Shell Transport			E15

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*

Schedules not included have been omitted because they are not applicable or not required. Alternatively, the required information is shown in the financial statements or notes thereto. Summarised financial information in aggregate for majority-owned subsidiaries not consolidated and 50% or less-owned persons, the investments in which are accounted for by the equity method, has been provided in the notes to the financial statements. Separate financial statements for any such individual majority-owned subsidiary not consolidated or 50% or less-owned person, the investments in which are accounted for by the equity method, have been omitted because none constitutes a “significant subsidiary”.

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Royal Dutch Petroleum Company

To: Royal Dutch Petroleum Company

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by the Board of Management in the preparation of the Financial Statements, as well as evaluating the overall Financial Statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Financial Statements referred to above present fairly, in all material respects, the financial position of Royal Dutch Petroleum Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in accordance with accounting principles generally accepted in the Netherlands.

The report of the registered independent public accounting firms on the 2004, 2003 and 2002 Financial Statements of the Royal Dutch/Shell Group of Companies, appears on page G39.

As discussed in Note 3 on pages R5 and R6, the Royal Dutch Petroleum Company has restated its Financial Statements for the two years ended December 31, 2003, to correct for the financial impact of the Second Reserves Restatement.

Accounting principles generally accepted in the Netherlands vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such difference is presented in Note 17 on page R11.

 

 

/s/ KPMG Accountants N.V.

 

March 29, 2005

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Financial Statements

Profit and Loss Account										€ million
										2003				2002
		Note				2004				As restated				As restated
Share in the net income of companies of the Royal Dutch/Shell Group from continuing operations							7,958				6,398				5,957
Share in the net income of companies of the Royal Dutch/Shell Group from discontinued operations			2				754				13				119
Share in the net income of companies of the Royal Dutch/Shell Group			4				8,712				6,411				6,076
less Administrative expenses							8				8				5
							8,704				6,403				6,071
Interest income							10				18				28
Profit before taxation							8,714				6,421				6,099
less Taxation			5				1				3				8
Profit after taxation							8,713				6,418				6,091

Statement of Appropriation of Profit										€ million
										2003				2002
		Note				2004				As restated				As restated
Profit after taxation							8,713				6,418				6,091
Taken from/(to) Statutory investment reserve			6				(4,870	)			(3,543	)			(2,759	)
Undistributed profit at beginning of year							2,909				3,650				4,712
Final dividend distributed							(2,125	)			(2,084	)			(2,042	)
(Repurchase)/cancellation of share capital							(375	)			9				(847	)
Unclaimed dividends forfeited							1				1				1
Available for distribution							4,253				4,451				5,156
less Interim dividenda							1,562				1,542				1,506
Undistributed profit at end of yearb							2,691				2,909				3,650

Earnings per share											€
											2003				2002
			Note				2004				As restated				As restated
	Basic earnings per ordinary share from continuing operations							3.94				3.14				2.90
	Basic earnings per ordinary share from discontinued operations							0.37				0.01				0.06
Basic earnings per ordinary share				13				4.31				3.15				2.96
	Diluted earnings per ordinary share from continuing operations							3.93				3.14				2.90
	Diluted earnings per ordinary share from discontinued operations							0.37				0.01				0.06
Diluted earnings per ordinary share				13				4.30				3.15				2.96

a	Including 4% cumulative preference dividend for 2004 amounting to €26,880 on priority shares (2003: €26,880; 2002: €26,880).
b	Before second interim dividend of €2,165 million (second interim dividend 2003: €2,125; final dividend 2002: €2,084 million).

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Balance Sheet (before appropriation of profit)											€ million
											Dec 31,
							Dec 31,				2003
			Note				2004				As restated
Fixed assets
Financial fixed assets
	Investments in companies of the Royal Dutch/ Shell Group			6				37,018				34,349
	Investment in associated company			7				179				–
Current assets
Receivables
	Dividends receivable from companies of the Royal Dutch/ Shell Group							2,130				2,449
	Other receivables from companies of the Royal Dutch/ Shell Group							44				363
	Other receivables			8				35				36
Cash and cash equivalents								252				8
								2,461				2,856
Current liabilities
	Other liabilities			9				13				10
Current assets less current liabilities								2,448				2,846
Total assets less current liabilities								39,645				37,195
Shareholders’ equity
Paid-up capital				10
	Ordinary shares							1,165				1,166
	Priority shares							1				1
								1,166				1,167
Share premium reserve								1				1
Investment reserves				6
	Statutory							25,185				22,707
	Currency translation differences							1,848				486
	Other							8,739				9,910
								35,772				33,103
Other statutory reserves				11				15				15
Undistributed profit								2,691				2,909
								39,645				37,195

Statement of Cash Flows										€ million
		2004				2003				2002
Returns on investments and servicing of finance
Dividends received from Group companies			4,162				3,401				4,446
Interest received			10				18				32
Other			315				212				(587	)
Net cash inflow/(outflow) from returns on investments and servicing of finance			4,487				3,631				3,891
Taxation
Tax (paid)/recovered			(1	)			(4	)			(8	)
Financing
Repurchase of share capital, including expenses			(376	)			–				(889	)
Investment in associated company			(179	)			–				–
Dividends paid			(3,687	)			(3,626	)			(3,536	)
Increase/(decrease) in cash and cash equivalents			244				1				(542	)
Cash at January 1			8				7				549
Cash at December 31			252				8				7

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Notes to the Financial Statements

1 The Company

The Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies as presented on pages G40 to G42 and the Notes thereto on pages G5 to G37, G43 to G48 form part of the Notes to the Annual Accounts.

Arrangements between Royal Dutch and Shell Transport provide, inter alia, that notwithstanding variations in shareholdings, Royal Dutch and Shell Transport shall share in the aggregate net assets and in the aggregate dividends and interest received from Group companies in the proportion of 60:40, respectively. It is further arranged that the burden of all taxes in the nature of, or corresponding to, an income tax leviable in respect of such dividends and interest shall fall in the same proportion.

Unification Proposal

2	Accounting principles

The Financial Statements of Royal Dutch are reported in euro, while the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies are reported in US dollars. Notes 4, 6, 13 and 17 to these Financial Statements contain currency translations of certain items presented in US dollars in the Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies into euro.

References are made to the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies in these Notes to facilitate an understanding of the relationships between the Financial Statements of Royal Dutch and the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies, particularly as they relate to Royal Dutch’s 60% interest in net income and net assets of companies of the Royal Dutch/ Shell Group of Companies.

The investments in and the share in the net income of companies of the Royal Dutch/Shell Group are accounted for by the equity method (see also Notes 4 and 6). Accounting principles used by the Group are given in Note 31 to the Netherlands GAAP Financial

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Statements of the Royal Dutch/Shell Group of Companies on page G43. Investments in associated companies are accounted for by the equity method.

Current assets and liabilities are stated at their nominal value. Assets and liabilities in foreign currencies are translated into euros at year-end rates of exchange, whereas results for the year are translated at average rates. For the Profit and Loss Account euros are translated from US dollars at the weighted average rate of exchange. Currency translation differences arising from translating the investments in companies of the Royal Dutch/Shell Group are taken to Investment reserves (see Note 6).

Administrative expenses, Interest income and Taxation are stated at the amounts attributable to the respective financial years.

The Group separately reports income from discontinued operations (see Notes 4 and 32 to the Financial Statements of the Royal Dutch/ Shell Group of Companies). As a consequence, the Company also separately reports its share in the net income of discontinued operations of companies of the Royal Dutch/ Shell Group and the basic- and diluted earnings per ordinary share from discontinued operations. Amounts reported in previous years have been reclassified. Royal Dutch’s share in the net income of companies of the Royal Dutch/Shell Group from discontinued operations amounted to €13 million in 2003 (2002: €119 million). These amounts are based on Royal Dutch’ 60% share in the Net Income from discontinued operations of companies of the Royal Dutch/Shell Group of $25 million in 2003 (2002: $187 million) translated into euros at the average rate of exchange for the year of 1$ = €0.90 (2002: 1$ = €1.06).

Under a 2002 EU Regulation, publicly-listed companies in the European Union will be required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) from 2005. The 2005 Financial Statements of the Group or, subject to completion of the transaction described in Note 1, of its successor, will be prepared under IFRS and will include comparative data for 2004, together with reconciliations to opening balances as at January 1, 2004 and to 2004 data previously published in accordance with accounting principles generally accepted in the United States (US GAAP). With effect from January 1, 2005 Royal Dutch intends to prepare its consolidated Financial Statements under International Financial Reporting Standards.

3 Restatement of previously issued Financial Statements

Following the January 9, 2004 announcement of the initial reserves recategorisation, the Group Audit Committee (GAC) appointed Davis Polk & Wardwell to lead an independent review of the facts and circumstances surrounding the recategorisation, and to report its findings and any proposed remedial actions to the GAC for its consideration. Based largely on the Davis Polk & Wardwell report, the Parent Companies, Royal Dutch and Shell Transport, determined that the principal causes that permitted the initial booking and maintenance of the volumes impacted by the First Reserves Restatement as proved reserves are as follows:

–	the Group’s guidelines for booking proved reserves were inadequate in several respects, including (i) containing inconsistencies with the SEC’s rules and published guidance relating to proved reserves and (ii) failing to clearly and sufficiently impact these requirements and guidance to users of the guidelines. In addition, users of the guidelines in certain cases misapplied or disregarded SEC rules and published guidance and in some cases only applied changes in the guidelines prospectively rather than retrospectively. There was also insufficient knowledge and training among users of the guidelines of the SEC requirements relating to proved reserves;
–	executives and employees encouraged the booking of proved reserves, while discouraging the debooking of previously booked reserves. This fostered an atmosphere that failed to emphasise the paramount importance of the compliance element of proved reserves decisions; and
–	there were other material weaknesses in the Group’s controls relating to the booking of proved reserves, including insufficient resources allocated to the Group Reserves Auditor and Group Reserves Co-ordinator functions, a lack of clarity in the allocation of responsibilities between the Group Reserves Auditor and the Group Reserves Co-ordinator and a lack of direct reporting responsibility of the Group Reserves Auditor to the Group internal audit function and of the business Chief Financial Officers to the Group Chief Financial Officer.

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Second Reserves Restatement

Second Financial Restatement

The effect on profit after taxation and the Shareholder’s equity of Royal Dutch, is as follows:

		€ million
										Shareholders’
		Profit after taxation								equity
		2003				2002				Dec 31, 2003
As previously reported			6,520				6,108				37,362
Second Reserves Restatement			(100	)			(42	)			(166	)
Currency Translation effect			(2	)			25				(1	)
As restated			6,418				6,091				37,195

4	Share in the net income of companies of the Royal Dutch/Shell Group

The dividend for 2004 distributed and yet to be distributed by Group companies to Royal Dutch amounted to €3,842 million, the equivalent of $4,793 million (2003: €2,868 million, the equivalent of $3,396 million).

5 Taxation

6 Investments and reserves

Royal Dutch’s investments in the companies of the Royal Dutch/Shell Group are stated at an amount equal to its 60% share in Group net assets, translated into euros at the year-end rate of exchange. Movements during the year are translated at different rates of exchange. The resulting difference from movements in the US dollar/euro rate is included in currency translation differences.

The difference of €35,772 million between the cost of the investments and the amounts at which the investments are stated in the Balance Sheet has been taken to Investment reserves.

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The Statutory investment reserve comprises Royal Dutch’s 60% share in the undistributed net income of Group companies which has arisen as from January 1, 1984; Royal Dutch’s share in the undistributed net income of Group companies accumulated until that date is included in Investment reserves – Other.

Royal Dutch’s 60% share in the cumulative Group currency translation differences arises as a result of translating the assets and liabilities of non-US dollar companies to US dollars at year-end rates of exchange and is shown under Investment reserves as currency translation differences. Distribution from Group companies and loss on sale of Parent Companies’ shares are translated at a rate of exchange used for distribution of dividends.

The net increase/decrease in Parent Companies’ shares held by Group companies results from sales and purchases of these shares minus dividends received on these shares, translated at the average rate of exchange for the year.

Other comprehensive income, net of tax, consists of currency translation differences, unrealised gains/losses on securities and on cash flow hedges and minimum pension liability adjustments and is translated at the year-end rate (see Note 38 to the Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies on pages G46 to G48).

Movements in Investments and Investment reserves
				$ million								€ million
																Investment reserves
				60% interest																Currency
				in Group				Exchange rate				Royal Dutch								translation
				net assetsa				(€/$)				investments				Statutory				differences				Other				Total
Balance at December 31, 2002 (as restated)					36,094				0.96				34,490				23,052				(2,370	)			12,562				33,244
	Cumulative effect of change in accounting for asset retirement obligationsb				153				0.96				146				146												146
Balance at January 1, 2003					36,247				0.96				34,636				23,198				(2,370	)			12,562				33,390
Movements during the year 2003
		Share in the net income of Group companies			7,134				0.90				6,411
		Distribution to Royal Dutch			(3,396	)			0.84				(2,868	)
	Undistributed net income of Group companies				3,738				0.95				3,543				3,543												3,543
	Loss on sale of Parent Companies’ shares				(1	)			0.95				(1	)			(1	)											(1	)
	Net (increase)/decrease in Parent Companies’ shares held by Group companies				(378	)			0.89				(335	)											(335	)			(335	)
	Other comprehensive income, net of tax				3,720				0.79				2,951				499				2,452								2,951
	Translation effect arising from movements in US dollar/euro rate												(6,445	)			(4,532	)			404				(2,317	)			(6,445	)
Balance at December 31, 2003 (as restated)					43,326				0.79				34,349				22,707				486				9,910				33,103
Movements during the year 2004
		Share in the net income of Group companies			10,818				0.81				8,712
		Distribution to Royal Dutch			(4,793	)			0.80				(3,842	)
	Undistributed net income of Group companies				6,025				0.81				4,870				4,870												4,870
	Net (increase)/decrease in Parent Companies’ shares held by Group companies				(455	)			0.81				(366	)											(366	)			(366	)
	Other comprehensive income, net of tax				1,586				0.73				1,163				(236	)			1,399								1,163
	Translation effect arising from movements in US dollar/euro rate												(2,998	)			(2,156	)			(37	)			(805	)			(2,998	)
Balance at December 31, 2004					50,482				0.73				37,018				25,185				1,848				8,739				35,772

a	See Note 33 to the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies for the impact of the differences between US GAAP and Netherlands GAAP on Group net assets and net income. See Note 38 of the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies for the determination of Royal Dutch’s 60% interest in Group net assets and movements therein, including movements resulting from Group net income and distributions to the Parent Companies.
b	This relates to a change in Group accounting policies in 2003 for asset retirement obligations which is recorded as an adjustment to the opening balance of net assets in 2003. Prior periods have not been restated due to the absence of comparative data for 2002.

As the amounts dealt with under Investment reserves have been, or will be, substantially reinvested by the companies concerned, it is not meaningful to provide for taxes on possible future distributions out of earnings retained by those companies; no such provision has therefore been made.

The movements during the year in the value of the Group reporting currency (US dollar) against the Royal Dutch reporting currency (euro) lead to currency translation differences.

7 Investment in associated company

The aggregate amount of the paid up capital of RDS Holding at December 31, 2004 is €299.1 million.

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8 Other receivables						€ million
		Dec 31,				Dec 31,
		2004				2003
Dividend tax receivable			35				36
Other receivables			–				–
			35				36

9 Other liabilities						€ million
		Dec 31,				Dec 31,
		2004				2003
Dividends			6				8
Accounts payable			6				2
Corporation tax			1				–
			13				10

10 Share capital

Share capital
Number of shares							€
Ordinary shares of N.fl.1.25/€0.56
At December 31, 2002				2,099,285,000				1,175,599,600
	Cancelled during 2003			(15,785,000	)			(8,839,600	)
At December 31, 2003				2,083,500,000				1,166,760,000
	Cancelled during 2004			(1,775,000	)			(994,000	)
At December 31, 2004				2,081,725,000				1,165,766,000
Priority shares of N.fl.1,000/€448
At December 31, 2002				1,500				672,000
At December 31, 2003				1,500				672,000
At December 31, 2004				1,500				672,000
Total ordinary and priority shares
At December 31, 2003				2,083,501,500				1,167,432,000
At December 31, 2004				2,081,726,500				1,166,438,000

On June 17, 2004, the Board of Directors of Royal Dutch announced that it will propose to its annual meeting of shareholders to be held on June 28, 2005 to abolish the priority shares.

11 Other statutory reserves

12 Royal Dutch shares held by Group companies

		Number of shares				€ million
										Royal Dutch
										60% interest
										in the
						Book value				book value
At December 31, 2003			50,280,082				2,394				1,436
Purchases			12,184,414				501				301
Deliveries and other movements			545,456				(115	)			(69	)
At December 31, 2004			61,919,040				2,780				1,668

These movements relate to the granting and exercise of stock options and to other incentive compensation plans as mentioned in Note 23 to the Financial Statements of the Royal Dutch/ Shell Group of Companies.

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13 Earnings per share

The diluted earnings per share are based on the same profit figures. For this calculation the weighted number of shares is increased by 2,283,163 for 2004 (2003: 674,210; 2002: 442,580). These numbers relate to share options schemes as mentioned above.

Amounts reported in previous years have been reclassified following the separate reporting of income from discontinued operations (see Note 2). The basic earnings per ordinary share from discontinued operations of the Royal Dutch/Shell Group of Companies amounted to €0.01 for 2003 (2002: €0.06). The diluted earnings per ordinary share from discontinued operations of the Royal Dutch/Shell Group of Companies amounted to €0.01 for 2003 (2002: €0.06).

Royal Dutch’s 60% interest in line items as derived from the Group

		€ million				$ million
Balance Sheet
2004:
Current assets			27,212				37,109
Non current assets			57,381				78,250
Current liabilities			(26,691	)			(36,398	)
Non current liabilities			(18,548	)			(25,294	)
Minority interests in Group companies (60% of Group amount on page G41 translated at year end rate on page R7)			(2,336	)			(3,185	)
Royal Dutch share of Group net assets (see pages R7-euro & G47-US dollar)			37,018				50,482
Other assets and liabilities of Royal Dutch			2,627
Net Assets			39,645
2003 (as restated):
Current assets			20,745				26,167
Non current assets			59,773				75,395
Current liabilities			(25,888	)			(32,654	)
Non current liabilities			(18,657	)			(23,533	)
Minority interests in Group companies (60% of Group amount on page G41 translated at year end rate on page R7)			(1,624	)			(2,049	)
Royal Dutch share of Group net assets (see page R7 – euro & G47-US dollar)			34,349				43,326
Other assets and liabilities of Royal Dutch			2,846
Net Assets			37,195
Profit and Loss account
2004:
Sales proceeds (Revenue)			163,104				202,513
Operating profit			15,306				19,004
Income from continuing operations			7,958				9,882
Income from discontinued operations			754				936
Net income for the year			8,712				10,818
Distribution for the year			3,842				4,793
2003 (as restated):
Sales proceeds (Revenue)			142,345				158,333
Operating profit			11,412				12,694
Income from continuing operations			6,398				7,119
Income from discontinued operations			13				15
Net income for the year			6,411				7,134
Distribution for the year			2,868				3,396
2002 (as restated):
Sales proceeds (Revenue)			138,514				130,972
Operating profit			11,256				10,643
Income from continuing operations			5,957				5,610
Income from discontinued operations			119				112
Net income for the year			6,076				5,722
Distribution for the year			3,317				3,261

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14 List of companies of the Royal Dutch/ Shell Group

15 Remuneration of members of the Supervisory Board and Managing Directors

Walter van de Vijver resigned as a Managing Director of Royal Dutch on March 3, 2004. The amount of remuneration he received whilst a Managing Director of the Company in 2004 is stated in the tables on pages R17 to R21. His employment terminated with effect from September 1, 2004. From March 4, 2004 to August 31, 2004 an amount of €589,939 was borne by the Royal Dutch/ Shell Group of Companies in respect of the remuneration he received as an employee of the Group.

For the amounts borne in 2004 by Royal Dutch and by companies of the Royal Dutch/Shell Group in respect of remuneration of the members of the Supervisory Board, reference is made to the relevant table on page R23. This table also includes amounts borne by companies of the Royal Dutch/Shell Group in respect of remuneration for two members of the Supervisory Board who served simultaneously as Directors of these companies.

In addition to the pensions from a pension fund, ten former Managing Directors receive retirement benefits for duties performed by them simultaneously in the past as Directors of Group companies, as referred to in the previous paragraph. These retirement benefits have not been insured but provisions have been made in respect thereof in accordance with applicable accounting principles.

The breakdown of these charges per former Managing Director is as follows:

€
		2004				2003
Drs M.A. van den Bergh			67,071				145,893
A.P. Bénard			28,443				42,165
Ir. J.H. Choufoer			32,956				55,381
Ir. J.M.H. van Engelshoven			43,903				80,712
R.M. Hart			49,146				80,399
Drs C.A.J. Herkströter			48,833				101,043
Ir. H. de Ruiter			63,835				124,019
Ir. K. Swart			13,741				19,664
Ir. L.C. van Wachem			61,751				115,672
Ir. E.G.G. Werner			22,545				32,621
Totala			432,224				797,569

a	These amounts differ from actual relevant pensions paid.

16 Employee numbers

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17 Reconciliation between Netherlands GAAP and US GAAP

																											€ million
			€
			Basic earnings per ordinary share												Net income												Net assets
																															Dec 31,
							2003				2002								2003				2002				Dec 31,				2003
			2004				As restated				As restated				2004				As restated				As restated				2004				As restated
In accordance with Netherlands GAAP				4.31				3.15				2.96				8,713				6,418				6,091				39,645				37,195
Adjustments for US GAAP:
Goodwill amortisation				0.04				0.04				0.04				81				90				76				200				137
Cumulative effect of change in accounting for asset retirement obligations								0.07												141
Recoverability of assets
	Impairments			0.11												220												200
	Reversal of impairments			(0.11	)											(226	)											(206	)
In accordance with US GAAP				4.35				3.26				3.00				8,788				6,649				6,167				39,839				37,332
less: Interest income less expenses and tax																(1	)			(7	)			(15	)
less: Current assets less current liabilities																												(2,627	)			(2,846	)
Share in net income and net assets in companies of the Royal Dutch/Shell Group (US GAAP)																8,787				6,642				6,152				37,212				34,486
Exchange rate (euro/$)																0.81				0.90				1.06				0.73				0.79
																											$ million
Share in net income and net assets in companies of the Royal Dutch/Shell Group (see Note 30 on page G37)																10,910				7,387				5,794				50,746				43,498

The table above reconciles Royal Dutch’s net income and net assets under Netherlands GAAP to US GAAP. In addition, the table shows the adjustments necessary to reconcile Royal Dutch’s net income and net assets under US GAAP to its 60% share of Group net income and net assets (as shown in Note 30 to the Group Financial Statements). These adjustments consist of the elimination of Parent Company net assets and net income, which are not included in the net assets or net income of the Royal Dutch/Shell Group of Companies, and currency translation.

The differences affecting basic earnings per share, net income and net assets between Netherlands GAAP, as applied to the preparation of these Financial Statements (and after giving effect to the restatement described in Note 3) and US GAAP are as follows:

(i) goodwill:

Under US GAAP, goodwill is not amortised but is tested for impairment annually or when certain events occur that indicate potential impairment. Under Netherlands GAAP, goodwill is amortised on a straight-line basis over its estimated useful economic life, which is assumed not to exceed 20 years unless there are grounds to rebut this assumption;

(ii) asset retirement obligations

Under US GAAP, a change in accounting for asset retirement obligations in 2003, was accounted for prospectively, with the cumulative effect of the change at the beginning of 2003 being reflected in 2003 net income. This change in accounting was also made under Netherlands GAAP. However, the cumulative effect of the change under Netherlands GAAP was reported as an adjustment to the opening balance of net assets and, due to the absence of comparative data, net income for prior years was not restated.

(iii) recoverability of assets

	(a)	impairments: Under US GAAP, only if an asset’s estimated undiscounted future cash flows are below its carrying amount is a determination required of the amount of any impairment based on discounted cash flows. There is no undiscounted test under Netherlands GAAP;

	(b)	reversals of impairments: Under US GAAP impairments are not reversed. Under Netherlands GAAP, a favourable change in the circumstances which resulted in an impairment would trigger the requirement for a redetermination of the amount of the impairment and any reversal is recognised in income.

18 Contingencies and litigation

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issues relating to the litigation, including the pending motions to dismiss on lack of jurisdiction and failure to state a claim. In addition, potential damages, if any, in a fully litigated securities class action would depend on the losses caused by the alleged wrongful conduct that would be demonstrated by individual class members in their purchases and sales of Royal Dutch and Shell Transport shares during the relevant class period. Accordingly, based on the current status of the litigation, management of Royal Dutch is unable to estimate a range of possible losses or any minimum loss. Management of Royal Dutch will review this determination as the litigation progresses.

Also in connection with the hydrocarbon reserves recategorisation, putative shareholder class actions were filed on behalf of participants in various Shell Oil Company qualified plans alleging that Royal Dutch, Shell Transport and various current and former officers and directors breached various fiduciary duties to employee participants imposed by the Employee Retirement Income Security Act of 1974 (“ERISA”). These suits were consolidated in the United States District Court in New Jersey and a consolidated class action complaint was filed in July 2004. Defendants’ motions to dismiss have been fully briefed. Some document discovery has taken place. The case is at an early stage and subject to substantial uncertainties concerning the outcome of the material factual and legal issues relating to the litigation, including the pending motion to dismiss and the legal uncertainties with respect to the methodology for calculating damage, if any, should defendants become subject to an adverse judgment. The Group is in settlement discussions with counsel for plaintiffs, which it hopes will lead to a successful resolution of the case without the need for further litigation. No financial provisions have been taken with respect to the ERISA litigation.

The reserves recategorisation also led to the filing of shareholder derivative actions in June 2004. The four suits pending in New York state court, New York federal court and New Jersey state federal court demand Group management and structural changes and seek unspecified damages from current and former members of the Boards of Directors of Royal Dutch and Shell Transport. The suits are in preliminary stages and no responses are yet due from defendants. Because any money “damages” in the derivative actions would be paid to Royal Dutch and Shell Transport, management of the Royal Dutch does not believe that the resolution of these suits will have a material adverse effect on Royal Dutch’s financial condition or operating results.

The United States Securities and Exchange Commission (SEC) and UK Financial Services Authority (FSA) issued formal orders of private investigation in relation to the reserves recategorisation which Royal Dutch and Shell Transport resolved by reaching agreements with the SEC and the FSA. In connection with the agreement with the SEC, Royal Dutch and Shell Transport consented, without admitting or denying the SEC’s findings or conclusions, to an administrative order finding that Royal Dutch and Shell Transport violated, and requiring Royal Dutch and Shell Transport to cease and desist from future violations of, the antifraud, reporting, recordkeeping and internal control provisions of the US Federal securities laws and related SEC rules, agreed to pay a $120 million civil penalty and has undertaken to spend an additional $5 million developing a comprehensive internal compliance program. In connection with the agreement with the FSA, Royal Dutch and Shell Transport agreed, without admitting or denying the FSA’s findings or conclusions, to the entry of a Final Notice by the FSA finding that Royal Dutch and Shell Transport breached market abuse provisions of the UK’s Financial Services and Markets Act 2000 and the Listing Rules made under it and agreed to pay a penalty of £17 million. The penalties from the SEC and FSA and the additional amount to develop a comprehensive internal compliance program have been paid by Group companies and fully included in the Income Statement of the Group. The United States Department of Justice has commenced a criminal investigation, and Euronext Amsterdam, the Dutch Authority Financial Markets and the California Department of Corporations are investigating the issues related to the reserves recategorisation. Management of Royal Dutch cannot currently predict the manner and timing of the resolution of these pending matters and is currently unable to estimate the range of reasonably possible losses from such matters.

Group companies are subject to a number of other loss contingencies arising out of litigation and claims brought by governmental and private parties, which are handled in the ordinary course of business.

The operations and earnings of Group companies continue, from time to time, to be affected to varying degrees by political, legislative, fiscal and regulatory developments, including those relating to the protection of the environment and indigenous people, in the countries in which they operate. The industries in which Group companies are engaged are also subject to physical risks of various types. The nature and frequency of these developments and events, not all of which are covered by insurance, as well as their effect on future operations and earnings, are unpredictable.

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Remuneration Report

About this report

This report also discloses the individual remuneration of the Managing Directors and Supervisory Board members of Royal Dutch for the year ended December 31, 2004. It has been compiled with reference to the principles and best practice provisions put forward by the Tabaksblat Committee in the Netherlands. In reflection of the joint arrangements between Royal Dutch and Shell Transport, UK corporate governance disclosure requirements have also been taken into account. This report has been approved for inclusion in this Annual Report on Form 20-F and its policies will be submitted for approval by shareholders at the General Meeting.

This report contains the following sections:

–	The Remuneration and Succession Review Committee;
–	Remuneration policy;
–	2004 actual remuneration; and
–	Supervisory Board members.

The Remuneration and Succession Review Committee

The committee

Appointed by the Supervisory Board of Royal Dutch
Aarnout Loudon		Chairman of the Committee
Maarten van den Bergh		Appointed to the Committee with effect from July 1, 2004
Hubert Markl
Henny de Ruiter		Retired from the Committee on June 30, 2004

Appointed by the Board of Shell Transport
Nina Henderson
Sir Peter Job
Lord Kerr of Kinlochard

The Chairman of the committee is currently Aarnout Loudon. Of the current Royal Dutch members of the committee only Maarten van den Bergh is not an independent member of the Royal Dutch Supervisory Board, as he served as a Managing Director of the Group from 1992 to 2000, as President of Royal Dutch from 1998 to 2000, and he currently serves as a Managing Director of one of the Group Holding Companies. The Shell Transport members of the committee are currently all independent Non-executive Directors. Biographical details of the REMCO members are shown on page 88.

REMCO’s responsibilities

1	Further information in respect of the proposed unification transaction and Royal Dutch Shell plc will be available at www.shell.com in due course.

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As a joint committee of two independent boards, REMCO cannot formally determine the remuneration of individual Executive Directors. The committee makes recommendations to the Supervisory Board of Royal Dutch and the Board of Shell Transport. All such recommendations made in 2004 were approved by the Boards.

Following REMCO’s annual review of its Terms of Reference, a revised version, on its recommendation, was approved by the Supervisory Board of Royal Dutch and the Board of Shell Transport in February 2004. They can be found on the Shell website (www.shell.com/investor).

During 2004 REMCO met eight times; attendance figures for the individual committee members are shown below:

Attendance
Members		Attendance
Aarnout Loudon			8			Chairman of the Committee
Maarten van den Bergh			2			Appointed to the Committee with effect from July 1, 2004
Nina Henderson			8
Sir Peter Job			7
Lord Kerr of Kinlochard			7
Hubert Markl			3
Henny de Ruiter			5			Retired from the Committee on June 30, 2004

Advisers to REMCO

Remuneration policy

The remuneration policy and plans for the Executive Directors for the 2005 financial year and beyond are described below.

Philosophy

–	Statement of General Business Principles, including the Group’s core values and commitment to contribute to sustainable development;
–	strategic direction;
–	need to attract and retain talented individuals;
–	aim to motivate and reward Executive Directors for exceptional performance that enhances the value of the Group; and
–	desire to align Executive Directors’ interests with those of shareholders.

The Group’s remuneration policy is based on the following working principles:

Performance driven

Competitiveness

Consistency

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Base pay

The salary scales are reviewed annually by REMCO and are adjusted in line with market practice with effect from July 1 each year.

The committee recognised the enhanced role of the Chief Executive, compared to his previous role of Chairman of the Committee of Managing Directors and it has adjusted the Chief Executive’s salary level to reflect the increased responsibilities. The current base pay levels of the Chief Executive and the Managing Directors of the Company are:

Current base pay levels
Role		€
Chief Executive, Jeroen van der Veer		1,500,000
Managing Director, Linda Cook		810,000
Managing Director, Rob Routs		900,000

Annual incentive

As part of the annual business planning process, challenging financial, operational and sustainable development targets are set to form a Group Scorecard. Performance during the year is then measured against this Scorecard and annual bonus awards are made on this basis. For 2005 the Group Scorecard has been simplified and the elements made more transparent as part of the Group’s efforts to set clear priorities and reduce complexity. There are four components to the new Scorecard, each with its own different weighting:

–	Total shareholder return (TSR) relative to our industry peers, with a 25% weighting;
–	Operational cash flow, with a 25% weighting;
–	Operational excellence in each of the businesses, with a 30% weighting; and
–	Sustainable Development, primarily based on the number of reportable cases of work related injuries, with a 20% weighting.

A clear process of measuring performance against the Scorecard has been put in place with agreed definitions, calculation methodologies and controls. The Scorecard elements will also be auditable. Targets are set at stretching but realistic levels. At the end of the financial year the results are translated into an overall Group score, which can range anywhere between zero and two, the minimum and maximum, respectively. Bonus awards are based on the Group score multiplied by the target bonus level with REMCO using its judgment in making its final recommendations. The target level for Executive Directors for 2005 will be 100% of base pay, in line with competitive practices.

Long-term incentives

The proposed amendments to the Deferred Bonus Plan and the LTIP, outlined below, would not lead to an increase in the overall value of compensation for Executive Directors.

Deferred Bonus Plan

Under the plan, Executive Directors can elect to invest a proportion of their annual bonus in shares. Provided that a participant remains in Group employment for three years following the deferral, or retires within the three-year period, he or she will be eligible for matching shares. The deferred bonus shares, together with shares equivalent to the value of dividends payable on the deferred bonus shares (dividend shares) and matching shares, are released three years after deferral.

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REMCO has considered shareholder feedback on the current arrangements and has recommended that the proportion of annual bonus able to be deferred be increased and that performance conditions be attached to the release of matching shares.

The amended plan will allow Executive Directors to invest up to 50% of their annual bonus in shares. From 2006 25% of their annual bonus will be deferred on a mandatory basis. A participant will receive one matching share for every four deferred bonus and dividend shares accumulated. Provided that the performance condition is met, he or she will receive up to three further performance-based matching shares.

The performance condition is the Total Shareholder Return (TSR) of the Group against the major integrated oil companies, as follows:

–	TSR ranked 5th or 4th: no performance-based matching shares;
–	TSR ranked 3rd: one performance-based matching share;
–	TSR ranked 2nd: two performance-based matching shares;
–	TSR ranked 1st: three performance-based matching shares.

Deferrals in relation to the 2004 have been made on these amended terms, conditional upon the approval of the Plan.

Long-Term Incentive Plan

–	200% of an award will be released if the Group is in first place;
–	150% for second place;
–	80% for third place;
–	awards will lapse entirely if the Group is in fourth or fifth place.

For any award to be released to Executive Directors the committee must be assured of the underlying performance of the Group. For this, it will take into consideration the Group Scorecard results, excluding TSR, over the applicable performance period, as it provides quantifiable measures of the Group’s performance and operational excellence.

Industry peer group for base pay, annual bonus, deferred bonus, and LTIP

Major integrated oil companies
as at January 1, 2005
BP
ChevronTexaco
ExxonMobil
Royal Dutch/ Shell Group
Total

Pension policy

For the Dutch Executive Directors² the principal source of their pensions is the Stichting Shell Pensioenfonds (SSPF). This is a defined benefit fund to which Executive Directors contribute the same percentage of relevant earnings as other employees. Contributions to the pension fund are based on the advice of actuaries. Neither the annual bonus nor the deferred bonuses are pensionable.

The latest date on which the Dutch Executive Directors may retire is on June 30, following their 60th birthday. Currently a change in retirement age is under consideration for the pension plan offered by the SSPF. A change to age 65 with effect from January 1, 2006 is proposed. Details of the proposal and its effects will be assessed further during 2005. There are provisions in the SSPF for a surviving

2	Dutch Managing Directors of Royal Dutch during 2004 were Jeroen van der Veer, Rob Routs, and Walter van de Vijver. Walter van de Vijver resigned as a Managing Director of Royal Dutch on March 3, 2004 and his employment terminated with effect from September 1, 2004.

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dependant benefit of 70% of actual or prospective pension. In case of death-in-service, a lump sum of two times annual base pay is paid by the respective Group company.

For the American Executive Director³ the principal sources of pension include pension plans and savings plans. Pension plans in which she participates are the Shell Pension Plan, and the US Senior Staff Pension Plan. These are defined benefit plans which are non-contributory. Savings plans are the Shell Provident Fund for US employees, the Shell Pay Deferral Investment Fund for US employees, the Senior Executive Group Deferral Plan and the Senior Staff Savings Fund. These are defined contribution plans which are contributory on a voluntary basis. In line with standard US market practice the annual bonus is pensionable.

As there is no mandatory or normal retirement date in the USA, pensions include provisions to allow for retirement at age 60. There are also provisions for a dependant benefit of 50% of actual or prospective pension. A lump sum death-in-service payment is not offered under the plans.

Other benefits policy

All-employee share schemes

Contracts policy

Standard Executive Directors contracts do not contain any predetermined settlements for early termination. If and when a situation arises in which a severance payment is appropriate, its terms and conditions will be recommended by REMCO and decided by the Supervisory Board taking into account applicable law and corporate governance provisions. In the case of Executive Directors appointed from outside the Group, temporary severance arrangements may be agreed to facilitate the recruitment process. The Company will bear the costs of legal proceedings against a Managing Director, except if the Managing Director concerned is ruled to be seriously at fault by a court of law.

External appointments

Shareholdings

2004 actual remuneration⁴

Base pay

3	Linda Cook, a US citizen, was appointed as a Managing Director of Royal Dutch on August 1, 2004.

4	The information in the tables in this section has been subjected to audit by KPMG Accountants N.V., except for the Expected value columns in the Stock options table and in the Long-Term Incentive Plan table on pages R20 and R21, which are unaudited.

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Annual incentive

The overall 2004 Group Scorecard score was 0.9 and REMCO confirmed the outcome. Having regard to the Group’s performance against all targets, REMCO recommended and it was decided that the annual bonuses payable to Executive Directors in respect of the year 2004 are 90% of base pay.

Stock options

Stock options granted in March 2002 were 50% performance-linked and were due to vest in March 2005. The performance period for the options was January 1, 2002 to December 31, 2004. The Royal Dutch/ Shell Group ranked fourth in TSR against the industry peer group (three-year average over the period 2002 to 2004). Taking all these factors into consideration, the committee determined that none of the performance vesting stock options should vest. Based on this determination, half of the stock options granted to Executive Directors and Senior Executives in 2002 will vest based on time, and the other half of the stock options granted in 2002 will lapse.

Long-Term Incentive Plan

Half of each conditional award will be tested against the first group and half against the second group. For the first comparator group, 100% of the shares tested against that group will be awarded for performance in the top quartile and 25% will be awarded for performance at the median. Between these two points a straight-line calculation will be used. No shares will be received for performance below the median. For the second comparator group, 100% of the shares tested against that group will be received if the Group is in first place, 75% for second place and 50% for third place. No shares will be received for fourth or fifth place.

Home markets peer group for LTIP in 2004

AEX10		FTSE20
as at January 1, 2004		as at January 1, 2004
ABN AMRO		Anglo American
AEGON		AstraZeneca
Ahold		Barclays
Fortis		BHP Billiton
Heineken		BP
ING Group		British American Tobacco
KPN		British Sky Broadcasting
Philips		BT
Royal Dutch		Diageo
Unilever N.V		GlaxoSmithKline
		HBOS
		HSBC
		Lloyds TSB
		National Grid Transco
		Rio Tinto
		Royal Bank of Scotland
		Shell Transport
		Tesco
		Unilever PLC
		Vodafone

a	In the case of Royal Dutch and Shell Transport, and Unilever N.V. and Unilever PLC, the weighted average TSR of the two companies will be used.

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Emoluments of Managing Directors of Royal Dutch in office during 2004																		€
										Payment
						Annual				following				Other
		Salaries				bonusa				severance				benefitsb				Total
Jeroen van der Veer
2004			1,281,774	c			1,350,000				–				18,043				2,649,817
2003			1,120,000				0				–				11,502				1,131,502
2002			1,013,729				1,230,500	d			–				4,768				2,248,997
Malcolm Brinded
2004e			148,080				160,593	f			–				6,156				314,829
2003			800,000				0				–				23,707				823,707
2002e			372,500				428,375	d			–				2,210	g			803,085
Linda Cook
2004h			338,892				442,000				–				189,623				970,515
Rob Routs
2004			884,516				810,000				–				139,850				1,834,366
2003i			405,000				0				–				55,612				460,612
Walter van de Vijver
2004j			186,774				0				1,900,000				7,074				2,093,848
2003			842,500				0				–				26,060				868,560
2002			735,095				902,750				–				18,091	k			1,655,936

a	The annual bonus is included in the related performance year and not in the following year in which it is paid.
b	Includes social security premiums paid by the employer, employer’s contribution to the health insurance plan, where applicable school fees and other benefits stated at a value employed by the Fiscal Authorities in the Netherlands.
c	Jeroen van der Veer’s salary increase with effect from November 1, 2004 did not come into payment until 2005 and will therefore be reported in the 2005 Annual Report and Accounts.
d	Of which one-third was deferred under the Deferred Bonus Plan.
e	Malcolm Brinded was appointed as a Managing Director of Royal Dutch with effect from July 1, 2002 until March 3, 2004, therefore, where appropriate, the 2002 and 2004 emoluments are prorated.
f	Malcolm Brinded’s 2004 annual bonus amounted to £634,500 for the full year. His annual bonus from March 4, 2004 to December 31, 2004 has been listed in the 2004 Shell Transport Annual Reports and Accounts. Sterling converted to euro at the quarterly average rate of exchange.
g	Exclusive of deferred payment in shares amounting to £386,000 granted in 1999.
h	Linda Cook was appointed as a Managing Director of Royal Dutch with effect from August 1, 2004, therefore, where appropriate, the 2004 emoluments are prorated. US dollar converted to Euro at the monthly average rate of exchange.
i	Rob Routs was appointed as a Managing Director of Royal Dutch with effect from July 1, 2003, therefore, where appropriate, the 2003 emoluments are prorated
j	Walter van de Vijver resigned as a Managing Director of Royal Dutch on March 3, 2004, therefore, where appropriate, the 2004 emoluments are prorated.
k	Exclusive of deferred payment in shares amounting to €688,839 granted in 1999.

Deferred Bonus Plan

Total number

Average

of deferred

Number of deferred

Market price

market price of

bonus and

bonus and

Deferred

of deferred

dividend shares

dividend shares

dividend shares

bonus shares

bonus shares

Dividend

paid during

under award

under award as at

awarded

at awardb

shares accrued

the yeard

as at December 31,

January 1, 2004

during the yeara

€

during the yearc

€

2004

Jeroen van der Veer

2003 award

11,695

–

36.66

503

41.71

12,198

2002 award

3,710

–

60.09

159

41.71

3,869

Awards made in 2002 and 2003 refer to the portion of the 2001 and 2002 annual bonus which was deferred in 2002 and 2003 and their related accrued dividends. In 2004 there was no opportunity for Managing Directors of Royal Dutch to defer any of their 2003 bonuses into the Deferred Bonus Plan, as no 2003 bonuses were awarded.

Due to his appointment as Executive Director of Shell Transport in 2004 Malcolm Brinded’s Deferred Bonus Plan interests have been reported in the Shell Transport 2004 Annual Report and Accounts.

a	Representing the proportion of the annual bonus that has been deferred and converted into notional share entitlements (deferred bonus shares), in which there is no in beneficial ownership. The value of these deferred bonus shares is also included in the annual bonus figures in the Emoluments of the Managing Directors of Royal Dutch table above.
b	The market price is based on the average share price over a period of five trading days prior to and including the day on which the share awards are made.
c	Representing dividends paid during the year on the number of shares equal to the deferred bonus shares awarded.
d	The market price shown is the average at the date of the 2003 final and 2004 interim annual dividends paid during the year: €41.08 and €42.34, respectively.

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Stock Options
		Number of options
																														Expected								Realised
										Exercised																				value of				Realisable				gains on
										(cancelled/																				the 2004				gains as at				stock
						Granted				lapsed)								Exercise												stock options				Dec 31,				options
		At Jan 1,				during the				during the				At Dec 31,				pricea				Exercisable				Expiry				grantb				2004c				exercised
Royal Dutch		2004				year				year				2004				€				from date				date				€				€				€
Jeroen van der Veer			40,850				–				–				40,850				41.16				22.12.01				21.12.08				–				48,612				–
			33,750				–				–				33,750				59.54				23.03.03				22.03.10				–				0				–
			80,000				–				(40,000	)			40,000				62.60				26.03.04				25.03.11				–				0				–
			105,000				–				–				105,000				62.10				21.03.05				20.03.12				–				–				–
			150,000				–				–				150,000				36.81				19.03.06				18.03.13				–				–				–
			–				150,000				–				150,000				41.29				07.05.07				06.05.14				1,362,570				–				–
Linda Cook			–				106,300	d			–				106,300				42.67				05.11.07				04.11.14				997,881				–				–
Rob Routs			20,000				–				–				20,000				41.16				22.12.01				21.12.08				–				23,800				–
			18,000				–				–				18,000				59.54				23.03.03				22.03.10				–				0				–
			50,000				–				–				50,000				62.10				21.03.05				20.03.12				–				–				–
			49,400				–				–				49,400				36.81				19.03.06				18.03.13				–				–				–
			50,066				–				–				50,066				40.95				19.08.06				18.08.13				–				–				–
			–				115,000				–				115,000				41.29				07.05.07				06.05.14				1,044,637				–				–
Walter van de Vijvere			10,000				–				–				10,000				48.92				11.12.00				10.12.07				–				0				–
			20,000				–				–				20,000				41.16				22.12.01				21.12.08				–				23,800				–
			24,000				–				–				24,000				59.54				23.03.03				31.08.09				–				0				–
			7,500				–				–				7,500				68.73				23.08.03				31.08.09				–				0				–
			40,000				–				(20,000	)			20,000				62.60				26.03.04				31.08.09				–				0				–
			75,000				–				–				75,000				62.10				21.03.05				31.08.09				–				–				–
			115,000				–				–				115,000				36.81				19.03.06				31.08.09				–				–				–
Maarten van den Berghf			37,950				–				–				37,950				41.16				22.12.01				29.06.05				–				45,161				–
Royal Dutchg																			$								€
Linda Cookh			13,087	i			–				–				13,087				54.31				05.03.99				05.03.08				–				29,462	j			–
			23,000	i			–				–				23,000				43.50				04.03.00				04.03.09				–				234,099	j			–
			45,000				–				–				45,000				52.08				01.03.01				01.03.10				–				174,892	j			–
			2,175				–				–				2,175				56.33				21.04.01				21.04.10				–				1,675	j			–
			70,000				–				(26,250	)			43,750				60.75				08.03.02				07.03.11				–				0				–
			70,000				–				–				70,000				54.35				21.03.03				20.03.12				–				155,533	j			–
			70,500				–				–				70,500				40.64				19.03.04				18.03.13				–				865,419	j			–
Shell Canada Limited																			CAD																				€
Linda Cookd			120,000				–				(120,000	)			0				62.55				28.01.04				26.07.04				–				–				23,710	k
Rob Routsl			7,500				–				(7,500	)			0				17.83				29.01.97				28.01.07				–				–				230,659	m
			24,000				–				(24,000	)			0				23.50				27.01.98				26.01.08				–				–				646,619	n

Due to his appointment as a Managing Director of Shell Transport in 2004 Malcolm Brinded’s stock options interests have been reported in the Shell Transport 2004 Annual Report and Accounts.

a	The exercise price is the average of the opening and closing share prices over a period of five trading days prior to and including the day on which the options are granted (no discount).
b	The expected values of the 2004 stock options grants have been calculated on the basis of the Black-Scholes model valuations provided by Towers Perrin and Kepler Associates. The values are unaudited. The expected value is equal to 22% of the face value of the grant.
c	Represents the value of unexercised stock options at the end of the financial year, which is calculated by taking the difference between the exercise price of the option and the fair market value of Royal Dutch shares at December 31, 2004, and multiplied by the number of shares under option at December 31, 2004. The actual gain, if any, a Managing Director will realise, will depend on the market price of the Royal Dutch shares at the time of exercise.
d	As CEO of Shell Canada Limited (SCL) Linda Cook was awarded 120,000 options in January 2004. Half of these options were subject to performance conditions. Upon her appointment as a Managing Director of Royal Dutch, Linda Cook was prohibited from exercising any SCL options. All the SCL options were therefore cancelled on Monday July 26, 2004. Linda Cook was paid a cash equivalent to the paper value of 10,000 of the non-performance related shares, on the basis that Linda Cook had qualified for 1/6th of these options on a time prorated basis. She also received a replacement grant of 106,300 options over Royal Dutch shares in respect of the potential value of the options cancelled, in relation to both the remaining performance related shares and the non-performance related shares, offset by the cash payment to her.
e	Upon Walter van de Vijver’s termination of employment on September 1, 2004, the exercise terms of his remaining stock options have been shortened so that they expire five years after the termination of his employment, on August 31, 2009, or earlier if their original expiry date is prior to August 31, 2009. Walter van de Vijver did not receive any stock option grants in 2004.
f	Maarten van den Bergh holds share options relating to his former service with the Group.
g	Options over Royal Dutch New York shares.
h	During her employment with the Group and prior to her appointment as Chief Executive Officer of Shell Canada Limited Linda Cook was awarded US-dollar based options and Stock Appreciation Rights, as well as 14,000 conditional Royal Dutch ordinary shares on October 1, 2002; the latter will be released on October 1, 2005.
i	Stock Appreciation Rights with an entitlement to receive any gain upon exercise in either cash or shares.
j	US dollar converted to euro at the year-end rate of exchange.
k	The exercise price was CAD 66.36. Canadian dollar converted to euro at the mean rate of exchange on the day of exercise.
l	Rob Routs’ Shell Canada Limited stock options were awarded to him in 1997 and 1998, when he was a Shell Canada executive.
m	The price at which the options were exercised was CAD 66.65. Canadian dollar converted to euro at the mean rate of exchange on the day of exercise.
n	The price at which the options were exercised was CAD 66.27. Canadian dollar converted to euro at the mean rate of exchange on the day of exercise.

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Long-Term Incentive Plan (LTIP)
							Performance shares																								Expected value				Theoretical
							conditionally				Released								Market price at				Start of				End of				of the 2004				gains as
			At Jan 1,				awarded during				(cancelled/ lapsed)				At Dec 31,				date of				performance				performance				performance				at Dec 31,
			2004				the year				during the year				2004				awarda				period				period				shares awardb				2004c
																			€												€				€
Jeroen van der Veer
	2004			–				63,211				–				63,211				41.29				01.01.04				31.12.06				1,122,292				–
	2003			57,142				–				–				57,142				40.95				01.01.03				31.12.05				–				0
Rob Routs
	2004			–				43,594				–				43,594				41.29				01.01.04				31.12.06				773,998				–
	2003			39,560				–				–				39,560				40.95				01.01.03				31.12.05				–				0
Walter van de Vijverd
	2003			43,956				–				(43,956	)			–				40.95				01.01.03				31.12.05				–				–

a	The market price is based on the average of the opening and closing share prices over a period of five trading days prior to and including the day on which the number of shares are determined in accordance with the Plan rules.
b	The expected values of the conditional performance shares awards have been calculated on the basis of a standard valuation approach provided by Towers Perrin and Kepler Associates.
	The values are unaudited. The expected value based on this approach is equal to 43% of the face value of the award.
c	Represents the value of the conditional performance shares under the LTIP at the end of the financial year, which is calculated by multiplying the fair market value of Royal Dutch shares, at December 31, 2004, by the number of shares under the LTIP that would vest based on the achievement of performance conditions up to December 31, 2004.
d	Walter van de Vijver resigned as a Managing Director of Royal Dutch on March 3, 2004. and his employment contract terminated on September 1, 2004. None of the conditional award of Royal Dutch shares made to him in August 2003 under the Long Term Incentive Plan vested. He did not receive any further Long-Term Incentive Plan awards in 2004.

Pensions

Increase

Accumulated

Pension

Pension

Years of

in accrued

annual

premium 2004

premium 2003

Group

pension

pension as at

paid by

paid by

Age as at

service as at

during 2004

Dec 31, 2004

employer

employer

Dec 31, 2004

Dec 31, 2004

€ thousand

€ thousand

€ thousand

€ thousand

Jeroen van der Veera

57

33

102

777

256

171

Malcolm Brindedb

51

30

–

–

46

c

622

d

Linda Cooke

46

24

21

f

324

g

8

h

–

Rob Routs

58

26

54

506

177

81

i

Walter van de Vijver

49

25

j

10

385

120

k

129

a	Jeroen van der Veer’s salary increase with effect from November 1, 2004 did not come into payment until 2005. The pension figures in the 2005 Annual Report and Accounts will reflect this increase.
b	Malcolm Brinded resigned as a Managing Director of Royal Dutch on March 3, 2004 and was appointed Managing Director of Shell Transport on the same date. Therefore his pension figures for the full year 2004 have been disclosed in the Shell Transport Annual Report and Accounts 2004.
c	Represents pension premium paid by the employer up to March 3, 2004. Sterling converted to euro at the quarterly average rate of exchange.
d	As a result of the 2002 valuation of the SOCPF fund the Actuary requested that an additional one-time company contribution to the fund be paid. The amount stated comprises the basic pension increase and a prorated amount relating to this additional employer contribution. Sterling converted to euro at the average quarterly rate of exchange.
e	Linda Cook was appointed a Managing Director of Royal Dutch with effect from August 1, 2004, therefore, where appropriate, the 2004 pension figures are with effect from this date.
f	Includes an accrued pension increase and a movement in the exchange rate between the US dollar and euro over the period disclosed; US dollar converted to euro at the quarterly average rate of exchange.
g	US dollar converted to euro at the year-end rate of exchange.
h	US dollar converted to euro at the quarterly average rate of exchange. In addition, the Company contributed €42,650 based on the quarterly average exchange rate to the Shell Provident Fund for US employees and the Senior Executive Group Deferral Plan, which both are defined contribution plans.
i	The 2003 pension premium paid by the employer is reflective of Rob Routs’ appointment as a Managing Director of Royal Dutch with effect from July 1, 2003.
j	As at August 31, 2004.
k	The 2004 pension premium paid by the employer is reflective of Walter van de Vijver’s termination of employment on September 1, 2004.

Pensions

Company contributions were not required for the US Senior Staff Pension Plan during 2004. The employing company’s contribution rate for the Shell Pension Plan was 5.1% in 2004. Executive Directors are not required to contribute to these plans.

Managing Directors’ contracts of service

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Walter van der Vijver was employed with one of the Group Holding Companies on similar terms and conditions. Linda Cook’s employment contract is with Shell Expatriate Employment US Inc. on an “at-will” basis.

There are no predetermined termination compensation arrangements in place for Managing Directors of Royal Dutch.

Walter van de Vijver resigned as Managing Director of the Company on March 3, 2004. His employment terminated with effect from September 1, 2004. Under the terms of the agreement addressing termination of his employment contract, Walter van de Vijver will be eligible to receive a total amount of up to €3.8 million. This amount was determined by reference to the so called “Kantonrechtersformule”, the formula used by the courts in the Netherlands to determine compensation upon termination of employment contracts, taking into account, amongst other things, his 25 years of service with the Group. Under the agreement, an amount of €1.9 million was paid out following termination of his employment contract. Another €1.9 million is held in escrow and is subject to continuing cooperation with and review by relevant authorities, amongst other conditions. Walter van de Vijver did not receive a performance-related annual bonus or stock options or any awards under the LTIP in respect of 2004. The exercise terms of his stock options have been shortened to expire five years after the termination of his employment, on August 31, 2009, or earlier if the original expiry date is prior to August 31, 2009. The schedule for his stock options is disclosed in the Stock Options table on page R20. None of the conditional award of 43,956 Royal Dutch shares made to Walter van de Vijver in August 2003 under the Long-Term Incentive Plan vested on September 1, 2004. From June 30, 2015, Walter van de Vijver has the legal right to a deferred pension of €385,388 per annum under the Stichting Shell Pensioenfonds pension scheme to which he has contributed over the past 25 years. Under pre-existing provisions, Mr. van de Vijver is also entitled to the reimbursement of litigation costs under certain circumstances. See “Discussion and Analysis of Financial Condition and Results of Operations — Legal Proceedings”.

Supervisory Board members

Policy

Fees

There are no proposals to increase Royal Dutch Supervisory Board members’ fees in 2005. A proposal to abandon the payment of fees to Directors of the Holding Companies and to reduce the fees to Supervisory Board Members of Royal Dutch, following approval of the unification proposal by the General Meeting of shareholders, is under consideration.

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Emoluments of the Supervisory Board										€
		2004				2003				2002
Aad Jacobs
Chairman’s fee			15,000				15,000				5,750
Supervisory Board fees			55,000				55,000				46,000
Committee fees			7,000				7,000				7,000
			77,000				77,000				58,750
Maarten van den Bergh
Supervisory Board fees			55,000				55,000				46,000
Committee fees			10,500				7,000				7,000
Holding Company feesa			27,968				27,711				29,021
			93,468				89,711				82,021
Wim Kok
Supervisory Board fees			55,000				27,500				–
Committee fees			7,000				3,500				–
			62,000				31,000				–
Aarnout Loudon
Supervisory Board fees			55,000				55,000				46,000
Committee fees			14,000				14,000				14,000
			69,000				69,000				60,000
Hubert Markl
Supervisory Board fees			55,000				55,000				23,000
Committee fees			7,546				–				–
			62,546				55,000				23,000
Christine Morin-Postelb
Supervisory Board fees			27,500				–				–
Committee fees			3,500				–				–
			31,000				–				–
Lawrence Ricciardi
Supervisory Board fees			55,000				55,000				46,000
Committee fees			7,000				3,500				–
Intercontinental travel fees			28,500				21,375				–
			90,500				79,875				46,000
Henny de Ruiterc
Supervisory Board fees			27,500				55,000				46,000
Committee fees			7,000				14,000				10,500
Holding Company feesa			13,984				27,711				29,021
			48,484				96,711				85,521

The information in this table is subject to audit.

a	Maarten van den Bergh and Henny de Ruiter received fees from the Group Holding Companies in respect of duties performed by them as Directors of these companies.
b	Appointed as from July 1, 2004.
c	Retired on June 30, 2004.

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Group share plans

Set out below is a summary of the principal employee share schemes operated by Group companies.¹ The shares subject to the plans are existing issued shares of Royal Dutch or Shell Transport. Shares to be delivered by a Group company under these plans are generally bought in the market at the time the commitment is made.

Long-Term Incentive Plan (LTIP)

Restricted Share Plan

Stock Option Plans

Options under the Stock Option Plans are exercisable three years from grant except for those granted under the US plans which vest one-third per year for three years. Stock options lapse ten years after grant; however, leaving Group employment may cause options to lapse earlier.

For the Executive Directors and the most senior executives 100% of options granted under the Stock Option Plans in 2003 and 2004 are subject to performance conditions.

Global Employee Share Purchase Plan

UK Sharesave Scheme

Shell All-employee Share Ownership Plan

1	Details of the number of shares held by Group companies in connection with the above plans are shown in Note 23 of the Group Financial Statements on pages G26 to G28.

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The “Shell” Transport and Trading Company, Public Limited Company

To: The Board of Directors and Shareholders of The “ Shell ” Transport and Trading Company, Public Limited Company

We have audited the Financial Statements of The “ Shell ” Transport and Trading Company, Public Limited Company for the years 2004, 2003 and 2002 appearing on pages S2 to S15. The preparation of the Financial Statements is the responsibility of the Company’s Directors. Our responsibility is to express an opinion on the Financial Statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by the Company’s Directors in the preparation of the Financial Statements, as well as evaluating the overall Financial Statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Financial Statements referred to above present fairly, in all material respects, the financial position of The “ Shell ” Transport and Trading Company, Public Limited Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with the accounting principles generally accepted in the United Kingdom.

As discussed in Note 3 on pages S6 and S7, the Company has restated its Financial Statements for the two years ended December 31, 2003, to correct for the financial impact of the Second Reserves Restatement.

Accounting principles generally accepted in the United Kingdom vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in Note 14 on pages S12 to S14, as restated.

 

 

/s/ PricewaterhouseCoopers LLP

 

March 29, 2005

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Financial Statements

Profit and Loss Account		£ million
		Note				2004				2003				2002
Income from shares in companies of the Royal Dutch/Shell Group			4				1,735.4				1,361.5				1,403.2
Interest and other income							7.2				5.6				5.4
							1,742.6				1,367.1				1,408.6
Administrative expenses							7.0				4.4				4.2
Profit on ordinary activities before taxation							1,735.6				1,362.7				1,404.4
Tax on profit on ordinary activities			5				0.1				0.3				0.4
Distributable profit for the year							1,735.5				1,362.4				1,404.0

											As				As
											restated				restated
	Distributable profit for the year							1,735.5				1,362.4				1,404.0
	Share of earnings retained by companies of the Royal Dutch/Shell Group			2,7				2,203.8				1,576.7				1,140.7
	Earnings for the year attributable to shareholders							3,939.3				2,939.1				2,544.7
	From continuing operations			4				3,598.5				2,932.9				2,494.8
	From discontinued operations			4				340.8				6.2				49.9
Aggregate dividends paid and proposed								1,633.2				1,523.1				1,475.0

Earnings per 25p Ordinary sharea											pence
											2003				2002
											As				As
							2004				restated				restated
Distributable profit for the year				6				18.3				14.3				14.6
	Distributable profit for the year							18.3				14.3				14.6
	Share of earnings retained by companies of the Royal Dutch/Shell Group			2				23.2				16.5				11.9
	Earnings for the year attributable to shareholders							41.5				30.8				26.5
	From continuing operations			4				37.9				30.7				26.0
	From discontinued operations			4				3.6				0.1				0.5

a	Of the earnings per share amounts shown above, those relating to earnings for the year attributable to shareholders are, in the opinion of the Directors, the most meaningful since they reflect the full entitlement of the Company in the income of Group companies.

Balance Sheet				£ million
												Dec 31,
								Dec 31,				2003
				Note				2004				As restated
Fixed assets
Investments
	Shares (unlisted) in companies of the Royal Dutch/ Shell Group				7				17,452.6				16,200.6
	Other investments				8				82.6				–
Current assets
Debtors:
	Dividends receivable from companies of the Royal Dutch/Shell Group								970.1				1,140.3
	Other debtors								0.3				0.1
									970.4				1,140.4
Cash at bank:
	Short-term deposits								203.0				86.8
	Cash								0.6				0.3
									1,174.0				1,227.5
Total Assets									18,709.2				17,428.1
Creditors: amounts due within one year
	Amounts due to companies of the Royal Dutch/ Shell Group								0.9				0.8
	Corporation tax								–				0.2
	Unclaimed dividends								10.9				10.2
	Other creditors and accruals								2.7				2.2
	Preference dividends accrued								0.3				0.3
	Ordinary dividend proposed								1,029.9				932.9
									1,044.7				946.6
Net current assets									129.3				280.9
Total assets less current liabilities									17,664.5				16,481.5
Capital and reserves
Equity interests:
	Called-up share capital; Ordinary shares				9				2,406.2				2,416.9
	Capital redemption reserve				10				79.7				69.0
	Revaluation reserve				7				14,952.9				13,700.9
	Profit and Loss Account								213.7				282.7
									17,652.5				16,469.5
Non-equity interests
	Called-up share capital:				9
		First Preference shares							2.0				2.0
		Second Preference shares							10.0				10.0
									12.0				12.0
Shareholders’ funds					11				17,664.5				16,481.5

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Statement of Total Recognised Gains and Losses										£ million
										2003				2002
		Note				2004				As restated				As restated
Distributable profit for the year							1,735.5				1,362.4				1,404.0
Unrealised surplus/(deficit) on revaluation of investments in companies of the Royal Dutch/ Shell Group			7				1,252.0				1,241.6				(529.1	)
Total recognised gains and losses relating to the year							2,987.5				2,604.0				874.9

Statement of Retained Profit																£ million
								2004				2003				2002
Distributable profit for the year									1,735.5				1,362.4				1,404.0
Distributable retained profit at beginning of year									282.7				443.4				884.0
									2,018.2				1,805.8				2,288.0
	Dividends on non-equity shares:				9
		First Preference shares							0.1				0.1				0.1
		Second Preference shares							0.7				0.7				0.7
									0.8				0.8				0.8
									2,017.4				1,805.0				2,287.2
	Dividends on equity shares:				9
	25p Ordinary shares
		Interim of 6.25p in 2004, 6.10p in 2003 and 5.95p in 2002							603.7				589.7				578.0
		Second interim of 10.7p in 2004, second interim of 9.65p in 2003 and 9.30p in 2002							1,029.9				932.9				899.1
		Reduction due to share buyback and unclaimed dividends							(1.2	)			(0.3	)			(2.9	)
									1,632.4				1,522.3				1,474.2
	Share repurchase including expenses								171.3				–				369.6
Distributable retained profit at end of year									213.7				282.7				443.4

Statement of Cash Flows		£ million
		2004				2003				2002
Returns on investments and servicing of finance
Dividends received from companies of the Royal Dutch/Shell Group			1,905.6				1,484.9				1,838.8
Interest received			7.0				5.6				5.6
Preference dividends paid			(0.8	)			(0.8	)			(0.8	)
Other			(5.8	)			(3.8	)			(3.7	)
Net cash inflow from returns on investments and servicing of finance			1,906.0				1,485.9				1,839.9
Taxation
Tax paid			(0.3	)			(0.3	)			(0.6	)
Capital expenditure and financial investment
Other investments			(82.6	)			–				–
Equity dividends paid
Ordinary shares			(1,535.4	)			(1,488.5	)			(1,447.6	)
Management of liquid resources (short-term deposits)
Net cash inflow/(outflow) from management of liquid resources			(116.2	)			3.1				(22.4	)
Financing
Repurchase of share capital, including expenses			(171.3	)			–				(369.6	)
Net (decrease)/increase in amounts due to companies of the Royal Dutch/Shell Group			0.1				(0.3	)			0.1
Net cash outflow from financing			(171.2	)			(0.3	)			(369.5	)
Increase/(Decrease) in cash			0.3				(0.1	)			(0.2	)
Cash at January 1			0.3				0.4				0.6
Cash at December 31			0.6				0.3				0.4

Net debts, being amounts due to the companies of the Royal Dutch/ Shell Group less cash, decreased during 2004 from £0.5 million to £0.3 million (2003: net debts decreased from £0.7 million to £0.5 million).

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The Company adopts a policy of minimising cash holdings whilst ensuring that operating costs, the financing of dividend payments and funding of the Company’s share buyback programme, are met. The Company’s debtors and creditors are short term and are all denominated in sterling.

At December 31, 2004 the Company had £203.0 million (2003: £86.8 million) on short-term deposit with third-party banks. The fixed interest rate earned on these sterling deposits at year-end was 4.79% (2003: 3.4%). The carrying amount and fair value of these deposits are the same.

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Notes to the Financial Statements

1 The Company

Arrangements between Royal Dutch and Shell Transport provide, inter alia, that notwithstanding variations in shareholdings, Royal Dutch and Shell Transport shall share in the aggregate net assets and in the aggregate dividends and interest received from Group companies in the proportion of 60:40. It is further arranged that the burden of all taxes in the nature of or corresponding to an income tax leviable in respect of such dividends and interest shall fall in the same proportion.

Unification Proposal

2 Accounting policies and convention

The inclusion in this Annual Report on Form 20-F and the Financial Statements of Shell Transport appearing on S2 to S15 has been approved by the Board of Shell Transport for filing with the Securities and Exchange Commission. The Financial Statements of Shell Transport included in this Annual Report do not, as of the date of filing, constitute the accounts of the Company filed at United Kingdom Companies House in accordance with United Kingdom legal requirements.

The 2003 Annual Report on Form 20-F and the Financial Statements of Shell Transport contained therein has been re-filed to account for the impact of the Second Reserves Restatement (see Note 3). The 2003 Annual Report and Accounts have not been re-filed at United Kingdom Companies House and therefore the 2004 Annual Report and Accounts will include additional disclosures on the impact of the Second Reserves Restatement on opening shareholders’ funds. Statutory accounts for comparative periods have been delivered to United Kingdom Companies House and the Company’s auditors issued an unqualified report on those accounts. As of March 29, 2005, the auditors have not yet issued a report under Section 235 of the United Kingdom Companies Act in relation to the 2004 Annual Report and Accounts.

The Company records income from shares in Group companies, in the form of dividends, in its Profit and Loss Account. The Company’s investments in Group companies comprises a 40% interest in the Group’s net assets. An amount equal to 40% of the net assets of the Group, as presented in the Group Financial Statements in accordance with Netherlands GAAP, is included in the Company’s Financial

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Statements as the Directors’ valuation of this investment. The difference between the cost and the amount at which the investments are stated in the Balance Sheet has been taken to the Revaluation Reserve.

The Financial Statements of Shell Transport are reported in pounds sterling, while the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies are reported in US dollars. Notes 4, 7 and 14 to these Financial Statements contain currency translation of certain items presented in US dollars in the Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies into pounds sterling.

References are made to the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies in these Notes to facilitate an understanding of the relationships between the Financial Statements of Shell Transport and the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies, particularly as they relate to Shell Transport’s 40% interest in net income and net assets of companies of the Royal Dutch/ Shell Group of Companies.

Other fixed asset investments are held at historical cost.

Under a 2002 EU Regulation, publicly-listed companies in the European Union will be required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) from 2005. The 2005 Financial Statements of the Group or, subject to completion of the transaction described in Note 1, of its successor, will be prepared under IFRS and will include comparative data for 2004, together with reconciliations to opening balances as at January 1, 2004 and to 2004 data previously published in accordance with accounting principles generally accepted in the United States (US GAAP). With effect from January 1, 2005 Shell Transport intends to prepare its Financial Statements under International Financial Reporting Standards.

3 Restatement of previously issued Financial Statements

Following the January 9, 2004 announcement of the initial reserves recategorisation, the Group Audit Committee (GAC) appointed Davis Polk & Wardwell to lead an independent review of the facts and circumstances surrounding the recategorisation, and to report its findings and any proposed remedial actions to the GAC for its consideration. Based largely on the Davis Polk & Wardwell report, the Parent Companies, Royal Dutch and Shell Transport, determined that the principal causes that permitted the initial booking and maintenance of the volumes impacted by the First Reserves Restatement as proved reserves are as follows:

–	the Group’s guidelines for booking proved reserves were inadequate in several respects, including (i) containing inconsistencies with the SEC’s rules and published guidance relating to proved reserves and (ii) failing to clearly and sufficiently impart these requirements and guidance to users of the guidelines. In addition, users of the guidelines in certain cases misapplied or disregarded SEC rules and published guidance and in some cases only applied changes in the guidelines prospectively rather than retrospectively. There was also insufficient knowledge and training among users of the guidelines of the SEC requirements relating to proved reserves;
–	executives and employees encouraged the booking of proved reserves, while discouraging the debooking of previously booked reserves. This fostered an atmosphere that failed to emphasise the paramount importance of the compliance element of proved reserves decisions; and
–	there were other material weaknesses in the Group’s controls relating to the booking of proved reserves, including insufficient resources allocated to the Group Reserves Auditor and Group Reserves Co-ordinator functions, a lack of clarity in the allocation of responsibilities between the Group Reserves Auditor and the Group Reserves Co-ordinator and a lack of direct reporting responsibility of the Group Reserves Auditor to the Group internal audit function and of the business chief financial officers to the Group Chief Financial Officer.

Second Reserves Restatement

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that it would remove from proved reserves an additional 1,371 million boe of oil and natural gas that were reported as at December 31, 2003 and further restate the unaudited oil and natural gas reserves disclosures contained in the supplementary information accompanying the Financial Statements of the Group (the Second Reserves Restatement and, together with the First Reserves Restatement, the Reserves Restatements) to give effect to the removal of these volumes as of the earliest date on which they did not represent “proved reserves” within the applicable rules of the SEC (which in many cases is the date on which the volumes were initially booked as proved reserves). 43% of the volumes debooked as of December 31, 2003 as part of the Second Reserves Restatement had been categorised as proved developed reserves and 57% had been categorised as proved undeveloped reserves. The effects of the Second Reserves Restatement are reflected in the comparative periods presented in the Financial Statements of the Group. These effects were also reflected in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with the SEC on March 7, 2005.

Second Financial Restatement

In view of the inappropriate overstatement of unaudited proved reserves information resulting in the Second Reserves Restatement, it was determined to restate the Financial Statements of the Group and each of the Parent Companies for the year ended December 31, 2003 and prior periods (the Second Financial Restatement) to reflect the impact of the Second Reserves Restatement on those Financial Statements (as announced on February 3, 2005). This overstatement of unaudited proved reserves information had the effect of understating the depreciation, depletion and amortisation charges in the Financial Statements of the Group related to Exploration & Production in each of the years covered by the Second Financial Restatement. As capitalised costs relating to Exploration & Production were amortised across fewer proved reserves (following the Second Reserves Restatement), depreciation, depletion and amortisation associated with annual production volumes increased proportionally.

The effect of the Second Financial Restatement was to reduce the Company’s earnings for the year attributable to shareholders in 2003 by £35.5 million (2002: £15.6 million), and to reduce the previously reported net assets of the Company as at December 31, 2003 by £78.6 million (2002: £41.8 million). There was no impact on the Profit and Loss Account of the Company (2002: nil). The effect of the Second Financial Restatement was not significant to the Directors’ valuation of the Company’s investment in Group companies and is reflected in the comparative periods presented in these Financial Statements. The effect is also reflected in the Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed with the SEC on March 7, 2005.

The effect of the above change on the Company’s investments, is as follows:

			£ million
			2003				2002
Investments as previously stated				16,279.2				15,000.8
Oil and gas reserves related adjustments:
	Second Reserves Restatement			(78.6	)			(41.8	)
Restated investments				16,200.6				14,959.0

There is an equivalent effect on the Revaluation Reserve, which is reflected in the Company’s share of earnings retained by companies of the Royal Dutch/ Shell Group. There is no impact on the Company’s distributable profit.

4 Share in the income and assets of Group companies

Shell Transport’s share in certain items relating to the two Group Holding Companies is set out below. These companies own directly or indirectly the investments, which, with them, comprise the Group. The following supplementary information has therefore been provided in respect of Group Holding Companies in the aggregate and is derived from the Group Financial Statements on pages G2 to G48.

		£ million
						2003
		2004				As restateda
Fixed assets			24,016.2				25,646.6
Current assets including other long-term assets			15,867.0				12,330.7
Current liabilities			12,584.3				12,210.7
Long-term liabilities			3,457.0				3,400.1
Provisions			5,287.9				5,399.7

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						£ million
						2003				2002
		2004				As restateda				As restateda
Sales proceeds			73,742.4				65,205.3				58,232.8
Sales taxes, excise duties and similar levies			15,803.2				16,191.3				14,628.2
Net proceeds			57,939.2				49,014.0				43,604.6
Operating profit after net currency gains/losses			6,911.7				5,170.4				4,725.6
Interest and other income			372.5				486.1				199.5
Interest expense			265.2				327.2				344.4
Income before taxation			7,019.0				5,329.3				4,580.7
Taxation			3,283.8				2,310.1				2,040.0
Minority interests			136.8				87.2				46.7
Income from continuing operations			3,598.4				2,932.0				2,494.0
Income from discontinued operations, net of tax			340.8				6.2				49.9
Net income for the year			3,939.2				2,938.2				2,543.9

						$ million
Net income for the yearb			7,212				4,757				3,814

a	See Note 2 to the Group Financial Statements.
b	See Note 38 to the Group Financial Statements.

This supplementary information has been calculated in conformity with the accounting policies of the Group Financial Statements set out in Note 3 to those financial statements and as adjusted in Note 31 to conform with Netherlands GAAP. These policies differ in certain respects from accounting principles generally accepted in the UK. If this supplementary information was presented in conformity with accounting principles generally accepted in the UK, the impact on net assets at December 31, 2004 would not be significant, although current assets including other long-term assets would increase by approximately £0.3 billion (2003: £0.4 billion), fixed assets would decrease by approximately £0.6 billion (2003: £0.8 billion), long-term liabilities would decrease by approximately £0.1 billion (2003: £0.2 billion) and provisions would decrease by approximately £0.4 billion (2003: £0.6 billion). The impact on net income for the year is not significant. Shell Transport’s distributions from Group companies were as follows:

						£ million
		2004				2003				2002
Distributions from Group companies			1,735.4				1,361.5				1,403.2

						$ million
Distributions from Group companiesa			3,196				2,264				2,174

a	See Note 38 to the Group Financial Statements.

The Group separately reports income from discontinued operations (see Note 32 to the Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies). As a consequence, the Company’s earnings for the year attributable to shareholders and the related earnings per share have been separately identified between discontinued and continuing operations on page S2.

5 Tax on profit on ordinary activities

						£ million
		2004				2003				2002
Corporation tax at 30% (2003 and 2002: 30%) in respect of interest income less administrative expenses			0.1				0.3				0.4

No taxation liability arises in respect of income from shares in companies of the Group as this income consists of a distribution, which is not subject to taxation, from a UK resident company. Consequently, the effective tax rate is substantially lower than the UK Corporation tax rate of 30%.

Shell Transport’s share of taxation borne by Group and associated companies is given in Note 4.

6 Earnings per share

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7 Investments in Group companies

The 40% interest in Group net assets of £17,452.6 million (2003: 16,200.6 million) is equal to the interest attributable to Shell Transport of $33,654 million (2003: 28,884 million) shown in Note 38 to the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies.

Movements in Investments and Revaluation reserves

			$ million								£ million
											Shell
			40% interest in								Transport				Revaluation
			Group net				Exchange rate				investments				reserve
			assetsa,d				($/£)				As restated				As restated
Balance at December 31, 2002 (as restated)				24,062				0.62				14,959.0				12,459.3
Cumulative effect of change in accounting policyc				102				0.56				57.2				57.2
Balance at January 1, 2003				24,164								15,016.2				12,516.5
Movements during the year 2003:
	Share in the net income of Group companies			4,757				0.62				2,938.2				2,938.2
	Distribution to Shell Transport			(2,264	)			0.60				(1,361.5	)			(1,361.5	)
	Undistributed net income of Group companies			2,493				0.63				1,576.7				1,576.7
	Net (increase)/decrease in Parent Companies’ shares held by Group companies			(253	)			0.62				(156.0	)			(156.0	)
	Other comprehensive incomeb			2,480				0.60				1,498.7				1,498.7
	Translation effect arising from movements in the US dollar/ sterling rate											(1,735.0	)			(1,735.0	)
Balance at December 31, 2003 (as restated)				28,884				0.56				16,200.6				13,700.9
Movements during the year 2004:
	Share in the net income of Group companies			7,212				0.55				3,939.2				3,939.2
	Distribution to Shell Transport			(3,196	)			0.54				(1,735.4	)			(1,735.4	)
	Undistributed net income of Group companies			4,016				0.55				2,203.8				2,203.8
	Net (increase)/decrease in Parent Companies’ shares held by Group companies			(304	)			0.55				(167.5	)			(167.5	)
	Other comprehensive incomeb			1,058				0.53				563.2				563.2
	Translation effect arising from movements in the US dollar/ sterling rate											(1,347.5	)			(1,347.5	)
Balance at December 31, 2004				33,654				0.52				17,452.6				14,952.9

$ million
						2003				2002
		2004				As restated				As restated
Shell Transport’s 40% interest in Group net assets at December 31			33,654				28,884				24,062

£ million
							2003				2002
			2004				As restated				As restated
Shell Transport’s investment in Group companies comprise:
	Cost of investment			178.4				178.4				178.4
Shell Transport’s share of:
	Retained earnings of Group companies			20,560.7				18,356.9				16,723.0
	Parent Companies’ shares held, net of dividends received			(1,059.9	)			(892.4	)			(736.4	)
	Cumulative other comprehensive incomeb			482.2				(81.0	)			(1,579.7	)
Currency translation differences				(2,708.8	)			(1,361.3	)			373.7
				17,452.6				16,200.6				14,959.0
£/$ exchange rate at December 31				0.52				0.56				0.62

a	The Group Financial Statements have been restated (see Note 2 to the Group Financial Statements).
b	Other comprehensive income comprises principally cumulative currency translation differences arising within the Group Financial Statements.
c	This relates to a change in Group accounting policy in 2003 for asset retirement obligations which is recorded as an adjustment to the opening balance of net assets in 2003 in the Netherlands GAAP Group Financial Statements.
d	See Note 38 to the Netherlands GAAP Financial Statements.

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See Note 38 of the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies for the determination of Shell Transport’s 40% interest in Group net assets and movements therein, including movements resulting from Group net income and distributions to the Parent Companies.

The earnings retained by Group companies have been, or will be, substantially reinvested by the companies concerned, and any taxation unprovided on possible future distributions out of any uninvested retained earnings will not be material.

The Company will continue to hold its investments in Group companies. However, as the investments are stated in the Balance Sheet on a valuation basis, it is necessary to report that, if the investments were to be disposed of for the amount stated, and in absence of any substantial share holding exemptions applying, a taxation liability of approximately £1.5 billion would arise (restated 2003: £1.2 billion). It is likely that substantial share holding exemptions would apply to the majority of the investment in Group companies and would reduce this potential tax liability.

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8 Other investments

The aggregate amount of the paid up capital of RDS Holding at December 31, 2004 is €299.1 million (£155.1 million).

9 Share capital and dividends

The allotted, called up and fully paid share capital at December 31, 2004 was as follows:

			Number of shares				£
Equity shares
	Ordinary shares of 25p each
	As at 1 January			9,667,500,000				2,416,875,000
	Shares repurchased for cancellation			(42,600,000	)			(10,650,000	)
As at December 31				9,624,900,000				2,406,225,000
Non-equity shares
	First Preference shares of £1 each			2,000,000				2,000,000
	Second Preference shares of £1 each			10,000,000				10,000,000
				9,636,900,000				2,418,225,000

The First and Second Preference shares (the Preference shares) confer on the holders the right to a fixed cumulative dividend (5.5% and 7% on First and Second Preference shares respectively) and rank in priority to Ordinary shares. On a winding-up or repayment the Preference shares also rank in priority to the Ordinary shares for the nominal value of £1 per share (plus a premium, if any, equal to the excess over £1 of the daily average price for the respective shares quoted in the London Stock Exchange Daily Official List for a six-months period preceding the repayment or winding-up) but do not have any further rights of participation in the profits or assets of the Company. The Preference shares do not have voting rights unless their dividend is in arrears or the proposal concerns a reduction of capital, winding-up, sanctioning the sale of undertaking, an alteration of the Articles of Association or otherwise directly affects their class rights.

The Preference shares are irredeemable and form part of the permanent capital of the Company. The number in issue has remained unchanged since 1922. The fair value of the Preference shares based on market valuations at December 31, 2004 was 102.80 pence per share (2003: 94.25 pence per share) for the First Preference shares and 145.00 pence per share (2003: 137.75 pence per share) for the Second Preference shares.

Ordinary dividends paid and proposed are as follows:

		£ million
		2004				2003				2002
Interim of 6.25p in 2004, 6.10p in 2003 and 5.95p in 2002			603.7				589.7				578.0
Second interim of 10.7p in 2004, second interim of 9.65p in 2003 and final of 9.30p in 2002			1,029.9				932.9				899.1
Reduction due to share buyback and unclaimed dividends			(1.2	)			(0.3	)			(2.9	)
			1,632.4				1,522.3				1,474.2

10 Capital redemption reserve

		£ million
		2004				2003
As at January 1			69.0				69.0
Movement relating to shares bought by Shell Transport and cancelled			10.7				–
As at December 31			79.7				69.0

Share capital was cancelled on all shares repurchased under the Company’s share buyback programme. As required by the Companies Act 1985, the equivalent of the nominal value of the shares cancelled is transferred to a capital redemption reserve.

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11 Reconciliation of movements in Shareholders’ funds

		£ million
		2004				2003
						As Restated
Distributable profit for the year			1,735.5				1,362.4
Dividends			(1,633.2	)			(1,523.1	)
Repurchase of share capital, including expenses			(171.3	)			–
Unrealised surplus on revaluation of investments in companies of the Royal Dutch/Shell Group (Note 7)			1,252.0				1,241.6
Net addition to Shareholders’ funds			1,183.0				1,080.9
Shareholders’ funds as at January 1			16,481.5				15,400.6
Shareholders’ funds as at December 31			17,664.5				16,481.5

12 Auditors’ remuneration

13 Aggregate Directors’ emoluments

		£
		2004				2003				2002
Salaries, fees and benefits			4,073,864				2,436,181				1,716,378
Performance-related element			525,283				–				1,506,500
			4,599,147				2,436,181				3,222,878
Excess retirement benefitsa			31,675				40,165				23,495
Realised share option gains			–				–				16,476

Of the emoluments disclosed, £720,793 in 2004 (2003: £687,311; 2002: £458,162) were borne by Shell Transport and charged in the Profit and Loss Account.

a	Excess retirement benefits are the amount of unfunded retirement benefits paid to or receivable by past Directors which exceed those to which they were entitled on the date on which the benefits first became payable or March 31, 1997, whichever is the later.

14 Reconciliation between US GAAP and UK GAAP

		pence																								£million
		Earnings per share												Net income												Net assets
																														Dec. 31,
						2003				2002								2003				2002				Dec. 31,				2003
		2004				As restated				As restated				2004				As restated				As restated				2004				As restated
In accordance with UK GAAP			18.3				14.3				14.6				1,735.5				1,362.4				1,404.0				17,664.5				16,481.5
add: Share of earnings retained by companies of the Royal Dutch/ Shell Group			23.2				16.5				11.9				2,203.8				1,576.7				1,140.7
Earnings for year attributable to shareholders			41.5				30.8				26.5				3,939.3				2,939.1				2,544.7
Adjustments for US GAAP:
Ordinary dividend proposed																											1,029.9				932.9
Amortisation of goodwill (see i below)			0.4				0.4				0.4				36.7				42.0				33.3				94.2				64.4
Retirement obligation accounting policy change (see ii below)			–				0.7				–				–				64.1				–				–				–
Impairments (see iii below)			1.1				–				–				99.9				–				–				94.4				–
Reversal of impairments (see iv below)			(1.1	)			–				–				(102.9	)			–				–				(97.3	)			–
In accordance with US GAAP			41.9				31.9				26.9				3,973.0				3,045.2				2,578.0				18,785.7				17,478.8
less: Interest and other income less expenses and tax of Shell Transport															(0.1	)			(0.9	)			(0.8	)
less: Net current assets excluding ordinary dividend proposed of Shell Transport																											(1,159.2	)			(1,213.8	)
less: Other fixed assets investments of Shell Transport																											(82.6	)			–
Share in net income and net assets in companies of the Royal Dutch/ Shell Group (US GAAP)															3,972.9				3,044.3				2,577.2				17,543.9				16,265.0
Exchange rate (£/ $)															0.55				0.62				0.67				0.52				0.56
Share in net income and net assets in companies of the Royal Dutch/ Shell Group (US GAAP) (see Note 30 on page G37)															7,273				4,926				3,862				33,830				28,999

The table above reconciles Shell Transport’s net income and net assets under UK GAAP to US GAAP. In addition, the table shows the adjustments necessary to reconcile Shell Transport’s net income and net assets under US GAAP to its 40% share of Group net income

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and net assets (as shown in Note 30 to the Group Financial Statements). These adjustments consist of the elimination of Parent Company net assets and net income, which are not included in the net assets or net income of the Royal Dutch/Shell Group of Companies, and currency translation.

Under UK GAAP Shell Transport, as a Parent Company with no subsidiaries, accounts for its share of earnings in the Group on a dividend receivable basis in its profit and loss account. Its investment in the Group is at a Directors’ valuation based on 40% of the net assets of the Group, as presented in the Group Financial Statements in accordance with Netherlands GAAP. This is not in accordance with US GAAP which, in the circumstances of Shell Transport, would require equity accounting.

In addition under UK GAAP dividends are recorded in the year in respect of which they are declared (in the case of interim dividends) or proposed by the board of directors to the shareholders (in the case of final dividends). US GAAP requires dividends to be recorded in the period in which they are declared. The reconciliation between US GAAP and UK GAAP for 2003 in the table above has been updated for this item, which increases the US GAAP net assets in previously issued financial statements of £16,624.5 million by £932.9 million. The dividend adjustment has no impact on net income for 2004 (2003: nil). In addition, the net assets of 2003 both under UK GAAP and US GAAP have reduced by £78.6 million and net income under US GAAP has reduced by £35.5 million in respect of the Second Financial Restatement as detailed in Note 3.

The adjustment to net income and earnings per share represents the impact on net income for Shell Transport if the equity method of accounting was applied incorporating Shell Transport’s share of net income of Group companies on a US GAAP basis. This includes:

i)	an adjustment to Shell Transport’s share of net income of Group companies for the amortisation of goodwill. Under US GAAP goodwill is not amortised but is tested for impairment annually or when certain events occur that indicates potential impairment. Under Netherlands GAAP, goodwill is amortised on a straight-line basis over its estimated useful economic life, which is assumed not to exceed 20 years unless there are grounds to rebut this assumption;
ii)	an adjustment to Shell Transport’s share of net income of Group companies in relation to asset retirement obligations. Under US GAAP, a change in accounting for asset retirement obligations in 2003, was accounted for prospectively, with the cumulative effect of the change at the beginning of 2003 being reflected in 2003 net income. This change in accounting was also made under Netherlands GAAP. However, the cumulative effect of the change under Netherlands GAAP was reported as an adjustment to the opening balance of net assets and, due to the absence of comparative data, net income for prior years was not restated.
iii)	an adjustment to Shell Transport’s share of net income of Group companies in relation to impairment. Under US GAAP, only if an asset’s estimated undiscounted future cash flows are below its carrying amount is a determination required of the amount of any impairment based on discounted cash flows. Netherlands GAAP has no undiscounted test.
iv)	an adjustment to Shell Transport’s share of net income of Group companies in relation to recoverability of assets. Under US GAAP reversals of impairments are not permitted. Under Netherlands GAAP, a favourable change in the circumstances which resulted in an impairment would trigger the requirement for a redetermination of the amount of the impairment and any reversal is recognised in income.

The adjustment to net assets represents the effect of adopting equity accounting on a US GAAP basis and of recording dividends in the period in which they are declared as required by US GAAP.

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40% interest of Shell Transport in line items as derived from the Netherlands GAAP Group Financial Statements

		£ million				$ million
Balance Sheet
2004:
Current assets			12,829.6				24,739
Non current assets			27,053.6				52,167
Current liabilities			12,584.3				24,266
Non current liabilities			8,744.9				16,862
Minority interests in Group companies (40% of Group amount on page G41 translated at year end rate on page S9)			1,101.4				2,124
Shell Transport share of Group net assets (pages S9-£ & G47-$)			17,452.6				33,654
Other assets and liabilities of Shell Transport			211.9
Net Assets			17,664.5
2003 (as restated):
Current assets			9,784.5				17,444
Non current assets			28,192.8				50,264
Current liabilities			12,210.7				21,769
Non current liabilities			8,799.8				15,689
Minority interests in Group companies (40% of Group amount on page G41 translated at year end rate on page S9)			766.2				1,366
Shell Transport share of Group net assets (pages S9-£ & G47-$)			16,200.6				28,884
Other assets and liabilities of Shell Transport			280.9
Net Assets			16,481.5
Profit and Loss account
2004:
Sales proceeds (Revenue)			73,742.4				135,009
Operating profit			6,920.2				12,670
Income from continuing operations			3,598.4				6,588
Income from discontinued operations, net of tax			340.8				624
Net income for the year			3,939.2				7,212
Distribution for the year			1,735.4				3,196
2003 (as restated):
Sales proceeds (Revenue)			65,205.3				105,556
Operating profit			5,227.5				8,462
Income from continuing operations			2,932.0				4,746
Income from discontinued operations, net of tax			6.2				10
Net income for the year			2,938.2				4,756
Distribution for the year			1,361.5				2,264
2002 (as restated):
Sales proceeds (Revenue)			58,232.8				87,315
Operating profit			4,732.3				7,096
Income from continuing operations			2,494.0				3,739
Income from discontinued operations, net of tax			49.9				75
Net income for the year			2,543.9				3,814
Distribution for the year			1,403.2				2,174

15 Contingencies and litigation

Also in connection with the hydrocarbon reserves recategorisation, putative shareholder class actions were filed on behalf of participants in various Shell Oil Company qualified plans alleging that Royal Dutch, Shell Transport and various current and former officers and directors breached various fiduciary duties to employee participants imposed by the Employee Retirement Income Security Act of 1974 (“ERISA”). These suits were consolidated in the United States District Court in New Jersey and a consolidated class action complaint was filed in July 2004. Defendants’ motions to dismiss have been fully briefed. Some document discovery has taken place. The case is at

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an early stage and subject to substantial uncertainties concerning the outcome of the material factual and legal issues relating to the litigation, including the pending motion to dismiss and the legal uncertainties with respect to the methodology for calculating damage, if any, should defendants become subject to an adverse judgment. The Group is in settlement discussions with counsel for plaintiffs, which it hopes will lead to a successful resolution of the case without the need for further litigation. No financial provisions have been taken with respect to the ERISA litigation.

The reserves recategorisation also led to the filing of shareholder derivative actions in June 2004. The four suits pending in New York state court, New York federal court and New Jersey federal court demand Group management and structural changes and seek unspecified damages from current and former members of the Boards of Directors of Royal Dutch and Shell Transport. The suits are in preliminary stages and no responses are yet due from defendants. Because any money “damages” in the derivative actions would be paid to Royal Dutch and Shell Transport, management of Shell Transport does not believe that the resolution of these suits will have a material adverse effect on Shell Transport’s financial condition or operating results.

The United States Securities and Exchange Commission (SEC) and UK Financial Services Authority (FSA) issued formal orders of private investigation in relation to the reserves recategorisation which Royal Dutch and Shell Transport resolved by reaching agreements with the SEC and the FSA. In connection with the agreement with the SEC, Royal Dutch and Shell Transport consented, without admitting or denying the SEC’s findings or conclusions, to an administrative order finding that Royal Dutch and Shell Transport violated, and requiring Royal Dutch and Shell Transport to cease and desist from future violations of, the antifraud, reporting, recordkeeping and internal control provisions of the US Federal securities laws and related SEC rules, agreed to pay a $120 million civil penalty and has undertaken to spend an additional $5 million developing a comprehensive internal compliance program. In connection with the agreement with the FSA, Royal Dutch and Shell Transport agreed, without admitting or denying the FSA’s findings or conclusions, to the entry of a Final Notice by the FSA finding that Royal Dutch and Shell Transport breached market abuse provisions of the UK’s Financial Services and Markets Act 2000 and the Listing Rules made under it and agreed to pay a penalty of £17 million. The penalties from the SEC and FSA and the additional amount to develop a comprehensive internal compliance program have been paid by Group companies and fully included in the Income Statement of the Group. The United States Department of Justice has commenced a criminal investigation, and Euronext Amsterdam, the Dutch Authority Financial Markets and the California Department of Corporations are investigating the issues related to the reserves recategorisation. Management of Shell Transport cannot currently predict the manner and timing of the resolution of these pending matters and is currently unable to estimate the range of reasonably possible losses from such matters.

Group companies are subject to a number of other loss contingencies arising out of litigation and claims brought by governmental and private parties, which are handled in the ordinary course of business.

The operations and earnings of Group companies continue, from time to time, to be affected to varying degrees by political, legislative, fiscal and regulatory developments, including those relating to the protection of the environment and indigenous people, in the countries in which they operate. The industries in which Group companies are engaged are also subject to physical risks of various types. The nature and frequency of these developments and events, not all of which are covered by insurance, as well as their effect on future operations and earnings, are unpredictable.

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Directors’ Remuneration Report

Directors’ Remuneration Report

This report also discloses the individual remuneration of the Directors of Shell Transport for the year ended December 31, 2004. It has been compiled with reference to Schedule 7A of the Companies Act 1985, the Combined Code, and other corporate governance guidance on Directors’ remuneration. In reflection of the joint arrangements between Shell Transport and Royal Dutch, Dutch corporate governance disclosure requirements including the best practice provisions put forward by the Tabaksblat Committee in the Netherlands have also been taken into account. This report has been approved for inclusion in this Annual Report on Form 20-F and will be submitted for approval by shareholders at the Annual General Meeting.

This report contains the following sections:

–	The Remuneration and Succession Review Committee;
–	Remuneration policy;
–	2004 actual remuneration; and
–	Non-executive Directors.

The Remuneration and Succession Review Committee

The committee

Appointed by the Board of Shell Transport
Nina Henderson
Sir Peter Job
Lord Kerr of Kinlochard

Appointed by the Supervisory Board of Royal Dutch
Aarnout Loudon		Chairman of the Committee
Maarten van den Bergh		Appointed to the Committee with effect from July 1, 2004
Hubert Markl
Henny de Ruiter		Retired from the Committee on June 30, 2004

The Chairman of the committee is currently Aarnout Loudon, an appointee of Royal Dutch. Sir Peter Job has been nominated by the Board of Shell Transport to respond at the Annual General Meeting to any questions relating to remuneration issues. The Shell Transport members of the committee are currently all independent Non-executive Directors. Of the current Royal Dutch members of the committee, only Maarten van den Bergh is not an independent member of the Royal Dutch Supervisory Board, as allowed under Dutch corporate governance, since he served as a Managing Director of the Group from 1992 to 2000, as President of Royal Dutch from 1998 to 2000, and he currently serves as a Managing Director of one of the Group Holding Companies. Biographical details of the REMCO members are shown on page 100.

REMCO’s responsibilities

1	Further information in respect of the proposed unification transaction and Royal Dutch Shell plc will be available at www.shell.com in due course.

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senior executives of the Group, and periodically reviews these to assess alignment and consistency. In addition to fulfilling these responsibilities, REMCO also undertook a review of long-term incentive plans for Executive Directors.

As a joint committee of two independent boards, REMCO cannot formally determine the remuneration of individual Executive Directors. The committee makes recommendations to the Board of Shell Transport and the Supervisory Board of Royal Dutch. All such recommendations made in 2004 were approved by the Boards.

Following REMCO’s annual review of its Terms of Reference a revised version, on its recommendation, was approved by the Board of Shell Transport and the Supervisory Board of Royal Dutch in February 2004. They can be found on the Shell website (www.shell.com/investor).

During 2004 REMCO met eight times; attendance figures for the individual committee members are shown below:

Attendance
Members		Attendance
Aarnout Loudon			8			Chairman of the Committee
Maarten van den Bergh			2			Appointed to the Committee with effect from July 1, 2004
Nina Henderson			8
Sir Peter Job			7
Lord Kerr of Kinlochard			7
Hubert Markl			3
Henny de Ruiter			5			Retired from the Committee on June 30, 2004

Advisers to REMCO

Remuneration policy

Philosophy

–	Statement of General Business Principles, including the Group’s core values and commitment to contribute to sustainable development;
–	strategic direction;
–	need to attract and retain talented individuals;
–	aim to motivate and reward Executive Directors for exceptional performance that enhances the value of the Group; and
–	desire to align Executive Directors’ interests with those of shareholders.

The Group’s remuneration policy is based on the following working principles:

Performance driven

Competitiveness

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Consistency

Base pay

The committee recognised the enhanced role of the Chief Executive, compared to his previous role of Chairman of the Committee of Managing Directors and it has adjusted the Chief Executive’s salary level to reflect the increased responsibilities. The current base pay levels of the Chief Executive and the Managing Directors of the Company are:

Current base pay levels
Role		£
Chief Executive, Jeroen van der Veer			1,060,647	a
Managing Director, Malcolm Brinded			705,000
Managing Director, Peter Voser			545,000

a	Euro converted to sterling at the year-end rate of exchange to achieve a sterling equivalent of €1,500,000, which is the total annual base pay Jeroen van der Veer currently receives from the Group.

Annual incentive

As part of the annual business planning process, challenging financial, operational and sustainable development targets are set to form a Group Scorecard. Performance during the year is then measured against this Scorecard and annual bonus awards are made on this basis. For 2005 the Group Scorecard has been simplified and the elements made more transparent as part of the Group’s efforts to set clear priorities and reduce complexity. There are four components to the new Scorecard, each with its own weighting:

–	Total shareholder return (TSR) relative to our industry peers, with a 25% weighting;
–	Operational cash flow, with a 25% weighting;
–	Operational excellence in each of the businesses, with a 30% weighting; and
–	Sustainable Development, primarily based on the number of reportable cases of work related injuries, with a 20% weighting.

A clear process of measuring performance against the Scorecard has been put in place with agreed definitions, calculation methodologies and controls. The Scorecard elements will also be auditable. Targets are set at stretching but realistic levels. At the end of the financial year the results are translated into an overall Group score, which can range anywhere between zero and two, the minimum and the maximum, respectively. Bonus awards are based on the Group score multiplied by the target bonus level with REMCO using its judgment in making its final recommendations. The target level for Executive Directors for 2005 will be 100% of base pay, in line with competitive practices.

Long-term incentives

The proposed amendments to the Deferred Bonus Plan and the LTIP, outlined below, would not lead to an increase in the overall value of compensation for Executive Directors.

Deferred Bonus Plan

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Under the plan, Executive Directors can elect to invest a proportion of their annual bonus in shares. Provided that a participant remains in Group employment for three years following the deferral, or retires within the three-year period, he or she will be eligible for matching shares. The deferred bonus shares, together with shares equivalent to the value of dividends payable on the deferred bonus shares (dividend shares) and matching shares, are released three years after deferral.

REMCO has considered shareholder feedback on the current arrangements and has recommended that the proportion of annual bonus able to be deferred be increased and that performance conditions be attached to the release of matching shares.

The amended plan will allow Executive Directors to invest up to 50% of their annual bonus in shares. From 2006 25% of their annual bonus will be deferred on a mandatory basis. A participant will receive one matching share for every four deferred bonus and dividend shares accumulated. Provided that the performance condition is met, he or she will receive up to three further performance-based matching shares.

The performance condition is the Total Shareholder Return (TSR) of the Group against the major integrated oil companies, as follows:

–	TSR ranked 5th or 4th: no performance-based matching shares;
–	TSR ranked 3rd: one performance-based matching share;
–	TSR ranked 2nd: two performance-based matching shares;
–	TSR ranked 1st: three performance-based matching shares.

Deferrals in relation to the 2004 annual bonus have been made on these amended terms, conditional upon the approval of the Plan.

Long-Term Incentive Plan (LTIP)

–	200% of an award will be released if the Group is in first place;
–	150% for second place;
–	80% for third place;
–	awards will lapse entirely if the Group is in fourth or fifth place.

For any award to be released to Executive Directors the committee must be assured of the underlying performance of the Group. For this, it will take into consideration the Group Scorecard results, excluding TSR, over the applicable performance period, as it provides quantifiable measures of the Group’s performance and operational excellence.

Industry peer group for base pay, annual bonus, deferred bonus and LTIP

Major integrated oil companies

as at January 1, 2005
BP
Chevron Texaco
ExxonMobil
Royal Dutch/ Shell Group
Total

Pension policy

For the British Executive Directors² the principal sources of pension are the Shell Contributory Pension Fund (for service in the UK) and the Shell Overseas Contributory Pension Fund (for service overseas). Both Funds are defined benefit plans to which Executive Directors contribute the same percentage of relevant earnings as other employees. Neither the annual bonus nor the deferred bonuses are

2	British Managing Directors during 2004 were Sir Philip Watts and Malcolm Brinded. Sir Philip Watts resigned as a Managing Director of Shell Transport on March 3, 2004.

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pensionable. The latest date on which Executive Directors may retire is June 30, following their 60th birthday, and the maximum pension is two-thirds of final remuneration, excluding bonuses. There are provisions, as for all members of the above Funds, for a dependant benefit of 60% of actual or prospective pension, and a lump sum death-in-service payment of three times annual pensionable salary.

For the Swiss Executive Director³, the principal source of pension is the Shell Swiss Expatriate Pension Fund (SSEPF). This is a defined benefit fund to which all members contribute the same percentage of pensionable salaries. The pension retirement age for members of this fund is 60 and the maximum pension is 63% of their final remuneration, excluding bonuses. Neither the annual bonus nor the deferred bonuses are pensionable. There are provisions in the SSEPF for a surviving dependant benefit of 70% of prospective pension. A lump sum of two times base pay will be paid in case of death-in-service.

In light of changes to UK and Swiss pension law the pension policies for British and Swiss Executive Directors will be reviewed in 2005.

Other benefits policy

All-employee share schemes

Contracts policy

In the case of Executive Directors appointed from outside the Group, temporary severance arrangements may be agreed to facilitate the recruitment process.

External appointments

Shareholdings

Directors’ shareholdings can be found under the heading The “Shell” Transport and Trading Company public limited company on page 101. Details of Managing Directors’ interests in shares of Shell Transport under the Stock Option Plans, the Long-Term Incentive Plan and the Deferred Bonus Plan are on pages S23 to S24.

3	Peter Voser, a Swiss citizen, was appointed as a Managing Director of Shell Transport on October 4, 2004.

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Performance graph

2004 actual remuneration⁴

Base pay

Annual incentive

The overall 2004 Group Scorecard score was 0.9 and REMCO confirmed the outcome. Having regard to the Group’s performance against all targets, REMCO recommended and it was decided that the annual bonuses payable to Executive Directors in respect of the year 2004 are 90% of base pay.

Stock options

Stock options granted in March 2002 were 50% performance-linked and were due to vest in March 2005. The performance period for the options was January 1, 2002 to December 31, 2004. The Royal Dutch/ Shell Group ranked fourth in TSR against the industry peer group (three-year average over the period 2002 to 2004). Taking all these factors into consideration, the committee determined that none (0%) of the performance vesting stock options should vest. Based on this determination, half of the stock options granted to Executive Directors and Senior Executives in 2002 will vest based on time, and the other half of the stock options granted in 2002 will lapse.

Long-Term Incentive Plan

4	The information in the tables in this section has been subjected to audit by PricewaterhouseCoopers LLP, except for the Expected value columns in the Stock options table and in the Long-Term Incentive Plan table on pages S23 to S24, which are unaudited.

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of the FTSE20 together with the AEX10 as at January 1, 2004 (see below). The second comparator group consists of the five major integrated oil companies.

Half of each conditional award will be tested against the first group and half against the second group. For the first comparator group, 100% of the shares tested against that group will be awarded for performance in the top quartile and 25% will be awarded for performance at the median. Between these two points a straight-line calculation will be used. No shares will be received for performance below the median. For the second comparator group, 100% of the shares tested against that group will be received if the Group is in first place, 75% for second place and 50% for third place. No shares will be received for fourth or fifth place.

Home markets peer group for LTIP in 2004

FTSE20		AEX10
as at January 1, 2004		as at January 1, 2004
Anglo American		ABN AMRO
AstraZeneca		AEGON
Barclays		Ahold
BHP Billiton		Fortis
BP		Heineken
British American Tobacco		ING Group
British Sky Broadcasting		KPN
BT		Philips
Diageo		Royal Dutch
GlaxoSmithKline		Unilever N.V.
HBOS
HSBC
Lloyds TSB
National Grid Transco
Rio Tinto
Royal Bank of Scotland
Shell Transport
Tesco
Unilever PLC
Vodafone

a	In the case of Shell Transport and Royal Dutch, and Unilever PLC and Unilever N.V., the weighted average TSR of the two companies will be used.

Emoluments of Managing Directors in office during 2004																						£
										Payment
		Salaries				Annual				following				Car				Other
		and fees				bonusa				severance				benefitb				benefits				Total
Malcolm Brinded
2004c			601,478				525,283	d			–				12,381				9,261				1,148,403
Judith Boyntone
2004			222,926				0				553,827	f			0				0				776,753
2003			381,833				0				–				0				18,937				400,770
Peter Voserg
2004			788,935				0				–				0				0				788,935
Sir Philip Wattsh
2004			219,196				0				1,057,971				3,773				0				1,280,940
2003			843,021				0				–				21,876				0				864,897
2002			745,969				874,000	i			–				21,922				0				1,641,891

The aggregate amount of remuneration paid to or accrued for Managing Directors of Shell Transport as a group by Shell Transport and companies of the Group for services in all capacities during the fiscal year ended December 31, 2004, was £3,995,031.

a	The annual bonus is included in the related performance year and not in the following year in which it is paid.
b	The car benefit is the Inland Revenue defined cash equivalent of the cost of company-provided vehicles.
c	Malcolm Brinded was appointed a Shell Transport Managing Director with effect from March 3, 2004, therefore his Shell Transport emoluments are shown from this date. His emoluments during 2002, 2003 and up to and including March 3, 2004 have been listed in the 2004 Royal Dutch Annual Reports and Accounts.
d	Malcolm Brinded’s 2004 annual bonus amounted to £ 634,500 for the full year. His annual bonus up to and including March 3, 2004 has been listed in the 2004 Royal Dutch Annual Reports and Accounts.
e	Judith Boynton was appointed to the Board on July 1, 2003. Judith Boynton stepped aside as Group Chief Financial Officer and as Group Managing Director and Managing Director of Shell Transport on April 18, 2004. She remained with the Group in an advisory capacity reporting to the Chief Executive Jeroen van der Veer. Ms Boynton left the Group, by mutual agreement, effective December 31, 2004. Where appropriate, the 2003 and 2004 emoluments are prorated. Her benefits include the provision of a housing allowance. The emoluments she received from the Group in respect of this period amounted to £542,387.
f	This amount was paid in January 2005 following cessation of Judith Boynton’s employment on December 31, 2004. It includes an amount of £35,227 in respect of Shell Transport fees Judith Boynton would have received had she remained as a Director until December 31, 2004.
g	Peter Voser was appointed a Shell Transport Managing Director with effect from October 4, 2004, therefore, where appropriate, the 2004 emoluments are prorated. His salaries and fees include a one-off transition payment of £645,000 paid on joining the Group. He was not eligible for a 2004 annual bonus.
h	Sir Philip Watts resigned as a Shell Transport Managing Director and as an employee on March 3, 2004. Therefore, where appropriate, his 2004 emoluments are prorated. His salary and fees include compensation for unused leave days.
i	Of which one-third was deferred under the Deferred Bonus Plan.

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Table of Contents

Stock options
Shell Transport
		Number of 25p Ordinary shares under option
																														Expected								Realised
										Exercised																				value of				Realisable				gains on
										(cancelled/																				the 2004				gains at				stock
						Granted				lapsed)								Exercise												stock options				Dec 31,				options
		At Jan 1,				during				during				At Dec 31,				pricea				Exercisable				Expiry				grantb				2004c				exercised
		2004				the year				the year				2004				£				from date				date				£				£				£
Malcolm Brinded			37,500				–				–				37,500				4.39				11.12.00				10.12.07				–				1,875				–
			139,200				–				–				139,200				3.63				22.12.01				21.12.08				–				112,752				–
			183,750				–				–				183,750				5.05				23.03.03				22.03.10				–				0				–
			14,000				–				–				14,000				5.63				13.11.03				12.11.10				–				0				–
			278,200				–				(139,100	)			139,100				5.52				26.03.04				25.03.11				–				0				–
			–				800,000				–				800,000				3.99				07.05.07				06.05.14				702,240				–				–
Sir Mark Moody-Stuartd			440,800				–				–				440,800				3.63				22.12.01				29.06.06				–				357,048				–
			365,250				–				–				365,250				5.05				23.03.03				29.06.06				–				0				–
Peter Voser			–				800,000				–				800,000				4.32				05.11.07				04.11.14				760,320								–
Sir Philip Wattse			308,750				–				–				308,750				3.63				22.12.01				21.12.08				–				250,088				–
			255,750				–				–				255,750				5.05				23.03.03				02.03.09				–				0				–
			465,000				–				(232,500	)			232,500				5.52				26.03.04				02.03.09				–				0				–
			3,251	f			–				(3,251	)			0				5.09				01.02.07				31.07.07				–				–				–
			885,000				–				–				885,000				5.23				21.03.05				02.03.09				–				–				–
			1,165,000				–				–				1,165,000				3.66				19.03.06				02.03.09				–				–				–
Royal Dutch																			€																£
Malcolm Brinded			50,000				–				–				50,000				62.10				21.03.05				20.03.12				–				–				–
			115,000				–				–				115,000				36.81				19.03.06				18.03.13				–				–				–
Judith Boyntong			80,000				–				–				80,000				62.02				21.08.04				30.12.09				–				0				–
			60,000				–				–				60,000				62.10				21.03.05				30.12.09				–				–				–
Royal Dutch																			$																£
Judith Boyntong			70,500				–				–				70,500				40.64				19.03.04				18.03.13				–				612,036	h			–

The stock options listed above relate to Shell Transport Ordinary shares, with the exception of those stock options held by Malcolm Brinded and Judith Boynton which relate to Royal Dutch Ordinary shares. Other than the UK Sharesave Scheme options, they have a10-year term and are not exercisable within three years of grant. Of the stock options granted to Executive Directors before 2003, 50% are subject to performance conditions and 50% will vest over time. These performance conditions include TSR and other long-term indicators of Group performance over a three-year period. TSR is measured relative to other major integrated oil companies. 100% of the stock options granted in 2003 and 2004 are subject to performance conditions. Details of these performance conditions can be found in Actual remuneration 2004 – Stock options on page S21. The price range of the Shell Transport Ordinary shares during the year was £3.49 to £4.48 and the market price at year-end was £4.44.

The stock options listed above for Malcolm Brinded granted to him when a Managing Director of Royal Dutch, and for Judith Boynton, granted to her before she became a Managing Director of Shell Transport, relate to Royal Dutch Ordinary shares and have a10-year term. The euro-based options are not exercisable within three years of grant; the US-dollar based options vest in equal tranches over three years. The price range of the Royal Dutch Ordinary shares listed at the Euronext Exchange during the year was €36.76 to €43.67 and the market price at year-end was €42.35. The price range of the Royal Dutch Ordinary shares listed at the NYSE during the year was $46.10 to $57.69 and the market price at year-end was $57.38.

There were no other changes in the above interests in share options during the period from December 31, 2004 to March 29, 2005.

a	The exercise price is the average of the opening and closing share prices over a period of five trading days prior to and including the day on which the stock options are granted (no discount). For the US-dollar based options of Judith Boynton, the exercise price is the NYSE closing price on the date of grant (no discount). The exercise price of the UK Sharesave Scheme options is the mid-market price on the day of the launch of the plan in the year concerned.
b	The expected values of the 2004 stock options grants have been calculated on the basis of the Black-Scholes model valuations provided by Towers Perrin and Kepler Associates. The values are unaudited. The expected value is equal to 22% of the face value of the grant.
c	Represents the value of unexercised stock options at the end of the financial year, which is calculated by taking the difference between the exercise price of the option and the fair market value of Shell Transport or Royal Dutch shares, respectively, at December 31, 2004, multiplied by the number of shares under option at December 31, 2004. The actual gain, if any, a Managing Director will realise, will depend on the market price of the Shell Transport or Royal Dutch shares at the time of exercise.
d	Sir Mark Moody-Stuart holds share options relating to his former service with the Group.
e	Upon Sir Philip Watts’ resignation on March 3, 2004, the exercise dates of his options, other than his options held under the UK Sharesave Scheme, remained unchanged if the original expiry date was earlier than five years after this date, and changed to March 2, 2009, if the original expiry date was later than five years after this date. Except for his 2001 performance-linked stock options and his UK Sharesave stock options, his stock options interests did not change between March 3, 2004 and December 31, 2004, as none of them were exercised. Following REMCO’s recommendations all of the performance-linked stock options granted to Managing Directors in March 2001 lapsed on March 26, 2004. Sir Philip Watts did not receive any stock option grants in 2004.
f	These options were held under the UK Sharesave Scheme of The Shell Petroleum Company Limited. Sir Philip Watts’ interests in the UK Sharesave Scheme at March 3, 2004, amounted to 3,251 options. Following his resignation his account was closed on August 27, 2004. The funds, including £170 accumulated interest, were withdrawn. The dates stated in the table reflect the original exercise period.
g	Judith Boynton retains rights to various existing stock options and restricted share grants in accordance with plan rules. Her stock options interests did not change between April 18, 2004 and December 31, 2004, as none of them were exercised. She did not receive any stock option grants in 2004.
h	US dollar converted to sterling at the year-end rate of exchange.

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Deferred Bonus Plan

Number of

Market price

Average market

deferred bonus,

Matching

of deferred

price of

Total number

dividend and

Deferred

shares

bonus and

Dividend

dividend shares

of shares

matching shares

bonus shares

conditionally

matching shares

shares

paid during

Released/

under award

under award as at

awarded

awarded

at awardb

accrued

the year

lapsed

as at

Jan 1, 2004

during the yeara

during the year

£

during the yearc

£

during the year

Dec 31, 2004

Shell Transport Ordinary shares

Sir Philip Watts e

2003 award

124,327

–

–

3.66

3,014

3.98

f

(127,341

)g

0

2002 award

45,803

–

–

5.33

1,111

3.98

f

(46,914

)h

0

Royal Dutch ordinary shares

€

€

Malcolm Brinded

2003 award

6,718

–

3,359

36.66

433

41.71

d

–

10,510

i

Awards made in 2002 and 2003 refer to the portion of the 2001 and 2002 annual bonus which was deferred in 2002 and 2003, respectively, and the related accrued dividends and matching shares. The 2003 award listed above for Malcolm Brinded was deferred by him when a Managing Director of Royal Dutch and it relates to Royal Dutch ordinary shares. In 2004 there was no opportunity for Malcolm Brinded to defer any of his 2003 bonus into the Deferred Bonus Plan, as no 2003 bonuses were awarded.

a	Representing the proportion of the annual bonus that has been deferred and converted into notional share entitlements (deferred bonus shares), in which there is no beneficial ownership. The value of these deferred bonus shares is also included in the annual bonus figures in the Emoluments of Managing Directors table on page S22.
b	The market price is based on the average share price over a period of five trading days prior to and including the day on which the share awards are made.
c	Representing dividends paid during the year on the number of shares equal to the deferred bonus shares awarded, and also matching shares on those dividend shares.
d	The market price shown is the average at the date of the 2003 final and 2004 interim annual dividends paid during the year: €41.08 and €42.34, respectively.
e	Sir Philip Watts’ accrued bonus and dividend shares were released following his resignation on March 3, 2004. His matching shares (58,085 in total) lapsed.
f	Representing the actual five-days average market price at the date of the 2003 final annual dividends.
g	Comprised of deferred bonus and dividend shares that were released (84,894) and matching shares that lapsed (42,447). The related share price was £4.09.
h	Comprised of deferred bonus and dividend shares that were released (31,276) and matching shares that lapsed (15,638). The related share price was £4.09.
i	During the period January 1, 2005 to March 29, 2005, the total number of shares under award increased by 231 dividend and matching shares as a result of the second 2004 interim dividend pay-out. This results in a total number of shares under award of 10,741.

Long-Term Incentive Plan (LTIP)
																															Expected value				Theoretical
							Performance shares																								of the 2004				gains as at
							conditionally				Released								Market price at				Start of				End of				performance				Dec 31,
			At Jan 1,				awarded during				(cancelled/lapsed)				At Dec 31,				date of awarda				performance				performance				shares awardb				2004c
			2004				the year				during the year				2004				£				period				period				£				£
Shell Transport Ordinary shares
Malcolm Brinded
	2004			–				353,383				–				353,383				3.99				01.01.04				31.12.06				606,299				–
Judith Boyntond
	2003			266,475				–				(266,475	)			0				4.09				01.01.03				31.12.05				–				–
Peter Voser
	2004			–				252,314				–				252,314				4.32				01.01.04				31.12.06				468,698				–
Sir Philip Wattse
	2003			427,872				–				(427,872	)			0				4.09				01.01.03				31.12.05				–				–
Royal Dutch ordinary shares																				€																£
Malcolm Brinded
	2003			41,758				–				–				41,758				40.95				01.01.03				31.12.05				–				0

100% of the performance shares awarded in 2003 and 2004 are subject to performance conditions. Details of these conditions can be found in Actual Remuneration 2004 – Long-Term Incentive Plan (LTIP) on page S19.

a	The market price is based on the average of the opening and closing share prices over a period of five trading days prior to and including the day on which the number of shares are determined in accordance with the Plan rules.
b	The expected values of the 2004 performance shares awards have been calculated on the basis of a standard valuation approach provided by Towers Perrin and Kepler Associates. The values are unaudited. The expected value based on this approach is equal to 43% of the face value of the award.
c	Represents the value of the conditional performance shares under the LTIP at the end of the financial year, which is calculated by multiplying the fair market value of Shell Transport or Royal Dutch, respectively, at December 31, 2004, by the number of shares under the LTIP that would vest based on the achievement of performance conditions up to December 31, 2004.
d	Judith Boynton stepped aside as Group Chief Financial Officer and as Group Managing Director and Managing Director of Shell Transport on April 18, 2004. She remained with the Group in an advisory capacity reporting to the Chief Executive Jeroen van der Veer. Ms Boynton left the Group, by mutual agreement, effective December 31, 2004. Long-Term Incentive Plan interests crystallised following the end of employment (not Directorship). None of her 2003 Long-Term Incentive Plan shares awarded in 2003 vested. She did not receive any Long-Term Incentive Plan awards in 2004. As part of her remuneration prior to her appointment as a Shell Transport Managing Director, Judith Boynton received 17,000 conditional Royal Dutch ordinary shares on October 1, 2002; these were paid out to her in cash in January 2005, at a gross value of £552,306.
e	Sir Philip Watts resigned as a Shell Transport Managing Director and as an employee on March 3, 2004. Long-Term Incentive Plan interests crystallised following the end of employment, not Directorship. None of the shares awarded to him in August 2003 under the Long-Term Incentive Plan vested. He did not receive any Long-Term Incentive Plan awards in 2004.

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Table of Contents

Pensions																						£ thousand
		Accrued pension												Transfer values of accrued benefits
																										Increase in
																										accrued
																										pension over
																										the year
										Increase over												Increase over				(excluding
										the year												the year less				inflation) less
		At Dec 31,				Increase over				(excluding				At Dec 31,				At Dec 31,				Director’s				Director’s
		2004				the year				inflation)				2004				2003				contributions				contributions
Malcolm Brindeda			411.25	b			77.00				65.30				6,219.10				4,525.00				1,656.40				949.80
Judith Boyntonc			67.71	d			19.58	e			17.89	e			510.43	d			404.99	d			143.22	e			153.93	e
Sir Philip Wattsf			468.54				20.00				(4.30	)			12,691.90				10,007.80				2,675.10				(107.50	)
Peter Voserg			119.42	h			114.58	i			114.58	i			1,130.41	h			0	h			18.94	i			18.94	i

a	Malcolm Brinded resigned as a Managing Director of Royal Dutch on March 3, 2004 and was appointed a Managing Director of Shell Transport on the same date. His pension figures reflect 2004 in full, including the period of January 1, 2004 to March 3, 2004, when he was a Royal Dutch Managing Director.
b	As a result of the 2003 valuation of the SOCPF the Actuary requested that a special company contribution should be paid in addition to the usual company monthly contributions, consistently applied to all participants in the SOCPF. The amount stated comprises the basic pension increase and a prorated amount relating to this additional employer contribution.
c	For Judith Boynton, the Company contributed £43,155 based on the quarterly average exchange rate to the Shell Savings Plans, which are defined contribution schemes, during the period January 1, 2004 to December 31, 2004. She left the Group, by mutual agreement, effective 31 December 2004 and in January 2005 withdrew her pension entitlements from the Shell Expatriate Employment US (SEEUS) Prior Service Pension Plan in the form of a lump sum of £510,435 based on the year-end rate of exchange.
d	US dollar converted to sterling at the year-end rate of exchange.
e	Includes an accrued pension increase and a movement in the exchange rate between the US dollar and sterling over the period disclosed; US dollar converted to sterling at the quarterly average rate of exchange.
f	Sir Philip Watts resigned as a Managing Director of the Company on March 3, 2004. He took a reduced pension to reflect his early retirement following his resignation. He commuted pension of £115,527 per annum in return for a lump sum of £1,621,311. His accrued pension at December 31, 2004, is reflective of this commutation. The stated accrued pension increase over the year figures do not take into account this commutation.
g	Peter Voser became a member of the Shell Swiss Expatriate Pension Fund (SSEPF) on October 4, 2004. His accrued rights from his previous employer have been transferred into the fund and are included in his accrued pension at December 31, 2004. The transfer value of the accrued benefits transferred from Peter Voser’s previous employer are treated as a Director’s contribution and therefore excluded from the transfer values of increases of accrued benefits over the year. Additional funding will be provided by the Company in 2005 such that pension benefits under the SSEPF are available to him will be equivalent to the pension benefit which would have been available to him under the SSEPF had he been a continuous active member of the SSEPF since January 1 following his 24th birthday to the date of him joining the SSEPF. The additional funding will amount to a lump sum of £1.57 million to be paid to the SSEPF in 2005 (Swiss franc converted to sterling at the year-end rate of exchange to achieve a sterling equivalent of CHF 3.43 million).
h	Swiss franc converted to sterling at the year-end rate of exchange.
i	Includes an accrued pension increase and a movement in the exchange rate between the Swiss franc and sterling over the period disclosed; Swiss franc converted to sterling at the quarterly average rate of exchange.

Pensions

The 2004 contribution rates for the Shell Swiss Expatriate Pension Fund (SSEPF) were 10% for both company and employees. Contributions to this pension fund are based on the advice of actuaries.

For Judith Boynton⁵ the principal sources of pension included pension plans and savings plans. Pension plans are the Shell Expatriate Employment US (SEEUS) Prior Service Pension Plan, the Shell Pension Plan and the Senior Executives Group Benefits Restoration Plan. These are defined benefit plans which are non-contributory. Savings plans are the Shell Provident Fund for US employees, the Shell Pay Deferral Investment Fund for US employees, and the Senior Executive Group Deferral Plan. These are defined contribution plans which are contributory on a voluntary basis. In line with standard US market practice the annual bonus is pensionable.

As there is no mandatory retirement date in the USA, pensions include provisions which allow for retirement at age 60, provided service requirements are met. There are also provisions for a spousal benefit of 50% of actual pension. A lump sum death benefit is offered under the defined benefit plans if death occurs before pension payments commence and if the participant is unmarried.

Company contributions were not required for the SEEUS Prior Service Pension Plan or for the Senior Executive Group Benefits Restoration Plan during 2004. The employing company contribution rate for the Shell Pension Plan was 5.1% in 2004. Executive Directors are not required to contribute to these plans.

During 2004 Judy Boynton, Malcolm Brinded, Peter Voser and Sir Philip Watts accrued retirement benefits under defined benefit plans (2003: three Managing Directors; 2002: two Managing Directors). In 2004 Judy Boynton also accrued retirement benefits under defined contribution schemes (2003: one Managing Director; 2002: not applicable). Managing Directors accrued pension benefits during the year as detailed in the table above. The transfer values are calculated using the cash equivalent transfer value method in accordance with Actuarial Guidance Note GN11.

5	Judith Boynton stepped aside as Group Chief Financial Officer and as Group Managing Director and Managing Director of Shell Transport on April 18, 2004. She remained with the Group in an advisory capacity reporting to the Chief Executive Jeroen van der Veer. Ms Boynton left the Group, by mutual agreement, effective December 31, 2004.

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Table of Contents

Managing Directors’ service contracts

Peter Voser’s contract is effective from October 4, 2004. His contract includes a temporary severance arrangement in the case of a company-initiated termination for reasons other than gross misconduct. During the first three years of his employment, the severance pay would be equal to the sum of the applicable gross annual base pay and the most recent annual bonus, but in no event less than £1,000,000.

Sir Philip Watts’ employment contract was effective from July 1, 2002, and he resigned on March 3, 2004. His severance payment following his resignation as a Managing Director of Shell Transport, and as an employee consisted of a lump sum payment of £1,057,971. This amount was based on his salary as an employee until his normal retirement date in June 2005. No Directors’ fees have been paid for this period. Sir Philip Watts did not receive a performance-related annual bonus or stock options or any awards under the LTIP in respect of 2004. He retained rights to various existing stock options in accordance with plan rules. The schedule for his stock options is disclosed in the Stock Options table on page S23. None of the 427,872 shares conditionally granted to him in August 2003 under the Long Term Incentive Plan vested. By his own choice, Sir Philip Watts had elected to invest part of his previously earned bonuses in Shell Transport shares under the Deferred Bonus Plan, which allows for matching shares to be granted to those who hold them for three years. In his case, no matching shares have been awarded. He has the legal right to a pension of £468,540 per annum under the Shell pension scheme to which he has contributed over the past 35 years. Under pre-existing provisions, Sir Philip Watts is also entitled to the reimbursement of litigation costs under certain circumstances. See “Discussion and Analysis of Financial Condition and Results of Operations — Legal Proceedings”.

Judith Boynton’s employment contract was effective from July 1, 2003 and was governed by US law. Employment was on an “at-will” basis. She was eligible for a severance arrangement in case of a company-initiated termination for reasons other than gross misconduct. Judith Boynton stepped aside as Group Chief Financial Officer and as Group Managing Director and Managing Director of Shell Transport on April 18, 2004. She remained with the Group in an advisory capacity reporting to the Chief Executive Jeroen van der Veer. Ms Boynton left the Group, by mutual agreement, effective December 31, 2004. She received a severance payment of $1,000,000 (£518,600) pursuant to the previously disclosed terms of her employment. She did not receive a performance-related annual bonus or stock options or any awards under the LTIP in respect of 2004. She retained rights to various existing stock options and restricted share grants in accordance with plan rules. The schedule for her stock options is disclosed in the Stock Options table on page S23. None of her 2003 Long-Term Incentive Plan award of conditional shares vested. Under pre-existing provisions, Ms. Boynton is also entitled to the reimbursement of litigation costs under certain circumstances. See “Discussion and Analysis of Financial Condition and Results of Operations — Legal Proceedings”.

No payments on termination were made to retiring or past Directors during the year under review other than those referred to above and listed in the Emoluments of Managing Directors table on page S22.

Non-executive Directors

Remuneration policy

Appointments

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Table of Contents

Fees

Executive Directors of Shell Transport also received Directors’ fees of £50,000 per annum from the Company. These fees are included in the overall salary levels for Executive Directors recommended by REMCO. After the Annual General Meeting of 2005 Directors’ fees will no longer be paid to Executive Directors, and they will only receive a salary from the Group. This will not affect their overall salary levels.

There are no proposals to increase Shell Transport Directors’ fees in 2005.

The aggregate amount of non-executive Directors fees paid to or accrued for non-executive Directors of Shell Transport by Shell Transport and companies of the Group for services in all capacities during the fiscal year ended December 31, 2004, was £604,116.

Remuneration of non-executive Directors										£
		2004				2003				2002
Teymour Alireza			65,000				63,500				45,375
Sir Peter Burt			50,000				50,000				21,795
Dr Eileen Buttle			52,500				50,000				39,375
Luis Giusti			69,500				63,500				45,375
Nina Henderson			65,000				63,500				45,375
Sir Peter Job			50,000				50,000				39,375
Lord Kerr of Kinlochard			50,000				50,000				21,795
Sir Mark Moody-Stuarta			68,982				69,170				57,689
Lord Oxburghb			133,134				55,000				42,800

The information in this table is subject to audit.

a	Sir Mark Moody-Stuart received fees from the Group Holding Companies in respect of duties performed by him as Director of these companies in 2004, 2003 and 2002; they amounted to £18,982, £19,170 and £18,314, respectively.
b	Lord Oxburgh received fees from the Group Holding Companies in respect of duties performed by him as Chairman of the Conference in 2004; they amounted to £41,123. The costs of this fee are borne equally by the Group Holding Companies.

Terms of Appointment
		Terms of Appointmenta
Teymour Alireza			2006
Sir Peter Burt			2009
Dr Eileen Buttle			2006
Luis Giusti			2007
Nina Henderson			2007
Sir Peter Job			2008
Lord Kerr of Kinlochard			2009
Sir Mark Moody-Stuart			2005
Lord Oxburgh			2005

a	The term of appointment is until the close of business of the Annual General Meeting in the year shown and is subject to the provisions of the Articles of Association.

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Group Share Plans

Set out below is a summary of the principal employee share schemes operated by Group companies¹. The shares subject to the plans are existing issued shares of Shell Transport or Royal Dutch. Shares to be delivered by a Group company under these plans are generally bought in the market at the time the commitment is made.

Long-Term Incentive Plan (LTIP)

Restricted Share Plan

Stock Option Plans

Options under the Stock Option Plans are exercisable three years from grant except for those granted under the US plans which vest one-third per year for three years. Stock options lapse ten years after grant; however, leaving Group employment may cause options to lapse earlier.

For the Executive Directors and the most senior executives 100% of options granted under the Stock Option Plans in 2003 and 2004 are subject to performance conditions.

Global Employee Share Purchase Plan

UK Sharesave Scheme

Shell All-employee Share Ownership Plan

1	Details of the number of shares held by Group companies in connection with the above plans are shown in Note 23 of the Group Financial Statements on pages G26 to G28.

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Royal Dutch/Shell Group of Companies

We have audited the Financial Statements appearing on pages G2 to G37 of the Royal Dutch/ Shell Group of Companies for the years 2004, 2003 and 2002. The preparation of the Financial Statements is the responsibility of management. Our responsibility is to express an opinion on the Financial Statements based on our audits.

We conducted our audits in accordance with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by management in the preparation of the Financial Statements, as well as evaluating the overall Financial Statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Financial Statements referred to above present fairly, in all material respects, the financial position of the Royal Dutch/ Shell Group of Companies at December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in accordance with generally accepted accounting principles in the United States.

As discussed in Note 2 on pages G5 to G8, the Group has restated its Financial Statements for the two years ended December 31, 2003, to correct for the financial impact of the Second Reserves Restatement.

As discussed in Note 3 on pages G8 to G12, the Group adopted the provisions of Statement of Financial Accounting Standard No. 143 “Accounting for Asset Retirement Obligations” as of January 1, 2003; the Group adopted the provisions of Financial Accounting Standards Board Interpretation No. 46 “Consolidation of Variable Interest Entities – an interpretation of ARB51” as of September 30, 2003.

 

 

 

/s/ KPMG Accountants N.V.

 

 

 

/s/ PricewaterhouseCoopers LLP

 

March 29, 2005

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Financial Statements

Statement of Income		$ million
										2003				2002
		Note				2004				As restateda				As restateda
Sales proceeds							337,522				263,889				218,287
Sales taxes, excise duties and similar levies							72,332				65,527				54,834
Net proceedsb							265,190				198,362				163,453
Cost of salesb							221,678				165,147				135,658
Gross profit							43,512				33,215				27,795
Selling and distribution expenses							12,340				11,409				9,617
Administrative expenses							2,516				1,870				1,587
Exploration							1,823				1,475				1,052
Research and development							553				584				472
Operating profit of Group companies							26,280				17,877				15,067
Share of operating profit of associated companies			7				5,653				3,446				2,792
Operating profit							31,933				21,323				17,859
Interest and other income			8				1,705				1,967				748
Interest expense			9				1,214				1,324				1,291
Currency exchange gains/(losses)							(39	)			(231	)			(25	)
Income before taxation							32,385				21,735				17,291
Taxation			10				15,136				9,349				7,647
Income after taxation							17,249				12,386				9,644
Income applicable to minority interests							626				353				175
Income from continuing operations							16,623				12,033				9,469
Income from discontinued operations, net of tax			4				1,560				25				187
Cumulative effect of a change in accounting principle, net of tax			3				–				255				–
Net income							18,183				12,313				9,656

Statement of Comprehensive Income and Parent Companies’ interest in Group net assets	$ million

											2003				2002
			Note				2004				As restated				As restated
Net income								18,183				12,313				9,656
Other comprehensive income, net of tax:				6
	currency translation differences			20				3,148				5,102				2,432
	unrealised gains/(losses) on securities							(350	)			689				25
	unrealised gains/(losses) on cash flow hedges							31				51				(225	)
	minimum pension liability adjustments							(185	)			358				(1,475	)
Comprehensive income								20,827				18,513				10,413
Distributions to Parent Companies								(7,989	)			(5,660	)			(5,435	)
Increase in Parent Companies’ shares held, net of dividends received				23				(759	)			(631	)			(844	)
Loss on sale of Parent Companies’ shares								–				(1	)			–
Parent Companies’ interest in Group net assets at January 1								72,497				60,276				56,142
Parent Companies’ interest in Group net assets at December 31				5				84,576				72,497				60,276

a	See Note 2.
b	Includes net proceeds for buy/sell contracts for which the costs are included in cost of sales. See Note 3 on page G8 to G12.

The Notes on pages G5 to G37 are an integral part of these statements.

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Statement of Assets and Liabilities				$ million
												Dec 31,
								Dec 31,				2003
				Note				2004				As restateda
Fixed assets
	Tangible assets				11				88,940				87,088
	Intangible assets				11				4,890				4,735
	Investments:
		associated companies			7				19,743				19,371
		securities			15				1,627				2,317
		other							1,121				1,086
Total fixed assets									116,321				114,597
Other long term assets
	Prepaid pension costs				21				8,278				6,516
	Deferred taxation				10				1,995				2,092
	Other				12				4,369				2,741
Total other long-term assets									14,642				11,349
Current assets
	Inventories				13				15,391				12,690
	Accounts receivable				14				37,998				28,969
	Cash and cash equivalents				15				8,459				1,952
Total current assets									61,848				43,611
Current liabilities: amounts due within one year
	Short-term debt				16				5,822				11,027
	Accounts payable and accrued liabilities				18				40,207				32,347
	Taxes payable				10				9,885				5,927
	Dividends payable to Parent Companies								4,750				5,123
Total current liabilities									60,664				54,424
Net current assets/(liabilities)									1,184				(10,813	)
Total assets less current liabilities									132,147				115,133
Long-term liabilities: amounts due after more than one year
	Long-term debt				16				8,600				9,100
	Other				19				8,065				6,054
									16,665				15,154
Provisions
	Deferred taxation				10				14,844				15,185
	Pensions and similar obligations				21				5,044				4,927
	Decommissioning and restoration costs				24				5,709				3,955
									25,597				24,067
Group net assets before minority interests									89,885				75,912
Minority interests									5,309				3,415
Net assets									84,576				72,497

a	See Note 2.

The Notes on pages G5 to G37 are an integral part of these statements.

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Statement of Cash Flows (see Note 20)					$ million
													2003				2002
					Note				2004				As restated				As restated
Cash flow provided by operating activities
	Net income									18,183				12,313				9,656
	Adjustments to reconcile net income to cash flow provided by operating activities
		Depreciation, depletion and amortisation				11				12,273				11,711				8,739
		Profit on sale of assets								(3,033	)			(2,141	)			(367	)
		Movements in:
			inventories							(2,731	)			(236	)			(2,079	)
			accounts receivable							(8,462	)			1,834				(5,830	)
			accounts payable and accrued liabilities							7,708				(212	)			6,989
			taxes payable							2,999				(218	)			(735	)
		Associated companies: dividends more/(less) than net income				7				258				511				117
		Deferred taxation and other provisions								(524	)			(621	)			423
		Long-term liabilities and other								(1,798	)			(1,588	)			(805	)
		Income applicable to minority interests								714				366				175
Cash flow provided by operating activities										25,587				21,719				16,283
Cash flow used in investing activities
	Capital expenditure (including capitalised leases)					11				(12,734	)			(12,252	)			(12,102	)
	Acquisitions (Enterprise Oil, Pennzoil-Quaker State and additional shares in Equilon)																	(8,925	)
	Proceeds from sale of assets									5,078				2,286				1,099
	New investments in associated companies					7				(1,058	)			(983	)			(1,289	)
	Disposals of investments in associated companies									1,328				708				501
	Proceeds from sale and other movements in investments									1,743				1,989				83
Cash flow used in investing activities										(5,643	)			(8,252	)			(20,633	)
Cash flow used in financing activities
	Long-term debt (including short-term part):
		new borrowings								544				572				5,267
		repayments								(1,688	)			(2,740	)			(5,610	)
										(1,144	)			(2,168	)			(343	)
	Net increase/(decrease) in short-term debt									(3,701	)			(2,507	)			7,058
	Change in minority interests									807				(1,363	)			421
	Dividends paid to:
		Parent Companies								(8,490	)			(6,248	)			(6,961	)
		minority interests								(264	)			(300	)			(228	)
Cash flow used in financing activities										(12,792	)			(12,586	)			(53	)
Parent Companies’ shares: net sales/(purchases) and dividends received										(758	)			(633	)			(864	)
Currency translation differences relating to cash and cash equivalents										113				148				153
Increase/(decrease) in cash and cash equivalents										6,507				396				(5,114	)
Cash and cash equivalents at January 1										1,952				1,556				6,670
Cash and cash equivalents at December 31										8,459				1,952				1,556

The Notes on pages G5 to G37 are an integral part of these statements.

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Notes to the Financial Statements

1 The Royal Dutch/Shell Group of Companies

Arrangements between Royal Dutch and Shell Transport provide, inter alia, that notwithstanding variations in shareholdings, Royal Dutch and Shell Transport shall share in the aggregate net assets and in the aggregate dividends and interest received from Group companies in the proportion of 60:40. It is further arranged that the burden of all taxes in the nature of, or corresponding to, an income tax leviable in respect of such dividends and interest shall fall in the same proportion. Dividends are paid by Group companies to Royal Dutch and Shell Transport in euros and pounds sterling, respectively. The division of Group net assets between the Parent Companies and movements therein, including movements resulting from Group net income and distributions to the Parent Companies, are disclosed in Note 30 to these Financial Statements.

Unification Proposal

Reflecting the existing 60:40 ownership by Royal Dutch and Shell Transport of the Group, it is proposed that Royal Dutch shareholders will be offered 60% of the ordinary share capital in Royal Dutch Shell and Shell Transport shareholders will receive 40% of the ordinary share capital in Royal Dutch Shell. To implement the proposal, it is intended that (i) Royal Dutch Shell will make an offer to acquire all of the issued and outstanding ordinary shares of Royal Dutch in exchange for Royal Dutch Shell Class A ordinary shares or American depositary shares (“ADSs”) representing Royal Dutch Shell Class A ordinary shares and (ii) Royal Dutch Shell will become the parent company of Shell Transport pursuant to a United Kingdom reorganisational procedure referred to as a “scheme of arrangement” under section 425 of the UK Companies Act 1985, as amended. As a result of the scheme of arrangement, holders of Shell Transport Ordinary shares (and holders of Shell Transport bearer warrants) will receive Royal Dutch Shell Class B ordinary shares and holders of Shell Transport ADSs will receive ADSs representing Royal Dutch Shell Class B ordinary shares. The Class A ordinary shares and Class B ordinary shares will have identical voting rights and will vote together as a single class on all matters, including the election of directors, unless a matter affects the rights of one class as a separate class. Class A ordinary shares and Class B ordinary shares will have identical rights upon a liquidation of Royal Dutch Shell and dividends declared on each will be equivalent in amount. However, for tax purposes, holders of Class A ordinary shares will receive Dutch source dividends, while holders of Class B ordinary shares will receive dividends that are UK source to the extent that these dividends are paid through a dividend access mechanism to be established. Implementation of the Transaction will be the subject of appropriate consultation with relevant employee representative bodies as required as well as the satisfaction of certain other conditions. It is currently expected that the Transaction will be completed in July 2005.

2 Restatement of previously issued Financial Statements

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Reserves Restatement were reflected in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F as originally filed with the Securities & Exchange Commission (SEC) on June 30, 2004.

Following the January 9, 2004 announcement of the initial reserves recategorisation, the Group Audit Committee (GAC) appointed Davis Polk & Wardwell to lead an independent review of the facts and circumstances surrounding the recategorisation, and to report its findings and any proposed remedial actions to the GAC for its consideration. Based largely on the Davis Polk & Wardwell report, the Parent Companies, Royal Dutch and Shell Transport, determined that the principal causes that permitted the initial booking and maintenance of the volumes impacted by the First Reserves Restatement as proved reserves are as follows:

–	the Group’s guidelines for booking proved reserves were inadequate in several respects, including (i) containing inconsistencies with the SEC’s rules and published guidance relating to proved reserves and (ii) failing to clearly and sufficiently impart these requirements and guidance to users of the guidelines. In addition, users of the guidelines in certain cases misapplied or disregarded SEC rules and published guidance and in some cases only applied changes in the guidelines prospectively rather than retrospectively. There was also insufficient knowledge and training among users of the guidelines of the SEC requirements relating to proved reserves;
–	executives and employees encouraged the booking of proved reserves, while discouraging the debooking of previously booked reserves. This fostered an atmosphere that failed to emphasise the paramount importance of the compliance element of proved reserves decisions; and
–	there were other material weaknesses in the Group’s controls relating to the booking of proved reserves, including insufficient resources allocated to the Group Reserves Auditor and Group Reserves Co-ordinator functions, a lack of clarity in the allocation of responsibilities between the Group Reserves Auditor and the Group Reserves Co-ordinator and a lack of direct reporting responsibility of the Group Reserves Auditor to the Group internal audit function and of the business chief financial officers to the Group Chief Financial Officer.

Second Reserves Restatement

Second Financial Restatement

The effect of the Second Financial Restatement was to reduce net income in 2003 by $183 million (2002: $66 million), of which additional depreciation in 2003 was $289 million (2002: $118 million), and to reduce the previously reported net assets as at December 31, 2003 by $351 million. The effects of the Second Financial Restatement are reflected in the comparative periods presented in these Financial Statements. These effects were also reflected in Amendment No. 2 to the 2003 Annual Report on Form 20-F, as filed

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with the SEC on March 7, 2005. The impact on the information included in these Financial Statements is summarised in the tables below:

Statement of Income																														$ million
																		2003																				2002
														Reclassification																				Reclassification
		As				Second								for								As				Second								for
		originally				Reserves				As				discontinued				As				previously				Reserves				As				discontinued				As
		reporteda				Restatement				restated				operationsb				restated				restateda				Restatement				restated				operationsb				restated
Net proceeds			201,728				–				201,728				(3,366	)			198,362				166,601				–				166,601				(3,148	)			163,453
Cost of sales			167,500				289				167,789				(2,642	)			165,147				137,997				118				138,115				(2,457	)			135,658
Exploration			1,476				–				1,476				(1	)			1,475				1,073				–				1,073				(21	)			1,052
Other operating expenses			14,428				–				14,428				(565	)			13,863				12,027				–				12,027				(351	)			11,676
Share of operating profit of associated companies			3,484				(19	)			3,465				(19	)			3,446				2,822				(6	)			2,816				(24	)			2,792
Operating profit			21,808				(308	)			21,500				(177	)			21,323				18,326				(124	)			18,202				(343	)			17,859
Net interest (income)/expense and currency exchange (gains)/losses			(370	)			–				(370	)			(42	)			(412	)			629				–				629				(61	)			568
Income before taxation			22,178				(308	)			21,870				(135	)			21,735				17,697				(124	)			17,573				(282	)			17,291
Taxation			9,572				(126	)			9,446				(97	)			9,349				7,796				(54	)			7,742				(95	)			7,647
Minority interests			365				1				366				(13	)			353				179				(4	)			175				–				175
Income from continuing operations			12,241				(183	)			12,058				(25	)			12,033				9,722				(66	)			9,656				(187	)			9,469
Income from discontinued operations, net of tax			–				–				–				25				25				–				–				–				187				187
Cumulative effect of a change in accounting principle, net of tax			255				–				255				–				255				–				–				–				–				–
Net income			12,496				(183	)			12,313				–				12,313				9,722				(66	)			9,656				–				9,656

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.
b	As a consequence of the separate reporting of income from discontinued operations (see Note 4), information for comparative periods has been reclassified where necessary.

The financial effect of the First Reserves Restatement was to reduce net income in 2002 by $108 million, all of which was reflected in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as originally filed with the SEC on June 30, 2004. The combined financial effect of the First Reserves Restatement and the Second Reserves Restatement was a reduction in net income of $183 million in 2003 (2002: $174 million).

Earnings by industry segment																		$ million
										2003												2002
		As				Second								As				Second
		originally				Reserves				As				previously				Reserves				As
		reporteda				Restatement				restated				restateda				Restatement				restated
Exploration & Production			9,105				(182	)			8,923				6,796				(70	)			6,726
Gas & Power			2,289				–				2,289				774				–				774
Oil Products			2,860				–				2,860				2,627				–				2,627
Chemicals			(209	)			–				(209	)			565				–				565
Corporate and Other			(1,184	)			–				(1,184	)			(861	)			–				(861	)
Minority interests			(365	)			(1	)			(366	)			(179	)			4				(175	)
Net income			12,496				(183	)			12,313				9,722				(66	)			9,656

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.

The financial effect of the First Reserves Restatement was a reduction in Exploration & Production earnings of $101 million and an increase in minority interests of $7 million in 2002, all of which was reflected in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as originally filed with the SEC on June 30, 2004. The combined financial effect of the First Reserves Restatement and the Second Reserves Restatement was a reduction in Exploration & Production earnings of $182 million in 2003 (2002: $171 million) and an increase in minority interests of $1 million in 2003 (2002: $3 million).

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Statement of Assets and Liabilities											$ million
															December 31, 2003
			As				Second								Reclassification
			originally				Reserves				As				for deferred				As
			reporteda				Restatement				restated				taxb				restated
Fixed assets
	Tangible			87,701				(613	)			87,088				–				87,088
	Intangible			4,735				–				4,735				–				4,735
	Investments			22,787				(13	)			22,774				–				22,774
Other long-term assets				9,257				–				9,257				2,092				11,349
Current assets				43,611				–				43,611				–				43,611
Current liabilities				54,424				–				54,424				–				54,424
Long-term liabilities				15,154				–				15,154				–				15,154
Provisions
	Deferred taxation			13,355				(262	)			13,093				2,092				15,185
	Pensions and decommissioning			8,882				–				8,882				–				8,882
Minority interests				3,428				(13	)			3,415				–				3,415
Net assets				72,848				(351	)			72,497				–				72,497

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.

b  Deferred tax assets and liabilities are presented at December 31, 2004 separately in the Statement of Assets and Liabilities, with reclassification of the prior year.

Parent Companies’ interest in Group net assets			$ million
			2003				2002
At December 31 as originally reported (2003)/ previously restated (2002)a				72,848				60,444
Effect of the Second Reserves Restatement:
	Interest at the beginning of the year			(168	)			(102	)b
	Net income for the year			(183	)			(66	)
At December 31 as restated				72,497				60,276

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.

b  Cumulative effect as at January 1, 2002

The financial effect of the First Reserves Restatement was to reduce the previously reported net assets as at December 31, 2002 by $276 million, all of which was reflected in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as originally filed with the SEC on June 30, 2004. The combined financial effect of the First Reserves Restatement and the Second Reserves Restatement was a reduction in Group net assets of $627 million at December 31, 2003 (2002: $444 million).

Amounts relating to prior periods have been restated in the following notes where applicable.

3 Accounting policies

US accounting pronouncement FIN 46 (Consolidation of Variable Interest Entities) was implemented in 2003 with a consequential increase in the Group’s tangible fixed assets and debt of $3.4 billion as of September 30, 2003, mainly relating to power generation contracts (“tolling agreements”) which were previously accounted for as executory contracts and marked to market.

Investments in companies over which Group companies have significant influence but not control are classified as associated companies and are accounted for on the equity basis. Investments in companies over which the Group has no significant influence are stated at cost and dividends received from these companies are accounted for when received. Certain joint ventures in oil and natural gas production activities are taken up in the Financial Statements in proportion to the relevant Group interest.

The Financial Statements are presented in accordance with US GAAP, with separate Financial Statements presented under Netherlands GAAP beginning on page G40.

The preparation of Financial Statements in conformity with generally accepted accounting principles requires management to make estimates and judgments that affect the amounts reported in the Financial Statements and Notes thereto. Actual results could differ from those estimates.

The Financial Statements have been prepared under the historical cost convention.

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Currency translation

The US dollar equivalents of exchange gains and losses arising as a result of foreign currency transactions (including those in respect of inter-company balances unless related to transactions of a long-term investment nature) are included in Group net income.

Revenue recognition

In Exploration & Production and Gas & Power title typically passes (and revenues are recognised) when product is physically transferred into a vessel, pipe or other delivery mechanism. For sales by refining companies, title typically passes (and revenues are recognised) either when product is placed onboard a vessel or offloaded from the vessel, depending on the contractually agreed terms. Revenues on wholesale sales of oil products and chemicals are recognised when transfer of ownership occurs and title is passed, either at the point of delivery or the point of receipt, depending on contractual conditions.

In November 2004 FASB’s Emerging Issues Task Force (EITF) discussed EITF Issue no. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”, in order to consider whether or not “buy/sell” contractual arrangements should be reported net in the Statement of Income and accounted for as non-monetary transactions. There was a further EITF meeting in March 2005 but no consensus was reached on this issue and further discussion is planned.

Buy/sell contractual arrangements in this context are defined as those entered into concurrently or in contemplation of one another with the same counterparty.

Buy/sell contracts are entered into by some Group companies for feedstock, principally crude oil, and finished products mainly in the Oil Products segment, and are reported gross in the Statement of Income. Title of the commodity passes to the buyer on delivery, purchases and sales may not necessarily take place at the same time and amounts are separately invoiced and settled; there is no legal right of offset. The Group considers therefore that these are not non-monetary transactions and are then outside the scope of APB Opinion no. 29 “Accounting for Nonmonetary Transactions”. In addition, the guidance provided in EITF no. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent”, EITF no. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” and EITF no. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement no. 133 and Not Held for Trading Purposes as Defined in Issue no. 02-3” has been considered in determining the presentation of the results of the Group’s operations. As a result of a communication to the oil and gas industry issued by the US Securities and Exchange Commission in February 2005 requesting additional disclosures regarding buy/sell contracts, the Group reviewed such contracts and has estimated that, if buy/sell contracts were required to be reported net, net proceeds and cost of sales for 2004 would be reduced by approximately $25 billion (this reduction of around 10% would be indicative of the impact for 2003 and 2002) with no impact on net income.

Such arrangements should be distinguished from purchases and sales under exchange contracts to obtain or reposition feedstock for refinery operations and which are, as described above, shown net in the Statement of Income. The obligations of each party are not independent and settlement is based on volumes.

Depreciation, depletion and amortisation

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Recoverability of assets

Estimates of future cash flows used in the evaluation for impairment for assets related to hydrocarbon production are made using risk assessments on field and reservoir performance and include outlooks on proved reserves and unproved volumes, which are then discounted or risk-weighted utilising the results from projections of geological, production, recovery and economic factors.

Administrative expenses

Exploration costs

Management makes quarterly assessments of the amounts included within tangible fixed assets to determine whether capitalisation is initially appropriate and can continue. Exploration wells capitalised beyond 12 months are subject to additional judgment as to whether the facts and circumstances have changed and therefore whether the conditions described in (a) and (b) no longer apply.

A proposed amendment to FASB Statement no. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” has been issued. If enacted, this would result, on a prospective basis, in the continued inclusion of the cost of certain exploratory wells in tangible fixed assets beyond 12 months which do not meet the current requirements given in (a) and (b) above. Under the proposal amounts remain capitalised beyond 12 months if both sufficient reserves have been found to justify completion as a producing well, and sufficient progress is being made towards assessing the reserves and the economic and operating viability of the project (which does not include delay for the possibility of a change in circumstances beyond an entity’s control, for example an increase in oil and/or gas prices).

If this amendment had been reflected in the Group accounting policy, there would not have been a significant effect on the Financial Statements presented; certain write-offs may not have been required which would result in subsequent additional depreciation, depletion and amortisation charges in future years.

Research and development

Deferred taxation

Leasing

Interest capitalisation

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Securities

Short-term securities with a maturity from acquisition of three months or less and that are readily convertible into known amounts of cash are classified as cash equivalents. Securities forming part of a portfolio which is required to be held long term are classified under fixed assets – investments.

Parent Companies’ shares held by Group companies are not included in the Group’s net assets but reflected as a deduction from Parent Companies’ interest in Group net assets.

Cash flows resulting from movements in securities of a trading nature are reported under cash flow provided by operating activities while cash flows resulting from movements in other securities are reported under cash flow used in investing activities.

Inventories

Derivative instruments

A change in the carrying amount of a fair value hedge is taken to income, together with the consequential adjustment to the carrying amount of the hedged item. The effective portion of a change in the carrying amount of a cash flow hedge is recorded in other comprehensive income, until income reflects the variability of underlying cash flows; any ineffective portion is taken to income. A change in the carrying amount of a foreign currency hedge is recorded on the basis of whether the hedge is a fair value hedge or a cash flow hedge. A change in the carrying amount of other derivatives is taken to income.

Group companies formally document all relationships between hedging instruments and hedged items, as well as risk management objectives and strategies for undertaking various hedge transactions. The effectiveness of a hedge is also continually assessed. When effectiveness ceases, hedge accounting is discontinued.

Environmental expenditures

Employee retirement plans

For plans which define the amount of pension benefit to be provided, pension cost primarily represents the increase in actuarial present value of the obligation for pension benefits based on employee service during the year and the interest on this obligation in respect of employee service in previous years, net of the expected return on plan assets.

For plans where benefits depend solely on the amount contributed to the employee’s account and the returns earned on investments of those contributions, pension cost is the amount contributed by Group companies for the period.

Postretirement benefits other than pensions

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included in the Financial Statements which is sufficient to cover the present value of the accumulated postretirement benefit obligation based on current assumptions. Valuations of these obligations are carried out by independent actuaries.

Stock-based compensation plans

Decommissioning and restoration costs

This policy reflects US accounting standard FAS 143 (Asset Retirement Obligations) which was effective for the Group from the beginning of 2003 and resulted in a credit to income of $255 million after tax, which was reported in 2003 as a cumulative effect of a change in accounting principle.

Acquisitions

Discontinued operations

Reclassifications

International Financial Reporting Standards

4 Discontinued operations

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Income from discontinued operations comprises:

						$ million
		2004				2003				2002
Income before taxation from discontinued operations (including gains on disposal of $1,564 million in 2004 and impairments of $88 million in 2003 and $9 million in 2002)			1,980				135				282
Taxation			332				97				95
Minority interests			88				13				–
Income from discontinued operations, net of tax			1,560				25				187

Net proceeds of discontinued operations in 2004 (up to the date of disposal, where applicable), excluding proceeds of the disposal of such operations, were $3.5 billion (2003: $3.4 billion; 2002: $3.1 billion).

Income from discontinued operations by segment is given in Note 25(b).

5 Parent Companies’ interest in Group net assets

							$ million
							2003				2002
			2004				As restated				As restated
Invested by Parent Companies				741				741				741
Retained earnings of Group companies				85,100				74,906				68,254
Parent Companies’ shares held, net of dividends received (Note 23)				(4,187	)			(3,428	)			(2,797	)
Cumulative currency translation differences				4,356				1,208				(3,894	)
Unrealised gains/(losses) on:
	securities (Note 15)			350				700				11
	cash flow hedges			(157	)			(188	)			(239	)
Minimum pension liability adjustments				(1,627	)			(1,442	)			(1,800	)
Balance at December 31				84,576				72,497				60,276

Earnings retained by the subsidiary and associated companies of the Group Holding Companies (namely Shell Petroleum N.V. and The Shell Petroleum Company Limited) and Shell Petroleum Inc. amounted to $34,374 million at December 31, 2004 (2003: $25,210 million; 2002: $18,060 million). A portion of these retained earnings will flow up to the Group Holding Companies without tax cost. The balance of these retained earnings have been, or will be, substantially reinvested by the companies concerned and provision has not been made for taxes on possible future distribution of these undistributed earnings as it is not meaningful to provide for these taxes nor is it practicable to estimate their full amount or the withholding tax element.

6 Other comprehensive income

2004						$ million
		Net credit/(charge)
		Pre-tax				Tax				After tax
Currency translation differences arising during the year			2,925				70				2,995
Net gains/(losses) realised in net income			153				–				153
Currency translation differences net			3,078				70				3,148
Unrealised gains/(losses) on securities arising during the year			109				(3	)			106
Net gains/(losses) realised in net income			(464	)			8				(456	)
Unrealised gains/(losses) on securities net			(355	)			5				(350	)
Unrealised gains/(losses) on cash flow hedges arising during the year			35				(6	)			29
Net gains/(losses) realised in net income			2				–				2
Unrealised gains/(losses) on cash flow hedges net			37				(6	)			31
Minimum pension liability adjustments			(289	)			104				(185	)
Other comprehensive income			2,471				173				2,644

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2003		$ million
		Net credit/(charge)
		Pre-tax				Tax				After tax
Currency translation differences arising during the year			5,418				(360	)			5,058
Net gains/(losses) realised in net income			44				–				44
Currency translation differences net			5,462				(360	)			5,102
Unrealised gains/(losses) on securities arising during the year			746				(16	)			730
Net gains/(losses) realised in net income			(41	)			–				(41	)
Unrealised gains/(losses) on securities net			705				(16	)			689
Unrealised gains/(losses) on cash flow hedges arising during the year			51				(3	)			48
Net gains/(losses) realised in net income			3				–				3
Unrealised gains/(losses) on cash flow hedges net			54				(3	)			51
Minimum pension liability adjustments			669				(311	)			358
Other comprehensive income			6,890				(690	)			6,200

2002		$ million
		Net credit/(charge)
		Pre-tax				Tax				After tax
Currency translation differences arising during the year			2,773				(303	)			2,470
Net gains/(losses) realised in net income			(38	)			–				(38	)
Currency translation differences net			2,735				(303	)			2,432
Unrealised gains/(losses) on securities arising during the year			26				10				36
Net gains/(losses) realised in net income			(12	)			1				(11	)
Unrealised gains/(losses) on securities net			14				11				25
Unrealised gains/(losses) on cash flow hedges arising during the year			(209	)			(7	)			(216	)
Net gains/(losses) realised in net income			(9	)			–				(9	)
Unrealised gains/(losses) on cash flow hedges net			(218	)			(7	)			(225	)
Minimum pension liability adjustments			(2,446	)			971				(1,475	)
Other comprehensive income			85				672				757

						2004				2003
Rates of exchange at December 31 were:			€/$				0.73				0.79
			£/$				0.52				0.56

7 Associated companies

A summarised Statement of Income with respect to the Group share of net income from associated companies, together with a segment analysis, is set out below:

						$ million
						2003				2002
		2004				As restateda				As restateda
Net proceeds			53,544				44,422				33,467
Cost of sales			43,694				37,084				26,744
Gross profit			9,850				7,338				6,723
Other operating expenses			4,197				3,892				3,931
Operating profit			5,653				3,446				2,792
Interest and other income			173				228				102
Interest expense			580				540				451
Currency exchange gains/(losses)			20				(3	)			(15	)
Income before taxation			5,266				3,131				2,428
Taxation			2,065				1,463				990
Income from continuing operations			3,201				1,668				1,438
Income from discontinued operations, net of tax			13				13				16
Net income			3,214				1,681				1,454

a	See Note 2.

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Income by segment						$ million
						2003				2002
		2004				As restated				As restated
Exploration & Production			1,145				800				541
Gas & Power			1,142				650				589
Oil Products			1,253				632				448
Chemicals			(7	)			(169	)			153
Corporate and Other			(319	)			(232	)			(277	)
			3,214				1,681				1,454

(b) Investments

										$ million
		2004												2003
														As restated
		Shares				Loans				Total				Total
At January 1			16,800				2,571				19,371				17,945
New investments			681				377				1,058				983
Net asset transfers to/(from) associates, disposals and other movements			(649	)			(284	)			(933	)			(173	)
Net income			3,214				–				3,214				1,681
Dividends			(3,472	)			–				(3,472	)			(2,192	)
Currency translation differences			455				50				505				1,127
At December 31			17,029				2,714				19,743				19,371

Net income for 2004 includes a $565 million write-down in the carrying amount of Basell (Chemicals). This impairment followed the announcement in 2004 of a review of strategic alternatives regarding this joint venture, and the carrying amount of the Group’s investment in Basell at December 31, 2004 is at expected net realisable value.

Net income for 2003 includes a $286 million write-down in the carrying amount of Basell (Chemicals) reflecting a reassessment of the outlook for the business, a $200 million write-down in the carrying amount of InterGen (Gas & Power) due to poor power market conditions, mainly in the US merchant power segment, and a $115 million write-down in the carrying amount of the Cuiaba power assets in South America (Gas & Power) in light of a reappraisal of the commercial outlook.

A summarised Statement of Assets and Liabilities with respect to the Group share of investments in associated companies is set out below:

		$ million
						2003
		2004				As restated
Fixed assets			28,665				30,892
Current assets			10,427				8,248
Total assets			39,092				39,140
Current liabilities			7,559				8,745
Long-term liabilities			11,790				11,024
Net assets			19,743				19,371

An analysis by segment is shown in Note 25.

The Group’s major investments in associated companies at December 31, 2004 comprised:

Segment
Name			Group interest				Country of incorporation
Exploration & Production
	Aera			52%				USA
	Brunei Shell			50%				Brunei
	Woodside			34%				Australia
Gas & Power
	InterGen			68%				The Netherlands
	Nigeria LNG			26%				Nigeria
	Oman LNG			30%				Oman
Oil Products
	Motiva			50%				USA
	Showa Shell			40%				Japan
Chemicals
	Basell			50%				The Netherlands
	Saudi Petrochemical			50%				Saudi Arabia
	Infinium			50%				The Netherlands

Although the Group has a 52% investment in Aera and a 68% investment in InterGen, the governing agreements and constitutive documents for these entities do not allow the Group to control these entities, as voting control is either split 50:50 between the

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shareholders or requires unanimous approval of the shareholders or their representatives and, therefore, these entities have not been consolidated.

(c) Transactions between Group companies and associated companies

		$ million
		2004				2003				2002
Charges to associated companies			14,018				18,155				10,573
Charges from associated companies			12,373				8,608				5,623

Balances outstanding at December 31, 2004 and 2003 in respect of the above transactions are shown in Notes 14 and 18.

8 Interest and other income

			$ million
							2003				2002
			2004				as reclassifieda				as reclassifieda
Group companies
	Interest income			432				325				487
	Other income			1,100				1,414				159
				1,532				1,739				646
Associated companies				173				228				102
				1,705				1,967				748

a	See Note 2.

Other income in 2004 includes gains from the disposal of the Group’s interest in Sinopec ($0.3 billion), and Fluxys and Distrigas ($0.5 billion). Other income in 2003 included a $1.3 billion gain from the disposal of the Group’s interest in Ruhrgas.

9 Interest expense

			$ million
							2003				2002
			2004				as reclassifieda				as reclassifieda
Group companies
	Interest incurred			840				828				883
	less interest capitalised			206				44				43
				634				784				840
Associated companies				580				540				451
				1,214				1,324				1,291

a	See Note 2.

10 Taxation

(a)	Taxation charge for the year

			$ million
							2003				2002
			2004				As restateda				As restateda
Group companies
	Current tax charge			13,584				8,197				6,650
	Deferred tax charge/(credit)			(513	)			(311	)			7
				13,071				7,886				6,657
Associated companies				2,065				1,463				990
				15,136				9,349				7,647

a	See Note 2.

Reconciliations of the expected tax charge of Group companies to the actual tax charge are as follows:

		$ million
						2003				2002
		2004				As restated				As restated
Expected tax charge at statutory rates			13,717				8,910				6,504
Adjustments in respect of prior years			(52	)			166				(252	)
Other reconciling items			(594	)			(1,190	)			405
Taxation charge of Group companies			13,071				7,886				6,657

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The taxation charge of Group companies includes not only income taxes of general application but also income taxes at special rates levied on income from Exploration & Production activities and various additional income and other taxes to which these activities are subject.

Tax adjustments in respect of prior years relate to events in the current period and reflect the effects of changes in rules, facts or other factors compared to those used in establishing the tax position or deferred tax balance.

Other reconciling items in 2004 mainly comprises the effects of disposals during the year that were taxed below the statutory rate.

Other reconciling items in 2003 include the effects of disposals during the year that were taxed below the statutory rate (including $534 million from the disposal of the Group’s interest in Ruhrgas), in addition to $442 million relating to the effects on deferred tax accounts of legislative changes to certain ring-fencing arrangements.

Other reconciling items in 2002 include $415 million due to the increase in the UK upstream corporate tax rate during the year.

(b) Taxes payable

		$ million
		2004				2003
Taxes on activities of Group companies			5,606				2,148
Sales taxes, excise duties and similar levies and social law taxes			4,279				3,779
			9,885				5,927

(c) Provision for deferred taxation

			$ million
							2003
			2004				As restated
Tangible and intangible fixed assets				17,738				17,365
Pensions and similar obligations				2,653				2,118
Other items				2,568				2,649
Total deferred tax liabilities				22,959				22,132
Tax losses carried forward				(4,214	)			(3,876	)
Foreign tax creditsa				(2,042	)			(1,633	)
US trademarkb				(247	)			(309	)
Provisions
	Pensions and similar obligations			(1,228	)			(1,329	)
	Decommissioning and restoration costs			(2,191	)			(1,934	)
	Environmental and other provisions			(455	)			(334	)
Tangible and intangible fixed assets				(461	)			(153	)
Other items				(3,266	)			(3,268	)
Total deferred tax assets				(14,104	)			(12,836	)
Asset valuation allowance				3,994				3,797
Deferred tax assets net of valuation allowance				(10,110	)			(9,039	)
Net deferred tax liability				12,849				13,093
Presented in the Statement of Assets and Liabilities as:
	Deferred tax assets			1,995				2,092
	Deferred tax liabilities			14,844				15,185

a	Foreign tax credits represent surplus credits arising in holding and sub-holding Group companies on income from other jurisdictions. A valuation allowance has been recorded against the substantial part of these balances in both 2004 and 2003.
b	Deferred tax asset created upon transfer of US trademark rights from a US wholly-owned Group company to a Netherlands wholly-owned Group company.

The Group has tax losses carried forward amounting to $12,705 million at December 31, 2004. Of these, $10,470 million can be carried forward indefinitely. The remaining $2,235 million expires in the following years:

		$ million
2005			702
2006			239
2007			452
2008			70
2009 – 2013			404
2014 – 2019			368

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11 Tangible and intangible fixed assets

$ million
		2004
																						2003
																						Total
										Other				Total				Total				Group
		Tangible				Goodwill				intangibles				intangibles				Group				As restated
Cost
At January 1			181,685				4,011				2,998				7,009				188,694				163,957
Capital expenditure			12,440				3				291				294				12,734				12,252
Sales, retirements and other movementsa			(9,345	)			(44	)			102				58				(9,287	)			(1,770	)
Currency translation differences			8,382				62				81				143				8,525				14,255
At December 31			193,162				4,032				3,472				7,504				200,666				188,694
Depreciation
At January 1			94,597				1,336				938				2,274				96,871				80,898
Depreciation, depletion and amortisation charge			11,945				–				328				328				12,273				11,711
Sales, retirements and other movements			(7,310	)			(37	)			(38	)			(75	)			(7,385	)			(3,711	)
Currency translation differences			4,990				42				45				87				5,077				7,973
At December 31			104,222				1,341				1,273				2,614				106,836				96,871
Net 2004			88,940				2,691				2,199				4,890				93,830
Net 2003 (as restated)			87,088				2,675				2,060				4,735								91,823

a	Sales, retirements and other movements in 2003 include the effect of a change in accounting policy for certain long-term agreements (see Note 3).
b	Tangible fixed assets at December 31, 2004 include rights and concessions of $11.1 billion (2003: $12.0 billion).

Other intangible fixed assets at December 31, 2004 include $0.8 billion (2003: $0.8 billion) in respect of Pennzoil-Quaker State trademarks acquired in 2002. The trademarks are being amortised over an estimated useful life of forty years. Continued brand maintenance in addition to the established long-term leadership of these brands in automotive lubricants and vehicle care markets support this estimate.

Tangible fixed assets at year end, capital expenditure, together with new investments in associated companies, and the depreciation, depletion and amortisation charges are shown in Note 25, classified, consistent with oil and natural gas industry practice, according to operating activities. Such a classification, rather than one according to type of asset, is given in order to permit a better comparison with other companies having similar activities.

The net balances at December 31 include:

$ million
			2004				2003
Capitalised costs in respect of assets not yet used in operations
	Unproved properties			2,844				4,576
	Proved properties under development and other assets in the course of construction			13,491				12,680
				16,335				17,256

Unproved properties include capitalised exploratory well costs, for which the amounts at December 31, 2004, 2003 and 2002, and movements during 2004, 2003 and 2002 are given in the following table.

$ million
		2004				2003				2002
At January 1			771				720				515
Additions pending determination of proved reserves			566				501				568
Amounts charged to expense			(432	)			(449	)			(393	)
Reclassifications to productive wells on determination of proved reserves			(94	)			(56	)			(24	)
Other movements, including acquisitions, disposals and currency translation effects			(22	)			55				54
At December 31			789				771				720

There are no amounts remaining capitalised (a) in areas requiring major capital expenditure before production can begin, where neither drilling of additional exploratory wells is underway nor firmly planned for the near future, or (b) beyond 12 months in areas not requiring major capital expenditure before production can begin.

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Depreciation, depletion and amortisation charges for the year are included within the following headings in the Statement of Income:

$ million
							2003				2002
			2004				As restateda				As restateda
Cost of sales				9,876				9,702				7,312
Selling and distribution expenses				1,438				1,229				1,041
Administrative expenses				121				121				62
Exploration				684				411				80
Research and development				33				28				33
Depreciation, depletion and amortisation:
	from continuing operations			12,152				11,491				8,528
	from discontinued operations			121				220				211
				12,273				11,711				8,739

a	See Note 2.

Depreciation, depletion and amortisation charges for 2004 include $617 million (2003: $1,249 million; 2002: $191 million) relating to the impairment of tangible fixed assets, and $5 million (2003: $127 million; 2002: $6 million) relating to the impairment of intangible fixed assets. Such charges are recorded within cost of sales. The impairment charges relate to assets held for use (2004: $229 million; 2003: $1,169 million; 2002: $105 million) and to assets held for sale (2004: $393 million; 2003: $207 million; 2002: $92 million).

For 2004, the majority of the impairment charges were in Oil Products ($579 million) and were related to the deterioration in the local operating environment for certain refinery assets and writing down to expected proceeds of marketing assets held for sale.

For 2003, the impairments were incurred in Exploration & Production ($698 million, mainly due to lower production outlooks in the UK and South America), in Oil Products ($331 million, mainly due to the announced closure of the Bakersfield refinery and the impact of local economic conditions in Latin America), in Chemicals ($220 million, mainly in CS Metals, as anticipated benefits from a prototype technology did not meet performance expectations) and in Renewables ($127 million for Shell Solar following an extensive review to assess the value of the business).

For 2002, the majority of the impairment charges (in total $197 million) were in Oil Products, reflecting plans in the USA to close surplus base oil production facilities, the closure of the Pililla base oil and bitumen refinery in the Philippines and a change in outlook for liquefied petroleum gas assets in Argentina coupled with the country’s economic downturn.

Depreciation, depletion and amortisation charges for 2004 also included $570 million relating to the write-off of various exploration properties mainly in Ireland, Norway and the United Kingdom, where new information during the year from exploratory work confirmed lower than expected volume projections (2003: $366 million, mainly in Brazil and Ireland).

12 Other long-term assets

13 Inventories

$ million
		2004				2003
Inventories of oil and chemicals			14,488				11,742
Inventories of materials			903				948
			15,391				12,690

14 Accounts receivable

		$ million
		2004				2003
Trade receivables			23,626				17,523
Amounts owed by associated companies			2,619				2,094
Other receivables			3,996				3,602
Deferred charges and prepayments			7,757				5,750
			37,998				28,969

Provisions for doubtful items deducted from accounts receivable amounted to $564 million at December 31, 2004 (2003: $557 million). Deferred charges and prepayments include amounts in respect of risk management activities.

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15 Securities

$125 million (2003: $125 million) of these securities are debt securities classified as held-to-maturity, with maturity falling between one and five years. The remainder are classified as available for sale, of which $688 million at December 31, 2004 (2003: $638 million) are debt securities. Of the available for sale securities, the maturities of $21 million fall within one year, $411 million fall between one year and five years, and $256 million exceed five years.

The carrying amount of securities classified as cash equivalent is $1,477 million at December 31, 2004 (2003: $107 million), all of which are debt securities classified as available for sale.

Total securities at December 31, 2004 amounting to $814 million (2003: $1,557 million) are listed on recognised stock exchanges.

During 2004 a Group company disposed of an equity investment, resulting in the reclassification of an unrealised gain of $348 million from Other comprehensive income to Net income.

16 Debt

$ million
		2004				2003
Debentures and other loans			4,661				8,181
Amounts due to banks and other credit institutions (including long-term debt due within one year)			1,108				2,737
			5,769				10,918
Capitalised lease obligations			53				109
Short-term debt			5,822				11,027
less long-term debt due within one year			1,291				1,874
Short-term debt excluding long-term debt due within one year			4,531				9,153

Short-term debt at December 31, 2003 included $1.3 billion of non-recourse debt owed by a Group company, for which a covenant had been breached in 2001. During 2004, this company was disposed of and this debt was relieved in its entirety.

Short-term debenture balances fell during the year as a consequence of the Group’s reduced need for commercial paper financing.

The following relates only to short-term debt excluding long-term debt due within one year:

$ million
			2004				2003
Maximum amount outstanding at the end of any quarter				6,688				9,159
Average amount outstanding				6,507				8,554
Amounts due to banks and other credit institutions				812				2,657
Unused lines of short-term credit				4,023				3,916
Approximate average interest rate on:
	average amount outstanding			3%				3%
	amount outstanding at December 31			3%				2%

The amount outstanding at December 31, 2004 includes $3,315 million of fixed rate and $252 million of variable rate US dollar debt at an average interest rate of 2% and 9% respectively.

(b) Long-term debt

$ million
		2004				2003
Debentures and other loans			4,204				4,868
Amounts due to banks and other credit institutions			3,744				3,724
			7,948				8,592
Capitalised lease obligations			652				508
Long-term debt			8,600				9,100
add long-term debt due within one year			1,291				1,874
Long-term debt including long-term debt due within one year			9,891				10,974

The following relates to long-term debt including the short-term part but excluding capitalised lease obligations.

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The amount at December 31, 2004 of $9,186 million (2003: $10,357 million) comprises:

							Average
			$ million				interest rate
US Dollar denominated debt
	Fixed rate			4,925				6%
	Variable rate			697				4%
Non-dollar denominated debt
	Fixed rate			3,101				4%
	Variable rate			463				5%
				9,186

The approximate weighted average interest rate in 2004 was 5% for both US dollar debt and total debt.

The aggregate maturities of long-term debts are:

$ million
2005			1,238
2006			1,884
2007			2,474
2008			530
2009			117
2010 and after			2,943
			9,186

During 2004, the Medium Term Note and Commercial Paper Facilities have been increased to a total level of $30.0 billion. As at December 31, 2004, debt outstanding under central borrowing programmes, which includes these facilities, totalled $8.3 billion with the remaining indebtedness raised by Group companies with no recourse beyond the immediate borrower and/or the local assets.

In accordance with the risk management policy, Group companies have entered into interest rate swap agreements against most of the fixed rate debt. The use of interest rate swaps is further discussed in Note 29.

17 Commitments

$ million
		Operating				Capital
		leases				leases
2005			1,744				105
2006			1,203				73
2007			958				67
2008			781				61
2009			709				58
2010 and after			4,460				852
Total minimum payments			9,855				1,216
less executory costs and interest							511
Present value of net minimum capital lease payments							705

The figures above for operating lease payments represent minimum commitments existing at December 31, 2004 and are not a forecast of future total rental expense.

Total rental expense for all operating leases was as follows:

$ million
		2004				2003				2002
Minimum rentals			2,140				2,135				1,557
Contingent rentals			75				60				104
Sub-lease rentals			(198	)			(198	)			(300	)
			2,017				1,997				1,361

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(b) Long-term purchase obligations

$ million
2005			461
2006			420
2007			413
2008			385
2009			380
2010 and after			3,437
			5,496

The agreements under which these unconditional purchase obligations arise relate mainly to the purchase of chemicals feedstock, utilities and to the use of pipelines.

Payments under these agreements, which include additional sums depending upon actual quantities of supplies, amounted to $542 million in 2004 (2003: $252 million).

18 Accounts payable and accrued liabilities

		$ million
		2004				2003
Trade payables			18,716				14,110
Amounts due to associated companies			1,927				1,829
Pensions and similar obligations			286				261
Other payables			11,620				8,832
Accruals and deferred income			7,658				7,315
			40,207				32,347

Other payables include amounts in respect of risk management activities.

19 Long-term liabilities – Other

		$ million
		2004				2003
Risk management activities			1,801				439
Deferred income			1,501				1,354
Environmental liabilities			664				676
Deposits for return items			603				566
Liabilities under staff benefit plans			541				315
Advance payments received under long-term supply contracts			354				315
Redundancy liabilities			127				165
Other			2,474				2,224
			8,065				6,054

These amounts include $1,222 million at December 31, 2004 (2003: $1,305 million) which does not fall due until more than five years after the respective balance sheet dates.

20 Statement of cash flows

Accordingly, the cash flows recorded in the Statement of Cash Flows exclude both the currency translation differences which arise as a result of translating the assets and liabilities of non-US dollar Group companies to US dollars at year-end rates of exchange (except for those arising on cash and cash equivalents) and non-cash investing and financing activities. These currency translation differences and non-cash investing and financing activities must therefore be added to the cash flow movements at average rates in order to arrive at the movements derived from the Statement of Assets and Liabilities.

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2004										$ million
														Movements
		Movements				Movements								derived from
		derived from				arising from								Statement of
		Statement of				currency				Non-cash				Assets and
		Cash Flows				translation				movements				Liabilities
Tangible and intangible fixed assets			(2,627	)			3,448				1,186				2,007
Investments			(599	)			122				194				(283	)
Other long-term assets			2,459				598				236				3,293
Inventories			2,731				691				(721	)			2,701
Accounts receivable			8,462				1,327				(760	)			9,029
Cash and cash equivalents			6,394				113				–				6,507
Short-term debt			3,701				(414	)			1,335				4,622
Short-term part of long-term debt			672				(89	)			–				583
Accounts payable and accrued liabilities			(7,708	)			(784	)			632				(7,860	)
Taxes payable			(2,999	)			(577	)			(382	)			(3,958	)
Long-term debt			817				(357	)			40				500
Other long-term liabilities			(1,442	)			(247	)			(322	)			(2,011	)
Deferred taxation			672				(673	)			342				341
Other provisions			(148	)			(471	)			(1,252	)			(1,871	)
Minority interests			(1,257	)			(109	)			(528	)			(1,894	)
Other items			(193	)			193				–				–
Dividends to Parent Companies in excess of retained earnings movements			501				(128	)			–				373
Adjustment for Parent Companies’ shares and Other comprehensive income excluding currency translation differences			758				505				–				–
											–
Movement in retained earnings of Group companies (Note 5)			10,194
Movement in cumulative currency translation differences (Note 6)							3,148
Movement in net assets (Note 5)															12,079

Income taxes paid by Group companies totalled $11.6 billion in 2004 (2003: $8.6 billion; 2002: $6.7 billion). Interest paid by Group companies was $0.9 billion in 2004 (2003: $0.9 billion; 2002: $1.0 billion).

The main non-cash movements relate to the impact on the Statement of Assets and Liabilities of divestments, particularly of the Group’s interest in Rayong Refinery which held $1.3 billion of short-term debt. There was also a review of the estimated provision for decommissioning and restoration costs during 2004 based on current experience and techniques which resulted in an increase of approximately $1.1 billion in both the provision and the corresponding tangible fixed assets.

21 Employee retirement plans and other postretirement benefits

Some Group companies have established unfunded defined benefit plans to provide certain postretirement healthcare and life insurance benefits to their retirees, the entitlement to which is usually based on the employee remaining in service up to retirement age and the completion of a minimum service period.

The Group has accounted for the impact of the United States Medicare Prescription Drug, Improvement and Modernization (“Medicare”) Act of 2003, with effect from January 1, 2004. The impact was a $300 million reduction in the accumulated postretirement benefit obligation at January 1, 2004 and a $52 million reduction in postretirement benefit cost for 2004. There was no reduction to accumulated postretirement benefit obligations of $159 million at January 1, 2004, for certain separately administered retiree benefit plans which must be analysed under final government regulations. The first subsidies arising from the Medicare Act are expected to be received in 2006.

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$ million
											Other benefits
			Pension benefits								2004												2003
			2004				2003				USA				Other				Total				USA				Other				Total
Change in benefit obligation
Obligations for benefits based on employee service to date at January 1				46,476				39,109				2,520				512				3,032				2,068				377				2,445
Increase in present value of the obligation for benefits based on employee service during the year				1,086				991				35				16				51				37				15				52
Interest on the obligation for benefits in respect of employee service in previous years				2,529				2,333				139				28				167				141				24				165
Benefit payments made				(2,350	)			(2,034	)			(119	)			(28	)			(147	)			(95	)			(25	)			(120	)
Currency translation effects				3,461				5,333				–				40				40				–				78				78
Other componentsa				3,620				744				(66	)			43				(23	)			369				43				412
Obligations for benefits based on employee service to date at December 31				54,822				46,476				2,509				611				3,120				2,520				512				3,032
Change in plan assets
Plan assets held in trust at fair value at January 1				43,960				33,035
Actual return on plan assets				5,262				6,598
Employer contributions				1,562				1,275
Plan participants’ contributions				56				40
Benefit payments made				(2,350	)			(2,034	)
Currency translation effects				3,367				4,911
Other componentsa				17				135
Plan assets held in trust at fair value at December 31				51,874				43,960
Plan assets in excess of/(less than) the present value of obligations for benefits at December 31				(2,948	)			(2,516	)			(2,509	)			(611	)			(3,120	)			(2,520	)			(512	)			(3,032	)
Unrecognised net (gains)/losses remaining from the adoption of current method of determining pension costs				3				5
Unrecognised net (gains)/losses since adoption				9,888				7,295				727				186				913				876				149				1,025
Unrecognised prior service cost/(credit)				1,185				1,258				(34	)			2				(32	)			(82	)			–				(82	)
Net amount recognised				8,128				6,042				(1,816	)			(423	)			(2,239	)			(1,726	)			(363	)			(2,089	)
Amounts recognised in the Statement of Assets and Liabilities:
Intangible assets				353				326
Prepaid benefit costs				8,278				6,516
Accrued benefit liabilities:
	Short-term			(213	)			(182	)			(40	)			(33	)			(73	)			(51	)			(28	)			(79	)
	Long-term			(2,878	)			(2,917	)			(1,776	)			(390	)			(2,166	)			(1,675	)			(335	)			(2,010	)
				5,540				3,743				(1,816	)			(423	)			(2,239	)			(1,726	)			(363	)			(2,089	)
Amount recognised in Parent Companies’ interest in Group net assets:
Accumulated other comprehensive income				2,588				2,299
Net amount recognised				8,128				6,042				(1,816	)			(423	)			(2,239	)			(1,726	)			(363	)			(2,089	)

a	Other components comprise mainly the effect of changes in actuarial assumptions, most notably the discount rate and in 2004 the impact of accounting for the US Medicare Act on the accumulated postretirement benefit obligation at January 1.

Additional information on pension benefits

			$ million
			2004				2003
Obligation for pension benefits in respect of unfunded plans				2,032				2,155
Accumulated benefit obligation				48,654				41,865
For employee retirement plans with projected benefit obligation in excess of plan assets, the respective amounts are:
	Projected benefit obligation			36,246				30,291
	Plan assets			33,646				28,176
For employee retirement plans with accumulated benefit obligation in excess of plan assets, the respective amounts are:
	Accumulated benefit obligation			11,844				10,452
	Plan assets			10,734				9,356

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Employer contributions to defined benefit pension plans during 2005 are estimated to be $1.4 billion. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

										$ million
						Other benefits
		Pension
		benefits				USA				Other				Total
2005			2,584				132				32				164
2006			2,664				135				33				168
2007			2,738				147				33				180
2008			2,829				157				34				191
2009			2,908				165				35				200
2010–2014			15,759				905				178				1,083

Benefit costs for the year comprise:

$ million
														Other benefits
		Pension benefits												2004												2003												2002
		2004				2003				2002				USA				Other				Total				USA				Other				Total				USA				Other				Total
Service cost			1,086				991				899				35				16				51				37				15				52				32				7				39
Interest cost			2,529				2,333				2,001				139				28				167				141				24				165				111				21				132
Expected return on plan assets			(3,894	)			(3,547	)			(3,339	)
Other components			317				303				(100	)			41				8				49				66				4				70				76				7				83
Cost of defined benefit plans			38				80				(539	)			215				52				267				244				43				287				219				35				254
Payments to defined contribution plans			221				171				84
			259				251				(455	)			215				52				267				244				43				287				219				35				254

Discount rates, projected rates of remuneration growth and expected rates of return on plan assets vary for the different plans as they are determined in the light of local conditions. Expected rates of return on plan assets are calculated using a common assumption-setting process based on a projection of real long-term bond yields and an equity risk premium which are combined with local inflation assumptions and applied to each plan’s actual asset mix. The weighted averages applicable for the principal plans in the Group are:

														Other benefits
		Pension benefits												2004								2003								2002
		2004				2003				2002				USA				Other				USA				Other				USA				Other
Assumptions used to determine benefit obligations at December 31
Discount rate			5.1%				5.6%				5.9%				5.8%				5.0%				6.0%				5.6%				6.5%				5.6%
Projected rate of remuneration growth			3.8%				3.9%				4.0%
Assumptions used to determine benefit costs for year ended December 31
Discount rate			5.6%				5.9%				6.0%				6.0%				5.6%				6.5%				5.6%				7.0%				6.0%
Expected rate of return on plan assets			7.6%				7.9%				8.0%
Projected rate of remuneration growth			3.9%				4.0%				4.0%
Healthcare cost trend rates
Healthcare cost trend rate in year after reporting year															10.0%				3.7%				10.0%				3.9%				7.8%				4.6%
Ultimate healthcare cost trend rate															5.0%				2.9%				5.0%				2.9%				5.0%				2.9%
Year ultimate healthcare cost trend rate is applicable															2012				2007				2011				2006				2010				2004

The effect of a one percentage point increase/(decrease) in the annual rate of increase in the assumed healthcare cost trend rates would be to increase/(decrease) annual postretirement benefit cost by approximately $35 million/($25 million) and the accumulated postretirement benefit obligation by approximately $456 million/($374 million).

Weighted-average plan asset allocations by asset category and the target allocation for December 31, 2004 for the principal pension plans in the Group are:

		Target				Percentage of plan
		allocation				assets at December 31
		2004				2004				2003
Equity securities			72%				73%				73%
Debt securities			23%				21%				22%
Real estate			2%				2%				2%
Other			3%				4%				3%
Total			100%				100%				100%

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Plan long-term investment strategies are generally determined by the responsible Pension Fund Trustees using a structured asset-liability modelling approach to determine the asset mix which best meets the objectives of optimising investment return and maintaining adequate funding levels.

22 Employee emoluments and numbers

		$ million
		2004				2003				2002
Remuneration			8,125				7,477				6,096
Social law taxes			695				660				518
Pensions and similar obligations (Note 21)			526				538				(201	)
			9,346				8,675				6,413

(b) Average numbers

		thousands
		2004				2003				2002
Exploration & Production			17				17				17
Gas & Power			2				2				2
Oil Products			78				82				75
Chemicals			8				9				9
Corporate and Other			9				9				8
			114				119				111

(c) Year-end numbers

		thousands
		2004				2003				2002
Exploration & Production			17				17				17
Gas & Power			2				2				2
Oil Products			76				82				80
Chemicals			8				9				9
Corporate and Other			9				9				8
			112				119				116

In addition to remuneration above, there were charges for redundancy of $526 million in 2004 (2003: $291 million; 2002: $215 million).

The charges relate to 4,000 employees in 2004 (mainly in the Oil Products segment, primarily due to portfolio restructuring, and in the Corporate and Other segment due to restructuring in information and technology), 2,000 employees in 2003 (mainly in the Exploration & Production and Oil Products segments) and 2,600 employees in 2002 (mainly in the Exploration & Production and Oil Products segments). The liabilities for redundancies at December 31, 2004 and 2003, and movements during 2004 and 2003 are given in the following table.

		$ million
		2004				2003
At January 1			494				395
Charges			526				291
Payments			(394	)			(245	)
Other movements and currency translation effects			(29	)			53
At December 31			597				494

23 Stock-based compensation plans and Parent Companies’ shares held by Group companies

The Group Stock Option Plans offer eligible employees options over Royal Dutch ordinary shares (Royal Dutch shares) or Shell Transport Ordinary shares (Shell Transport shares) at a price not less than the fair market value of the shares at the date the options were granted. The options are exercisable three years from grant, except for those granted under the US plans, which vest a third per year for three years. The options lapse ten years after grant, however leaving Group employment may cause options to lapse earlier. For Group Managing Directors and the most senior executives, 100% of the options granted in 2003 (and in subsequent years) are subject to performance conditions.

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Under the Restricted Stock Plan, grants are made on a highly selective basis to senior staff. A maximum of 250,000 Royal Dutch shares (or equivalent value in Shell Transport shares) can be granted under the plan in any year. Shares are granted subject to a three-year restriction period and the number of shares awarded is based on the share price at the start of the restricted period. The shares, together with additional shares equivalent to the value of the dividends payable over the restriction period, are released to the individual at the end of the three-year period.

The following table shows for 2003 and 2004, in respect of option plans, the number of shares under option at the beginning of the year, the number of options granted, exercised and expired during the year and the number of shares under option at the end of the year, together with their weighted average exercise price translated at the respective year-end exchange rates:

		Royal Dutch shares								Shell Transport shares								Shell Canada common sharesa
						Weighted								Weighted								Weighted
						average								average								average
						exercise								exercise								exercise
		Number				price				Number				price				Number				price
		(thousands)				($)				(thousands)				($)				(thousands)				($)
Under option at January 1, 2003			33,381				59.86				101,447				8.26				4,777				21.71
Granted			15,643				45.13				41,893				6.74				1,674				35.65
Exercised			–				–				(192	)			6.47				(505	)			22.88
Expired			(1,003	)			64.03				(2,813	)			8.92				(73	)			26.03
Under option at December 31, 2003b			48,021				60.09				140,335				8.44				5,873				29.43
Granted			14,816				52.42				42,998				7.47				1,697				45.99
Exercised			(495	)			47.20				(1,341	)			7.10				(1,175	)			22.73
Expired			(1,644	)			68.14				(6,033	)			9.69				(285	)			25.85
Under option at December 31, 2004b			60,698				60.56				175,959				8.73				6,110				37.17

a	Unissued.
b	The underlying weighted average exercise prices for Royal Dutch and Shell Transport shares under option at December 31, 2004 were €44.42 (2003: €47.64) and £4.53 (2003: £4.73) respectively.

The following tables provide further information about the options outstanding at December 31, 2004:

														Royal Dutch shares
		Options outstanding												Options exercisable
						Weighted
						average				Weighted								Weighted
						remaining				average								average
						contractual				exercise								exercise
		Number				life				price				Number				price
Range of exercise prices		(thousands)				(years)				($)				(thousands)				($)
$40 to $45			6,541				8.2				42.25				2,027				42.24
$45 to $50			7,096				9.1				48.65				223				45.71
$50 to $55			19,118				7.4				52.72				6,241				53.49
$55 to $60			8,354				7.6				56.30				2,353				56.21
$60 to $65			3,759				6.2				60.77				3,759				60.77
$65 to $70			773				2.3				66.70				773				66.70
$75 to $80			149				6.8				76.94				149				76.94
$80 to $85			9,503				6.3				82.92				1,959				81.34
$85 to $90			2,124				5.4				85.36				2,124				85.36
$90 to $95			79				5.2				94.11				79				94.11
$95 to $100			3,202				6.2				96.21				3,202				96.21
$40 to $100			60,698				7.3				60.56				22,889				65.95

														Shell Transport shares
		Options outstanding												Options exercisable
						Weighted
						average				Weighted								Weighted
						remaining				average								average
						contractual				exercise								exercise
		Number				life				price				Number				price
Range of exercise prices		(thousands)				(years)				($)				(thousands)				($)
$7 to $8			93,250				7.8				7.36				9,847				7.00
$8 to $9			6,937				3.3				8.45				6,137				8.47
$9 to $10			11,694				4.4				9.74				11,694				9.74
$10 to $11			51,761				6.3				10.29				14,110				10.64
$11 to $12			12,317				6.0				11.80				12,317				11.80
$7 to $12			175,959				6.8				8.73				54,105				9.80

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In the UK, The Shell Petroleum Company Limited and Shell Petroleum N.V. each operate a savings-related stock option scheme, under which options are granted over shares of Shell Transport at prices not less than the market value on a date not more than 30 days before the date of the grant of option and are normally exercisable after completion of a three-year or five-year contractual savings period. The following table shows for 2003 and 2004, in respect of these plans, the number of Shell Transport shares under option at the beginning of the year, the number of options granted, exercised and expired during the year and the number of shares under option at the end of the year:

		thousands
		2004				2003
Under option at January 1			15,089				18,680
Granted			–				4,975
Exercised			(1,924	)			(707	)
Expired			(2,634	)			(7,859	)
Under option at December 31			10,531				15,089

Certain Group companies have incentive compensation plans containing stock appreciation rights linked to the value of Royal Dutch shares. During 2004 1,375,989 of these stock appreciation rights were exercised and 21,833 forfeited, leaving a balance of 7,484,779 at December 31, 2004 (2003: 8,882,601).

In 2001, the Global Employee Share Purchase Plan was implemented giving eligible employees the opportunity to buy Royal Dutch or Shell Transport shares, with 15% added after a specified holding period. At December 31, 2004 16,024 (2003: 4,754) Royal Dutch shares and 25,881 (2003: 19,742) Shell Transport shares were held by Group companies in connection with the Global Employee Share Purchase Plan.

Effects on Group net income and Earnings per share under the fair value method

		2004								2003								2002
		As reported				Pro forma				As restated				Pro forma				As restated				Pro forma
Group net income ($ million)			18,183				17,938				12,313				12,036				9,656				9,453
Basic earnings per share attributable to Royal Dutch ($)			5.39				5.32				3.63				3.55				2.82				2.76
Diluted earnings per share attributable to Royal Dutch ($)			5.39				5.31				3.63				3.55				2.81				2.76
Basic earnings per ADR attributable to Shell Transport ($)			4.60				4.54				3.10				3.03				2.41				2.36
Diluted earnings per ADR attributable to Shell Transport ($)			4.60				4.54				3.10				3.03				2.41				2.36

The fair value of the Group’s 2004 option grants was estimated using a Black-Scholes option pricing model and the following assumptions for US dollar, euro and sterling denominated options respectively: risk-free interest rates of 3.5%, 3.1% and 4.9%; dividend yield of 4.1%, 4.5% and 4.0%; volatility of 28.2%, 30.3% and 31.7% and expected lives of five to seven years.

Parent Companies’ shares held by Group companies

In connection with other incentive compensation plans linked to the appreciation in value of Royal Dutch and of Shell Transport shares, 9.2 million Royal Dutch shares and 0.4 million Shell Transport shares were held by Group companies at December 31, 2004 and 2003. In addition, 33,600 shares of Royal Dutch were held by Group companies at December 31, 2004 and 2003.

The carrying amount of these and all Parent Company shares held in connection with the stock-based compensation plans at December 31, 2004 was $4,187 million (2003: $3,428 million).

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24 Decommissioning and restoration costs

		$ million
										2004												2003
		Short-term				Long-term				Total				Short-term				Long-term				Total
At January 1			89				3,955				4,044				71				3,528				3,599
Cumulative effect of change in accounting policya			–				–				–				108				(102	)			6
Liabilities incurred			6				291				297				–				174				174
Liabilities settled			(77	)			(18	)			(95	)			(106	)			(37	)			(143	)
Accretion expense			–				284				284				–				49				49
Reclassifications and other movements			160				912				1,072				12				12				24
Currency translation differences			7				285				292				4				331				335
At December 31			185				5,709				5,894				89				3,955				4,044

a	US accounting standard FAS 143 (Asset Retirement Obligations) was effective from the beginning of 2003 (see Note 3).

A review of the estimated provision for decommissioning and restoration costs was performed during 2004 based on current experience and techniques. This resulted in an increase of $1.1 billion in both the provision and corresponding tangible fixed assets, reported within other movements.

For the purposes of calculating provisions for decommissioning and restoration costs, estimated total ultimate liabilities of $9.8 billion at December 31, 2004 (2003: $7.5 billion) were used. Such estimates are subject to various regulatory and technological developments.

25 Information by geographical area and by industry segment

		$ million
										2003								2002
		2004								As restateda								As restateda
		Net				Fixed				Net				Fixed				Net				Fixed
		proceeds				assets				proceeds				assets				proceeds				assets
Europe			94,904				37,930				70,375				37,686				62,575				36,516
Other Eastern Hemisphere			49,482				36,977				37,482				33,530				32,406				28,492
USA			102,877				27,580				75,109				30,343				54,677				27,266
Other Western Hemisphere			17,927				13,834				15,396				13,038				13,795				11,869
Total Group			265,190				116,321				198,362				114,597				163,453				104,143

a	As a consequence of the separate reporting of income from discontinued operations (see Note 4), information for comparative periods has been reclassified where necessary:

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(b) Industry segment

2004			$ million
			Total				Exploration				Gas &				Oil								Corporate
			Group				& Production				Power				Products				Chemicals				and Other
Sales
	third parties			265,190				20,643				9,604				207,006				26,877				1,060
	inter-segment							19,001				1,210				11,924				2,620				11
Net proceeds								39,644				10,814				218,930				29,497				1,071
Operating profit/(loss)
	Group companies			26,280				18,386				331				7,152				1,245				(834	)
	Group share of associated companies			5,653				2,438				1,384				1,749				94				(12	)
				31,933				20,824				1,715				8,901				1,339				(846	)
Interest and other income				1,705				244				768				90				1				602
Interest expense				1,214																				1,214
Currency exchange gains/(losses)				(39	)			(78	)			15				(19	)			(16	)			59
Taxation				15,136				12,033				429				2,691				394				(411	)
Income applicable to minority interests				626
Income from continuing operations				16,623				8,957				2,069				6,281				930				(988	)
Income from discontinued operations, net of taxb				1,560				358				86				1,256				–				(52	)
Net income				18,183				9,315				2,155				7,537				930				(1,040	)
Total assets at December 31				192,811				68,199				23,214				71,447				18,330				11,621
Total liabilities at December 31				(102,926	)			(44,602	)			(15,897	)			(44,509	)			(8,062	)			10,144
Tangible fixed assets at December 31
	Cost			193,162				115,404				8,028				53,773				14,561				1,396
	Accumulated depreciation			(104,222	)			(63,411	)			(1,107	)			(30,689	)			(8,381	)			(634	)
Goodwill at December 31				2,691				–				184				2,470				23				14
Investments in associated companies at December 31				19,743				4,762				4,312				6,206				4,139				324
Capital expenditure and new investments in associated companies				13,792				8,745				1,633				2,466				705				243
Depreciation, depletion and amortisation charge from continuing operations
	Impairment			622				7				–				580				29				6
	Other			11,530				8,132				262				2,476				515				145

2003 (as restated)a			$ million
			Total				Exploration				Gas &				Oil								Corporate
			Group				& Production				Power				Products				Chemicals				and Other
Sales
	third parties			198,362				12,224				7,377				159,075				18,843				843
	inter-segment							20,244				850				3,416				1,974				29
Net proceeds								32,468				8,227				162,491				20,817				872
Operating profit/(loss)
	Group companies			17,877				14,968				510				3,175				(112	)			(664	)
	Group share of associated companies			3,446				1,857				871				910				(165	)			(27	)
				21,323				16,825				1,381				4,085				(277	)			(691	)
Interest and other income				1,967				88				1,366				(39	)			(29	)			581
Interest expense				1,324																				1,324
Currency exchange gains/(losses)				(231	)			(16	)			(23	)			(23	)			(14	)			(155	)
Taxation				9,349				8,307				454				1,202				(111	)			(503	)
Income applicable to minority interests				353
Income from continuing operations				12,033				8,590				2,270				2,821				(209	)			(1,086	)
Income from discontinued operations, net of taxb				25				78				19				39				–				(98	)
Cumulative effect of change in accounting principle, net of tax				255				255
Net income				12,313				8,923				2,289				2,860				(209	)			(1,184	)
Total assets at December 31				169,557				63,641				19,212				64,725				15,297				6,682
Total liabilities at December 31				(93,645	)			(47,866	)			(13,277	)			(42,549	)			(7,888	)			17,935
Tangible fixed assets at December 31
	Cost			181,685				105,540				6,934				53,556				14,028				1,627
	Accumulated depreciation			(94,597	)			(56,265	)			(985	)			(28,784	)			(7,851	)			(712	)
Goodwill at December 31				2,675				–				184				2,455				23				13
Investments in associated companies at December 31				19,371				4,108				4,924				5,965				4,017				357
Capital expenditure and new investments in associated companies				13,235				8,278				1,511				2,405				599				442
Depreciation, depletion and amortisation charge from continuing operations
	Impairment			1,288				679				–				262				220				127
	Other			10,203				7,048				116				2,455				458				126

a	See Note 2 to the Group Financial Statements.
b	$88 million of income applicable to minority interests is deducted in arriving at income from discontinued operations for the Group in 2004 (2003: $13 million).

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2002 (as restated)a			$ million
			Total				Exploration				Gas &				Oil								Corporate
			Group				& Production				Power				Products				Chemicals				and Other
Sales
	third parties			163,453				11,640				4,254				132,681				14,125				753
	inter-segment							14,680				620				3,080				1,082				17
Net proceeds								26,320				4,874				135,761				15,207				770
Operating profit/(loss)
	Group companies			15,067				11,976				89				3,009				438				(445	)
	Group share of associated companies			2,792				1,316				729				554				213				(20	)
				17,859				13,292				818				3,563				651				(465	)
Interest and other income				748				98				118				10				3				519
Interest expense				1,291																				1,291
Currency exchange gains/(losses)				(25	)			(25	)			6				(67	)			(16	)			77
Taxation				7,647				6,724				195				1,021				73				(366	)
Income applicable to minority interests				175
Income from continuing operations				9,469				6,641				747				2,485				565				(794	)
Income from discontinued operations, net of tax				187				85				27				142				–				(67	)
Net income				9,656				6,726				774				2,627				565				(861	)
Total assets at December 31				153,131				56,988				16,057				60,549				14,172				5,365
Total liabilities at December 31b				(89,287	)			(45,191	)			(12,223	)			(41,826	)			(7,903	)			17,856
Tangible fixed assets at December 31
	Cost			157,499				93,333				2,843				47,689				12,010				1,624
	Accumulated depreciation			(79,136	)			(47,076	)			(763	)			(23,926	)			(6,711	)			(660	)
Goodwill at December 31				2,324				–				184				1,989				22				129
Investments in associated companies at December 31				17,945				3,591				4,679				5,344				4,154				177
Capital expenditure, acquisitions and new investments in associated companies				23,651				13,154				953				7,968				998				578
Depreciation, depletion and amortisation charge from continuing operations
	Impairment			188				33				4				102				29				20
	Other			8,340				5,603				112				2,160				372				93

As a consequence of the separate reporting of income from discontinued operations (see Note 4), information for comparative periods has been reclassified where necessary.

a	See Note 2.
b	Deferred taxation as at December 31, 2002 is included on a net liability basis, rather than as separate deferred taxation assets and liabilities as in 2004 and 2003.

26 Oil and gas exploration and production activities

$ million
						2003				2002
		2004				As restated				As restated
Cost
Proved properties			104,479	a			94,069	a			83,964
Unproved properties			4,281				5,400				4,768
Support equipment and facilities			3,266				3,128				2,352
			112,026				102,597				91,084
Depreciation
Proved properties			60,101	a			53,867	a			45,525
Unproved properties			1,437				824				325
Support equipment and facilities			1,582				1,443				1,224
			63,120				56,134				47,074
Net capitalised costs			48,906				46,463				44,010
Oil sands: net capitalised costs			3,087				2,811				2,246

a	Includes capitalised asset retirement costs.

The Group share of associated companies’ net capitalised costs was $3,958 million at December 31, 2004 (2003: $3,772 million; 2002: $3,173 million).

(b) Costs incurred

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2004											$ million
			Eastern Hemisphere																Western Hemisphere
															Middle
															East,
											Asia				Russia,
			Europe				Africa				Pacific				CISa				USA				Other				Total
Acquisition of properties
	Proved			–				–				–				192				17				(1	)			208
	Unproved			(3	)			46				(3	)			7				19				44				110
Exploration				152				196				141				127				418				214				1,248
Developmentb
	Excluding oil sands			2,404				1,831				363				2,645				867				362				8,472
	Oil sands																							132				132

2003											$ million
			Eastern Hemisphere																Western Hemisphere
															Middle
															East,
											Asia				Russia,
			Europe				Africa				Pacific				CISa				USA				Other				Total
Acquisition of properties
	Proved			6				8				177				194				–				–				385
	Unproved			–				209				3				273				17				8				510
Exploration				187				163				139				273				342				155				1,259
Developmentb
	Excluding oil sands			2,776				1,660				311				1,251				1,599				588				8,185
	Oil sands																							88				88

2002											$ million
			Eastern Hemisphere																Western Hemisphere
															Middle
															East,
											Asia				Russia,
			Europe				Africa				Pacific				CIS				USA				Other				Total
Acquisition of properties
	Proved			3,776				–				–				122				565				801				5,264
	Unproved			1,693				53				–				3				368				412				2,529
Exploration				217				279				115				170				328				182				1,291
Development
	Excluding oil sands			1,605				1,370				442				685				1,465				407				5,974
	Oil sands																							931				931

a	These amounts do not include Sakhalin II project costs in 2004 of $869 million (2003: $384 million) reported in the Gas & Power segment.
b	Includes capitalised asset retirement costs.

The Group share of associated companies’ cost incurred was $415 million in 2004 (2003: $417 million; 2002: $551 million).

(c) Earnings

2004											$ million
			Eastern Hemisphere																Western Hemisphere
															Middle
															East,
											Asia				Russia,
			Europe				Africa				Pacific				CIS				USA				Other				Total
Sales:
	Third parties			5,856				137				1,045				1,806				2,092				1,277				12,213
	Intra-group			7,223				5,616				1,517				4,616				4,755				1,187				24,914
Net proceeds				13,079				5,753				2,562				6,422				6,847				2,464				37,127
Production costsb				1,895				1,548				537				1,687				779				518				6,964
Exploration expense				201				157				139				101				364				209				1,171
Depreciation, depletion and amortisation				3,764				700				566				799				1,622				811				8,262
Other income/(costs)				(1,308	)			(353	)			280				(517	)			(340	)			(334	)			(2,572	)
Earnings before taxation				5,911				2,995				1,600				3,318				3,742				592				18,158
Taxation				3,559				2,448				350				2,795				1,298				186				10,636
Earnings from continuing operations				2,352				547				1,250				523				2,444				406				7,522
Earnings from discontinued operations, net of tax				–				144				109				105				–				–				358
Earnings from operations				2,352				691				1,359				628				2,444				406				7,880
Earnings from oil sands																								290				290

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2003 (as restated)a											$ million
			Eastern Hemisphere																Western Hemisphere
															Middle
															East,
											Asia				Russia,
			Europe				Africa				Pacific				CIS				USA				Other				Total
Sales:
	Third parties			5,386				129				808				1,640				1,903				1,115				10,981
	Intra-group			5,873				3,888				1,179				3,713				4,480				713				19,846
Net proceeds				11,259				4,017				1,987				5,353				6,383				1,828				30,827
Production costsb				1,886				1,087				419				1,408				603				366				5,769
Exploration expense				229				235				112				121				275				144				1,116
Depreciation, depletion and amortisation				3,723				462				539				585				1,667				681				7,657
Other income/(costs)				(512	)			(187	)			238				(443	)			30				(240	)			(1,114	)
Earnings before taxation				4,909				2,046				1,155				2,796				3,868				397				15,171
Taxation				1,686				1,437				217				2,239				1,497				204				7,280
Earnings from continuing operations				3,223				609				938				557				2,371				193				7,891
Earnings from discontinued operations, net of tax				–				(16	)			68				26				–				–				78
Earnings from operations				3,223				593				1,006				583				2,371				193				7,969
Earnings from oil sands																								(101	)			(101	)

2002 (as restated)a											$ million
			Eastern Hemisphere																Western Hemisphere
															Middle
															East,
											Asia				Russia,
			Europe				Africa				Pacific				CIS				USA				Other				Total
Sales:
	Third parties			5,472				73				763				1,772				1,997				892				10,969
	Intra-group			4,572				2,538				1,186				3,087				2,863				433				14,679
Net proceeds				10,044				2,611				1,949				4,859				4,860				1,325				25,648
Production costsb				1,826				754				420				1,275				589				298				5,162
Exploration expense				177				204				58				81				249				208				977
Depreciation, depletion and amortisation				2,469				458				572				777				1,461				265				6,002
Other income/(costs)				(428	)			(97	)			160				(654	)			(221	)			(219	)			(1,459	)
Earnings before taxation				5,144				1,098				1,059				2,072				2,340				335				12,048
Taxation				2,340				789				294				1,638				791				93				5,945
Earnings from continuing operations				2,804				309				765				434				1,549				242				6,103
Earnings from discontinued operations, net of tax				–				(15	)			70				30				–				–				85
Earnings from operations				2,804				294				835				464				1,549				242				6,188
Earnings from oil sands																								(3	)			(3	)

a	As a consequence of the separate reporting of income from discontinued operations (see Note 4), information for comparative periods has been reclassified where necessary. Certain other amounts have been reclassified for comparative purposes. Also see Note 2.
b	Includes certain royalties paid in cash amounting to $2,019 million in 2004 (2003: $1,700 million; 2002: $1,449 million).

The Group share of associated companies’ earnings was $1,145 million in 2004 (2003: $800 million; 2002: $541 million) mainly in the USA $603 million (2003: $424 million; 2002: $330 million) and Asia Pacific $522 million (2003: $353 million; 2002: $170 million).

27 Auditors’ remuneration

Remuneration of KPMG and PricewaterhouseCoopers						$ million
										2002
		2004				2003				As restated
Audit fees			42				32				27
Audit-related feesa			13				11				17
Tax feesb			9				7				6
Fees for all other non-audit services			6				6				12

a	Fees for audit-related services such as employee benefit plan audits, due diligence assistance, assurance of non-financial data, operational audits, training services and special investigations.
b	Fees for tax compliance, tax advice and tax planning services.

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28 Contingencies and litigation

		$ billion
In respect of debt			1.7
In respect of customs duties			0.5
Other			0.7
			2.9

The $1.7 billion of guarantees in respect of debt relate to project finance. Guarantees in respect of customs duties mainly relate to a cross guarantee, renewable annually, for amounts payable by industry participants in a western European country.

Shell Oil Company (including subsidiaries and affiliates, referred to collectively as SOC), along with numerous other defendants, has been sued by public and quasi-public water purveyors, as well as governmental entities, alleging responsibility for groundwater contamination caused by releases of gasoline containing oxygenate additives. Most of these suits assert various theories of liability, including product liability, and seek to recover actual damages, including clean-up costs. Some assert claims for punitive damages. As of December 31, 2004, there were approximately 66 pending suits by such plaintiffs that asserted claims against SOC and many other defendants (including major energy and refining companies). Although a majority of these cases do not specify the amount of monetary damages sought, some include specific damage claims collectively against all defendants. While the aggregate amounts claimed against all defendants for actual and punitive damages in such suits could be material to the financial statements if they were ultimately recovered against SOC alone rather than apportioned among the defendants, management of the Group considers the amounts claimed in these pleadings to be highly speculative and not an appropriate basis on which to determine a reasonable estimate of the amount of the loss that may be ultimately incurred, for the reasons described below.

The reasons for this determination can be summarised as follows:

•	While the majority of the cases have been consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York, there are many cases pending in other jurisdictions throughout the U.S. Most of the cases are at a preliminary stage. In many matters, little discovery has been taken and the courts have yet to rule upon motions on substantive legal issues. Consequently, management of the Group does not have sufficient information to assess the facts underlying the plaintiffs’ claims; the nature and extent of damages claimed, if any; the reasonableness of any specific claim for money damages; the allocation of potential responsibility among defendants; or the law that may be applicable. Additionally, given the pendency of cases in varying jurisdictions, there may be inconsistencies in the determinations made in these matters.
•	There are significant unresolved legal questions relating to claims asserted in this litigation. For example, it has not been established whether the use of oxygenates mandated by the 1990 amendments to the Clean Air Act can give rise to a products liability based claim. While some trial courts have held that it cannot, other courts have left the question open or declined to dismiss claims brought on a products liability theory. Other examples of unresolved legal questions relate to the applicability of federal preemption, whether a plaintiff may recover damages for alleged levels of contamination significantly below state environmental standards, and whether a plaintiff may recover for an alleged threat to groundwater before detection of contamination.
•	There are also significant unresolved legal questions relating to whether punitive damages are available for products liability claims or, if available, the manner in which they might be determined. For example, some courts have held that for certain types of product liability claims, punitive damages are not available. It is not known whether that rule of law would be applied in some or all of the pending oxygenate additive cases. Where specific claims for damages have been made, punitive damages represent in most cases a majority of the total amounts claimed.
•	There are significant issues relating to the allocation of any liability among the defendants. Virtually all of the oxygenate additives cases involve multiple defendants including most of the major participants in the retail gasoline marketing business in the regions involved in the pending cases. The basis on which any potential liability may be apportioned among the defendants in any particular pending case cannot yet be determined.

For these reasons, management of the Group is not currently able to estimate a range of reasonably possible losses or minimum loss for this litigation; however, management of the Group does not currently believe that the outcome of the oxygenate-related litigation pending as of December 31, 2004 will have a material impact on the Group’s financial condition, although such resolutions could have a significant effect on periodic results for the period in which they are recognised.

A $490 million judgment in favour of 466 plaintiffs in a consolidated matter that had once been nine individual cases was rendered in 2002 by a Nicaraguan court jointly against SOC and three other named defendants (not affiliated with SOC), based upon Nicaraguan Special Law 364 for claimed personal injuries resulting from alleged exposure to dibromochloropropane (DBCP) — a pesticide manufactured by SOC prior to 1978. This special law imposes strict liability (in a predetermined amount) on international manufacturers

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of DBCP. The statute also provides that unless a deposit (calculated as described below) of an amount denominated in Nicaraguan cordobas is made into the Nicaraguan courts, the claims would be submitted to the US courts. In SOC’s case the deposit would have been between $19 million and $20 million (based on an exchange rate between 15 and 16 cordobas per US dollar). SOC chose not to make this deposit. The Nicaraguan courts did not, however, give effect to the provision of Special Law 364 that requires submission of the matter to the US courts. Instead, the Nicaraguan court entered judgment against SOC and the other defendants. Further, SOC was not afforded the opportunity to present any defences in the Nicaraguan court, including that it was not subject to Nicaraguan jurisdiction because it had neither shipped nor sold DBCP to parties in Nicaragua. At this time, SOC has not completed the steps necessary to perfect an appeal in Nicaragua and, as described below, the Nicaraguan claimants have sought to enforce the Nicaraguan judgment against SOC in the U.S. and in Venezuela. SOC does not have any assets in Nicaragua. In 2003, an attempt by the plaintiffs to enforce the Nicaraguan judgment described above in the United States against Shell Chemical Company and purported affiliates of the other named defendants was rejected by the U.S. District Court for the Central District of California, which decision is on appeal before the Ninth Circuit Court of Appeals. Enforcement of the Nicaraguan judgment was rejected because of improper service and attempted enforcement against non-existent entities or entities that were not named in the Nicaraguan judgment. Thereafter, SOC filed a declaratory judgment action seeking ultimate adjudication of the non-enforceability of this Nicaraguan judgment in the U.S. District Court for the Central District of California. This district court denied motions filed by the Nicaraguan claimants to dismiss SOC claims that Nicaragua does not have impartial tribunals, the proceedings violated due process, the relationship between SOC and Nicaragua made the exercise of personal jurisdiction unreasonable, and Special Law 364 is repugnant to U.S. public policy because it violates due process. A finding in favour of SOC on any of these grounds will result in a refusal to recognize and enforce the judgment in the United States. Several requests for Exequatur were filed in 2004 with the Tribunal Suprema de Justicia (the Venezuelan Supreme Court) to enforce Nicaraguan judgments. The petitions imply that judgments can be satisfied with assets of Shell Venezuela, S.A., which was neither a party to the Nicaraguan judgment nor a subsidiary of SOC, against whom the Exequatur was filed. The petitions are pending before the Tribunal Suprema de Justicia but have not been accepted. As of December 31, 2004, five additional Nicaraguan judgments had been entered in the collective amount of approximately $226.5 million in favor of 240 plaintiffs jointly against Shell Chemical Company and three other named defendants (not affiliated with Shell Chemical Company) under facts and circumstances almost identical to those relating to the judgment described above. Additional judgments are anticipated (including a suit seeking more than $3 billion). It is the opinion of management of the Group that the above judgments are unenforceable in a U.S. court, as a matter of law, for the reasons set out in SOC’s declaratory judgment action described above. No financial provisions have been established for these judgments or related claims.

Since 1984, SOC has been named with others as a defendant in numerous product liability cases, including class actions, involving the failure of residential plumbing systems and municipal water distribution systems constructed with polybutylene plastic pipe. SOC fabricated the resin for this pipe while the co-defendants fabricated the raw materials for the pipe fittings. As a result of two class action settlements in 1995, SOC and the co-defendants agreed on a mechanism to fund until 2009 the settlement of most of the residential plumbing claims in the United States. Financial provisions have been taken by SOC for its settlement funding needs anticipated at this time. Additionally, claims that are not part of these class action settlements or that challenge these settlements continue to be filed primarily involving alleged problems with polybutylene pipe used in municipal water distribution systems. It is the opinion of management of the Group that exposure from this other polybutylene litigation pending as of December 31, 2004, is not material. Management of the Group cannot currently predict when or how all polybutylene matters will be finally resolved.

In connection with the recategorisation of certain hydrocarbon reserves that occurred in 2004, a number of putative shareholder class actions were filed against Royal Dutch, Shell Transport, Managing Directors of Royal Dutch during the class period, Managing Directors of Shell Transport during the class period and the external auditors for Royal Dutch, Shell Transport and the Group. These actions were consolidated in the United States District Court in New Jersey and a consolidated complaint was filed in September 2004. The parties are awaiting a decision with respect to defendants’ motions to dismiss asserting lack of jurisdiction with respect to the claims of non-United States shareholders who purchased on non-United States securities exchanges and failure to state a claim. Merits discovery has not begun. The case is at an early stage and subject to substantial uncertainties concerning the outcome of the material factual and legal issues relating to the litigation, including the pending motions to dismiss on lack of jurisdiction and failure to state a claim. In addition, potential damages, if any, in a fully litigated securities class action would depend on the losses caused by the alleged wrongful conduct that would be demonstrated by individual class members in their purchases and sales of Royal Dutch and Shell Transport shares during the relevant class period. Accordingly, based on the current status of the litigation, management of the Group is unable to estimate a range of possible losses or any minimum loss. Management of the Group will review this determination as the litigation progresses.

Also in connection with the hydrocarbon reserves recategorisation, putative shareholder class actions were filed on behalf of participants in various Shell Oil Company qualified plans alleging that Royal Dutch, Shell Transport and various current and former officers and directors breached various fiduciary duties to employee participants imposed by the Employee Retirement Income Security Act of 1974 (ERISA). These suits were consolidated in the United States District Court in New Jersey and a consolidated class action complaint was filed in July 2004. Defendants’ motions to dismiss have been fully briefed. Some document discovery has taken place. The case is at an early stage and subject to substantial uncertainties concerning the outcome of the material factual and legal issues relating to the

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litigation, including the pending motion to dismiss and the legal uncertainties with respect to the methodology for calculating damage, if any, should defendants become subject to an adverse judgment. The Group is in settlement discussions with counsel for plaintiffs, which it hopes will lead to a successful resolution of the case without the need for further litigation. No financial provisions have been taken with respect to the ERISA litigation.

The reserves recategorisation also led to the filing of shareholder derivative actions in June 2004. The four suits pending in New York state court, New York federal court and New Jersey federal court demand Group management and structural changes and seek unspecified damages from current and former members of the Boards of Directors of Royal Dutch and Shell Transport. The suits are in preliminary stages and no responses are yet due from defendants. Because any money “damages” in the derivative actions would be paid to Royal Dutch and Shell Transport, management of the Group does not believe that the resolution of these suits will have a material adverse effect on the Group’s financial condition or operating results.

The United States Securities and Exchange Commission (SEC) and UK Financial Services Authority (FSA) issued formal orders of private investigation in relation to the reserves recategorisation which Royal Dutch and Shell Transport resolved by reaching agreements with the SEC and the FSA. In connection with the agreement with the SEC, Royal Dutch and Shell Transport consented, without admitting or denying the SEC’s findings or conclusions, to an administrative order finding that Royal Dutch and Shell Transport violated, and requiring Royal Dutch and Shell Transport to cease and desist from future violations of, the antifraud, reporting, recordkeeping and internal control provisions of the US Federal securities laws and related SEC rules, agreed to pay a $120 million civil penalty and has undertaken to spend an additional $5 million developing a comprehensive internal compliance program. In connection with the agreement with the FSA, Royal Dutch and Shell Transport agreed, without admitting or denying the FSA’s findings or conclusions, to the entry of a Final Notice by the FSA finding that Royal Dutch and Shell Transport breached market abuse provisions of the UK’s Financial Services and Markets Act 2000 and the Listing Rules made under it and agreed to pay a penalty of £17 million. The penalties from the SEC and FSA and the additional amount to develop a comprehensive internal compliance program have been paid by Group companies and fully included in the Income Statement of the Group. The United States Department of Justice has commenced a criminal investigation, and Euronext Amsterdam, the Dutch Authority Financial Markets and the California Department of Corporations are investigating the issues related to the reserves recategorisation. Management of the Group cannot currently predict the manner and timing of the resolution of these pending matters and is currently unable to estimate the range of reasonably possible losses from such matters.

Group companies are subject to a number of other loss contingencies arising out of litigation and claims brought by governmental and private parties, which are handled in the ordinary course of business.

The operations and earnings of Group companies continue, from time to time, to be affected to varying degrees by political, legislative, fiscal and regulatory developments, including those relating to the protection of the environment and indigenous people, in the countries in which they operate. The industries in which Group companies are engaged are also subject to physical risks of various types. The nature and frequency of these developments and events, not all of which are covered by insurance, as well as their effect on future operations and earnings, are unpredictable.

29 Financial instruments

Some Group companies enter into derivatives such as interest rate swaps/ forward rate agreements to manage interest rate exposure. The financing of most Operating Companies is structured on a floating-rate basis and, except in special cases, further interest rate risk management is discouraged. Foreign exchange derivatives, such as forward exchange contracts and currency swaps/ options, are used by some Group companies to manage foreign exchange risk. Commodity swaps, options and futures are used to manage price and timing risks mainly involving crude oil, natural gas and oil products.

The contract/notional amount, together with the estimated fair value (carrying amount) of derivatives held by Group companies at December 31 is as follows:

$ million
		2004								2003
										Contract/
		Contract/				Estimated				notional				Estimated
		notional				fair value				amount				fair value
		amount
Interest rate swaps/forward rate agreements			4,307				70				4,322				121
Forward exchange contracts and currency swaps/options			18,830				53				18,874				165
Commodity swaps, options and futures			101,021				81				65,800				61
			124,158				204				88,996				347

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The contract/national amounts of commodity swaps, options and futures have increased during the year as a consequence of rising crude oil and natural gas prices.

Other financial instruments in the Statement of Assets and Liabilities include fixed assets: investments – securities, trade receivables, short-term securities, cash and cash equivalents, short and long-term debt, and assets and liabilities in respect of risk management activities. The estimated fair values of these instruments approximate their carrying amounts.

30 Division of Group net assets between the Parent Companies and movements therein

$ million
						Royal				Shell
		Total				Dutch (60%)				Transport (40%)
		As restated				As restated				As restated
At January 1, 2002			56,142				33,685				22,457
Movements during the year 2002:
Group net income			9,656				5,794				3,862
less: distributions to Parent Companies			(5,435	)			(3,261	)			(2,174	)
Undistributed net income			4,221				2,533				1,688
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(844	)			(507	)			(337	)
Other comprehensive income (see Note 6)			757				455				302
At December 31, 2002			60,276				36,166				24,110
Movements during the year 2003:
Group net income			12,313				7,387				4,926
less: distributions to Parent Companies			(5,660	)			(3,396	)			(2,264	)
Undistributed net income			6,653				3,991				2,662
Loss on sale of Parent Companies’ shares			(1	)			(1	)			–
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(631	)			(378	)			(253	)
Other comprehensive income (see Note 6)			6,200				3,720				2,480
At December 31, 2003			72,497				43,498				28,999
Movements during the year 2004:
Group net income			18,183				10,910				7,273
less: distributions to Parent Companies			(7,989	)			(4,793	)			(3,196	)
Undistributed net income			10,194				6,117				4,077
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(759	)			(455	)			(304	)
Other comprehensive income (see Note 6)			2,644				1,586				1,058
At December 31, 2004			84,576				50,746				33,830

The above table is based on the Group’s US GAAP results. See Note 33 for the impact of differences between US GAAP and Netherlands GAAP on the Group’s net income and net assets. Note 38 shows the division of Group net assets and movements therein under Netherlands GAAP.

Reconciliation of Division of Group net assets between the Parent Companies and movements therein to previously issued Financial Statements

$ million
		Total												Royal Dutch (60%)												Shell Transport (40%)
						Second												Second												Second
		As previously				Reserves								As previously				Reserves								As previously				Reserves
		restateda				Restatement				As restated				restateda				Restatement				As restated				restateda				Restatement				As restated
At January 1, 2002			56,244				(102	)			56,142				33,746				(61	)			33,685				22,498				(41	)			22,457
Movements during the year 2002:
Group net income			9,722				(66	)			9,656				5,833				(39	)			5,794				3,889				(27	)			3,862
less: distributions to Parent Companies			(5,435	)			–				(5,435	)			(3,261	)			–				(3,261	)			(2,174	)			–				(2,174	)
Undistributed net income			4,287				(66	)			4,221				2,572				(39	)			2,533				1,715				(27	)			1,688
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(844	)			–				(844	)			(507	)			–				(507	)			(337	)			–				(337	)
Other comprehensive income (see Note 6)			757				–				757				455				–				455				302				–				302
At December 31, 2002			60,444				(168	)			60,276				36,266				(100	)			36,166				24,178				(68	)			24,110
Movements during the year 2003:
Group net income			12,496				(183	)			12,313				7,498				(111	)			7,387				4,998				(72	)			4,926
less: distributions to Parent Companies			(5,660	)			–				(5,660	)			(3,396	)			–				(3,396	)			(2,264	)			–				(2,264	)
Undistributed net income			6,836				(183	)			6,653				4,102				(111	)			3,991				2,734				(72	)			2,662
Loss on sale of Parent Companies’ shares			(1	)			–				(1	)			(1	)			–				(1	)			–				–				–
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(631	)			–				(631	)			(378	)			–				(378	)			(253	)			–				(253	)
Other comprehensive income (see Note 6)			6,200				–				6,200				3,720				–				3,720				2,480				–				2,480
At December 31, 2003			72,848				(351	)			72,497				43,709				(211	)			43,498				29,139				(140	)			28,999

a	2003 data is as originally reported.

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Royal Dutch/Shell Group of Companies

We have audited the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies for the years 2004, 2003 and 2002 (which include the Notes on pages G5 to G37 and G40 to G48). The preparation of the Financial Statements is the responsibility of management. Our responsibility is to express an opinion on the Financial Statements based on our audits.

We conducted our audits in accordance with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Financial Statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Financial Statements referred to above present fairly in all material respects the financial position of the Royal Dutch/ Shell Group of Companies as of December 31, 2004 and 2003 and of the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in accordance with the accounting principles generally accepted in the Netherlands.

As discussed in Note 32 on pages G43 and G44, the Group restated its Financial Statements for the two years ended December 31, 2003, to correct for the financial impact of the Second Reserves Restatement.

 

 

 

/s/ KPMG Accountants

 

 

/s/ PricewaterhouseCoopers LLP

March 29, 2005

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Netherlands GAAP Financial Statements

Statement of Income		$ million
										2003				2002
		Note				2004				As restateda				As restateda
Sales proceeds							337,522				263,889				218,287
Sales taxes, excise duties and similar levies							72,332				65,527				54,834
Net proceeds							265,190				198,362				163,453
Cost of sales							222,334				165,314				135,778
Gross profit							42,856				33,048				27,675
Selling and distribution expenses							12,340				11,409				9,617
Administrative expenses							2,516				1,870				1,587
Exploration							1,823				1,475				1,052
Research and development							553				584				472
Operating profit of Group companies							25,624				17,710				14,947
Share of operating profit of associated companies			34				6,050				3,446				2,792
Operating profit							31,674				21,156				17,739
Interest and other income			8				1,705				1,967				748
Interest expense			9				1,214				1,324				1,291
Currency exchange gains/(losses)							(39	)			(231	)			(25	)
Income before taxation							32,126				21,568				17,171
Taxation			35				15,030				9,349				7,647
Income after taxation							17,096				12,219				9,524
Income applicable to minority interests							626				353				175
Income from continuing operations							16,470				11,866				9,349
Income from discontinued operations, net of tax			4				1,560				25				187
Net income			33				18,030				11,891				9,536

Statement of Comprehensive Income and Parent Companies’ interest in Group net assets															$ million
											2003				2002
			Note				2004				As restated				As restated
Net income								18,030				11,891				9,536
Other comprehensive income, net of tax:				6
	currency translation differences			20				3,148				5,102				2,432
	unrealised gains/(losses) on securities							(350	)			689				25
	unrealised gains/(losses) on cash flow hedges							31				51				(225	)
	minimum pension liability adjustments							(185	)			358				(1,475	)
Comprehensive income								20,674				18,091				10,293
Distributions to Parent Companies								(7,989	)			(5,660	)			(5,435	)
Increase in Parent Companies’ shares held, net of dividends received				23				(759	)			(631	)			(844	)
Loss on sale of Parent Companies’ shares								–				(1	)			–
Parent Companies’ interest in Group net assets:
	At January 1							72,210				60,156				56,142
	Cumulative effect of change in accounting policy							–				255				–
	At January 1 after cumulative effect of change							72,210				60,411				56,142
Parent Companies’ interest in Group net assets at December 31				38				84,136				72,210				60,156

a  See Note 2.

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Statement of Assets and Liabilities				$ million
												Dec 31,
								Dec 31,				2003
				Note				2004				As restateda
Fixed assets
	Tangible assets				36				88,451				87,088
	Intangible assets				36				4,436				4,448
	Investments:
		associated companies			34				20,140				19,371
		securities			15				1,627				2,317
		other							1,121				1,086
Total fixed assets									115,775				114,310
Other long-term assets
	Prepaid pension costs				21				8,278				6,516
	Deferred taxation				10				1,995				2,092
	Other				12				4,369				2,741
Total other long-term assets									14,642				11,349
Current assets
	Inventories				13				15,391				12,690
	Accounts receivable				14				37,998				28,969
	Cash and cash equivalents				15				8,459				1,952
Total current assets									61,848				43,611
Current liabilities: amounts due within one year
	Short-term debt				16				5,822				11,027
	Accounts payable and accrued liabilities								40,207				32,347
	Taxes payable				10				9,885				5,927
	Dividends payable to Parent Companies								4,750				5,123
Total current liabilities									60,664				54,424
Net current assets/(liabilities)									1,184				(10,813	)
Total assets less current liabilities									131,601				114,846
Long-term liabilities: amounts due after more than one year
	Long-term debt				37				8,600				9,100
	Other								8,065				6,054
									16,665				15,154
Provisions
	Deferred taxation				35				14,738				15,185
	Pensions and similar obligations				21				5,044				4,927
	Decommissioning and restoration costs				24				5,709				3,955
									25,491				24,067
Group net assets before minority interests									89,445				75,625
Minority interests									5,309				3,415
Net assets									84,136				72,210

a  See Note 2.

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Statement of Cash flows					$ million
					Note				2004				2003				2002
Cash flow provided by operating activities										18,030				11,891				9,536
	Net income
	Adjustments to reconcile net income to cash flow provided by operating activities
		Depreciation, depletion and amortisation				36				12,929				11,878				8,859
		Profit on sale of assets								(3,033	)			(2,141	)			(367	)
		Movements in:
			inventories							(2,731	)			(236	)			(2,079	)
			accounts receivable							(8,462	)			1,834				(5,830	)
			accounts payable and accrued liabilities							7,708				(212	)			6,989
			taxes payable							2,999				(218	)			(735	)
		Associated companies: dividends more/ (less) than net income				34				(139	)			511				117
		Deferred taxation and other provisions								(630	)			(366	)			423
		Long-term liabilities and other								(1,798	)			(1,588	)			(805	)
		Income applicable to minority interests								714				366				175
Cash flow provided by operating activities										25,587				21,719				16,283
Cash flow used in investing activities
	Capital expenditure (including capitalised leases)					36				(12,734	)			(12,252	)			(12,102	)
	Acquisitions (Enterprise Oil, Pennzoil-Quaker State and additional shares in Equilon)																	(8,925	)
	Proceeds from sale of assets									5,078				2,286				1,099
	New investments in associated companies					7				(1,057	)			(983	)			(1,289	)
	Disposals of investments in associated companies									1,327				708				501
	Proceeds from sale and other movements in investments									1,743				1,989				83
Cash flow used in investing activities										(5,643	)			(8,252	)			(20,633	)
Cash flow used in financing activities
	Long-term debt (including short-term part):
		new borrowings								544				572				5,267
		repayments								(1,688	)			(2,740	)			(5,610	)
										(1,144	)			(2,168	)			(343	)
	New increase/(decrease) in short-term debt									(3,701	)			(2,507	)			7,058
	Change in minority interests									807				(1,363	)			421
	Dividends paid in:
		Parent Companies								(8,490	)			(6,248	)			(6,961	)
		minority interests								(264	)			(300	)			(228	)
Cash flow used in financing activities										(12,792	)			(12,586	)			(53	)
Parent Companies’ shares: net sales/(purchases) and dividends received										(758	)			(633	)			(864	)
Currency translation differences relating to cash and cash equivalents										113				148				153
Increase/(decrease) in cash and cash equivalents										6,507				396				(5,114	)
Cash and cash equivalents at January 1										1,952				1,556				6,670
Cash and cash equivalents at December 31										8,459				1,952				1,556

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Notes to the Netherlands GAAP Financial Statements

31 Basis of Presentation of Group Financial Statements under Netherlands GAAP

The differences between Netherlands GAAP, as applied to the preparation of these Financial Statements (and after giving effect to the restatement described in Note 32) and US GAAP, as applied to the Group’s Financial Statements prepared in conformity with US GAAP, are as follows:

(i)	goodwill: Under US GAAP, goodwill is not amortised but is tested for impairment annually or when certain events occur that indicate potential impairment. Under Netherlands GAAP, goodwill is amortised on a straight-line basis over its estimated useful economic life, which is assumed not to exceed 20 years unless there are grounds to rebut this assumption;
(ii)	recoverability of assets

	(a)	impairments: Under US GAAP, only if an asset’s estimated undiscounted future cash flows are below its carrying amount is a determination required of the amount of any impairment based on discounted cash flows. There is no undiscounted test under Netherlands GAAP;
	(b)	reversals of impairments: Under US GAAP impairments are not reversed. Under Netherlands GAAP, a favourable change in the circumstances which resulted in an impairment would trigger the requirement for a redetermination of the amount of the impairment and any reversal is recognised in income;

(iii)

asset retirement obligations: Under US GAAP, a change in accounting for asset retirement obligations in 2003, as described in Note 3, has been accounted for prospectively, with the cumulative effect of the change at the beginning of 2003 of $255 million being reflected in 2003 net income. This change in accounting was also made under Netherlands GAAP. However, the cumulative effect of the change under Netherlands GAAP has been reported as an adjustment to the opening balance of net assets and, due to the absence of comparative data, net income for prior years has not been restated.

Reconciliations of Group net assets and net income presented in the Group Financial Statements prepared in conformity with US GAAP (on pages G2 to G4), to Group net assets and net income in these Group Financial Statements which have been prepared in conformity with Netherlands GAAP, are presented in Note 33. Additionally, the division of Group net assets and movements therein, including movements resulting from Group net income and distributions to Parent Companies, determined in conformity with Netherlands GAAP, are presented in Note 38.

32 Restatement of previously issued financial statements

Quantitative information concerning the effect of these adjustments is set forth in the tables below and additional information on the Reserves Restatement is contained in Note 2 on pages G5 to G8.

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Statement of Income																																						$ million
		2003																				2002
														Reclassification																				Reclassification
						Second								for												Second								for
		As originally				Reserves								discontinued				As				As previously				Reserves								discontinued				As
		reporteda				Restatement				As restated				operationsb				restated				restateda				Restatement				As restated				operationsb				restated
Net proceeds			201,728				–				201,728				(3,366	)			198,362				166,601				–				166,601				(3,148	)			163,453
Cost of sales			167,667				289				167,956				(2,642	)			165,314				138,117				118				138,235				(2,457	)			135,778
Exploration			1,476				–				1,476				(1	)			1,475				1,073				–				1,073				(21	)			1,052
Other operating expenses			14,428				–				14,428				(565	)			13,863				12,027				–				12,027				(351	)			11,676
Share of operating profit of associated companies			3,484				(19	)			3,465				(19	)			3,446				2,822				(6	)			2,816				(24	)			2,792
Operating profit			21,641				(308	)			21,333				(177	)			21,156				18,206				(124	)			18,082				(343	)			17,739
Net interest (income)/expense and currency exchange (gains)/losses			(370	)			–				(370	)			(42	)			(412	)			629				–				629				(61	)			568
Income before taxation			22,011				(308	)			21,703				(135	)			21,568				17,577				(124	)			17,453				(282	)			17,171
Taxation			9,572				(126	)			9,446				(97	)			9,349				7,796				(54	)			7,742				(95	)			7,647
Minority interests			365				1				366				(13	)			353				179				(4	)			175				–				175
Income from continuing operations			12,074				(183	)			11,891				(25	)			11,866				9,602				(66	)			9,536				(187	)			9,349
Income from discontinued operations, net of tax			–				–				–				25				25				–				–				–				187				187
Net income			12,074				(183	)			11,891				–				11,891				9,602				(66	)			9,536				–				9,536

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.
b	As a consequence of the separate reporting of income from discontinued operations (see Note 4), information for comparative periods has been reclassified where necessary.

Statement of Assets and Liabilities																				$ million
				December 31, 2003
								Second								Reclassification
				As originally				Reserves								for deferred				As
				reporteda				Restatement				As restated				taxb				restated
Fixed assets
	Tangible				87,701				(613	)			87,088				–				87,088
	Intangible				4,448				–				4,448				–				4,448
	Investments				22,787				(13	)			22,774				–				22,774
Other long-term assets					9,257				–				9,257				2,092				11,349
Current assets					43,611				–				43,611				–				43,611
Current liabilities					54,424				–				54,424				–				54,424
Long-term liabilities					15,154				–				15,154				–				15,154
Provisions
		Deferred taxation			13,355				(262	)			13,093				2,092				15,185
		Pensions and decommissioning			8,882				–				8,882				–				8,882
Minority interests					3,428				(13	)			3,415				–				3,415
Net assets					72,561				(351	)			72,210				–				72,210

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.
b	Deferred tax assets and liabilities are presented at December 31, 2004 separately in the Statement of Assets and Liabilities, with reclassification of the prior year.

Parent Companies’ interest in Group net assets							$ million
			2003				2002
At December 31 as originally reported (2003)/previously restated (2002)a				72,561				60,324
Effect of the Second Reserves Restatement:
	Interest at the beginning of the year			(168	)			(102	)b
	Net income for the year			(183	)			(66	)
At December 31 as restated				72,210				60,156

a	As reported in the 2003 Annual Report and Accounts and the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004.
b	Cumulative effect as at January 1, 2002.

Amounts relating to prior periods have been restated in the following notes where applicable.

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33 Reconciliation between US GAAP and Netherlands GAAP

$ million
			Net income												Net assets
																			Dec 31,
							2003				2002				Dec 31,				2003
			2004				As restated				As restated				2004				As restated
In accordance with US GAAP				18,183				12,313				9,656				84,576				72,497
Adjustments for Netherlands GAAP:
Goodwill amortisation				(167	)			(167	)			(120	)			(454	)			(287	)
Cumulative effect of change in accounting for asset retirement obligations				–				(255	)			–				–				–
Recoverability of assets:
	Impairments			(455	)			–				–				(455	)			–
	Reversals of impairments			469				–				–				469				–
In accordance with Netherlands GAAP				18,030				11,891				9,536				84,136				72,210

The above table should be used to understand the differences in the movements in the Group’s net assets found in Note 30 and 38 as the tables are prepared based on US GAAP and Netherlands GAAP respectively.

Net income by segment in accordance with Netherlands GAAP is as follows:

$ million
		Net income
						2003				2002
		2004				As restated				As restated
Exploration & Production			9,784				8,668				6,726
Gas & Power			1,739				2,279				764
Oil Products			7,380				2,703				2,517
Chemicals			881				(209	)			565
Corporate and Other			(1,040	)			(1,184	)			(861	)
Minority interests			(714	)			(366	)			(175	)
			18,030				11,891				9,536

Where applicable, differences between Netherlands GAAP and US GAAP affecting these Notes are disclosed below.

34 Associated companies

35 Taxation

36 Tangible and intangible fixed assets

$ million
		2004																				2003
																						Total
										Other				Total				Total				Group
		Tangible				Goodwill				intangibles				intangibles				Group				As restated
Cost
At January 1			181,685				4,011				2,998				7,009				188,694				167,027
Capital expenditure			12,440				3				291				294				12,734				12,252
Sales, retirements and other movements			(9,345	)			(44	)			102				58				(9,287	)			(4,840	)
Currency translation differences			8,382				62				81				143				8,525				14,255
At December 31			193,162				4,032				3,472				7,504				200,666				188,694
Depreciation
At January 1			94,597				1,623				938				2,561				97,158				81,018
Depreciation, depletion and amortisation charge			12,434				167				328				495				12,929				11,878
Sales, retirements and other movements			(7,310	)			(37	)			(38	)			(75	)			(7,385	)			(3,711	)
Currency translation differences			4,990				42				45				87				5,077				7,973
At December 31			104,711				1,795				1,273				3,068				107,779				97,158
Net 2004			88,451				2,237				2,199				4,436				92,887
Net 2003 (as restated)			87,088				2,388				2,060				4,448								91,536

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There is an increase in depreciation, depletion and amortisation for tangible fixed assets recorded in cost of sales in 2004 of $489 million, with a corresponding reduction in the net book amount at December 31, 2004, compared with Note 11 prepared under US GAAP. This relates to additional impairments mainly in Gas & Power ($625 million), as a result of economic conditions in the power generation market (where an impairment was required under Netherlands GAAP but not under US GAAP because estimated undiscounted cash flows exceeded carrying amount), partly offset by an impairment reversal in Exploration & Production of $211 million, as a result of an increase in the longer-term expectation for oil prices.

There is an increase in depreciation, depletion and amortisation for intangible fixed assets recorded in cost of sales in 2004 of $167 million (2003: $167 million), with a cumulative impact of $454 million at December 31, 2004 (2003: $287 million), compared with Note 11 prepared under US GAAP. This relates to the amortisation of goodwill under Netherlands GAAP. Goodwill arising on the acquisition of Pennzoil-Quaker State in 2002 is amortised over forty years. Continued brand maintenance in addition to the established long-term leadership of these brands in automotive lubricants and vehicle care markets support this amortisation period.

37 Debt

(a) Long-term debt

$ million
		2004				2003
Debentures and other loans			4,204				4,868
Amounts due to banks and other credit institutions			980				1,061
			5,184				5,929
Capitalised lease obligations			3,416				3,171
Long-term debt			8,600				9,100
add long-term debt due within one year			1,291				1,874
Long-term debt including long-term debt due within one year			9,891				10,974

(b) Capitalised lease obligations

$ million
		Capital
		leases
2005			450
2006			423
2007			423
2008			420
2009			418
2010 and after			5,677
Total minimum payments			7,811
less executory costs and interest			4,280
Present value of net minimum capital lease payments			3,531

38 Division of Group net assets between the Parent Companies and movements therein

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Division of Group net assets and movements therein, including Group net income										$ million
						Royal				Shell
						Dutch				Transport
		Total				(60%)				(40%)
		As restated				As restated				As restated
At January 1, 2002			56,142				33,685				22,457
Movements during the year 2002:
Group net income			9,536				5,722				3,814
less: distributions to Parent Companies			(5,435	)			(3,261	)			(2,174	)
Undistributed net income			4,101				2,461				1,640
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(844	)			(507	)			(337	)
Other comprehensive income (see Note 6)			757				455				302
At December 31, 2002			60,156				36,094				24,062
Cumulative effect of a change in accounting policy			255				153				102
At January 1, 2003			60,411				36,247				24,164
Movements during the year 2003:
Group net income			11,891				7,134				4,757
less: distributions to Parent Companies			(5,660	)			(3,396	)			(2,264	)
Undistributed net income			6,231				3,738				2,493
Loss on sale of Parent Companies’ shares			(1	)			(1	)			–
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(631	)			(378	)			(253	)
Other comprehensive income (see Note 6)			6,200				3,720				2,480
At December 31, 2003			72,210				43,326				28,884
Movements during the year 2004:
Group net income			18,030				10,818				7,212
less: distributions to Parent Companies			(7,989	)			(4,793	)			(3,196	)
Undistributed net income			10,041				6,025				4,016
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(759	)			(455	)			(304	)
Other comprehensive income (see Note 6)			2,644				1,586				1,058
At December 31, 2004			84,136				50,482				33,654

The above table is based on the Group’s Netherlands GAAP results. See Note 33 for the impact of differences between US GAAP and Netherlands GAAP on the Group’s net income and net assets. Note 30 shows the division of Group net assets and movements therein under US GAAP.

Parent Companies’ interest in Group net assets											$ million
							2003				2002
			2004				As restated				As restated
Invested by Parent Companies				741				741				741
Retained earnings of Group companies				84,660				74,619				68,134
Parent Companies’ shares held, net of dividends received (Note 23)				(4,187	)			(3,428	)			(2,797	)
Cumulative currency translation differences				4,356				1,208				(3,894	)
Unrealised gains/(losses) on:
	securities (Note 15)			350				700				11
	cash flow hedges			(157	)			(188	)			(239	)
Minimum pension liability adjustments				(1,627	)			(1,442	)			(1,800	)
Balance at December 31				84,136				72,210				60,156

The reduction in retained earnings of Group companies at December 31, 2004 of $440 million (2003: $287 million) compared with Note 5 prepared in accordance with US GAAP, relates to impairments, reversals of impairments and the amortisation of goodwill under Netherlands GAAP (see Note 33).

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Reconciliation of Division of Group net assets and movements therein, including Group net income, to previously issued Financial Statements

$ million
		Total												Royal Dutch (60%)												Shell Transport (40%)
						Second												Second												Second
		As previously				Reserves								As previously				Reserves								As previously				Reserves
		restateda				Restatement				As restated				restateda				Restatement				As restated				restateda				Restatement				As restated
At January 1, 2002			56,244				(102	)			56,142				33,746				(61	)			33,685				22,498				(41	)			22,457
Movements during the year 2002:
Group net income			9,602				(66	)			9,536				5,761				(39	)			5,722				3,841				(27	)			3,814
less: distributions to Parent Companies			(5,435	)			–				(5,435	)			(3,261	)			–				(3,261	)			(2,174	)			–				(2,174	)
Undistributed net income			4,167				(66	)			4,101				2,500				(39	)			2,461				1,667				(27	)			1,640
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(844	)			–				(844	)			(507	)			–				(507	)			(337	)			–				(337	)
Other comprehensive income (see Note 6)			757				–				757				455				–				455				302				–				302
At December 31, 2002			60,324				(168	)			60,156				36,194				(100	)			36,094				24,130				(68	)			24,062
Cumulative effect of a change in accounting policy			255				–				255				153				–				153				102				–				102
			60,579				(168	)			60,411				36,347				(100	)			36,247				24,232				(68	)			24,164
Movements during the year 2003:
Group net income			12,074				(183	)			11,891				7,244				(110	)			7,134				4,830				(73	)			4,757
less: distributions to Parent Companies			(5,660	)			–				(5,660	)			(3,396	)			–				(3,396	)			(2,264	)			–				(2,264	)
Undistributed net income			6,414				(183	)			6,231				3,848				(110	)			3,738				2,566				(73	)			2,493
Loss on sale of Parent Companies’ shares			(1	)			–				(1	)			(1	)			–				(1	)			–				–				–
Movement in Parent Companies’ shares held by Group companies, net of dividends received			(631	)			–				(631	)			(378	)			–				(378	)			(253	)			–				(253	)
Other comprehensive income (see Note 6)			6,200				–				6,200				3,721				(1	)			3,720				2,479				1				2,480
At December 31, 2003			72,561				(351	)			72,210				43,537				(211	)			43,326				29,024				(140	)			28,884

a	2003 data is as originally reported.

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Supplementary information – Oil and Gas (unaudited)

Reserves

Proved reserves are shown net of any quantities of crude oil or natural gas that are expected to be taken by others as royalties in kind but do not exclude quantities related to royalties expected to be paid in cash (except in North America and in other situations in which the royalty quantities are owned by others) or those related to fixed margin contracts. Proved reserves include certain quantities of crude oil or natural gas which will be produced under arrangements which involve Group companies in upstream risks and rewards but do not transfer title of the product to those companies.

Oil and gas reserves cannot be measured exactly since estimation of reserves involves subjective judgment. These estimates remain subject to revision and are unaudited supplementary information.

Recategorisation and restatement of unaudited proved reserves volumes

Second Half Review

The Second Half Review reflected the implementation of certain remedial actions undertaken following the First Half Review and First Reserves Restatement, and in light of the report of Davis, Polk & Wardwell to the Group Audit Committee. These actions were designed to strengthen the controls relating to the reporting of proved reserves and included the following:

–	The Group’s reserves reporting guidelines were revised to comply with the SEC requirements and published SEC staff guidance.
–	The Group implemented a program to train approximately 3,000 staff members in the revised proved reserve guidelines. This training effort was substantially completed during the fourth quarter of 2004.
–	Beginning in July 2004, asset teams in each operating unit, using the revised guidelines and in some cases assisted by external consultants, undertook a reservoir-by-reservoir review of the Group’s proved reserve base as part of its annual reserves determination process.
–	Teams from Group internal audit, assisted by separate external consultants, conducted on-site reviews to evaluate compliance of reported volumes with SEC requirements, as well as the functioning of the reserves control framework and governance. For 2004, this audit process covered approximately 90% of the Group’s proved reserves originally reported in the 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004 (14,350 million boe). The findings of Group internal audit are reported directly to management and the Group Audit Committee.

1	The Group converts natural gas to crude oil equivalent using a factor of 5,800 standard cubic feet per barrel.

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–	All changes to proved reserves, were agreed by the Regional Reserves Committee and the Global Reserves Committee and reviewed by the Executive Committee, the Group Audit Committee and the boards of the Parent Companies.

See “Controls and Procedures – Remedial Actions Taken in 2004” (page 76) for an additional discussion of the remedial actions taken following the First Half Review and in light of the report to the Group Audit Committee of Davis, Polk & Wardwell.

Reserves Restatements

Variations from SEC Requirements

First Reserves Restatement

Market assurance

Governmental or regulatory approval

Field performance and project delivery

Year-end pricing

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Technical definition

–	Lowest Known Hydrocarbon: In some cases, volumes occurring below the “Lowest Known Hydrocarbon” (ie, the deepest point that has been logged as hydrocarbon-bearing) had been included in proved reserves estimates. Such volumes were considered defensible prior to 2003 generally on the grounds that evidence of the location of fluid contacts was available through measurements of the pressure gradients in the reservoirs concerned. This volume was estimated to be 172 million boe at the end of 2003 and was accounted for as a revision during the year 2003. It was not reflected in the Reserves Restatements for prior years.
–	Proved Area – Lateral Extent: In some cases, volumes occurring in parts of the reservoir that are more than one offset development well location from existing well penetrations had been booked as proved reserves in the absence of sufficient proof of continuous and economically productive reservoir in the areas concerned. This volume was estimated to be 180 million boe at the end of 2003 and substantially all was accounted for through restatement of proved reserves for prior years. The 2003 reserves additions as announced on February 5, 2004 were also reduced by approximately 180 million boe as a result of these issues.
–	Improved Recovery – Availability of Suitable Analogues: In some cases, volumes related to the successful implementation of improved recovery processes had been booked as proved reserves in the absence of either qualifying analogues or sufficient performance proof. SEC guidance requires “reasonable certainty” that the processes would be effective in the specific reservoirs concerned. This volume was estimated to be 160 million boe at the end of 2003 and substantially all was accounted for through restatement of proved reserves for prior years.
–	Recovery Factor Forecasting Methodology: In some cases, volumes booked on the basis of sophisticated computer modelling were not sufficiently supported by actual reservoir performance, as seen principally in decline curve analysis, to satisfy the requirement of “reasonable certainty” in the estimation of proved reserves. This volume was estimated to be 160 million boe at the end of 2003 and substantially all was accounted for through the revisions occurring during the year 2003.
–	Economic Producibility: In some cases, proved reserves may have been assigned to reservoirs in the absence of information from a combination of electrical and other type logs and core analyses sufficient to indicate the reservoirs were analogous to similar reservoirs in the same field which were producing or had demonstrated the ability to produce on a formation test. However, there were no material instances of reserves being debooked solely for this reason.

Royalty

Second Reserves Restatement

Proved Area – Lateral Extent

Improved Recovery – Availability of Suitable Analogues

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boe at the end of 2003 (9% of the Second Reserves Restatement) and was accounted for through restatement of proved reserves for prior years. Western Hemisphere (excluding USA) accounted for 48% of this volume followed by Africa (42%) and Europe (10%).

Recovery Factor Forecasting Methodology

Other Reasons

Effect of Reserves Restatements

The effect of the Reserves Restatements on unaudited proved reserve volumes and the standardised measure for each of the years covered by this report is summarised as follows:

Year ended December 31, 2003

The Second Reserves Restatement gave rise to an estimated reduction of $5,672 million in the standardised measure of discounted future net cash flow for Group companies and a further $327 million for associated companies. Together, these effects equate to approximately 10% of the total standardised measure that was originally stated at that date.

The effect of the combined Reserves Restatements on the standardised measure of discounted future net cash flows on 2002 and earlier years is disproportionately low (17% in 2002) compared with the effect on proved reserves (29% in 2002) primarily due to the fact that particularly for the First Reserves Restatement many of the volumes affected are located in relatively low margin operating areas and that the majority are undeveloped (the cost of development for these reserves tends to suppress the standardised measure of these volumes, as compared to the standardised measure for volumes that have already been developed).

The effect of the Second Reserves Restatement on the standardised measure of discounted future cash flows for year end 2003 (10%) is the same as the effect on proved reserves (10%). The volumes affected are not located primarily in low margin areas and there is a higher percentage of proved developed volumes than in the First Reserves Restatement.

Year ended December 31, 2002

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2,795 million barrels of crude oil and natural gas liquids and 9,736 thousand million standard cubic feet of gas. The balance of 1,153 million boe is reflected herein as part of the Second Reserves Restatement. Of the total unaudited proved reserves restated as part of the Second Reserves Restatement, 92% (1,060 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 42% of the total had been in the proved developed reserves category and 58% had been categorised as proved undeveloped reserves. Africa accounted for 35% of the Second Reserves Restatement, Asia Pacific 26%, Middle East 3%, Europe 21%, and Other Western Hemisphere 15%. Please refer to the narrative above for explanation of the principal reasons for the Second Reserves Restatement. After giving effect to the Second Reserves Restatement, the proportion of total unaudited proved reserve volumes that was accounted for as proved developed reserves at that date increased from 56%, as stated in the 2003 Annual Report and Accounts and 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004, to 57%.

The Reserves Restatements gave rise to an aggregate estimated reduction of $10,542 million in the standardised measure of discounted future net cash flow for Group companies and a further $1,470 million for associated companies. Together, these effects equate to approximately 17% of the total standardised measure that was originally stated at that date in the 2003 Annual Report and Accounts and 2003 Annual Report on Form 20-F, as filed with the SEC on June 30, 2004. The reduction of the net present value disclosed by the standardised measure includes an offset due to the correction of an error in the original statement that was discovered during compilation of the restated figures. The error related to the application of an incorrect net margin accruing to production on a fixed margin contract and resulted in an understatement of approximately 1% of the standardised measure value originally reported for the year 2002. The percentage effect is even less in 2001. Of the total reduction, $6,648 was reflected in the First Reserves Restatement and $5,364 is reflected herein as part of the Second Reserves Restatement.

Years prior to 2002

–	At December 31, 2001 (and January 1, 2002), the aggregated effect on unaudited proved reserves of the Reserves Restatements was 5,324 million boe, comprising 3,205 million barrels of crude oil and natural gas liquids and 12,293 thousand million standard cubic feet of gas. This amounted to 28% of the total unaudited proved reserve volumes originally stated at that date (19,095 million boe). Of the volumes restated, 88% (4,683 million boe) were attributable to Group companies and the remainder were attributable to associated companies. 16% of the total had been in the proved developed reserves category and 84% had been categorised as proved undeveloped reserves. Africa accounted for 45% of the total restatement, Asia Pacific 33%, Middle East 11%, Europe 7%, and Other Western Hemisphere 4%. Various properties in Nigeria accounted for 43% of the restated volumes at that date, Australia accounted for 19% of the total. The effect of applying year end pricing accounted for 4% of the total;
–	at December 31, 2000 (and January 1, 2001), the aggregated effect on unaudited proved reserves of the Reserves Restatements was 5,584 million boe, comprising 3,346 million barrels of crude oil and natural gas liquids and 12,979 thousand million standard cubic feet of gas. This amounted to 29% of the total unaudited proved reserves originally stated at that date (19,455 million boe). Of the total aggregated effect, 89% (4,995 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 15% of the total had been in the proved developed reserves category and 85% had been categorised as proved undeveloped reserves. Africa accounted for 44% of the total restatement, Asia Pacific 31%, Middle East 14%, Europe 5%, and Other Western Hemisphere 5%. Various properties in Nigeria accounted for 42% of the restated volume at that date and Australia accounted for 19%. The effect of applying year-end pricing accounted for 8% of the total;
–	at December 31, 1999 (and January 1, 2000), the aggregated effect on proved reserves of the Reserves Restatements was 5,207 million boe, comprising 2,802 million barrels of crude oil and natural gas liquids and 13,947 thousand million standard cubic feet of gas. This amounted to 26% of the total proved reserves originally stated at that date (19,868 million boe). Of the total aggregated effect, 89% (4,630 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 19% of the total had been in the proved developed reserves category and 81% had been categorised as proved undeveloped reserves. Africa accounted for 47% of the total restatement, Asia Pacific 32%, Middle East 11%, Europe 5%, and Other Western Hemisphere 5%. Various properties in Nigeria accounted for 47% of the restated volume at that date and Australia accounted for 22%. The effect of applying year-end pricing accounted for 10% of the total;
–	at December 31, 1998 (and January 1, 1999), the aggregate effect on proved reserves of the Reserves Restatements was 4,111 million boe, comprising 2,314 million barrels of crude oil and natural gas liquids and 10,423 thousand million standard cubic feet of gas. This amounted to 20% of the total proved reserves originally stated at that date (20,455 million boe). Of the total aggregate effect, 85% (3,501 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 17% of the total had been in the proved developed reserves category and 83% had been categorised as proved undeveloped reserves. Africa accounted for 57% of the total restatement, Asia Pacific 39%, and Europe 4%. Various properties in Nigeria and Australia together accounted for 85% of the restated volume at that date; and
–	at December 31, 1997 (January 1, 1998), the aggregate effect on proved reserves of the Reserves Restatements was 3,462 million boe, comprising 1,776 million barrels of crude oil and natural gas liquids and 9,779 thousand million standard cubic feet of gas.

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This amounted to 19% of the total proved reserves originally stated at that date (19,359 million boe). Of the total aggregate effect, 83% (2,883 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 9% of the total had been in the proved developed reserves category and 91% had been categorised as proved undeveloped reserves. Africa accounted for 52% of the total restatement, Asia Pacific 45% and Europe 4%. Various properties in Nigeria and Australia together accounted for 85% of the restated volume at that date.

Reconciliation of previously reported Supplementary information – Oil and Gas

Reconciliation of Proved Reserve Volumes and Standardised Measure

			million barrels																thousand million standard cubic feeta																$ million
			Reserves: Crude oil and natural gas liquids																Reserves: Natural gas
			Proved developed																																Standardised measure
			and undeveloped								Proved developed								Proved developed and								Proved developed								of discounted
			reserves								reserves								undeveloped reserves								reserves								future cash flows
			2003				2002				2003				2002				2003				2002				2003				2002				2003				2002
Group companies
As originally reported (2003)/previously restated (2002)				5,723				6,405				3,512				3,684				41,601				40,290				20,490				21,362				53,844				60,362
Effect of the Second Reserves Restatement
	Amounts at beginning of year			(623	)			(507	)			(168	)			(145	)			(2,533	)			(1,529	)			(1,401	)			(1,453	)			(5,202	)			(2,504	)
	Movements during the year			(91	)			(116	)			(75	)			(23	)			(698	)			(1,004	)			(101	)			52				(470	)			(2,698	)
Total				(714	)			(623	)			(243	)			(168	)			(3,231	)			(2,533	)			(1,502	)			(1,401	)			(5,672	)			(5,202	)
As restated At December 31				5,009				5,782				3,269				3,516				38,370				37,757				18,988				19,961				48,172				55,160
Group share of associated companies
As originally reported (2003)/previously restated (2002)				882				933				672				659				3,319				3,412				1,914				1,847				5,828				5,762
Effect of the Second Reserves Restatement
	Amounts at beginning of year			(75	)			(55	)			(72	)			(53	)			(104	)			187				(16	)			18				(162	)			(28	)
	Movements during the year			(2	)			(20	)			(10	)			(19	)			(27	)			(291	)			(17	)			(34	)			(165	)			(134	)
Total				(77	)			(75	)			(82	)			(72	)			(131	)			(104	)			(33	)			(16	)			(327	)			(162	)
As restated at December 31				805				858				590				587				3,188				3,308				1,881				1,831				5,501				5,600

Geographical analysis of the Second Reserves Restatement

			million barrels																thousand million standard cubic feeta																$ million
			Reserves: Crude oil and natural gas liquids																Reserves: Natural gas
			Proved developed																																Standardised measure
			and undeveloped								Proved developed								Proved developed and								Proved developed								of discounted
			reserves								reserves								undeveloped reserves								reserves								future cash flows
			2003				2002				2003				2002				2003				2002				2003				2002				2003				2002
Group companies
	Europe			(168	)			(111	)			(94	)			(64	)			(1,242	)			(762	)			(873	)			(589	)			(1,499	)			(1,343	)
	Africab			(374	)			(379	)			(102	)			(64	)			(835	)			(152	)			(208	)			(446	)			(2,614	)			(2,910	)
	Asia Pacificc			(15	)			(15	)			(10	)			(5	)			(1,011	)			(1,132	)			(395	)			(370	)			(564	)			(556	)
	Middle East, Russia, CISd			(94	)			(38	)			(34	)			(33	)			(6	)			–				(3	)			–				(552	)			7
	USA			(3	)			(3	)			(2	)			(2	)			(32	)			(32	)			(4	)			(5	)			(52	)			(37	)
	Other Western Hemisphere			(60	)			(77	)			(1	)			–				(105	)			(455	)			(19	)			9				(391	)			(363	)
Total				(714	)			(623	)			(243	)			(168	)			(3,231	)			(2,533	)			(1,502	)			(1,401	)			(5,672	)			(5,202	)
Group share of associated companies
	Europe			–				–				–				–				–				–				–				–				–				–
	Africab			–				–				–				–				–				–				–				–								–
	Asia Pacificc			(77	)			(75	)			(82	)			(72	)			(131	)			(104	)			(33	)			(16	)			(326	)			(162	)
	Middle East, Russia, CISd			–				–				–				–				–				–				–				–				–				–
	USA			–				–				–				–				–				–				–				–				–				–
	Other Western Hemisphere			–				–				–				–				–				–				–				–				–				–
Total				(77	)			(75	)			(82	)			(72	)			(131	)			(104	)			(33	)			(16	)			(326	)			(162	)

a	These quantities have not been adjusted to standard heat content.
b	Excludes Egypt.

c	Excludes Sakhalin.

d	Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin.

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Crude oil and natural gas liquids

Proved developed and undeveloped reserves^a

		million barrels
		2004
		Eastern Hemisphere																Western Hemisphere
										Asia				Middle East								Americas
		Europe				Africab				Pacificc				Russia, CISd				USA				Other				Total
Group companies
At January 1			1,199				1,379				303				1,202				547				379				5,009
Revisions and reclassifications			(27	)			(46	)			13				80				(2	)			(197	)			(179	)
Improved recovery			6				2				–				4				–				–				12
Extensions and discoveries			5				13				10				68				12				2				110
Purchases of minerals in place			–				–				–				–				–				–				–
Sales of minerals in place			(2	)			(57	)			(35	)			–				–				–				(94	)
Production			(212	)			(146	)			(46	)			(172	)			(99	)			(38	)			(713	)
Transfers to associated companies			–				–				–				(384	)			–				–				(384	)
At December 31			969				1,145				245				798				458				146				3,761
Group share of associated companies
At January 1			2				–				304				86				413				–				805
Revisions and reclassifications			–				–				(22	)			(13	)			18				–				(17	)
Improved recovery			–				–				38				–				–				–				38
Extensions and discoveries			–				–				–				–				–				–				–
Purchases of minerals in place			–				–				–				–				–				–				–
Sales of minerals in place			–				–				(1	)			–				–				–				(1	)
Production			–				–				(43	)			–				(39	)			–				(82	)
Transfers from Group companies			–				–				–				384				–				–				384
At December 31			2				–				276				457				392				–				1,127
Minority Interests’ share of proved reserves of Group companies
At December 31			–				23				1				109				–				14				147

Oil sandse		million barrels
Group companies
At January 1			572				572
Revisions and reclassifications			72				72
Extensions and discoveries			–				–
Production			(29	)			(29	)
At December 31			615				615
Minority Interests’ share of oil sands
At December 31			135				135

Proved developed reserves

		million barrels
		2004
		Eastern Hemisphere																Western Hemisphere
										Asia				Middle East								Americas
		Europe				Africab				Pacificc				Russia, CISd				USA				Other				Total
Group companies
At January 1			962				777				184				864				291				191				3,269
At December 31f			755				617				134				475				242				115				2,338
Group share of associated companies
At January 1			1				–				224				1				364				–				590
At December 31f			1				–				187				360				349				–				897

a	A summary of changes is shown on page G54.
b	Excludes Egypt.
c	Excludes Sakhalin.
d	Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin.
e	Petroleum reserves from operations that do not qualify as oil and gas producing activities, such as our Athabasca Oil Sands Project, are not included in oil and gas reserves and are not considered in the standardised measure of discounted future cash flows for oil and gas reserves, which is found on page G60. The petroleum reserves for the Athabasca Oil Sands Project are presented in this report net of royalty volumes.
f	After accounting for a transfer of proved developed reserves from Group to associated companies of 360 million barrels at the end of 2004.

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										million barrels																				million barrels
2003																														2002
As restated																														As restated
Eastern Hemisphere																		Western Hemisphere												Eastern Hemisphere																Western Hemisphere
														Middle East,																												Middle East,
		Europe				Africab				Asia Pacificc				Russia, CISd				USA				Other				Total				Europe				Africab				Asia Pacificc				Russia, CISd				USA				Other				Total
			1,377				1,449				323				1,446				717				470				5,782				1,013				1,308				426				1,677				672				504				5,600
			88				(102	)			21				(204	)			(54	)			(57	)			(308	)			99				89				(27	)			(26	)			77				(42	)			170
			5				(6	)			16				10				8				1				34				13				–				6				47				51				–				117
			12				171				–				128				9				2				322				–				173				6				–				33				–				212
			1				–				–				3				–				–				4				507				–				–				–				7				41				555
			(39	)			–				–				–				(23	)			–				(62	)			(1	)			(19	)			(19	)			(62	)			(3	)			–				(104	)
			(245	)			(133	)			(57	)			(181	)			(110	)			(37	)			(763	)			(254	)			(102	)			(69	)			(190	)			(120	)			(33	)			(768	)
			–				–				–				–				–				–				–				–				–				–				–				–				–				–
			1,199				1,379				303				1,202				547				379				5,009				1,377				1,449				323				1,446				717				470				5,782
			2				–				325				118				413				–				858				1				–				307				–				356				–				664
			–				–				1				–				41				–				42				1				–				55				–				65				–				121
			–				–				13				–				–				–				13				–				–				4				–				–				–				4
			–				–				11				86				–				–				97				–				–				9				–				33				–				42
			–				–				–				–				–				–				–				–				–				–				121				–				–				121
			–				–				–				(117	)			–				–				(117	)			–				–				–				(1	)			–				–				(1	)
			–				–				(46	)			(1	)			(41	)			–				(88	)			–				–				(50	)			(2	)			(41	)			–				(93	)
			–				–				–				–				–				–				–				–				–				–				–				–				–				–
			2				–				304				86				413				–				805				2				–				325				118				413				–				858
			–				24				1				137				–				54				216				–				23				1				126				–				61				211

										million barrels																				million barrels
																							517				517																								594				594
																							10				10																								(77	)			(77	)
																							60				60																								–				–
																							(15	)			(15	)																							–				–
																							572				572																								517				517
																							126				126																								115				115

										million barrels																				million barrels
2003																														2002
As restated																														As restated
Eastern Hemisphere																		Western Hemisphere												Eastern Hemisphere																Western Hemisphere
														Middle East,																												Middle East,
		Europe				Africab				Asia Pacificc				Russia, CISd				USA				Other				Total				Europe				Africab				Asia Pacificc				Russia, CISd				USA				Other				Total
			1,063				674				194				1,023				371				191				3,516				750				662				245				1,089				429				212				3,387
			962				777				184				864				291				191				3,269				1,063				674				194				1,023				371				191				3,516
			1				–				206				15				365				–				587				1				–				208				–				330				–				539
			1				–				224				1				364				–				590				1				–				206				15				365				–				587

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Natural gas

Proved developed and undeveloped reserves^a

		thousand million standard cubic feetb
		2004
		Eastern Hemisphere																Western Hemisphere
										Asia				Middle East								Americas
		Europe				Africac				Pacificd				Russia, CISe				USA				Other				Total
Group companies
At January 1			19,876				2,743				7,352				3,628				3,143				1,628				38,370
Revisions and reclassifications			(270	)			(74	)			125				138				(100	)			(45	)			(226	)
Improved recovery			9				–				–				–				–				4				13
Extensions and discoveries			217				–				171				2,128				257				192				2,965
Purchases of minerals in place			–				–				–				–				9				–				9
Sales of minerals in place			(48	)			–				(310	)			(258	)			–				(37	)			(653	)
Production			(1,345	)			(137	)			(535	)			(253	)			(486	)			(197	)			(2,953	)
At December 31			18,439				2,532				6,803				5,383				2,823				1,545				37,525
Group share of associated companies
At January 1			39				–				3,122				–				27				–				3,188
Revisions and reclassifications			–				–				120				–				(8	)			–				112
Improved recovery			–				–				45				–				–				–				45
Extensions and discoveries			5				–				1				–				–				–				6
Purchases of minerals in place			–				–				–				–				–				–				–
Sales of minerals in place			–				–				(55	)			–				–				–				(55	)
Production			(7	)			–				(246	)			–				(2	)			–				(255	)
At December 31			37				–				2,987				–				17				–				3,041
Minority Interests’ share of proved reserves of Group companies
At December 31			209				–				56				2,231				–				274				2,770

Proved developed reserves

		thousand million standard cubic feetb
		2004
		Eastern Hemisphere																Western Hemisphere
										Asia				Middle East								Americas
		Europe				Africab				Pacificc				Russia, CISd				USA				Other				Total
Group companies
At January 1			11,477				886				3,128				446				1,754				1,297				18,988
At December 31			12,961				919				2,702				166				1,875				1,080				19,703
Group share of associated companies
At January 1			34				–				1,825				–				22				–				1,881
At December 31			28				–				1,606				–				15				–				1,649

a	A summary of the changes is shown on page G54.
b	These quantities have not been adjusted to standard heat content.
c	Excludes Egypt.
d	Excludes Sakhalin.
e	Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin.

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thousand million standard cubic feetb																														thousand million standard cubic feetb
2003																														2002
As restated																														As restated
		Eastern Hemisphere																Western Hemisphere												Eastern Hemisphere																Western Hemisphere
														Middle East,																												Middle East,
		Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total				Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total
			21,284				1,692				7,862				1,118				3,842				1,959				37,757				22,022				1,780				9,031				1,777				3,663				2,257				40,530
			(435	)			(688	)			8				(22	)			(70	)			(181	)			(1,388	)			(110	)			1				(680	)			(282	)			162				(123	)			(1,032	)
			4				506				17				–				10				30				567				6				–				150				–				20				–				176
			459				1,361				6				2,790				305				34				4,955				29				–				126				–				410				9				574
			6				–				–				–				–				–				6				673				–				–				–				208				12				893
			(139	)			–				–				–				(389	)			(17	)			(545	)			(5	)			–				(212	)			–				(10	)			–				(227	)
			(1,303	)			(128	)			(541	)			(258	)			(555	)			(197	)			(2,982	)			(1,331	)			(89	)			(553	)			(377	)			(611	)			(196	)			(3,157	)
			19,876				2,743				7,352				3,628				3,143				1,628				38,370				21,284				1,692				7,862				1,118				3,842				1,959				37,757
			44				–				3,243				–				21				–				3,308				48				–				2,943				–				15				–				3,006
			–				–				106				–				9				–				115				1				–				434				–				7				–				442
			1				–				11				–				–				–				12				–				–				8				–				–				–				8
			1				–				–				–				–				–				1				3				–				80				–				1				–				84
			–				–				–				–				–				–				–				–				–				–				–				–				–				–
			–				–				–				–				–				–				–				–				–				–				–				–				–				–
			(7	)			–				(238	)			–				(3	)			–				(248	)			(8	)			–				(222	)			–				(2	)			–				(232	)
			39				–				3,122				–				27				–				3,188				44				–				3,243				–				21				–				3,308
			–				–				63				1,285				–				300				1,648				–				–				61				59				–				342				462

thousand million standard cubic feeta,b																														thousand million standard cubic feeta,b
2003																														2002
As restated																														As restated
		Eastern Hemisphere																Western Hemisphere												Eastern Hemisphere																Western Hemisphere
														Middle East,																												Middle East,
		Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total				Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total
			11,472				735				3,405				574				2,311				1,464				19,961				11,880				668				3,635				1,097				2,363				1,754				21,397
			11,477				886				3,128				446				1,754				1,297				18,988				11,472				735				3,405				574				2,311				1,464				19,961
			38				–				1,776				–				17				–				1,831				41				–				1,759				–				11				–				1,811
			34				–				1,825				–				22				–				1,881				38				–				1,776				–				17				–				1,831

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Standardised measure of discounted future cash flows

$ million
		2004
		Eastern Hemisphere																Western Hemisphere
														Middle East,
		Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total
Group companies
Future cash inflows			107,956				47,326				26,461				51,565				33,525				12,578				279,411
Future production costs			29,641				13,354				4,882				10,020				5,354				3,600				66,851
Future development costs			11,778				4,928				3,669				10,216				1,841				834				33,266
Future tax expenses			34,635				16,831				6,147				14,031				9,860				2,074				83,578
Future net cash flows			31,902				12,213				11,763				17,298				16,470				6,070				95,716
Effect of discounting cash flows at 10%			14,925				4,037				5,270				11,375				5,803				2,007				43,417
Standardised measure of discounted future net cash flows			16,977				8,176				6,493				5,923				10,667				4,063				52,299
Group share of associated companies																											5,527
Minority interests			285				180				36				1,078				–				548				2,128

Change in standardised measure of Group companies discounted future net cash flows
relating to proved Oil and Gas Reservesa,b										$ million
		2004				2003				2002
						As restated				As restated
At January 1			48,172				55,160				37,910
Net changes in prices and production costs			23,524				12,178				34,592
Extensions, discoveries and improved recovery			6,223				9,255				5,177
Purchases and sales of minerals in place			(564	)			(2,558	)			7,319
Revisions of previous reserve estimates			(385	)			(4,103	)			375
Development cost related to future production			(6,829	)			(14,291	)			(6,168	)
Sales and transfers of oil and gas, net of production costsf			(27,530	)			(24,892	)			(20,387	)
Development cost incurred during the year			9,386				8,205				6,503
Accretion of discount			7,947				9,051				6,053
Net change in income tax			(7,645	)			167				(16,214	)
At December 31			52,299				48,172				55,160

a	A summary of the changes is shown on the tables on page G54.
b	The weighted average year-end spot oil price in 2004 was $37.61/bbl ($26.52/bbl in 2003, $24.49/bbl in 2002) and the weighted average year-end spot gas price in 2004 was $21.27/boe ($18.03/boe in 2003, $15.75/boe in 2002).
c	Excludes Egypt.
d	Excludes Sakhalin.
e	Middle East and Former Soviet Union / Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin.
f	Includes a transfer of proved developed reserves from Group to associated companies of 360 million barrels in 2004 ($260 million).

Additional information concerning proved reserves

Proved reserves are recognised under various forms of contractual agreements. Group proved reserves volumes present in agreements such as Production Sharing Contracts or other forms of economic entitlement contracts where Group share of reserves can vary with actual year-end price are approximately 859 million barrels of crude oil and natural gas liquids and 9,720 thousand million standard cubic feet of gas.

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Table of Contents

$ million																												$ million
2003																												2002
As restated																												As restated
Eastern Hemisphere																Western Hemisphere												Eastern Hemisphere																Western Hemisphere
												Middle East,																												Middle East,
Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total				Europe				Africac				Asia Pacificd				Russia, CISe				USA				Other				Total
	108,836				36,965				21,695				42,627				31,203				14,710				256,036				98,126				36,427				22,243				36,513				32,541				16,280				242,130
	20,241				6,347				4,365				7,579				4,949				4,156				47,637				18,721				5,034				3,563				5,174				4,841				3,673				41,006
	6,541				4,661				2,528				9,679				3,085				1,315				27,809				4,783				4,670				2,397				2,844				3,201				1,532				19,427
	39,605				16,396				4,076				15,309				8,467				2,469				86,322				32,125				18,690				4,538				17,443				9,103				3,447				85,346
	42,449				9,561				10,726				10,060				14,702				6,770				94,268				42,497				8,033				11,745				11,052				15,396				7,628				96,351
	21,126				4,210				4,590				8,491				5,170				2,509				46,096				19,511				3,601				5,343				4,166				5,427				3,143				41,191
	21,323				5,351				6,136				1,569				9,532				4,261				48,172				22,986				4,432				6,402				6,886				9,969				4,485				55,160
																									5,501																												5,600
	–				136				30				(1,186	)			–				547				(473	)			–				123				22				753				–				468				1,366

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The following information is provided in accordance with the Securities and Exchange Commission rules issued in 1997. The contract/ notional amounts of the derivative instruments outstanding give an indication of the extent of the use of these instruments but not of the exposure to credit or market risk. Variable interest rates stated are spot rates applying as at December 31. Amounts denominated in non-US dollar currencies have been translated using spot exchange rates at December 31. Associated companies’ data are excluded.

Debt securities held for trading purposes

Debt securities held for purposes other than trading

2004			$ million
																							2010
			2005				2006				2007				2008				2009				and after				Total
Fixed rate US dollar debt securities				1,090				29				100				105				162				95				1,581
	average Interest rate			2.5%				7.1%				7.2%				5.7%				5.5%				6.5%
Variable rate US dollar debt securities				1				–				–				–				–				–				1
	average Interest rate			1.4%				–				–				–				–				–
Fixed rate euro debt securities				255				47				45				–				17				119				483
	average Interest rate			2.2%				5.9%				5.5%				–				4.0%				4.8%
Fixed rate UK pound debt securities				5				–				–				6				–				17				28
	average Interest rate			8.5%				–				–				5.0%				–				7.5%
Variable rate UK pound debt securities				24				–				–				–				–				–				24
	average Interest rate			4.8%				–				–				–				–				–
Fixed rate Canadian dollar debt securities				106				–				–				–				–				10				116
	average Interest rate			2.5%				–				–				–				–				8.1%
Other fixed rate debt securities				1				–				–				–				–				14				15
	average Interest rate			4.9%				–				–				–				–				5.8%
Other variable rate debt securities				37				–				–				–				–				–				37
	average Interest rate			4.6%				–				–				–				–				–
Total				1,519				76				145				111				179				255				2,285

2003			$ million
																							2009
			2004				2005				2006				2007				2008				and after				Total
Fixed rate US dollar debt securities				9				54				23				230				75				131				522
	average Interest rate			0.7%				5.8%				7.1%				5.6%				3.3%				6.2%
Variable rate US dollar debt securities				9				–				–				–				–				–				9
	Average Interest rate			1.4%				–				–				–				–				–
Fixed rate euro debt securities				5				–				48				42				–				109				204
	average Interest rate			1.9%				–				6.1%				5.3%				–				5.7%
Fixed rate UK pound debt securities				–				8				–				–				10				5				23
	average Interest rate			–				8.5%				–				–				5.7%				7.0%
Fixed rate Canadian dollar debt securities				39				–				–				–				–				8				47
	average Interest rate			2.7%				–				–				–				–				9.6%
Fixed rate Swedish krone debt securities				–				–				–				–				–				6				6
	average Interest rate			–				–				–				–				–				6.8%
Fixed rate Danish krone debt securities				–				–				–				–				–				7				7
	average Interest rate			–				–				–				–				–				5.0%
Other fixed rate debt securities				2				–				–				–				–				–				2
	average Interest rate			9.0%				–				–				–				–				–
Other variable rate debt securities				48				–				–				–				–				–				48
	average Interest rate			5.6%				–				–				–				–				–
Total				112				62				71				272				85				266				868

Equity securities held for purposes other than trading

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Debt

2004			$ million
																											2010
							2005				2006				2007				2008				2009				and after				Total
Fixed rate US dollar debt								4,200				676				1,115				85				91				2,073				8,240
	average interest rate							2.9%				3.7%				5.2%				8.1%				8.2%				8.3%
Variable rate US dollar debt								343				260				19				9				9				309				949
	average interest rate							7.4%				1.8%				3.6%				3.6%				3.7%				5.8%
Fixed rate European debt								294				723				1,322				419				1				2				2,761
	average interest rate							2.6%				4.2%				3.4%				3.3%				4.2%				4.5%
Variable rate European debt								76				1				1				1				–				–				79
	average interest rate							2.9%				2.9%				3.0%				3.0%				5.0%				5.0%
Other fixed rate debt								201				14				17				16				16				559				823
	average interest rate							3.6%				6.6%				5.6%				6.9%				6.9%				7.3%
Other variable rate debt								655				210				–				–				–				–				865
	average interest rate							7.3%				2.8%				–				–				–				–
Total								5,769				1,884				2,474				530				117				2,943				13,717

2003			$ million
																							2009
			2004				2005				2006				2007				2008				and after				Total
Fixed rate US dollar debt				5,772				804				613				1,073				152				2,709				11,123
	average interest rate			1.2%				4.8%				3.2%				5.0%				5.5%				7.9%
Variable rate US dollar debt				1,654				144				169				17				9				316				2,309
	average interest rate			3.9%				2.2%				2.1%				3.3%				4.2%				6.1%
Fixed rate European debt				1,185				4				666				946				377				4				3,182
	average interest rate			6.1%				3.6%				4.2%				3.3%				3.5%				3.7%
Variable rate European debt				1,173				2				3				3				1				–				1,182
	average interest rate			2.3%				4.3%				4.1%				4.1%				4.6%				5.3%
Other fixed rate debt				203				3				33				1				–				180				420
	average interest rate			5.0%				4.2%				10.5%				5.5%				5.5%				7.5%
Other variable rate debt				931				255				42				27				22				17				1,294
	average interest rate			6.8%				5.3%				4.0%				4.8%				4.8%				4.8%
Total				10,918				1,212				1,526				2,067				561				3,226				19,510

Fixed rate European currency debt expected to mature in 2005 includes $268 million of UK pound debt (with an average interest rate of 2.8%). The fixed rate European currency debt expected to mature in 2006 is mainly UK pound debt with an average interest rate of 4.3%. Fixed rate European currency debt expected to mature in 2007 includes $1,025 million of Euro debt with an average interest rate of 3.5% and $297 million of UK pound debt with an average interest rate of 3.3%. The fixed rate European currency debt expected to mature in 2008 is Euro debt with an average interest rate of 3.3%. The fixed rate European currency debt due to mature after 2010 is Euro debt with an average interest rate of 4.4%.

Other fixed rate debt expected to mature in 2005 includes $101 million of Argentine peso debt at an average interest rate of 3.3%. Other fixed rate debt due to mature after 2010 is mainly comprised of $154 million of Malaysian Ringgit debt (at an average interest rate of 8.0%) and $391 million of Canadian Dollar debt (at an average interest rate of 6.9%).

Other variable rate debt expected to mature in 2005 includes $205 million of Philippine peso debt with an average interest rate of 8.6% and $116 million of Canadian dollar debt at an average interest rate of 2.5%. Other variable rate debt expected to mature in 2006 includes $191 million of Canadian dollar debt at an average interest rate 2.5%.

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Interest rate swaps/forward rate agreements

2004																										$ million
																		2009				Total contract/				Estimated
		2005				2006				2007				2008				and after				notional amount				fair value
US dollar
Fixed to Variable: contract/notional amount			801				600				1,000				300				–				2,701				72
average pay rate			1.7%				1.3%				1.4%				1.4%				–
average receive rate			5.1%				3.1%				5.0				3.3%				–
Variable to Fixed: contract/ notional amount			264				–				122				88				–				474				(17	)
average pay rate			2.8%				–				7.2%				6.2%				–
average receive rate			3.3%				–				4.4%				7.3%				–
UK pound
Fixed to Variable: contract/notional amount			–				723				–				–				–				723				8
average pay rate			–				4.5%				–				–				–
average receive rate			–				4.3%				–				–				–
Euro
Fixed to Variable: contract/notional amount			–				–				–				409				–				409				7
average pay rate			–				–				–				2.0%				–
average receive rate			–				–				–				3.3%				–
Total			1,065				1,323				1,122				797				–				4,307				70

2003																										$ million
																		2008				Total contract/				Estimated
		2004				2005				2006				2007				and after				notional amount				fair value
US dollar
Fixed to Variable: contract/notional amount			–				1,801				600				–				400				2,801				140
average pay rate			–				1.3%				1.1%				–				0.9%
average receive rate			–				5.0%				3.1%				–				3.2%
Variable to Fixed: contract/ notional amount			–				264				–				122				88				474				(25	)
average pay rate			–				2.8%				–				7.2%				6.8%
average receive rate			–				3.2%				–				4.2%				7.3%
UK pound
Fixed to Variable: contract/notional amount			–				–				669				–				–				669				11
average pay rate			–				–				3.6%				–				–
average receive rate			–				–				4.3%				–				–
Euro
Fixed to Variable: contract/notional amount			–				–				–				–				378				378				(5	)
average pay rate			–				–				–				–				2.1%
average receive rate			–				–				–				–				3.3%
Total			–				2,065				1,269				122				866				4,322				121

Foreign exchange contracts

2004 (all contracts mature in 2005)										$ million
		Average contractual				Contract/notional				Estimated
		exchange rate				amount				fair value
Buy euro/sell US dollar			1.34				3,919				81
Buy US dollar/sell euro			0.74				2,124				(19	)
Buy euro/sell UK pound			0.70				1,836				35
Buy UK pound/sell US dollar			1.89				1,376				25
Buy US dollar/sell Australian dollar			1.30				1,024				(9	)
Buy US dollar/sell Norwegian krone			6.26				741				(27	)
Buy Singapore dollar/sell US dollar			0.61				401				2
Buy New Zealand dollar/sell US dollar			0.71				335				2
Buy Canadian dollar/sell US dollar			0.79				208				11
Buy Norwegian krone/sell US dollar			0.16				202				1
Buy US dollar/sell Philippine peso			56.19				172				–
Buy US dollar/sell Swedish krone			6.61				141				–
Buy euro/sell Polish zloty			4.10				134				–
Buy US dollar/sell Hong Kong dollar			7.77				131				–
Other contracts							1,176				(7	)
Total							13,920				95

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2003 (all contracts mature in 2004)										$ million
		Average contractual				Contract/notional				Estimated
		exchange rate				amount				fair value
Buy US dollar/sell UK pound			0.59				2,255				(118	)
Buy US dollar/sell euro			0.80				1,897				(26	)
Buy euro/sell US dollar			1.18				2,742				177
Buy UK pound/sell US dollar			1.73				1,017				3
Buy euro/sell UK pound			0.69				824				24
Buy US dollar/sell Australian dollar			1.36				422				(7	)
Buy Swiss franc/sell US dollar			0.77				431				24
Buy US dollar/sell Norwegian krone			6.67				672				(18	)
Buy Singapore dollar/sell US dollar			0.58				381				2
Buy US dollar/sell Danish krone			5.88				239				(3	)
Buy US dollar/sell Swedish krone			7.14				429				(3	)
Buy Swedish krona/sell US dollar			0.14				217				1
Buy euro/sell Norwegian krone			8.33				127				5
Buy US dollar/sell Philippine peso			55.87				118				–
Other contracts							1,074				25
Total							12,845				86

Currency swaps/options

2004																																		$ million
		Average
		contractual																								2010				Total contract/				Estimated
		exchange rate				2005				2006				2007				2008				2009				and after				notional amount				fair value
Buy UK pound/sell euro			1.54				–				–				924				410				–				–				1,334				139
Buy US dollar/sell Canadian dollar			1.40				867				606				441				296				132				–				2,342				(175	)
Buy Canadian dollar/sell US dollar			0.69				283				85				59				33				3				–				463				35
Buy US dollar/sell Brazilian real			2.85				101				5				89				61				–				–				256				(60	)
Buy UK pound/sell US dollar			1.74				37				31				24				18				14				213				337				26
Buy US dollar/sell Thai baht			39.94				142				–				–				–				–				–				142				(3	)
Other contracts			–				36				–				–				–				–				–				36				(4	)
Total							1,466				727				1,537				818				149				213				4,910				(42	)

2003																																		$ million
		Average
		contractual																								2009				Total contract/				Estimated
		exchange rate				2004				2005				2006				2007				2008				and after				notional amount				fair value
Buy UK pound/sell euro			1.54				338				–				–				855				378				–				1,571				173
Buy US dollar/sell Canadian dollar			1.31				1,136				640				358				209				96				–				2,439				(126	)
Buy US dollar/sell euro			1.09				461				–				–				–				–				–				461				171
Buy Australian dollar/sell US dollar			1.67				472				–				–				–				–				–				472				(130	)
Buy Canadian dollar/sell US dollar			0.67				324				91				56				46				17				–				534				34
Buy US dollar/sell Brazilian real			2.82				121				47				–				71				–				15				254				(39	)
Buy UK pound/sell US dollar			1.74				14				18				5				–				–				144				181				1
Other contracts							98				18				1				–				–				–				117				(5	)
Total							2,964				814				420				1,181				491				159				6,029				79

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Commodity derivatives

The increases in fair values of commodity swaps, options and futures between 2003 and 2004 are primarily caused by underlying increases of commodity prices driven by an increase of crude oil prices in 2004.

Commodity swaps held for trading purposes

2004

$ million

2010 and

Total contract/

Estimated

2005

2006

2007

2008

2009

after

notional amount

fair value

Crude oil swaps

(a) Variable price to variable price contracts:

contract/notional amount ($ millions)

1,776

30

–

–

–

–

1,806

(8

)

Volume (million barrels “m bbl”)

42

1

–

–

–

–

average pay

42.3

41.6

–

–

–

–

average receive

42.1

41.5

–

–

–

–

(b) Buy fixed price/sell variable price contracts:

contract/notional amount ($ millions)

1,843

397

49

13

–

–

2,302

390

Volume (million barrels “m bbl”)

54

13

2

*

–

–

average pay

34.3

31.5

32.6

36.4

–

–

average receive

39.6

39.3

38.0

37.9

–

–

(c) Buy variable price/sell fixed price contracts:

contract/notional amount ($ millions)

2,304

286

38

10

–

–

2,638

(350

)

Volume (million barrels “m bbl”)

64

9

1

*

–

–

average pay

40.3

38.7

37.8

37.9

–

–

average receive

36.1

30.7

32.9

36.3

–

–

Crude oil basis swaps

(a) Buy variable/sell variable price contracts

contract/notional amount ($ millions)

53

–

–

–

–

–

53

(8

)

Volume (million barrels “m bbl”)

34

–

–

–

–

–

average pay

3.9

–

–

–

–

–

average receive

1.8

–

–

–

–

–

(b) Sell variable/buy variable price contracts

contract/notional amount ($ millions)

2

–

–

–

–

–

2

–

Volume (million barrels “m bbl”)

*

–

–

–

–

–

average pay

4.0

–

–

–

–

–

average receive

4.5

–

–

–

–

–

Crude oil freight swaps

(a) Buy fixed price/sell variable price contracts

contract/notional amount ($ millions)

53

–

–

–

–

–

53

(7

)

Volume (million barrels “m bbl”)

29

–

–

–

–

–

average pay

1.9

–

–

–

–

–

average receive

1.7

–

–

–

–

–

(b) Buy variable price/sell fixed price contracts

contract/notional amount ($ millions)

63

–

–

–

–

–

63

1

Volume (million barrels “m bbl”)

47

–

–

–

–

–

average pay

1.3

–

–

–

–

–

average receive

1.4

–

–

–

–

–

Oil products swaps

(a) Buy fixed price/sell variable price contracts

contract/notional amount ($ millions)

3,055

106

–

–

–

–

3,161

(111

)

Volume (million barrels “m bbl”)

117

3

–

–

–

–

average pay

26.0

39.4

–

–

–

–

average receive

25.1

40.3

–

–

–

–

(b) Buy variable price/sell fixed price contracts:

contract/notional amount ($ millions)

3,193

158

–

–

–

11

3,362

95

Volume (million barrels “m bbl”)

121

4

–

–

–

*

average pay

25.5

39.6

–

–

–

41.3

average receive

26.3

37.5

–

–

–

38.4

(c) Buy variable/sell variable price contracts

contract/notional amount ($ millions)

810

15

–

–

–

–

825

1

Volume (million barrels “m bbl”)

16

*

–

–

–

–

average pay

49.3

48.5

–

–

–

–

average receive

49.4

48.6

–

–

–

–

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Table of Contents

2004 continued																																			$ million
																											2010 and				Total contract/				Estimated
							2005				2006				2007				2008				2009				after				notional amount				fair value
Oil products basis swaps
(a) Buy variable/sell variable price contracts
	contract/notional amount ($ millions)							1,020				30				–				–				–				–				1,050				(8	)
	Volume (million barrels “m bbl”)							170				4				–				–				–				–
	average pay							5.8				8.5				–				–				–				–
	average receive							5.7				8.6				–				–				–				–
(b) Sell variable/buy variable price contracts
	contract/notional amount ($ millions)							137				–				–				–				–				–				137				23
	Volume (million barrels “m bbl”)							18				–				–				–				–				–
	average pay							7.5				–				–				–				–				–
	average receive							8.7				–				–				–				–				–
Electricity swaps
(a) Buy fixed price/sell variable price contracts:
	contract/notional amount ($ millions)							3,268				1,296				341				25				2				–				4,932				(2	)
	Volume (thousand megawatt hours)							57				24				7				0				0				–
	average pay							57.0				55.0				52.4				64.3				60.5				–
	average receive							55.8				56.6				56.4				65.1				56.5				–
(b) Buy variable price/sell fixed price contracts:
	contract/notional amount ($ millions)							3,250				1,245				391				54				6				–				4,946				(14	)
	Volume (thousand megawatt hours)							57				23				7				1				*				–
	average pay							56.1				56.4				57.0				60.6				57.3				–
	average receive							57.4				55.3				53.3				59.6				61.3				–
Natural gas swaps
(a) Buy fixed price/sell variable price contracts:
	contract/notional amount ($ millions)							5,947				1,350				308				312				70				–				7,987				188
	Volume (thousand million cubic feet “bcf”)							923				223				53				55				13				–
	average pay ($/thousand cf)							6.4				6.1				5.8				5.2				4.6				–
	average receive ($/thousand cf)							6.4				6.5				6.0				5.5				5.1				–
(b) Buy variable price/sell fixed price contracts:
	contract/notional amount ($ millions)							6,267				1,005				426				409				206				57				8,370				123
	Volume (thousand million cubic feet “bcf”)							954				162				70				69				37				11
	average pay ($/thousand cf)							6.4				6.6				6.0				5.7				5.5				5.2
	average receive ($/thousand cf)							6.6				6.2				6.1				5.9				5.6				5.1
(c) Buy variable price/sell variable price contracts:
	contract/notional amount ($ millions)							404				8				–				–				–				–				412				7
	Volume (thousand million cubic feet “bcf”)							64				1				–				–				–				–
	average pay ($/thousand cf)							6.4				6.6				–				–				–				–
	average receive ($/thousand cf)							6.5				6.6				–				–				–				–
Natural gas basis swaps
(a) Buy variable price/sell variable price
	contract/notional amount ($ millions)							455				184				60				35				22				10				766				(134	)
	Volume (thousand million cubic feet “bcf”)							903				365				116				72				43				24
	average pay ($/thousand cf)							0.5				0.6				0.7				0.6				0.6				0.5
	average receive ($/thousand cf)							0.4				0.4				0.5				0.5				0.5				0.3
(b) Sell variable price/buy variable price
	contract/notional amount ($ millions)							388				135				20				18				4				3				568				139
	Volume (thousand million cubic feet “bcf”)							827				281				56				56				18				15
	average pay ($/thousand cf)							0.3				0.3				0.3				0.3				0.0				0.0
	average receive ($/thousand cf)							0.4				0.5				0.5				0.4				0.3				0.2
																																43,433				325

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Table of Contents

2003

$ million

Total contract/

Estimated

2004

2005

2006

2007

2008

notional amount

fair value

Crude oil swaps

(a) Variable price to variable price contracts:

contract/notional amount ($ million)

2,671

13

–

–

–

2,684

(3

)

Volume (million barrels “m bbl”)

84

*

–

–

–

average pay ($/bbl)

31.9

26.3

–

–

–

average receive ($/bbl)

31.9

26.3

–

–

–

(b) Buy fixed price/sell variable price contracts:

contract/notional amount ($ million)

1,452

272

63

–

–

1,787

230

Volume (m bbl)

58

11

3

–

–

average pay ($/bbl)

25.0

24.3

24.2

–

–

average receive ($/bbl)

28.3

28.0

26.1

–

–

(c) Buy variable price/sell fixed price contracts:

contract/notional amount ($ million)

1,364

241

13

–

–

1,618

(160

)

Volume (m bbl)

58

10

1

–

–

average pay ($/bbl)

28.9

24.5

26.7

–

–

average receive ($/bbl)

27.1

23.2

23.8

–

–

Crude oil basis swaps

(a) Buy variable price/sell variable price contracts:

contract/notional amount ($ million)

2

–

–

–

–

2

–

Volume (m bbl)

5

–

–

–

–

average pay ($/bbl)

1.0

–

–

–

–

average receive ($/bbl)

0.3

–

–

–

–

(b) Sell variable price/buy variable price contracts:

contract/notional amount ($ million)

3

–

–

–

–

3

(1

)

Volume (m bbl)

2

–

–

–

–

average pay ($/bbl)

0.5

–

–

–

–

average receive ($/bbl)

1.5

–

–

–

–

Crude oil freight swaps

(a) Buy fixed price/sell variable price contracts:

contract/notional amount ($ million)

10

–

–

–

–

10

1

Volume (m bbl)

9

–

–

–

–

average pay ($/bbl)

1.2

–

–

–

–

average receive ($/bbl)

1.4

–

–

–

–

(b) Buy variable price/sell fixed price contracts:

contract/notional amount ($ million)

53

–

–

–

–

53

(9

)

Volume (m bbl)

79

–

–

–

–

average pay ($/bbl)

0.8

–

–

–

–

average receive ($/bbl)

0.7

–

–

–

–

Oil products swaps

(a) Buy fixed price/sell variable price contracts:

contract/notional amount ($ million)

853

19

–

–

–

872

42

Volume (m bbl)

34

1

–

–

–

average pay ($/bbl)

25.4

19.9

–

–

–

average receive ($/bbl)

26.4

22.2

–

–

–

(b) Buy variable price/sell fixed price contracts:

contract/notional amount ($ million)

934

4

11

–

–

949

(46

)

Volume (m bbl)

40

*

1

–

–

average pay ($/bbl)

24.3

23.8

24.3

–

–

average receive ($/bbl)

23.2

22.6

21.7

–

–

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Table of Contents

2003 continued																															$ million
																							2009				Total contract/				Estimated
			2004				2005				2006				2007				2008				and after				notional amount				fair value
Oil products basis swaps
(a) Buy variable price/sell variable price contracts:
	contract/notional amount ($ million)			268				–				–				–				–				–				268				(16	)
	Volume (m bbl)			94				–				–				–				–				–
	average pay ($/bbl)			1.8				–				–				–				–				–
	average receive ($/bbl)			2.9				–				–				–				–				–
(b) Sell variable price/buy variable price contracts:
	contract/notional amount ($ million)			95				–				–				–				–				–				95				13
	Volume (m bbl)			20				–				–				–				–				–
	average pay ($/bbl)			0.2				–				–				–				–				–
	average receive ($/bbl)			5.4				–				–				–				–				–
Electricity swaps
(a) Buy fixed price/sell variable price contracts:
	contract/notional amount ($ million)			832				177				147				88				12				–				1,256				35
	Volume (thousand megawatt hours “MMwh”)			17				3				3				2				**				–
	average pay ($/Mwh)			50.5				51.3				50.4				51.9				66.3				–
	average receive ($/Mwh)			52.9				51.4				49.0				51.0				61.3				–
(b) Buy variable price/sell fixed price contracts:
	contract/notional amount ($ million)			803				188				120				124				33				–				1,268				1
	Volume (MMwh)			16				3				2				2				1				–
	average pay ($/Mwh)			54.1				54.9				53.8				53.5				59.5				–
	average receive ($/Mwh)			54.9				53.1				52.3				52.2				56.4				–
Natural gas swaps
(a) Buy fixed price/sell variable price contracts:
	contract/notional amount ($ million)			5,212				485				135				47				–				–				5,879				750
	Volume (thousand million cubic feet “bcf”)			1,005				109				32				9				–				–
	average pay ($/thousand cf)			5.2				4.5				4.1				5.0				–				–
	average receive($/thousand cf)			5.8				5.2				4.8				5.0				–				–
(b) Buy variable price/sell fixed price contracts:
	contract/notional amount ($ million)			5,362				391				27				4				4				7				5,795				(711	)
	Volume (bcf)			1,025				83				445				1				1				2
	average pay ($/thousand cf)			5.9				5.2				4.7				4.7				4.7				4.6
	average receive ($/thousand cf)			5.2				4.7				4.8				4.2				4.2				4.2
Natural gas basis swaps
(a) Buy variable price/sell variable price contracts:
	contract/notional amount ($ million)			325				97				50				32				14				19				537				(180	)
	Volume (bcf)			829				210				109				62				33				46
	average pay ($/thousand cf)			1.81				0.58				0.60				1.33				0.49				0.43
	average receive ($/thousand cf)			2.57				0.46				0.46				1.05				0.42				0.42
(b) Sell variable price/buy variable price contracts:
	contract/notional amount ($ million)			255				59				22				9				5				6				356				196
	Volume (m bcf)			743				145				54				30				20				23
	average pay ($/thousand cf)			0.15				0.20				0.16				0.11				0.11				0.09
	average receive ($/thousand cf)			0.34				0.41				0.40				0.31				0.23				0.25
Total																												23,432				142

*	less than one million barrels
**	less than one thousand megawatt hours

Group companies also held chemical product and natural gas liquid swaps at December 21, 2004 with a contract/notional amount of $102 million (2003: $10 million) and an estimated fair value of $(1) million (2003: $(1) million) and expected maturity in 2005 – 2007 (2004).

Commodity swaps held for purposes other than trading

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Table of Contents

Commodity options held for trading purposes

2004																															$ million
											2005				2006				2007				2008				Total contract/				Estimated
																							and after				notional amount				fair value
Crude oil buy calls
	contract/notional amount ($ million)											870				143				11				–				1,024				(37	)
	volume (m bbl)											19				4				*				–
	average strike price ($/bbl)											44.7				33.2				39.7				–
Crude oil sell calls
	contract/notional amount ($ million)											873				145				–				–				1,018				46
	volume (m bbl)											20				4				–				–
	average strike price ($/bbl)											42.9				32.8				–				–
Crude oil buy put
	contract/notional amount ($ million)											917				97				3				–				1,017				10
	volume (m bbl)											27				3				*				–
	average strike price ($/bbl)											34.5				32.0				29.7				–
Crude oil sell put
	contract/notional amount ($ million)											972				103				20				–				1,095				(27	)
	volume (m bbl)											28				3				1				–
	average strike price ($/bbl)											34.2				33.4				31.2				–
Oil products buy put option
	contract/notional amount ($ million)											177				132				–				–				309				15
	volume (m bbl)											158				128				–				–
	average strike price ($/bbl)											1.1				1.0				–				–
Oil products sell put option
	contract/notional amount ($ million)											193				131				–				–				324				(14	)
	volume (m bbl)											158				128				–				–
	average strike price ($/bbl)											1.2				1.0				–				–
Oil products buy call option
	contract/notional amount ($ million)											176				51				–				–				227				–
	volume (m bbl)											50				42				–				–
	average strike price ($/bbl)											3.5				1.2				–				–
Oil products sell call option
	contract/notional amount ($ million)											128				51				–				–				179				(1	)
	volume (m bbl)											49				42				–				–
	average strike price ($/bbl)											2.6				1.2				–				–
Natural gas buy call
	contract/notional amount ($ million)											10,740				1,354				60				–				12,154				583
	volume (bcf)											1,493				180				9				–
	average strike price ($/thousand cf)											7.2				7.5				6.6				–
Natural gas sell call
	contract/notional amount ($ million)											9,309				1,060				22				6				10,397				(455	)
	volume (bcf)											1,312				158				4				*
	average strike price ($/thousand cf)											7.1				6.7				6.3				6.3
Natural gas buy put
	contract/notional amount ($ million)											8,332				942				25				14				9,313				674
	volume (bcf)											1,757				201				4				3
	average strike price ($/thousand cf)											4.7				4.7				5.5				4.8
Natural gas sell put
	contract/notional amount ($ million)											9,547				986				44				21				10,598				(818	)
	volume (bcf)											1,996				209				8				5
	average strike price ($/thousand cf)											4.8				4.7				5.8				5.7
Electricity buy call option
	contract/notional amount ($ million)											290				–				–				–				290				3
	volume (million MWh)											6				–				–				–
	average strike price ($/MWh)											48.4				–				–				–
Electricity sell call option
	contract/notional amount ($ million)											379				–				–				–				379				(7	)
	volume (million MWh)											8				–				–				–
	average strike price ($/MWh)											48.6				–				–				–
Electricity buy put option
	contract/notional amount ($ million)											486				–				–				–				486				8
	volume (million MWh)											12				–				–				–
	average strike price ($/MWh)											41.3				–				–				–
Electricity sell put option
	contract/notional amount ($ million)											204				–				–				–				204				1
	volume (million MWh)											5				–				–				–
	average strike price ($/MWh)											38.2				–				–				–
Total																												49,014				(19	)

* less than one million barrels

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Table of Contents

2003																															$ million
											2004				2005				2006				2007				Total contract/				Estimated
																											notional amount				fair value
Crude oil buy calls
	contract/notional amount ($ million)											397				7				–				–				404				31
	volume (m bbl)											14				*				–				–
	average strike price ($/bbl)											29.6				29.8
Crude oil sell calls
	contract/notional amount ($ million)											389				68				–				–				457				(58	)
	volume (m bbl)											14				2				–				–
	average strike price ($/bbl)											28.3				25.6				–				–
Crude oil buy put
	contract/notional amount ($ million)											570				28				–				–				598				9
	volume (m bbl)											24				1				–				–
	average strike price ($/bbl)											23.8				20.5				–				–
Crude oil sell put
	contract/notional amount ($ million)											455				7				–				–				462				(9	)
	volume (m bbl)											20				*				–				–
	average strike price ($/bbl)											23.4				26.6				–				–
Oil products buy put option
	contract/notional amount ($ million)											261				–				–				–				261				(2	)
	volume (m bbl)											11				–				–				–
	average strike price ($/bbl)											23.1				–				–				–
Oil products sell put option
	contract/notional amount ($ million)											41				–				–				–				41				–
	volume (m bbl)											2				–				–				–
	average strike price ($/bbl)											27.7				–				–				–
Oil products buy call option
	contract/notional amount ($ million)											8				–				–				–				8				–
	volume (m bbl)											*				–				–				–
	average strike price ($/bbl)											42.0				–				–				–
Oil products sell call option
	contract/notional amount ($ million)											274				–				–				–				274				(2	)
	volume (m bbl)											10				–				–				–
	average strike price ($/bbl)											27.2				–				–				–
Natural gas buy call
	contract/notional amount ($ million)											8,112				414				30				–				8,556				692
	volume (bcf)											1,242				74				6				–
	average strike price ($/thousand cf)											6.5				5.6				4.9				–
Natural gas sell call
	contract/notional amount ($ million)											6,788				232				39				1				7,060				(528	)
	volume (bcf)											1,024				36				7				*
	average strike price ($/thousand cf)											6.6				6.4				6.0				4.1
Natural gas buy put
	contract/notional amount ($ million)											6,316				168				63				–				6,547				174
	volume (bcf)											1,479				41				14				–
	average strike price ($/thousand cf)											4.3				4.1				4.5				–
Natural gas sell put
	contract/notional amount ($ million)											7,292				387				47				1				7,727				(252	)
	volume (bcf)											1,648				96				12				*
	average strike price ($ /thousand cf)											4.4				4.1				4.1				5.7
Electricity buy call option
	contract/notional amount ($ million)											409				–				–				–				409				(28	)
	volume (million MWh)											10				–				–				–
	average strike price ($/MWh)											41.6				–				–				–
Electricity sell call option
	contract/notional amount ($ million)											350				–				–				–				350				30
	volume (MWh)											9				–				–				–
	average strike price ($/MWh)											39.3				–				–				–
Electricity buy put option
	contract/notional amount ($ million)											176				–				–				–				176				(11	)
	volume (MWh)											6				–				–				–
	average strike price ($/MWh)											31.1				–				–				–
Electricity sell put option
	contract/notional amount ($ million)											183				–				–				–				183				16
	volume (MWh)											6				–				–				–
	average strike price ($/MWh)											28.8				–				–				–
Total																												33,513				62

*	less than one million barrels

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Table of Contents

Group companies also held chemical options at December 31, 2003 with a contract/notional amount of $1 million and estimated fair value less than $1 million and expected maturity in 2004.

Commodity options held for purposes other than trading

Commodity futures held for trading purposes

2004																			$ million
															Total contract/				Estimated
			2005				2006				2007				notional amount				fair value
IPE Brent futures
(a) Short contracts:
	contract/notional amount ($ million)			341				26				–				367				66
	volume (m bbl)			8				1				–
	weighted average price ($/bbl)			42.2				34.3				–
(b) Long contracts:
	contract/notional amount ($ million)			561				79				–				640				86
	volume (m bbl)			14				2				–
	weighted average price ($/bbl)			40.9				39.2				–
IPE Gasoil futures
(a) Short contracts:
	contract/notional amount ($ million)			274				–				–				274				17
	volume (m bbl)			6				–				–
	weighted average price ($/bbl)			34.81				–				–
(b) Long contracts:
	contract/notional amount ($ million)			196				2				–				198				(5	)
	volume (m bbl)			4				*				–
	weighted average price ($/bbl)			39.42				32.7				–
IPE Natural gas futures
(a) Short contracts:
	contract/notional amount ($ million)			6				–				–				6				3
	volume (bcf)			1				–				–
	weighted average price ($/thousands cf)			6.0				–				–
(b) Long contracts:
	contract/notional amount ($ million)			4				–				–				4				4
	volume (bcf)			1				–				–
	weighted average price ($/bbl)			5.7				–				–
Nymex crude oil futures
(a) Short contracts:
	contract/notional amount ($ million)			130				132				15				277				(18	)
	volume (m bbl)			3				3				*
	weighted average price ($/bbl)			43.9				39.4				36.4
(b) Long contracts:
	contract/notional amount ($ million)			427				21				10				458				(15	)
	volume (m bbl)			10				1				*
	weighted average price ($/bbl)			44.1				40.5				37.0
Nymex oil product futures
(a) Short contracts:
	contract/notional amount ($ million)			533				–				–				533				(28	)
	volume (m bbl)			11				–				–
	weighted average price ($/bbl)			50.9				–				–
(b) Long contracts:
	contract/notional amount ($ million)			308				4				–				312				–
	volume (m bbl)			6				*				–
	weighted average price ($/bbl)			51.9				47.88				–
Nymex natural gas futures
(a) Short contracts:
	contract/notional amount ($ million)			1,824				121				1				1,946				95
	volume (bcf)			278				19				**
	weighted average price ($/thousand cf)			5.9				6.1				5.7
(b) Long contracts:
	contract/notional amount ($ million)			1,678				77				2				1,757				(70	)
	volume (bcf)			256				13				**
	weighted average price ($/thousand cf)			5.7				5.2				5.8

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2004 continued

$ million

Total contract/

Estimated

2005

2006

2007

notional amount

fair value

Imarex freight futures

(a) Short contracts:

contract/notional amount ($ million)

14

–

–

14

2

volume (million tonnes)

3

–

–

weighted average price ($/tonne)

11.8

–

–

(b) Long contracts:

contract/notional amount ($ million)

7

–

–

7

–

volume (million tonnes)

1

–

–

weighted average price ($/tonne)

12.9

–

–

Nord Pool electricity futures

(a) Short contracts:

contract/notional amount ($ million)

–

–

–

–

–

volume (million MWh)

–

–

–

weighted average price ($/MWh)

–

–

–

(b) Long contracts:

contract/notional amount ($ million)

10

37

–

47

(2

)

volume (million MWh)

***

1

–

weighted average price ($/MWh)

34.7

378

–

Total

6,840

135

*	less than one million barrels
**	less than one billion cubic feet
***	less than one million megawatt hours

2003																			$ million
			2004				2005				2006				Total contract/				Estimated
															notional amount				fair value
IPE Brent futures
(a) Short contracts:
	contract/notional amount ($ million)			218				15				–				233				–
	volume (m bbl)			8				*				–
	weighted average price ($/bbl)			28.4				26.7				–
(b) Long contracts:
	contract/notional amount ($ million)			510				33				–				543				32
	volume (m bbl)			17				1				–
	weighted average price ($/bbl)			29.9				26.8				–
IPE Gasoil futures
(a) Short contracts:
	contract/notional amount ($ million)			89				21				–				110				(4	)
	volume (m bbl)			2				1				–
	weighted average price ($/bbl)			36.7				30.3				–
(b) Long contracts:
	contract/notional amount ($ million)			92				20				–				112				2
	volume (m bbl)			3				*				–
	weighted average price ($/bbl)			33.9				30.0				–
IPE Natural gas futures
(a) Short contracts:
	contract/notional amount ($ million)			11				–				–				11				(1	)
	volume (bcf)			2				–				–
	weighted average price ($/thousand bcf)			5.8				–				–
(b) Long contracts:
	contract/notional amount ($ million)			75				–				–				75				(3	)
	volume (bcf)			12				–				–
	weighted average price ($/thousand bcf			6.3				–				–
Nymex crude oil futures
(a) Short contracts:
	contract/notional amount ($ million)			82				4				–				86				1
	volume (mbbl)			3				*				–
	weighted average price ($/bbl)			31.6				24.9				–
(b) Long contracts:
	contract/notional amount ($ million)			456				22				–				478				43
	volume (m bbl)			16				1				–
	weighted average price ($/bbl)			28.9				25.2				–

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Table of Contents

2003 continued																			$ million
			2004				2005				2006				Total contract/				Estimated
															notional amount				fair value
Nymex oil product futures
(a) Short contracts:
	contract/notional amount ($ million)			350				–				–				350				(6	)
	volume (m bbl)			9				–				–
	weighted average price ($/bbl)			38.4				–				–
(b) Long contracts:
	contract/notional amount ($ million)			71				1				–				72				–
	volume (m bbl)			2				*				–
	weighted average price ($/bbl)			34.8				31.6				–
Nymex natural gas futures
(a) Short contracts:
	contract/notional amount ($ million)			1,983				22				–				2,005				(253	)
	volume (bcf)			384				4				–
	weighted average price ($/thousand cf)			5.2				5.2				–
(b) Long contracts:
	contract/notional amount ($ million)			1,776				81				2				1,859				242
	volume (bcf)			344				18				**
	weighted average price ($/thousand cf)			5.2				4.6				4.4
Nord Pool electricity futures
(a) Short contracts:
	contract/notional amount ($ million)			52				–				–				52				–
	volume (million MWh)			2				–				–
	weighted average price ($/MWh)			31.8				–				–
(b) Long contracts:
	contract/notional amount ($ million)			1,420				222				–				1,642				(5	)
	volume (million MWh)			43				7				–
	weighted average price ($/MWh))			33.0				32.9				–
Total																7,628				48

*	less than one million barrels.
**	less than one billion cubic feet.

Futures contracts shown above represent unmatched positions. The total contract/notional amount of short contracts represents an aggregation of Group companies’ positions where, at December 31, 2004 and 2003 respectively, sales contracts exceed the purchase contracts with the same maturity date. The total contract/notional amount of long contracts represents an aggregation of Group companies’ positions where, at December 31, 2004 and 2003 respectively, purchase contracts exceed the sales contracts with the same maturity date.

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Table of Contents

Exhibits

Exhibit index
Exhibit				Page
No.		Description		No.
1.1		Articles of Association of Royal Dutch (incorporated by reference to Exhibit 1.1 to the Annual Report on Form 20-F (Commission Files 1-3788 and 1-4039) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on March 31, 2003)
1.2		Memorandum and Articles of Association of Shell Transport (incorporated by reference to the Report of Foreign Issuer on Form 6-K (Commission File No. 1-4039) of Shell Transport furnished to the Securities and Exchange Commission on June 21, 2002)
4.1		Adjustment Agreement between Royal Dutch and Shell Transport dated July 5, 1907, and certain amendments thereto (incorporated by reference to Exhibit 4.1 to the Annual Report on Form 20-F (Commission File Nos. 1-3788 and 1-4039) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on March 31, 2003)
4.2		Shell Petroleum N.V. Stock Option Plan, as amended (incorporated by reference to the Post-Effective Amendment No. 1 to Registration Statement on Form S-8 (Registration No. 333-7590) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on June 28, 2001)
4.3		Shell Petroleum Company Limited Stock Option Plan (1967), as amended (incorporated by reference to the Post-Effective Amendment No. 1 to Registration Statement on Form S-8 (Registration No. 333-7590) of Royal Dutch and Shell Transport filed with the Securities and Exchange Commission on June 28, 2001)
8		Significant Group companies as at December 31, 2004			E2
23.1		Consent of KPMG Accountants N.V., The Hague			E3
23.2		Consent of PricewaterhouseCoopers LLP, London			E4
23.3		Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E5
23.4		Consent of KPMG Accountants N.V., The Hague			E6
23.5		Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E7
23.6		Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E8
23.7		Consent of KPMG Accountants N.V., The Hague and PricewaterhouseCoopers LLP, London			E9
99.1		Section 302 Certification of Royal Dutch			E10
99.2		Section 302 Certification of Royal Dutch			E11
99.3		Section 302 Certification of Shell Transport			E12
99.4		Section 302 Certification of Shell Transport			E13
99.5		Section 906 Certification of Royal Dutch			E14
99.6		Section 906 Certification of Shell Transport			E15

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Table of Contents

Signatures

As to the undersigned registrant, this Report consists solely of the information referred to on the cross-reference sheet headed Royal Dutch and does not include the information as to Shell Transport on pages 37 and 38 under the heading “Selected Financial Data”, on page 41, on pages 94 through 105 and pages S2 through S28.

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorised.

N.V. Koninklijke Nederlandsche Petroleum Maatschappij

 

/s/ Jeroen van der Veer

 

March 29, 2005

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Table of Contents

As to the undersigned registrant, this Report consists solely of the information referred to on the cross-reference sheet headed Shell Transport and does not include the information as to Royal Dutch on page 37 under the heading “Selected Financial Data”, on pages 39 to 40, on pages 82 through 93 and pages R2 through R24.

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorised.

The “ Shell ” Transport and Trading Company, Public Limited Company

 

/s/ Malcolm Brinded

 

March 29, 2005