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, 2003: 2,083,500,000 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, 2003: 9,667,500,000 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. YesüNo
Indicate by check mark which financial statement item the registrants have elected to follow. Item 17üItem 18
Copies of notices and communications from the Securities and Exchange Commission should be sent to:
CRAVATH, SWAINE & MOORE LLP
Explanatory Note
Reserves Restatement
Following the January 9, 2004 announcement of the reserves recategorisation described above, 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 (as described in further detail under “Controls and Procedures” on pages 67 to 70), Royal Dutch and Shell Transport have determined that the principal causes that permitted the initial booking and maintenance of the volumes impacted by the 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. |
| • | 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. |
These issues are described in more detail under “Controls and Procedures” and “Supplementary information – Oil and Gas (unaudited)”.
Financial Restatement
Reserves related adjustments
The following table sets forth the adjustments made to reported results to eliminate the effect of the inappropriate overstatement of reserves and to reflect impairments and write-offs of well costs related to the Reserves Restatement:
| Net income reserves restatement effects | $ million | |||||||||||
| pre 2001 | 2001 | 2002 | ||||||||||
| Depreciation, depletion and amortisation | (132 | ) | (84 | ) | (166 | ) | ||||||
| Exploration costs | (77 | ) | (7 | ) | – | |||||||
| Share of operating profit of associated companies | (37 | ) | 18 | – | ||||||||
Income before taxation | (246 | ) | (73 | ) | (166 | ) | ||||||
Total tax | 114 | 27 | 65 | |||||||||
| Income after taxation | 132 | (46 | ) | (101 | ) | |||||||
| Minority interest | 6 | 4 | (7 | ) | ||||||||
| Net income | (126 | ) | (42 | ) | (108 | ) | ||||||
Treatment of exploration costs
Treatment of certain gas contracts
Parent Company earnings per share
Change in accounting policy for inventories
Presentation of Netherlands GAAP Financial Statements
General
Cross reference sheet for Annual Report on Form 20-F
| Headings* in this Annual Report which relate to: | ||||
| The “Shell” Transport and | ||||
| N.V. Koninklijke Nederlandsche | Trading Company, Public | |||
| Petroleum Maatschappij | Limited Company | |||
| Item number and captions | (Royal Dutch Petroleum 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 – Group Group –Business and Property – risk factors | Selected Financial Data – Shell Transport Discussion and Analysis of Financial Condition and Results of Operations – Group Group –Business and Property – risk factor | ||
4 Information on the Company | Introduction – Parent Companies, Group Discussion and Analysis of Financial Condition and Results of Operations – Group Group –Business and Property Supplementary information – Oil and Gas Introduction (unaudited) | Introduction – Parent Companies, Group Discussion and Analysis of Financial Condition and Results of Operations – Group Group –Business and Property Supplementary information – Oil and Gas Introduction (unaudited) | ||
5 Operating and Financial Review and Prospects | Discussion and Analysis of Financial Condition and Results of Operations – Royal Dutch, Group Group –Business and Property – business environment, description of activities, research | Discussion and Analysis of Financial Condition and Results of Operations – Shell Transport, Group Group –Business and Property – business environment, description of activities, research | ||
6 Directors, Senior Management and Employees | Royal Dutch – control of registrant, management, share ownership Note 14 to Royal DutchFinancial Statements Group –Business and Property – personnel | Shell Transport – control of registrant, management, share ownership Note 11 to Shell TransportFinancial Statements Group –Business and Property – personnel | ||
7 Major Shareholders and Related Party Transactions | Royal Dutch – control of registrant | Shell Transport – control of registrant | ||
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, exchange controls and other limitations affecting security holders, taxation Introduction – documents on display | Shell Transport – Memorandum and Articles of Association, 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 | Controls and Procedures | Controls and Procedures | ||
16A Audit Committee Financial Expert | Management – Royal Dutch | Management – Shell Transport | ||
16B Code of Ethics | Management – Royal Dutch | Management – Shell Transport | ||
16C Principal Accountants Fees and Services | Principal Accountants Fees and Services | Principal Accountants Fees and Services | ||
17 Financial Statements | Financial Statements – Royal Dutch, Group | Financial Statements – Shell Transport, Group | ||
18 Financial Statements | Not applicable | Not applicable | ||
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. |
N.V. Koninklijke Nederlandsche Petroleum Maatschappij
(Royal Dutch Petroleum Company),
The “Shell” Transport and Trading Company, Public Limited Company
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Introduction
Structure of the Royal Dutch/Shell Group
Parent Companies
Royal Dutch/Shell Group of Companies
Group Holding Companies
Service Companies
Operating Companies
A The Parent Companies
The “Shell” Transport and Trading Company, Public Limited Company (hereinafter referred to as “Shell Transport”) was incorporated on October 18, 1897, under the laws of England.
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.
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 “Group 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 Committee of Managing Directors, which considers and develops objectives and long-term plans.
Service Companies
Operating Companies
Exploration and 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, develops 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. Provides technical consultancy services.
Chemicals: Our Chemicals businesses produce and sell petrochemicals including polyolefins to industrial customers globally.
Other industry segments include Renewables, Shell Consumer and Shell 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 on 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 changes implemented in the 2002 Form 20-F Amendment No. 1 due to the proximity of both filings.
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 and renewable energy as well as in other businesses. 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).
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.
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, 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
E SEC Review of 2002 Form 20-F
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, accounted for over 90% of net proceeds in 2003. In fact, Group and associated companies constitute one of the largest oil and gas enterprises in the world. 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; in 2003 chemicals accounted for around 9% of the net proceeds of Group companies. The Group’s interests in power generation and renewable energy are considerably smaller. Nevertheless, the Group’s Renewables business is now one of the largest global solar enterprises following the acquisition of the Siemens solar business early in 2002. Renewables also has plans to become a leading player in the wind energy sector. The Group’s various activities are conducted – to one extent or another – in more than 145 countries and territories.
The breakdown of net proceeds of Group companies by industry segment and by geographical region for the years 2001 to 2003 is set out in the following tables:
| Net Proceeds by Industry Segment | ||||||||||||
| (including inter-segment sales) | $ million | |||||||||||
| 2002b | 2001b | |||||||||||
| 2003 | As | As | ||||||||||
| restateda | restateda | |||||||||||
Exploration and Production | ||||||||||||
| Third parties | 12,481 | 11,901 | 12,057 | |||||||||
| Inter-segment | 20,244 | 14,680 | 13,790 | |||||||||
| 32,725 | 26,581 | 25,847 | ||||||||||
Gas & Powera | ||||||||||||
| Third parties | 7,398 | 4,278 | 5,951 | |||||||||
| Inter-segment | 850 | 620 | 705 | |||||||||
| 8,248 | 4,898 | 6,656 | ||||||||||
Oil Products | ||||||||||||
| Third parties | 162,161 | 135,544 | 93,517 | |||||||||
| Inter-segment | 3,416 | 3,080 | 2,108 | |||||||||
| 165,577 | 138,624 | 95,625 | ||||||||||
Chemicals | ||||||||||||
| Third parties | 18,843 | 14,125 | 13,260 | |||||||||
| Inter-segment | 1,974 | 1,082 | 990 | |||||||||
| 20,817 | 15,207 | 14,250 | ||||||||||
Corporate and other | ||||||||||||
| Third parties | 845 | 753 | 576 | |||||||||
| Inter-segment | 29 | 17 | 2 | |||||||||
| 874 | 770 | 578 | ||||||||||
| 228,241 | 186,080 | 142,956 | ||||||||||
| Net Proceeds by Geographical Area | ||||||||||||
| (excluding inter-segment sales) | $ million | |||||||||||
| 2002b | 2001b | |||||||||||
| 2003 | As | As | ||||||||||
| restateda | restateda | |||||||||||
| Europe | 71,864 | 63,761 | 62,259 | |||||||||
| Other Eastern Hemisphere | 38,494 | 33,322 | 31,866 | |||||||||
| USA | 75,669 | 55,411 | 15,924 | |||||||||
| Other Western Hemisphere | 15,701 | 14,107 | 15,312 | |||||||||
| 201,728 | 166,601 | 125,361 | ||||||||||
| a | The Group Financial Statements have been restated, see Note 2 to the Group Financial Statements. | |
| b | Certain prior year amounts have been reclassified, resulting in a reduction in sales proceeds and a corresponding reduction in cost of sales following the implementation of US accounting guidance ETIF Issue No. 02–03, see Note 3 to the Group Financial Statements. |
B Business environment
First quarter saw Brent prices rising in excess of $34 a barrel on supply concerns over the impending war in Iraq as oil stocks in the Atlantic Basin were drained to new historic lows by the Venezuelan supply outage and strong winter demand. Prices fell towards the end of the first quarter on general expectation that Iraqi export would resume quickly after the war. Further downward pressure came as the OPEC relief volumes to cover the Venezuelan deficit reached the Atlantic Basin at the same time output was recovering rapidly in Venezuela, pushing Brent prices towards the $23 a barrel level by the end of April. Prices recovered in the run up to the US driving season as supply concerns grew with the delay of sustainable export from Iraq and the terrorist bombings in Saudi Arabia. Further support came when OPEC reduced output sharply from June in response to the Venezuelan output recovery and in anticipation of rising Iraqi export. Brent prices recovered to around $30 a barrel by mid-third quarter but soon lost ground as the US driving season drew to a close. Prices rebounded again at the end of third quarter on OPEC’s decision to cut the crude oil production quota by 900 kbbl/d from November. Crude prices stood firm with Brent trading largely within the range of $28-30 a barrel in the fourth quarter on strong winter demand and a further pick up in the US and Chinese economies. Prices were tempered during the fourth quarter by poor OPEC quota compliance as member states sought to take advantage of the prevailing strong market fundamentals. In the fourth quarter, Brent crude oil prices averaged $29.45 a barrel compared with $26.80 a barrel in 2002, while WTI prices averaged $31.15 a barrel compared with $28.25 a barrel a year earlier.
Crude prices in the early part of 2004 rose sharply on strong Chinese and US oil demand growth and on heightened supply concerns arising from the deteriorating security situation in Iraq and the terrorist attacks in Saudi Arabia. Prices are envisaged to remain firm for the balance of this year on rising oil demand associated with global economic expansion and are expected to be volatile while oil stocks remain at the low end of the historical range. The eventual level for the year as a whole will depend on the sustainability of US and Chinese economic growth, the severity of the northern winter, OPEC supply discipline, the pace of Iraqi export recovery and political developments in key OPEC countries. The Group evaluates investments using multiple price conditions, including price conditions of less than $20 a barrel to assess the resilience of investments at low-price conditions.
Crude oil price conditions are determined after careful assessment of short, medium and long-term drivers under different sets of assumptions, yielding a range of prices to be used in evaluation. With regard to 2003, crude oil prices were higher than the conservative expectations of our 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.
The drivers of natural gas prices are more regionalized 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 2003, Henry Hub gas prices averaged $5.63 per million British Thermal Units (Btu) compared to $3.33 per million Btu in 2002. Prices were driven by increasing demand in the face of concerns over production declines onshore United States and Western Canada. Henry Hub prices for 2004 are expected to remain high.
Natural gas prices in Continental Europe and Asia are predominantly indexed to oil prices. In 2003, Japan industry wide LNG (cif) prices averaged $4.77 per million Btu versus $4.27 per million Btu in 2002, 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 $3.24 per million Btu in 2003 versus $2.70 per million Btu in 2002. Prices in both these markets are expected to remain high for 2004, 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 less than $20 a barrel to assess the resilience of investments at low price conditions.
In 2003, industry refining margins averaged $2.70, $1.05, $5.10 and $6.30 a barrel in Rotterdam, Singapore, US Gulf Coast (USGC) and US West Coast (USWC), respectively compared to $0.85, $0.40, $2.90 and $3.90 a barrel a year earlier. The strong margins in 2003 were driven by a number of exceptional and non-sustainable factors. Margins across the four key refining centres rose sharply in the first quarter when the global product supply/demand balance was tightened by a number of unusual factors, which pushed product prices
up at a faster pace than crude. Product availability was cut by the Venezuelan supply disruptions and large US refinery turnarounds, while demand was bolstered by a very cold winter, oil substitution for gas due to the high US natural gas prices and an extended shutdown of Japanese nuclear power generators.
Refining margins in the US and Europe reverted to a more structural level in the second quarter as the impact of many of these one-off factors abated. Singapore margins were hard hit in the second quarter by a sharp product demand downturn, especially jet kerosene for civil aviation, following the outbreak of the severe acute respiratory syndrome (SARS) virus in the region. Third quarter saw a return of exceptional margins in the USGC as a result of the August power blackout in the USA, which caused widespread disruption to refineries on the East Coast and in the Mid-continent. Refinery margins in the USWC also rose with a string of refinery and pipeline disruptions and reduced product supplies from the USGC. Singapore margins recovered marginally against an upturn in product demand as the adverse impact of SARS tailed off and with a high level of refinery maintenance activity in the region. Refining margins in the USA fell back in the fourth quarter but remained strong due to a number of unplanned refinery unit outages. Singapore margins further improved in the fourth quarter mainly as a result of reduced product exports from China due to strong domestic demand as the economy grew strongly. In the fourth quarter of 2003, industry refining margins averaged $2.30, $1.20, $4.10 and $6.65 a barrel in Rotterdam, Singapore, USGC and USWC respectively, compared to $2.00, $0.95, $3.50 and $4.00 a barrel a year earlier.
The early part of 2004 has seen strong refining margins, supported by a global tightness of gasoline supply. The ultimate level of refining margins for the year as a whole will depend on the pace of global economic recovery, the severity of the northern hemisphere winter, OPEC supply policy and potential product supply disruption following gasoline specification changes in the USA. Singapore margins are expected to remain relatively weak given the refinery capacity overhang in the region, but may improve if the Chinese economy grows at a fast pace and tightens regional supply/demand balances.
In Chemicals, trading conditions remained difficult, particularly in the USA, with high and volatile feedstock costs, excess capacity and low chemicals product prices in 2003. Profitability remained depressed as the rising cost of feedstock eroded margins. In the USA cracker margins declined slightly, whilst in Europe cracker margins in US dollars improved relative to a year ago. Overall Chemicals’ margins remained low by historical standards. The outlook for the industry remains challenging and improvement depends upon the continuation of initial signs of an economic recovery. Continued high energy prices could stall a recovery in the petrochemicals sector.
C General development of the business
The total five year proved oil and natural gas reserves replacement ratio, excluding oil sands, is 66% (70% for oil, including natural gas liquids, and 60% for gas). Oil sands, if included, would add a further 10%.
Group and associated companies’ natural gas production available for sale through the end of 2003 has increased by 9.3% 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 environmentally preferred fuel for power generation and demand for both gas and electricity is expected to grow.
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 maintained efforts to improve their health, safety and environmental performance.
In 2003, we further strengthened our Chemicals portfolio through new investments, upgrading existing facilities, and the restructuring and closure of a number of assets. The completion of project financing and the start of construction of the Nanhai petrochemicals plant in China were significant milestones for us in the key Chinese market. The new polymer polyols plant in the Netherlands marks the latest step in a long-term strategy to strengthen our position as a leading global supplier to manufacturers of polyurethane foams. In the Gulf Coast region of the USA, we completed a project to improve the quality of heavy olefin feed. The joint venture butadiene extraction plant in Texas started production in the first quarter of 2004. We invested to improve and expand cracker capacity to ensure ongoing efficiency and competitiveness. We completed the expansion of cracker capacity in Texas, USA, with production beginning in the first quarter of 2004. Also in 2003, we restructured the catalyst business and ceased operations at the Bayer-Shell Isocyanates joint venture.
In 2002, Renewables became one of the largest global solar photovoltaic (pv) players 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.
D Risk factors
Price fluctuations
Currency fluctuations
Drilling and production results
Reserve Estimates
Loss of market
Environmental risks
Physical risks
Legislative, fiscal and regulatory developments
Risks of doing business in politically sensitive or unstable countries
Global political developments
E Description of activities
| – | 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 13 to 14.
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 G44 to G55. 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 Reserves Review). The results of the Reserves Review can be summarised as follows:
| – | following the Reserves Review, 4,474 million barrels of oil equivalent (boe)(1) |
previously booked at December 31, 2002 as proved reserves have been removed from the proved category (the Reserves Restatement) (this was the subject of the announcement made on January 9, 2004, as updated on March 18, 2004 and April 19, 2004 and herein); and
| – | approximately 400 million boe of proved reserves additions that had been estimated for the year 2003, as announced on February 5, 2004, have not been made (this was also the subject of the announcement on March 18, 2004 as updated on April 19, 2004 and herein). |
Further information on the Reserves Restatement is provided in “Supplementary information – Oil and Gas (unaudited)” beginning on page G44. The Group has also restated its Financial Statements (the Financial Restatement) to reflect in part, the Reserves Restatement. For additional information on the Financial Restatement, please refer to Note 2 to the Group Financial Statements. The following tabulation of proved reserves reflects the situation after taking into account the effects of this re-categorisation, including restatement of previously reported figures.
| (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. |
| Proved developed and undeveloped reservesa | ||||||||||||
| (at December 31) | million barrels | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
Crude oil and natural gas liquids | ||||||||||||
| Group companies | 5,723 | 6,405 | 6,107 | |||||||||
| Group share of associated companies | 882 | 933 | 719 | |||||||||
| 6,605 | 7,338 | 6,826 | ||||||||||
| thousand million standard cubic feet | |||||||||||||
Natural gas | |||||||||||||
| Group companies | 41,601 | 40,290 | 42,059 | ||||||||||
| Group share of associated companies | 3,319 | 3,412 | 2,819 | ||||||||||
| 44,920 | 43,702 | 44,878 | |||||||||||
| a | Excludes oil sands. |
| Capital expenditure and exploration expense by | |||||||||||||
| geographical areaa(oil and gas exploration and production only) | $ million | ||||||||||||
| 2003 | 2002 | 2001 | |||||||||||
| Europe | 2,185 | 7,519 | 1,236 | ||||||||||
Africab | 1,861 | 1,674 | 1,235 | ||||||||||
Asia Pacificc | 579 | 537 | 1,506 | ||||||||||
Middle East, Russia, CISd | 2,155 | 785 | 473 | ||||||||||
| USA | 1,652 | 2,015 | 2,009 | ||||||||||
| Other Western Hemisphere | 686 | 600 | 426 | ||||||||||
| 9,118 | 13,130 | 6,885 | |||||||||||
| a | Capital expenditureis 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 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. |
| Average production costs of Group companies | ||||||||||||
| by geographical areaa | $/barrel of oil equivalent | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Europe | 3.23 | 2.94 | 2.35 | |||||||||
Africab | 2.80 | 2.75 | 2.54 | |||||||||
Asia Pacificc | 2.48 | 2.31 | 1.92 | |||||||||
Middle East, Russia, CISd | 3.62 | 2.64 | 2.38 | |||||||||
| USA | 3.03 | 2.61 | 2.38 | |||||||||
| Other Western Hemisphere | 5.14 | 4.52 | 3.79 | |||||||||
| Total Group | 3.23 | 2.81 | 2.41 | |||||||||
| 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. |
| Crude oil and natural gas liquids productiona | thousand barrels/day | ||||||||||||||||||||
| 2002b | 2001 | 2000 | 1999 | ||||||||||||||||||
| 2003 | As restated | As | As | As | |||||||||||||||||
| restated | restated | restated | |||||||||||||||||||
Europe | |||||||||||||||||||||
| UK | 354 | 402 | 311 | 378 | 402 | ||||||||||||||||
| Norway | 143 | 131 | 89 | 87 | 83 | ||||||||||||||||
| Denmark | 141 | 140 | 130 | 129 | 118 | ||||||||||||||||
| Italy | 19 | – | – | – | – | ||||||||||||||||
| Netherlands | 8 | 9 | 10 | 13 | 13 | ||||||||||||||||
| Germany | 5 | 5 | 6 | 6 | 6 | ||||||||||||||||
| Others | 1 | 9 | 1 | c | c | ||||||||||||||||
| 671 | 696 | 547 | 613 | 622 | |||||||||||||||||
Other Eastern Hemisphere | |||||||||||||||||||||
Africa | |||||||||||||||||||||
| Nigeria | 314 | 215 | 250 | 239 | 212 | ||||||||||||||||
| Gabon | 35 | 46 | 56 | 69 | 89 | ||||||||||||||||
| Cameroon | 16 | 17 | 19 | 21 | 22 | ||||||||||||||||
| Others | – | 2 | 3 | 3 | 3 | ||||||||||||||||
| 365 | 280 | 328 | 332 | 326 | |||||||||||||||||
Middle East | |||||||||||||||||||||
Omand | 269 | 319 | 327 | 326 | 299 | ||||||||||||||||
| Abu Dhabi | 126 | 100 | 94 | 96 | 82 | ||||||||||||||||
| Syria | 44 | 49 | 48 | 50 | 71 | ||||||||||||||||
| Russia | 30 | 33 | 23 | 9 | – | ||||||||||||||||
Egypte | 11 | 11 | 14 | 10 | 7 | ||||||||||||||||
| Others | 17 | 13 | – | – | 1 | ||||||||||||||||
| 497 | 525 | 506 | 491 | 460 | |||||||||||||||||
Asia Pacific | |||||||||||||||||||||
| Brunei | 103 | 101 | 97 | 95 | 86 | ||||||||||||||||
| Australia | 73 | 92 | 99 | 111 | 47 | ||||||||||||||||
| Malaysia | 51 | 59 | 60 | 56 | 66 | ||||||||||||||||
| China | 22 | 24 | 23 | 25 | 20 | ||||||||||||||||
| New Zealand | 19 | 29 | 30 | 9 | 10 | ||||||||||||||||
| Thailand | 14 | 15 | 16 | 18 | 18 | ||||||||||||||||
| Others | 3 | 5 | – | – | – | ||||||||||||||||
| 285 | 325 | 325 | 314 | 247 | |||||||||||||||||
Total Other Eastern Hemisphere | 1,147 | 1,130 | 1,159 | 1,137 | 1,033 | ||||||||||||||||
USA | 414 | 442 | 411 | 417 | 504 | ||||||||||||||||
Other Western Hemisphere | |||||||||||||||||||||
| Canada | 44 | 43 | 47 | 46 | 48 | ||||||||||||||||
| Venezuela | 46 | 46 | 44 | 44 | 41 | ||||||||||||||||
| Brazil | 11 | 2 | 2 | 2 | 2 | ||||||||||||||||
| Others | 1 | – | 1 | 3 | 5 | ||||||||||||||||
| 101 | 91 | 94 | 95 | 96 | |||||||||||||||||
Total | 2,333 | 2,359 | 2,211 | 2,262 | 2,255 | ||||||||||||||||
million tonnes a year | |||||||||||||||||||||
Metric equivalent | 117 | 118 | 111 | 113 | 113 | ||||||||||||||||
| 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 | ||||||||||||||||||||
| 2003 | 2002b | 2001 | 2000 | 1999 | |||||||||||||||||
| As restated | As restated | As restated | As restated | ||||||||||||||||||
Europe | |||||||||||||||||||||
| Netherlands | 1,527 | 1,527 | 1,555 | 1,431 | 1,520 | ||||||||||||||||
| UK | 1,002 | 1,148 | 1,196 | 1,118 | 967 | ||||||||||||||||
| Germany | 437 | 408 | 428 | 450 | 484 | ||||||||||||||||
| Denmark | 302 | 313 | 309 | 300 | 312 | ||||||||||||||||
| Norway | 287 | 242 | 176 | 199 | 230 | ||||||||||||||||
| Others | 32 | 29 | 20 | 17 | 16 | ||||||||||||||||
| 3,587 | 3,667 | 3,684 | 3,515 | 3,529 | |||||||||||||||||
Other Eastern Hemisphere | |||||||||||||||||||||
Africa | |||||||||||||||||||||
| Nigeria | 352 | 244 | 219 | 177 | 78 | ||||||||||||||||
| 352 | 244 | 219 | 177 | 78 | |||||||||||||||||
Middle East | |||||||||||||||||||||
| Oman | 468 | 786 | 553 | 459 | 119 | ||||||||||||||||
| Egypt | 228 | 232 | 248 | 140 | 105 | ||||||||||||||||
| Syria | 11 | 16 | 18 | 23 | 27 | ||||||||||||||||
| 707 | 1,034 | 819 | 622 | 251 | |||||||||||||||||
Asia Pacific | |||||||||||||||||||||
| Malaysia | 706 | 664 | 580 | 553 | 634 | ||||||||||||||||
| Brunei | 549 | 508 | 491 | 450 | 455 | ||||||||||||||||
| Australia | 403 | 373 | 379 | 367 | 361 | ||||||||||||||||
| New Zealand | 288 | 461 | 470 | 157 | 148 | ||||||||||||||||
| Others | 190 | 119 | 108 | 98 | 86 | ||||||||||||||||
| 2,136 | 2,125 | 2,208 | 1,625 | 1,684 | |||||||||||||||||
Total Other Eastern Hemisphere | 3,195 | 3,403 | 3,066 | 2,424 | 2,013 | ||||||||||||||||
USA | 1,527 | 1,679 | 1,598 | 1,644 | 1,774 | ||||||||||||||||
Other Western Hemisphere | |||||||||||||||||||||
| Canada | 466 | 473 | 507 | 478 | 473 | ||||||||||||||||
| Others | 74 | 64 | 47 | 35 | 46 | ||||||||||||||||
| 540 | 537 | 554 | 513 | 519 | |||||||||||||||||
Total | 8,849 | 9,286 | 8,902 | 8,096 | 7,835 | ||||||||||||||||
| Natural gas production available for salea | million standard cubic metres/day | ||||||||||||||||||||
| 2002b | 2001 | 2000 | 1999 | ||||||||||||||||||
| 2003 | As restated | As restated | As restated | As restated | |||||||||||||||||
Europe | |||||||||||||||||||||
| Netherlands | 43 | 43 | 44 | 40 | 43 | ||||||||||||||||
| UK | 28 | 32 | 34 | 32 | 27 | ||||||||||||||||
| Germany | 12 | 12 | 12 | 13 | 14 | ||||||||||||||||
| Denmark | 9 | 9 | 9 | 8 | 9 | ||||||||||||||||
| Norway | 8 | 7 | 5 | 6 | 7 | ||||||||||||||||
| Others | 2 | 1 | c | c | c | ||||||||||||||||
| 102 | 104 | 104 | 99 | 100 | |||||||||||||||||
Other Eastern Hemisphere | |||||||||||||||||||||
Africa | |||||||||||||||||||||
| Nigeria | 10 | 7 | 6 | 5 | 2 | ||||||||||||||||
| 10 | 7 | 6 | 5 | 2 | |||||||||||||||||
Middle East | |||||||||||||||||||||
| Oman | 13 | 22 | 16 | 13 | 4 | ||||||||||||||||
| Egypt | 6 | 7 | 7 | 4 | 3 | ||||||||||||||||
| Syria | c | c | 1 | 1 | 1 | ||||||||||||||||
| 19 | 29 | 24 | 18 | 8 | |||||||||||||||||
Asia Pacific | |||||||||||||||||||||
| Malaysia | 20 | 19 | 16 | 16 | 18 | ||||||||||||||||
| Brunei | 16 | 14 | 14 | 13 | 13 | ||||||||||||||||
| Australia | 11 | 11 | 11 | 10 | 10 | ||||||||||||||||
| New Zealand | 8 | 13 | 13 | 4 | 4 | ||||||||||||||||
| Others | 6 | 3 | 3 | 3 | 2 | ||||||||||||||||
| 61 | 60 | 57 | 46 | 47 | |||||||||||||||||
Total Other Eastern Hemisphere | 90 | 96 | 87 | 69 | 57 | ||||||||||||||||
USA | 43 | 48 | 45 | 46 | 50 | ||||||||||||||||
Other Western Hemisphere | |||||||||||||||||||||
| Canada | 13 | 13 | 15 | 14 | 13 | ||||||||||||||||
| Others | 2 | 2 | 1 | 1 | 1 | ||||||||||||||||
| 15 | 15 | 16 | 15 | 14 | |||||||||||||||||
Total | 250 | 263 | 252 | 229 | 221 | ||||||||||||||||
| 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. |
| Location of activitiesa,b(at December 31, 2003) | ||||||||||||||||||||||||
| 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 | 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 | |||||||||||||||||||||
| Bangladesh | l | l | l | l | l | |||||||||||||||||||
| Brunei | l | l | l | l | l | l | ||||||||||||||||||
| China | l | l | l | l | l | |||||||||||||||||||
| Malaysia | l | l | l | |||||||||||||||||||||
| New Zealand | l | l | l | l | l | l | ||||||||||||||||||
| Pakistan | l | l | l | l | ||||||||||||||||||||
| Philippines | l | l | l | |||||||||||||||||||||
| Thailand | l | l | l | l | ||||||||||||||||||||
Middle East, Russia, CIS | ||||||||||||||||||||||||
| U.A.E. (Abu Dhabi) | l | l | ||||||||||||||||||||||
| Azerbaijan | l | |||||||||||||||||||||||
| Egypt | l | l | l | l | l | l | ||||||||||||||||||
| Iran | l | l | ||||||||||||||||||||||
| Kazakhstan | l | l | l | |||||||||||||||||||||
| Oman | l | l | l | |||||||||||||||||||||
| Russia | l | l | l | l | l | l | ||||||||||||||||||
| Syria | l | l | ||||||||||||||||||||||
USA | ||||||||||||||||||||||||
| USA | l | l | l | l | l | l | ||||||||||||||||||
Other Western Hemisphere | ||||||||||||||||||||||||
| Argentina | l | l | l | |||||||||||||||||||||
| Canada | l | l | l | l | l | |||||||||||||||||||
| Brazil | l | l | l | |||||||||||||||||||||
| Trinidad | 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. |
| Oil and gas acreagea,b,c(at December 31) | thousand acres | thousand acres | ||||||||||||||||||||||||||||||
| 2002 | ||||||||||||||||||||||||||||||||
| 2003 | Undeveloped | |||||||||||||||||||||||||||||||
| Developed | Undeveloped | Developed | As restated | |||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
| Europe | 10,172 | 3,204 | 15,977 | 5,307 | 10,417 | 3,259 | 19,752 | 6,930 | ||||||||||||||||||||||||
Africad | 6,956 | 2,193 | 18,595 | 10,253 | 6,289 | 1,886 | 25,394 | 15,516 | ||||||||||||||||||||||||
Asia Pacifice | 3,793 | 1,638 | 113,978 | 33,357 | 3,964 | 1,864 | 118,471 | 40,453 | ||||||||||||||||||||||||
Middle East, Russia, CISf | 34,729 | 11,062 | 65,106 | 30,079 | 35,448 | 11,435 | 18,544 | 12,771 | ||||||||||||||||||||||||
| USA | 1,512 | 694 | 4,040 | 2,802 | 1,557 | 754 | 4,670 | 3,183 | ||||||||||||||||||||||||
| Other Western Hemisphere | 853 | 529 | 28,094 | 19,835 | 832 | 509 | 33,338 | 22,841 | ||||||||||||||||||||||||
| 58,015 | 19,320 | 245,790 | 101,633 | 58,507 | 19,707 | 220,169 | 101,694 | |||||||||||||||||||||||||
| Number of productive wellsa,b(at December 31) | ||||||||||||||||||||||||||||||||
| 2002 | ||||||||||||||||||||||||||||||||
| 2003 | Gas | |||||||||||||||||||||||||||||||
| Oil | Gas | Oil | As restated | |||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
| Europe | 1,799 | 468 | 1,432 | 485 | 2,002 | 533 | 1,454 | 458 | ||||||||||||||||||||||||
Africad | 1,380 | 414 | 43 | 14 | 1,399 | 446 | 42 | 13 | ||||||||||||||||||||||||
Asia Pacifice | 1,313 | 726 | 247 | 99 | 1,317 | 726 | 205 | 95 | ||||||||||||||||||||||||
Middle East, Russia, CISf | 3,673 | 1,145 | 203 | 129 | 3,456 | 1,085 | 179 | 115 | ||||||||||||||||||||||||
| USA | 15,891 | 7,998 | 697 | 486 | 15,686 | 8,294 | 945 | 686 | ||||||||||||||||||||||||
| Other Western Hemisphere | 116 | 111 | 322 | 265 | 112 | 110 | 314 | 259 | ||||||||||||||||||||||||
| 24,172 | 10,862 | 2,944 | 1,478 | 23,972 | 11,194 | 3,139 | 1,626 | |||||||||||||||||||||||||
| Number of net productive wells and dry holes drilleda | ||||||||||||||||||||||||||||||||||||||||
| 2002 | 2001 | 2000 | 1999 | |||||||||||||||||||||||||||||||||||||
| 2003 | As restated | As restated | As restated | As restated | ||||||||||||||||||||||||||||||||||||
| Productive | Dry | Productive | Dry | Productive | Dry | Productive | Dry | Productive | Dry | |||||||||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||||||||||||||||||
| Europe | 4 | 3 | 3 | 4 | 2 | 4 | 3 | 3 | 5 | 2 | ||||||||||||||||||||||||||||||
Africad | 2 | – | 4 | 4 | 3 | – | 4 | 1 | 4 | 1 | ||||||||||||||||||||||||||||||
Asia Pacifice | 5 | 7 | 3 | 3 | 8 | 12 | 5 | 6 | 9 | 9 | ||||||||||||||||||||||||||||||
Middle East, Russia, CISf | 6 | 4 | 5 | 4 | 7 | 3 | 7 | 4 | 3 | 5 | ||||||||||||||||||||||||||||||
| USA | 10 | – | 10 | 4 | 2 | 4 | 9 | 4 | 8 | 9 | ||||||||||||||||||||||||||||||
| Other Western Hemisphere | 2 | 5 | 2 | 2 | 3 | 3 | 1 | 2 | – | 13 | ||||||||||||||||||||||||||||||
| 29 | 19 | 27 | 21 | 25 | 26 | 29 | 20 | 29 | 39 | |||||||||||||||||||||||||||||||
Development | ||||||||||||||||||||||||||||||||||||||||
| Europe | 20 | 1 | 55 | – | 30 | 10 | 19 | – | 32 | 2 | ||||||||||||||||||||||||||||||
Africad | 23 | 1 | 41 | – | 17 | – | 12 | – | 26 | – | ||||||||||||||||||||||||||||||
Asia Pacifice | 41 | 2 | 42 | 1 | 56 | 2 | 41 | 3 | 37 | – | ||||||||||||||||||||||||||||||
Middle East, Russia, CISf | 149 | 4 | 83 | 12 | 90 | 9 | 99 | 7 | 84 | 2 | ||||||||||||||||||||||||||||||
| USA | 465 | – | 559 | 1 | 549 | 2 | 492 | 3 | 290 | – | ||||||||||||||||||||||||||||||
| Other Western Hemisphere | 8 | – | 31 | – | 25 | – | 10 | 1 | 14 | 2 | ||||||||||||||||||||||||||||||
| 706 | 8 | 811 | 14 | 767 | 23 | 673 | 14 | 483 | 6 | |||||||||||||||||||||||||||||||
| 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 Egypt. |
| e | Excludes Sakhalin. |
| f | Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin. |
| thousand acres | thousand acres | thousand acres | ||||||||||||||||||||||||||||||||||||||||||||||
| 2001 | 2000 | 1999 | ||||||||||||||||||||||||||||||||||||||||||||||
| As restated | As restated | As restated | ||||||||||||||||||||||||||||||||||||||||||||||
| Developed | Undeveloped | Developed | Undeveloped | Developed | Undeveloped | |||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||
| 9,570 | 3,031 | 12,616 | 4,581 | 9,399 | 2,973 | 13,951 | 4,920 | 10,162 | 3,218 | 16,697 | 5,790 | |||||||||||||||||||||||||||||||||||||
| 6,489 | 1,984 | 20,804 | 11,658 | 6,491 | 1,973 | 18,963 | 11,261 | 6,224 | 1,916 | 18,535 | 9,077 | |||||||||||||||||||||||||||||||||||||
| 3,762 | 1,816 | 115,294 | 41,691 | 3,766 | 1,599 | 85,219 | 37,893 | 4,114 | 1,712 | 87,569 | 47,060 | |||||||||||||||||||||||||||||||||||||
| 34,509 | 11,021 | 22,921 | 15,379 | 34,504 | 10,962 | 25,546 | 18,648 | 34,342 | 10,902 | 29,694 | 18,969 | |||||||||||||||||||||||||||||||||||||
| 1,599 | 702 | 3,931 | 2,609 | 1,967 | 934 | 4,280 | 2,743 | 3,642 | 1,245 | 6,074 | 3,499 | |||||||||||||||||||||||||||||||||||||
| 767 | 492 | 35,709 | 22,001 | 1,198 | 824 | 49,219 | 27,368 | 1,149 | 850 | 61,344 | 33,215 | |||||||||||||||||||||||||||||||||||||
| 56,696 | 19,046 | 211,275 | 97,919 | 57,325 | 19,265 | 197,178 | 102,833 | 59,633 | 19,843 | 219,913 | 117,610 | |||||||||||||||||||||||||||||||||||||
| 2001 | 2000 | 1999 | ||||||||||||||||||||||||||||||||||||||||||||||
| As restated | As restated | As restated | ||||||||||||||||||||||||||||||||||||||||||||||
| Oil | Gas | Oil | Gas | Oil | Gas | |||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||
| 1,618 | 429 | 1,299 | 427 | 1,640 | 442 | 1,349 | 438 | 1,642 | 447 | 1,359 | 436 | |||||||||||||||||||||||||||||||||||||
| 1,614 | 550 | 45 | 15 | 1,663 | 565 | 47 | 16 | 1,700 | 573 | 46 | 15 | |||||||||||||||||||||||||||||||||||||
| 1,242 | 588 | 199 | 91 | 1,162 | 542 | 199 | 77 | 1,638 | 753 | 226 | 77 | |||||||||||||||||||||||||||||||||||||
| 3,210 | 1,031 | 131 | 91 | 3,085 | 990 | 86 | 66 | 2,961 | 945 | 80 | 61 | |||||||||||||||||||||||||||||||||||||
| 16,717 | 8,511 | 956 | 658 | 17,870 | 8,870 | 1,044 | 627 | 28,165 | 11,636 | 1,631 | 845 | |||||||||||||||||||||||||||||||||||||
| 86 | 86 | 298 | 251 | 338 | 193 | 274 | 230 | 413 | 267 | 259 | 223 | |||||||||||||||||||||||||||||||||||||
| 24,487 | 11,195 | 2,928 | 1,533 | 25,758 | 11,602 | 2,999 | 1,454 | 36,519 | 14,621 | 3,601 | 1,657 | |||||||||||||||||||||||||||||||||||||
| Number of wells drillinga,b(at December 31, 2003) | ||||||||||||||||||||||||
| Exploration | Development | Total | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Europe | 4 | 1 | 15 | 4 | 19 | 5 | ||||||||||||||||||
Africac | 1 | 1 | 4 | 1 | 5 | 2 | ||||||||||||||||||
Asia Pacificd | – | – | 24 | 12 | 24 | 12 | ||||||||||||||||||
Middle East, Russia, CISe | 7 | 3 | 45 | 19 | 52 | 22 | ||||||||||||||||||
| USA | 3 | 2 | 21 | 13 | 24 | 15 | ||||||||||||||||||
| Other Western Hemisphere | 2 | 1 | 7 | 6 | 9 | 7 | ||||||||||||||||||
| 17 | 8 | 116 | 55 | 133 | 63 | |||||||||||||||||||
| a | Including associated companies. |
| b | See Note b on page 13. |
| c | Excludes Egypt. |
| d | Excludes Sakhalin. |
| e | Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin. |
(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) which is the major producer of oil and gas in Germany. 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 During 2002 EO Ireland (Group interest 100%) was acquired as a part of the Group’s acquisition of Enterprise Oil and was renamed as Shell E&P Ireland Ltd. It is the operator for the Corrib Gas Project (Shell equity 45%), currently under development and has further exploration interests in 24 Blocks offshore Ireland, 13 operated and 11 non-operated.
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 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. NAM’s production of oil and gas is covered by concessions (onshore) and production licences (offshore). Government participation in development and production varies between 0% and 50%, depending mainly on the legislation applicable when the concessions or licences were granted and whether the participation covered gas or oil. Production is preceded by a drilling permit (onshore) or an exploration licence (offshore), the duration of which, since 1997, varies with the work programme that has to be submitted with the application for a permit or licence. In practice, this means a period of about 3 to 10 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 concession (onshore) or production licence (offshore) is granted. The onshore concessions are not currently limited in time but the duration of the offshore licences 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 UK and continental Europe. Of the exploration licences acquired through Enterprise, the majority have been divested, farmed out or relinquished. Shell International Pipelines Inc. 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. 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, 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 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 tax rate from 30% to 40%. During 2003 a number of non-core assets were divested, including the Shell operated Kittiwake Field and several small equity interests resulting from the acquisition of Enterprise in 2002.
Africa
Cameroon Pecten Cameroon Company (PCC) (Group interest 80%) has a 40% working interest in a PCC operated property (Lokele), 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 seven onshore mining concessions/exploitation permits, four of which (Rabi/Kounga, Gamba/Ivinga, Toucan and Totou/Bende-M’Bassou) are operated by the company. The Rabi/Kounga concession was transferred to a PSC with effect from January 1, 2003; it expires in 2013 and includes an option for a five-year extension. The Gamba/Ivinga concession expires in 2042; all other concessions expire between 2010 and 2018. Toucan was converted into a Production licence in early 2003. Production in Gabon is dominated by the Rabi field, which is operated by Shell Gabon, which holds a 42.5% equity in the field. Shell Gabon’s portfolio also includes three exploration permits, one around the Gamba/Ivinga concession and two near the Rabi field. The Kenguerie Marin permit offshore Libreville held by Shell Gabon was relinquished in 2003. Two Group companies, Shell Offshore North Gabon BV (SONG) and Shell Offshore Gabon BV (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 A Group company, Shell Exploration et Production du Maroc GmbH, operates a 100% owned exploration licence named Rimella which includes five deepwater blocks and Enterprise Oil Exploration Ltd., acquired in 2002, and holds a 30% interest in the adjacent Cap Draa concession consisting of six blocks.
Nigeria The Shell Petroleum Development Company of Nigeria Ltd. (SPDC) (Group interest 100%) is 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.
Shell Nigeria Exploration and Production Company (SNEPCO) (Group interest 100%) operates PSCs with 30-year terms with a 55% interest in two deepwater blocks (OPL-212 and OPL-219). SNEPCO also has a 50% interest in deepwater blocks OML-125 and OPL-211, and a 44% interest in deepwater block OPL-209.
Somalia Shell Somalia B.V. holds a 50% working interest and operatorship of Blocks M3-M7, which are currently under force majeure.
Asia Pacific
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 renewable 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%) (see also page 20). 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 (Shell China Exploration & Production Company (SCEPCo), formerly Shell Exploration China Limited, and Pecten Orient China) hold a 47.75% interest in the offshore South China Sea Block 15/22 (Xijiang 30-2 producing field) and 24.5% in Block 15/11 (Xijiang 24-1 & 24-3 producing fields). Five PSCs were signed for the East China Sea project in 2003. SCEPCo holds 100% of the contractors 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 Four 100%-owned Group companies have PSCs with the state oil company Petronas. In most of these contracts Petronas Carigali Sendirian Berhad (PCSB), a 100% Petronas subsidiary, is the sole joint-venture partner. One Group company, Sarawak Shell
Berhad (SSB) is the operator, with a 50% equity stake, of five non-associated producing gas fields. The majority of the gas is supplied to Malaysian LNG Sendirian Berhad (Group interest 15%) for deliveries of liquefied natural gas to customers mainly in Japan and Korea. (See pages 20 and 21). SSB operates one oil field (D35) and has a 40% equity stake in the non-operated Baram Delta production-sharing contract. SSB has exploration interests in the deepwater SK-E block and shallow-water blocks SK-307, SK-308 and SK-8. SSB also holds exploration acreage in SB-301 and the deepwater blocks SBG & J. Sabah Shell Petroleum Company (SSPC) operates five producing fields in Sabah waters of which Kinabalu (80% equity share) is the largest. SSPC and Shell Sabah Selatan Sdn Bhd (SSS) also have a PSC for the exploration and production in Block SB-303, offshore Sabah. Shell Exploration and Production Malaysia (SEPM) operates an exploration licence in Peninsula Malaysia (PM-303) where they also have 50% interest in Block PM-301/302.
New Zealand Shell NZ Exploration and Production Holding BV (SNZ) (Group interest 100%) has 77.5% interest in the production licence for the offshore Maui gas field, in which another wholly owned Group company has a further 6.25% indirect interest. In addition, SNZ has a 50% interest in the onshore Kapuni gas field and a 48% interest in the undeveloped Offshore Pohokura gas field. The gas produced is sold domestically, mainly under long-term contracts. SNZ also has 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%).
Philippines Two Group companies hold interests in the deepwater PSC for block SC-38. Shell Philippines Exploration B.V. (SPEX) holds 20% and is operator and Shell Philippines LLC holds 25%. The SC-38 interest includes an exploration area and a production licence, the latter containing 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 with a total nameplate capacity of 2700MW. In addition to SC-38, SPEX currently holds a 50% interest in the deepwater exploration acreage of GSEC-99 north east of Palawan Island.
Middle East, Russia, CIS (including Sakhalin, Egypt and Caspian region)
Egypt Shell Egypt (Group interest 100%) participates in five exploration concessions (operator in four and non-operator in Rosetta) and in five development leases (operator in four and non-operator in Rashid). All concessions and leases are granted on the basis of production-sharing agreements. Included in Shell Egypt’s portfolio is an 84% interest in the North-eastern Mediterranean 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.
Oman A Group company has a 34% interest in Petroleum Development Oman (PDO), which is the operator of an oil concession expiring in 2012, 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) (in which a Group company has an 85% shareholding) 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%). (See page 21.) The upstream investment required to develop and supply the gas is being provided to the government by GISCO.
Syria Group companies have interests varying from 62.5% to 66.7% in five PSCs with the government and with the state-owned Syrian Petroleum Company (SPC). Under the contracts, they have certain rights and obligations in respect of the production of petroleum. Three contracts (Ash Sham, Deir Ez-Zor and Fourth Annex expiring between 2008 and 2014) concern development activities. In addition, Group companies are parties to a gas utilisation agreement with the government and SPC for the collection and processing of natural gas from the contract areas for use in Syrian power generation and other industrial plants.
USA
development, which started production in 2002, and in the Tahiti discovery. SEPCo also acquired additional interests in the Pinedale field in the Rocky Mountain region under two separate transactions.
Affiliates of SEPCo holds 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.
Other Western Hemisphere
Canada Shell Canada (Group interest 78%) is a major producer of natural gas, natural gas liquids and sulphur. The majority of its gas production comes from Alberta and the Sable gas fields offshore Nova Scotia (where Shell Canada has 31% working interest in the total Sable Offshore Energy Project.). 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 and recently completed a new oil sands mining project in the Athabasca oil sands area of Northern Alberta. Shell Canada holds 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 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. At full capacity, AOSP will produce 155,000 barrels of bitumen per day, approximately 10% of Canada’s oil requirements; and |
| – | the Scotford upgrader 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 Athabasca Oil Sands Project became fully operational in June, 2003 and production continues to increase, averaging 130,000 barrels per day (78,000 Shell share) of bitumen in the fourth quarter of 2003, up from 115,000 barrels per day in quarter three.
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.
A Preliminary Development Agreement for Mariscal Sucre Liquefied Natural Gas Project (MSLNG) was signed between associates (PDVSA 60%, Shell 30%, Mitsubishi 8%, Venezuelan Government Reserved 2%) in order to produce 4.7 annual tons of LNG with main destination the USA market. A Joint Venture Agreement is scheduled to be signed during 2004.
(c) Other oil and gas interests
Argentina Shell Compania Argentina de Petroleo (CAPSA) (Group interest 100%) holds an interest with rights to operatorship and 51.25% of production in the Valle Morado Exploitation Lot and a 22.5% interest in the Acambuco concession.
Azerbaijan A Group company holds a 25% interest in the non-operated Inam licence, offshore Azerbaijan.
Bangladesh A Group company holds a 50% interest in and is operator of Blocks 15 and 16, a 37.5% interest in the producing Sangu gas field (located in Block 16) and a 22% interest in Block 7. Another Group company holds a 45% interest in and is operator of a joint venture owning Block 5 and Block 10 (exploration only). Divestment in 2004 has been announced.
Iran A Group company has a 70% interest in an agreement with the National Iranian Oil Company (NIOC) to develop the Soroosh and Nowrooz field in the northern Persian Gulf. This Group company established operations 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 Production Sharing agreement in respect of some 6,000 sq. kms offshore in the Kazakhstan sector of the Caspian Sea. An additional 3.7% interest is in the process of being acquired, bringing total holdings to 20.37%. 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 either being further appraised or appraisal plans are being developed. In 2003, the Group acquired Kerr McGee’s interest in: Caspian Pipeline Company (1.75%), Arman Joint Venture (50% interest in small onshore producing property), and an onshore exploration lease.
Pakistan A Group company holds 28% interest in the Bhit Development and Production Lease and 33.25% interest in the Kirthar Exploration licence.
Qatar On October 20 2003 Shell signed a Heads of 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 early 2009.
Russia Shell Sakhalin Holdings B.V. (Group interest 100%) holds a 55% interest in Sakhalin Energy Investment Company Ltd. (Sakhalin Energy). Seasonal oil production continues from the Molikpaq facility on the Piltun-Astokhskoye field, offshore Sakhalin island. Full development of the Piltun-Astokhskoye oil field and Lunskoye gas field including an LNG plant in the south of Sakhalin Island for export to the Asia Pacific LNG markets commenced in 2003. During 2003 the Group divested its entire 49% interest in KMOC (Khanty Mansiysk Oil Corporation). Salym Petroleum Development (Group interest 50%) commenced developing the Salym fields in Western Siberia during 2003. Shell holds a 3.675% interest in the Caspian Pipeline Company which manages a pipeline running from Western Kazakhstan to the Black Sea.
Saudi Arabia Towards the end of 2003 Shell entered into an agreement for gas exploration and production from an area in the Rub Al-Khali in the south of the Kingdom. Shell will lead the project and has 40% interest, with Total and Saudi Aramco holding 30% each.
2 Gas & Power
| Utilisation of plant capacity | % | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
Liquefied natural gas (LNG)a | 97 | 97 | 92 | 89 | 93 | |||||||||||||||
| ProcessingLiquefied natural gas (LNG) plants | ||||||||||
| Location, Group interest in plantsband capacityc(at December 31, 2003) | ||||||||||
| Group | 100% capacity | |||||||||
| interest | million tonnes | |||||||||
| % | a year | |||||||||
| Nigeria | Bonny | 26 | 9.6 | |||||||
| Oman | Qalhat | 30 | 6.6 | |||||||
| Brunei | Lumut | 25 | 7.2 | |||||||
| Australia | Karratha | 22 | 7.5 | |||||||
| Malaysia | Bintulu | 15 | 14.6 | |||||||
| Regasifiation terminal | ||||||||||
| Belgium | Zeebrugge | 17 | 3.6 | |||||||
| a | Based on average plant capacity. | |
| b | Percentage rounded to nearest whole percentage point where appropriate. | |
| c | As reported by the joint ventures. |
| Liquefied natural gas sales volumes | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Malaysia | 1.5 | 2.3 | 2.3 | 2.3 | 2.2 | |||||||||||||||
| Australia | 1.8 | 1.7 | 1.7 | 1.7 | 1.7 | |||||||||||||||
| Brunei | 1.8 | 1.7 | 1.7 | 1.7 | 1.6 | |||||||||||||||
| Oman | 2.1 | 1.9 | 1.7 | 0.7 | — | |||||||||||||||
| Nigeria | 2.1 | 1.5 | 1.5 | 1.1 | — | |||||||||||||||
| Total | 9.3 | 9.1 | 8.9 | 7.5 | 5.5 | |||||||||||||||
Europe
Germany BEB Erdgas und Erdöl GmbH (BEB), a joint venture with ExxonMobil in which a Group company holds a 50% economic interest, is the major producer of oil and gas in Germany, and also one of the country’s major gas transmission companies. The natural gas marketing activities of BEB have been split and are operated by separate independent Shell and ExxonMobil organisations effectively
from April 2004. Group companies have minority shareholdings in major gas transmission and distribution companies, including Avacon AG (1.4%, through BEB) and Erdgas-Verkaufs-GmbH (13.8% through BEB). In 2003 the Group divested its indirect interest in Ruhrgas AG (14.75%) and its direct interest in Thyssengas GmbH (25%). Also in 2003, the sale of the indirect interest in Verbundnetz Gas AG (5.3%) was agreed and subsequently completed during the first quarter of 2004.
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 commercial and 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 30-year exclusive distribution licence to develop the distribution system infrastructure and to distribute gas to small industrial, commercial and residential customers in the Attiki area.
Netherlands N.V Nederlandse Gasunie (Group interest 25%) is the largest marketer of Dutch gas. In 2003, N.V Nederlandse Gasunie sold approximately 77 billion cubic metres of gas for both export and domestic consumption. N.V Nederlandse Gasunie is also the main gas transmission company in the Netherlands.
Wholly owned Shell Energy Europe B.V. was established in 2003 and took over the gas and power development activities throughout Europe from Shell Energy Ltd in the UK.
Spain Shell Espana, S.A., a wholly-owned Group subsidiary, continued to develop its natural gas marketing business selling in the wholesale as well as in the industrial and commercial market.
United Kingdom A wholly Group-owned gas marketing company, Shell Gas Direct Ltd, maintained its market position during 2003 selling in the industrial and commercial market. The wholly owned Shell Energy Ltd., established in 1999, ended its activities in 2003 with the sale of business and activities to Shell Energy Europe B.V. in the Netherlands.
Denmark A/S Dansk Shell A wholly owned Group subsidiary launched a natural gas marketing business in 2003.
Other European Countries Wholly-owned Shell Group companies in other European countries continue to seek opportunities to develop the gas and power business. For this purpose they receive advice and assistance from Shell Energy Europe B.V. a wholly owned Group company.
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.
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 2003, 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, brought into service in June 2002, owned by Brunei Gas Carriers Sendirian Berhad (Group interest 10%).
India The Group holds 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 capacity of this terminal is 2.5 mtpa, expandable to 5 mtpa and then 10 mtpa. Currently under construction the terminal is intended to be commissioned around the end of 2004. 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.
Malaysia Exports of LNG from Sarawak by Malaysia LNG Sendirian Berhad (MLNG Satu, Group interest 15%) began in January 1983 to two Japanese customers. The contract delivery rate was increased to 7.6 million tonnes of LNG a year in 1993. The Group shareholding in the first venture, MLNG, 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 additional liquefaction trains (Group interest 15%) came on-stream at the end of 1995 (MLNG Dua), doubling capacity to some 15.9 million tonnes a year, 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 a year two-train MLNG Tiga (Group interest 15%), was essentially completed and started up in March 2003 but due to a fire in August 2003, production from the first of MLNG Tiga’s trains was suspended until March 2004.
Adjacent to the LNG facilities is a Gas to Liquids plant, operated by Shell MDS (Malaysia) Sendirian Berhad (Group interest 71.8%). This plant converts approximately three million cubic metres a day of natural gas into some 12,500 barrels a day of high-quality middle distillates and other products using Shell-developed technology. First commercial production of middle distillates and solvents from the plant occurred during 1993 using feedstock from offshore gas fields. Following an incident in late 1997, the plant re-started successfully in mid 2000. The plant was de-bottle-necked during 2003, including the introduction of a new generation proprietary catalyst, which is expected to add approximately 20% additional capacity by 2005. 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 a 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. NLNG Plus will increase NLNG’s production capacity to approximately 17.6 million tonnes a year of LNG and 2.5 million tonnes a year of LPG by 2006. NLNG currently has operational control of 10 LNG vessels.
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.
Qatar In October 2003, Shell Qatar GTL Ltd (Group interest 100%) signed a Heads of Agreement with the State of Qatar for the construction of a 140,000 bbl/d Gas to Liquids plant in Ras Laffan, Qatar. FID is expected in 2006, with first sales in 2009.
Russia Shell Sakhalin Holdings B.V. (Group interest 100%) holds a 55% interest in Sakhalin Energy Investment Company Ltd. Phase 1 of the project has been successfully producing oil from the Vityaz Complex since July 1999, exporting 10.3 million barrels of oil in 2003. The final investment decision for Phase 2, which consists of a two-train LNG plant with 9.6 million tonnes a year, was announced on May 15, 2003. The first LNG cargo is scheduled to be delivered in the second half of 2007, and target markets for the LNG include the Asia Pacific and the west coast of North and Central America.
USA
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 with a concession area that covers a region responsible for about a third of Brazil’s GDP. 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 Brazileira Bolivia Brazil 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 pipelines 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 Shell won a tender to deliver gas through a receiving terminal at Altamira, now under construction, to CFE (state power company). Group interest is 75% after a 25% equity interest was sold to Total S.A. The terminal is located in the port of Altamira, Tamaulipas, on Mexico’s Gulf coast. The facility is expected to start operations in the second half of 2006 supplying up to 5 billion cubic meters 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.
Shell also announced a joint project (Group interest 50%), which plans to construct a LNG receiving terminal at Baja, California to supply Mexico and the USA.
Venezuela In 2002, a Group company signed a Framing Agreement (June) and a Preliminary Development Agreement (November) covering a 30% interest in the Mariscal Sucre LNG scheme.
LNG Supply and Shipping
InterGen
3 Oil Products
At the end of 2003, the Group had an interest in more than 50 refineries worldwide and markets fuels for the automotive, aviation and marine sectors, along with heating oils, industrial and consumer lubricants, speciality products such as bitumen and liquefied petroleum gas (LPG) and technical services.
The Oil Products business operates the world’s largest single branded retail network, serving some 25 million retail customers a day through over 50,000 service stations. 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 trusted 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 was the most preferred brand in 30 of the 49 markets covered. 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.
Group companies continue to be leaders in automotive fuel performance and quality. The range of innovative products and services offered to customers has been further expanded, drawing upon extensive research and development. The differentiated fuels programme has now been launched in some 50 countries. We continue to introduce products such as low-sulphur, diesel, lead replacement fuel and LPG which have reduced the impact on our environment.
Oil Products actively manages the health and safety risk of its operations and products for staff, contractors, customers and neighbours; all Oil Products business activities are covered by structured HSE management systems.
USA
In early 2002, Shell Oil Company acquired the 44% Texaco Inc. interest in Equilon Enterprises LLC, which is now operating as Shell Oil Products US. At the same time Shell Oil Company and Saudi Refining, Inc. acquired Texaco’s interest in Motiva Enterprises LLC,
making each company a 50% owner of that business. Shell Oil Company also holds a 50% interest in the Deer Park Refining Limited Partnership, which is a joint venture between Shell Oil Company and a subsidiary of Mexico’s national oil company Petroleos Mexicanos Pemex.
Together, Shell Oil Products US and Motiva hold a significant position in the US refined products industry, with a market-leading 13% share of US gasoline sales. At the end of 2003, the two companies together with Deer Park Refining Limited Partnership operated nine refineries with a combined capacity of approximately 1.7 million barrels per day.
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 have the exclusive rights to use the “Texaco” brand on refined oil product sales in their respective areas through June 2004, and non-exclusive rights through June 2006. Shell Oil Products US and Motiva plan to reduce the number of service stations in the overall network by around 30%, to some 15,000 sites. Through quarter four 2003, some 45% of the site rationalisation programme was complete. Furthermore, a programme is underway to re-brand Texaco branded sites to the Shell brand, which will be largely completed by end-2004. Through quarter four 2003, over 4,200 sites had been rebranded from Texaco to the Shell brand.
The purchase of Pennzoil-Quaker State Company (PQS) was completed in October 2002 after regulatory clearance. The transaction had a total equity value of $1.9 billion and debt of $1.3 billion. This acquisition has made the Group a leader in both passenger car motor oil and diesel engine oil in the USA and aligns with the Group’s strategy to establish a leadership position in the global lubricants market. The PQS acquisition marked the start of a period during which there were a series of lubricants portfolio changes. Some of the more significant portfolio changes included divestment of Shell’s interest of the Excel Paralubes plant in Lake Charles, Louisiana to Flint Hills Resources on July 31, 2003 (a FTC-mandated requirement of the PQS acquisition); closing of the Deer Park, Texas and Martinez, California base oil manufacturing plants; and rationalising 7 of 16 lube oil blend plants.
In November 2003, Shell Oil Products US announced the planned closure of its Bakersfield, California refinery. Additionally, several non-strategic onshore crude pipeline systems have been either closed, sold, or announced for sale, during 2003. These include the Michigan gathering system sale completed in December; the Poplar/Butte/Baker Gathering/Powder River/Little Missouri sale completed in December; the Cushing Ozark/Woodpat/Osage sale closed in quarter one 2004; and the Capline/Capwood sale also closed in quarter one 2004. Finally, a group of five western state products terminals were packaged and sold to Kinder Morgan in October (Mission Valley and Rialto, California; Phoenix and Tucson, Arizona; and Reno, Nevada).
In May 2004, Shell Oil Products US announced that Motiva Enterprises LLC had completed the sale of Motiva’s Delaware City Refinery to The Premcor Refining Group Inc.
Canada
Europe
The sale and purchase agreements for the acquisition of 70 retail sites in Hungary, 33 sites in the Czech Republic and seven motorway sites in France from Total were announced in quarter one. In exchange, Total will purchase 133 retail sites in Germany. The divestment of some 5% of retail volumes required by the German Cartel Office, following the formation of Shell and DEA Oil, has now been completed.
The Group also announced in quarter one 2003, its intention to seek buyers for the shares in AB Svenska Shell, a 100% owned subsidiary. It is expected that the sale will be completed during 2004. It is the intention to retain the lubricants, LPG and Marine products businesses in Sweden.
An expansion of the retail alliance with Sainsbury’s Supermarkets Ltd in the UK was announced in quarter two. The expansion will involve up to 100 retail sites over the coming two to three years – Shell will exclusively supply the fuel products.
Furthermore in quarter two, the Group sold its 20.69% interest in Skeljungur in Iceland, where retail operations will continue under the Shell Brand. Shell Hydrogen’s involvement in the pilot retail hydrogen site in Iceland is unaffected by this development.
Middle East and Asia Pacific
A new retail alliance with Coles Myer Ltd in Australia was announced in May, with Coles Myer becoming the operator of the Shell-Branded retail network – Shell will exclusively supply fuel and lubricants products. The alliance commenced in July, and in March 2004 Shell Australia announced that the rollout of more than 590 service stations had been completed, well ahead of the mid-2004 schedule originally envisaged.
Africa
The sale of a 25% interest in Shell’s marketing businesses in South Africa to Thebe Investment Corporation was completed in the first quarter 2002. This sale is a positive response to the South African Government’s Black Economic Empowerment initiative.
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 supply over 21 million gallons (80 million litres) of fuel. In 2003 Shell Aviation was voted best ‘Jet Fuel Marketer’ in the Armbrust Survey for Africa-MESA and Asia-Pacific and second best globally. Shell has won the coveted Armbrust Aviation award three times in the last six years.
Shell Marine Products is one of the world’s leading suppliers of premium quality marine fuels, lubricants and services, working with international and local marine customers worldwide. The business supplies 20 different types of marine fuel oil to power diesel engine, 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 40 million customers in over 55 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. During 2003 Shell Gas LPG completed the acquisition of Great Lakes Energy Services and Cherryland Propane in the USA. LPG activities in Brazil, Senegal, Haiti and New Caledonia were divested, as well as non-automotive activities in Italy.
Global Lubricants In January 2004, Shell Lubricants formally launched as the newest globally managed business within the Oil Products portfolio. The globalisation of our lubricants business means the Group is better placed to offer increased value to customers through the benefits of global reach and local knowledge. Operating in more than 120 countries with an extensive network of base oils and lubricants blending plants, the business produces a range of high quality lubricants for use in garages and workshops, commercial road transport, manufacturing, mining, agriculture, shipping and aviation. Products range from the light, food-quality formulations used in soft-drink canning plants to the thick, industrial greases that protect the massive roller bearings in steel mills.
The acquisition of PQS makes Shell a leader in both the US and global lubricants markets and creates a powerful portfolio of trusted products and brands. The PQS Jiffy Lube format further extends Shell’s lubricants portfolio, providing vehicle maintenance services to some 30 million customers each year.
Shell Global Solutions brings the Group’s technology and technical experience to market by providing industry and other Group companies with innovative solutions to improve their performance.
Shell Global Solutions has an extensive network of offices around the world, with primary commercial centres now operating in the USA, Europe and the Far-East. The business has shown steady growth in revenues over the last 4-5 years. Shell Global Solutions as the Technical Adviser to the Group’s gas and LNG business, providing technologies, project management and asset performance improvement consultancy, benefited from positive decisions to move ahead in the Sakhalin LNG Venture and in a first world-scale Gas to Liquids venture in Qatar.
Refininga
| Cost of crude oil processed or consumed | $ per barrel | |||||||||||||||||||
| (including upstream margin on crude supplied by Group and associated | ||||||||||||||||||||
| exploration and production companies) | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| 26.75 | 24.35 | 23.56 | 27.50 | 17.58 | ||||||||||||||||
| Operable crude oil distillation capacityb | thousand barrels/calendar dayc | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Europe | 1,808 | 1,809 | 1,400 | 1,395 | 1,546 | |||||||||||||||
| Other Eastern Hemisphere | 1,072 | 1,108 | 1,155 | 1,099 | 1,073 | |||||||||||||||
| USA | 1,073 | 1,075 | 689 | 222 | 222 | |||||||||||||||
| Other Western Hemisphere | 361 | 395 | 398 | 372 | 371 | |||||||||||||||
| 4,314 | 4,387 | 3,642 | 3,088 | 3,212 | ||||||||||||||||
| Crude oil processedd | thousand barrels/stream day | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Europe | 1,712 | 1,701 | 1,309 | 1,337 | 1,531 | |||||||||||||||
| Other Eastern Hemisphere | 916 | 870 | 933 | 899 | 918 | |||||||||||||||
| USA | 974 | 996 | 624 | 196 | 188 | |||||||||||||||
| Other Western Hemisphere | 347 | 314 | 361 | 355 | 352 | |||||||||||||||
| 3,949 | 3,881 | 3,227 | 2,787 | 2,989 | ||||||||||||||||
| Group share of associated companies | 515 | 473 | 480 | 1,117 | 1,139 | |||||||||||||||
| Crude oil distillation unit intake as percentage | ||||||||||||||||||||
| of operable capacitye | % | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Europe | 96 | 94 | 95 | 97 | 99 | |||||||||||||||
| Other Eastern Hemisphere | 89 | 84 | 90 | 85 | 90 | |||||||||||||||
| USA | 89 | 91 | 91 | 88 | 86 | |||||||||||||||
| Other Western Hemisphere | 90 | 86 | 91 | 98 | 97 | |||||||||||||||
| Worldwide | 92 | 90 | 92 | 92 | 95 | |||||||||||||||
| Refinery processing intakef | thousand barrels/stream day | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Crude oil | 3,949 | 3,881 | 3,227 | 2,787 | 2,989 | |||||||||||||||
| Feedstocks | 218 | 203 | 173 | 136 | 148 | |||||||||||||||
| 4,167 | 4,084 | 3,400 | 2,923 | 3,137 | ||||||||||||||||
| Europe | 1,776 | 1,761 | 1,358 | 1,394 | 1,602 | |||||||||||||||
| Other Eastern Hemisphere | 956 | 941 | 1,018 | 971 | 983 | |||||||||||||||
| USA | 1,079 | 1,064 | 663 | 198 | 192 | |||||||||||||||
| Other Western Hemisphere | 356 | 318 | 361 | 360 | 360 | |||||||||||||||
| 4,167 | 4,084 | 3,400 | 2,923 | 3,137 | ||||||||||||||||
| million tonnes a year | ||||||||||||||||||||
Metric equivalent | 204 | 201 | 166 | 147 | 157 | |||||||||||||||
| Refinery processing outturng | thousand barrels/stream day | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Gasolines | 1,575 | 1,537 | 1,242 | 957 | 1,021 | |||||||||||||||
| Kerosines | 418 | 400 | 369 | 320 | 368 | |||||||||||||||
| Gas/Diesel oils | 1,312 | 1,287 | 1,068 | 974 | 1,035 | |||||||||||||||
| Fuel oil | 378 | 355 | 339 | 316 | 361 | |||||||||||||||
| Other products | 550 | 546 | 417 | 350 | 283 | |||||||||||||||
| 4,233 | 4,125 | 3,435 | 2,917 | 3,068 | ||||||||||||||||
| Group share of Equilon and Motiva volumes | ||||||||
| (not included above) | thousand barrels/stream day | |||||||
| 2000 | 1999 | |||||||
| Refinery processing intake | 656 | 797 | ||||||
| a | For 1999 and 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. |
Oil salesa,b,c
| Product volumesd | thousand barrels/day | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
Europe | ||||||||||||||||||||
| Gasolines | 616 | 647 | 531 | 510 | 506 | |||||||||||||||
| Kerosines | 194 | 190 | 164 | 178 | 192 | |||||||||||||||
| Gas/Diesel oils | 936 | 950 | 776 | 718 | 747 | |||||||||||||||
| Fuel oil | 184 | 177 | 174 | 192 | 186 | |||||||||||||||
| Other products | 207 | 209 | 207 | 212 | 199 | |||||||||||||||
| 2,137 | 2,173 | 1,852 | 1,810 | 1,830 | ||||||||||||||||
Other Eastern Hemisphere | ||||||||||||||||||||
| Gasolines | 315 | 332 | 328 | 334 | 344 | |||||||||||||||
| Kerosines | 166 | 142 | 132 | 124 | 131 | |||||||||||||||
| Gas/Diesel oils | 489 | 476 | 460 | 452 | 437 | |||||||||||||||
| Fuel oil | 180 | 188 | 200 | 203 | 220 | |||||||||||||||
| Other products | 138 | 149 | 138 | 138 | 130 | |||||||||||||||
| 1,288 | 1,287 | 1,258 | 1,251 | 1,262 | ||||||||||||||||
USA | ||||||||||||||||||||
| Gasolines | 1,343 | 1,239 | 737 | 189 | 185 | |||||||||||||||
| Kerosines | 212 | 221 | 138 | 31 | 31 | |||||||||||||||
| Gas/Diesel oils | 430 | 401 | 266 | 82 | 74 | |||||||||||||||
| Fuel oil | 189 | 105 | 65 | 17 | 25 | |||||||||||||||
| Other products | 218 | 173 | 111 | 114 | 71 | |||||||||||||||
| 2,392 | 2,139 | 1,317 | 433 | 386 | ||||||||||||||||
Other Western Hemisphere | ||||||||||||||||||||
| Gasolines | 296 | 317 | 315 | 306 | 321 | |||||||||||||||
| Kerosines | 72 | 74 | 80 | 81 | 85 | |||||||||||||||
| Gas/Diesel oils | 243 | 246 | 252 | 275 | 277 | |||||||||||||||
| Fuel oil | 86 | 92 | 100 | 107 | 104 | |||||||||||||||
| Other products | 52 | 49 | 54 | 128 | 123 | |||||||||||||||
| 749 | 778 | 801 | 897 | 910 | ||||||||||||||||
Export sales | ||||||||||||||||||||
| Gasolines | 193 | 251 | 202 | 455 | 279 | |||||||||||||||
| Kerosines | 154 | 155 | 154 | 128 | 128 | |||||||||||||||
| Gas/Diesel oils | 213 | 222 | 194 | 204 | 222 | |||||||||||||||
| Fuel oil | 181 | 196 | 168 | 204 | 175 | |||||||||||||||
| Other products | 138 | 198 | 197 | 192 | 174 | |||||||||||||||
| 879 | 1,022 | 915 | 1,183 | 978 | ||||||||||||||||
Total product sales | ||||||||||||||||||||
| Gasolines | 2,763 | 2,786 | 2,113 | 1,794 | 1,635 | |||||||||||||||
| Kerosines | 798 | 782 | 668 | 542 | 567 | |||||||||||||||
| Gas/Diesel oils | 2,311 | 2,295 | 1,948 | 1,731 | 1,757 | |||||||||||||||
| Fuel oil | 820 | 758 | 707 | 723 | 710 | |||||||||||||||
| Other products | 753 | 778 | 707 | 784 | 697 | |||||||||||||||
| 7,445 | 7,399 | 6,143 | 5,574 | 5,366 | ||||||||||||||||
| Sales by product as percentage of total | ||||||||||||||||||||
| product sales | % | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Gasolines | 37.1 | 37.7 | 34.4 | 32.2 | 30.5 | |||||||||||||||
| Kerosines | 10.7 | 10.6 | 10.9 | 9.7 | 10.6 | |||||||||||||||
| Gas/Diesel oils | 31.1 | 31.0 | 31.7 | 31.0 | 32.7 | |||||||||||||||
| Fuel oil | 11.0 | 10.2 | 11.5 | 13.0 | 13.2 | |||||||||||||||
| Other products | 10.1 | 10.5 | 11.5 | 14.1 | 13.0 | |||||||||||||||
| 100.0 | 100.0 | 100.0 | 100.0 | 100.0 | ||||||||||||||||
| a | For 1999 and 2000 the sales volumes include the Group share of Equilon (now Shell Oil Products US) and Motiva volumes. | |
| b | 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. | |
| c | 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. | |
| d | 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. |
| Total oil sales volumesa | thousand barrels/day | |||||||||||||||||||
| Oil products by geographical area | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
Europe | ||||||||||||||||||||
| Germany | 785 | 789 | 454 | 421 | 369 | |||||||||||||||
| France | 313 | 299 | 306 | 294 | 310 | |||||||||||||||
| UK and Republic of Ireland | 283 | 317 | 319 | 263 | 286 | |||||||||||||||
| Netherlands | 180 | 191 | 204 | 213 | 231 | |||||||||||||||
| Others | 576 | 577 | 569 | 619 | 634 | |||||||||||||||
| 2,137 | 2,173 | 1,852 | 1,810 | 1,830 | ||||||||||||||||
Other Eastern Hemisphere | ||||||||||||||||||||
| Australia | 190 | 194 | 203 | 207 | 198 | |||||||||||||||
| Others | 1,098 | 1,093 | 1,055 | 1,044 | 1,064 | |||||||||||||||
| 1,288 | 1,287 | 1,258 | 1,251 | 1,262 | ||||||||||||||||
USA | 2,392 | 2,139 | 1,317 | 433 | 386 | |||||||||||||||
Other Western Hemisphere | ||||||||||||||||||||
| Canada | 276 | 263 | 267 | 346 | 346 | |||||||||||||||
| Brazil | 168 | 191 | 203 | 216 | 232 | |||||||||||||||
| Others | 305 | 324 | 331 | 335 | 332 | |||||||||||||||
| 749 | 778 | 801 | 897 | 910 | ||||||||||||||||
Export sales | 879 | 1,022 | 915 | 1,183 | 978 | |||||||||||||||
Total oil products | 7,445 | 7,399 | 6,143 | 5,574 | 5,366 | |||||||||||||||
Crude oil | 4,769 | 5,025 | 4,461 | 3,279 | 3,637 | |||||||||||||||
Total oil sales | 12,214 | 12,424 | 10,604 | 8,853 | 9,003 | |||||||||||||||
| million tonnes a year | ||||||||||||||||||||
Metric equivalent | 611 | 621 | 530 | 444 | 450 | |||||||||||||||
| Group share of Equilon and Motiva volumes | ||||||||
| (not included above) | thousand barrels/day | |||||||
| 2000 | 1999 | |||||||
| Total oil products sales | 1,508 | 1,429 | ||||||
| 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. |
| Net product proceeds | $ million | |||||||||||||||||||
| by product | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||
| Gasolines | 44,830 | 38,861 | 30,455 | 27,046 | 18,594 | |||||||||||||||
| Kerosines | 10,826 | 9,170 | 8,710 | 7,877 | 5,300 | |||||||||||||||
| Gas/ Diesel oils | 35,344 | 28,077 | 25,735 | 25,211 | 16,985 | |||||||||||||||
| Fuel oil | 8,424 | 6,591 | 5,900 | 6,752 | 4,309 | |||||||||||||||
| Other products | 13,834 | 11,420 | 9,845 | 10,470 | 8,243 | |||||||||||||||
| Total oil products | 113,258 | 94,119 | 80,645 | 77,356 | 53,431 | |||||||||||||||
by geographical area | ||||||||||||||||||||
| Europe | 35,618 | 30,228 | 25,077 | 26,189 | 18,648 | |||||||||||||||
| Other Eastern Hemisphere | 19,957 | 16,801 | 17,371 | 18,278 | 13,254 | |||||||||||||||
| USA | 34,533 | 26,200 | 17,199 | 5,068 | 3,202 | |||||||||||||||
| Other Western Hemisphere | 12,751 | 10,836 | 12,118 | 14,226 | 11,300 | |||||||||||||||
| Export sales | 10,399 | 10,054 | 8,880 | 13,595 | 7,027 | |||||||||||||||
| Total oil products | 113,258 | 94,119 | 80,645 | 77,356 | 53,431 | |||||||||||||||
| Average net product proceeds | $ per barrel | |||||||||||||||||||
| by product | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||
| Gasolines | 44.46 | 38.22 | 39.50 | 41.20 | 31.16 | |||||||||||||||
| Kerosines | 37.18 | 32.12 | 35.70 | 39.69 | 25.61 | |||||||||||||||
| Gas/Diesel oils | 41.90 | 33.52 | 36.19 | 39.79 | 26.49 | |||||||||||||||
| Fuel oil | 28.14 | 23.82 | 22.85 | 25.52 | 16.62 | |||||||||||||||
| Other products | 50.30 | 40.21 | 38.14 | 36.51 | 32.38 | |||||||||||||||
| Total oil products | 41.68 | 34.85 | 35.96 | 37.92 | 27.28 | |||||||||||||||
by geographical area | ||||||||||||||||||||
| Europe | 45.67 | 38.11 | 37.09 | 39.52 | 27.92 | |||||||||||||||
| Other Eastern Hemisphere | 42.45 | 35.77 | 37.83 | 39.93 | 28.78 | |||||||||||||||
| USA | 39.56 | 33.55 | 35.78 | 31.98 | 22.70 | |||||||||||||||
| Other Western Hemisphere | 46.64 | 38.18 | 41.47 | 43.34 | 34.00 | |||||||||||||||
| Export sales | 32.41 | 26.95 | 26.59 | 31.40 | 19.69 | |||||||||||||||
| Total oil products | 41.68 | 34.85 | 35.96 | 37.92 | 27.28 | |||||||||||||||
(b) Trading
(c) Shipping
| Oil tankersa(at December 31) | number of ships | million deadweight tonnes | ||||||||||||||||||||||||||||||||||||||
| Owned/demise-hired | 2003 | 2002 | 2001 | 2000 | 1999 | 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||||||||||||||||
| VLCCs (very large crude carriers over 160,000 dwt) | 7 | 7 | 7 | 8 | 9 | 2.1 | 2.1 | 2.1 | 2.3 | 2.6 | ||||||||||||||||||||||||||||||
| Large range (45,000 to 160,000 dwt) | 13 | 16 | 16 | 16 | 17 | 0.9 | 1.3 | 1.3 | 1.3 | 1.4 | ||||||||||||||||||||||||||||||
| Medium range (25,000 to 45,000 dwt) | 5 | 5 | 6 | 5 | 7 | 0.2 | 0.2 | 0.2 | 0.1 | 0.2 | ||||||||||||||||||||||||||||||
| General purpose (10,000 to 25,000 dwt)/Specialist) | 3 | 2 | 2 | 1 | 1 | 0.1 | 0.1 | 0.1 | 0.1 | 0.1 | ||||||||||||||||||||||||||||||
| 28 | 30 | 31 | 30 | 34 | 3.3 | 3.7 | 3.7 | 3.8 | 4.3 | |||||||||||||||||||||||||||||||
Time-chartered | ||||||||||||||||||||||||||||||||||||||||
| VLCCs (very large crude carriers over 160,000 dwt) | 1 | 1 | – | – | – | 0.3 | 0.3 | – | – | – | ||||||||||||||||||||||||||||||
| Large range (45,000 to 160,000 dwt) | 15 | 18 | 17 | 9 | 9 | 1.3 | 1.5 | 1.5 | 0.7 | 0.8 | ||||||||||||||||||||||||||||||
| Medium range (25,000 to 45,000 dwt) | 13 | 15 | 7 | 8 | 7 | 0.5 | 0.6 | 0.3 | 0.3 | 0.3 | ||||||||||||||||||||||||||||||
| General purpose (10,000 to 25,000 dwt)/Specialist) | 10 | 6 | 7 | 1 | 1 | 0.2 | 0.1 | 0.1 | 0.1 | 0.1 | ||||||||||||||||||||||||||||||
| 39 | 40 | 31 | 18 | 17 | 2.3 | 2.5 | 1.9 | 1.1 | 1.2 | |||||||||||||||||||||||||||||||
Total oil tankers | 67 | 70 | 62 | 48 | 51 | 5.6 | 6.2 | 5.6 | 4.9 | 5.5 | ||||||||||||||||||||||||||||||
| Gas carriersa(at December 31) | number of ships | thousand cubic metres | ||||||||||||||||||||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||||||||||||||||||
| Owned/demise-hired (LNG) | 5 | 4 | 2 | – | – | 662 | 522 | 253 | – | – | ||||||||||||||||||||||||||||||
| Time-chartered (LNG) | – | – | – | 2 | 2 | – | – | – | 253 | 253 | ||||||||||||||||||||||||||||||
| Owned/demise-hired (LPG) | 1 | 1 | 1 | 1 | 1 | 59 | 59 | 59 | 59 | 59 | ||||||||||||||||||||||||||||||
| Time-chartered (LPG) | 2 | 3 | 2 | 2 | 2 | 136 | 145 | 113 | 155 | 157 | ||||||||||||||||||||||||||||||
Total gas carriers | 8 | 8 | 5 | 5 | 5 | 857 | 726 | 425 | 467 | 469 | ||||||||||||||||||||||||||||||
| Owned/demise-hired under construction or on order (LNG) | 1 | 2 | 4 | – | – | 135 | 277 | 556 | – | – | ||||||||||||||||||||||||||||||
| a | Excluding ships of less than 10,000 dwt. |
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 1st line derivatives such as styrene monomer, propylene oxide, solvents, detergent intermediates and ethylene oxide.
The Chemicals portfolio also includes the CRI International Group and several ventures including Basell NV, Infineum International Ltd., Saudi Petrochemical Company (SADAF), and CNOOC and Shell Petrochemicals Company Ltd. (CSPCL). The CRI International Group (CRII) consists of wholly owned Group companies, as well as 50:50 jointly owned companies, and is a major producer in the refinery, petrochemical, and environmental catalyst markets. In 2004, CRI International Inc. a wholly-owned Shell Oil subsidiary, plans to sell or initiate closure of two services businesses, its spent catalyst metals reclamation business and its catalyst regeneration business. 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 19 countries and its products are sold in more than 120 countries. Infineum, a 50:50 joint venture between Group companies and ExxonMobil with manufacturing locations in 11 countries, formulates, manufactures and markets high-quality fuel, lubricants, and specialty additives and components. SADAF, a 50:50 manufacturing 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. (CPIL) will produce a range of petrochemicals, primarily for the Chinese market. Construction of the $4.3 billion Nanhai petrochemicals complex in southern China commenced in 2003.
At December 31, 2003, 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 | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Base chemicals | 7,447 | 4,895 | 4,495 | 5,017 | 3,025 | |||||||||||||||
| First-line derivatives | 7,189 | 5,869 | 5,502 | 5,667 | 4,020 | |||||||||||||||
| Other | 550 | 726 | 619 | 4,521 | 5,841 | |||||||||||||||
| 15,186 | 11,490 | 10,616 | 15,205 | 12,886 | ||||||||||||||||
| Net proceeds by geographical areaa | $ million | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Europe | 5,731 | 4,086 | 3,721 | 5,657 | 5,365 | |||||||||||||||
| Other Eastern Hemisphere | 3,106 | 2,192 | 1,659 | 1,921 | 1,621 | |||||||||||||||
| USA | 5,597 | 4,710 | 4,950 | 7,095 | 5,327 | |||||||||||||||
| Other Western Hemisphere | 752 | 502 | 286 | 532 | 573 | |||||||||||||||
| 15,186 | 11,490 | 10,616 | 15,205 | 12,886 | ||||||||||||||||
| Sales volumes by main product categoryb | thousand tonnes | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Base chemicals | 13,165 | 10,031 | 8,760 | 7,909 | 7,295 | |||||||||||||||
| First-line derivatives | 9,779 | 9,565 | 8,849 | 8,219 | 6,605 | |||||||||||||||
| Other | 164 | 1,767 | 1,269 | 4,160 | 7,006 | |||||||||||||||
| 23,108 | 21,393 | 18,878 | 20,288 | 20,906 | ||||||||||||||||
| Ethylene capacitycGroup and associated companies | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Nominal capacity (thousand tonnes/year) | 6,203 | 6,023 | 5,586 | 5,215 | 5,116 | |||||||||||||||
| Utilisation (%) | 90 | 92 | 87 | 94 | 94 | |||||||||||||||
| a | Excluding proceeds from chemical feedstock trading. |
| b | Excluding volumes from chemical feedstock trading and non-chemical by-products. |
| c | Data includes Group share of capacity entitlement (offtake rights) that may be different from nominal Group equity interest. Prior year data has been stated on the same basis. |
Europe
Luxembourg Catalyst Recovery Europe S.A. (Group interest 100%), from its plant in Rodange, Luxembourg, provides regeneration, presulfurizing and length and density grading services to the petroleum refining and chemical industries in Europe, Former Soviet Union, Middle East and Africa. Divestment of this site is planned to take place before the end of 2004.
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. The production of cyclo-octadiene/cyclododecatriene ceased in December 2003. SPM also operates additives units on behalf of Infineum France S.A.S. (a 50:50 joint venture between Group companies and ExxonMobil), polypropylene and polyethylene units on behalf of Basell entities, 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 Production France S.A.), 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 SDO’s shareholding (32.25%) in the relevant operating company, SCE is entitled to a proportion of the production of propylene and methyl tertiary butyl ether from plants in Karlsruhe. By reason of a similar shareholding in a company in Schwedt, (SDO interest 37.5%) SCE receives propylene, benzene, toluene, and xylenes. Kataleuna GmbH Catalysts, a CRII company, manufactures catalyst at its Leuna, Germany plant.
Netherlands Shell Nederland Chemie BV (SNC) (Group interest 100%) manufactures solvents, methyl tertiary butyl ether, brake fluids, glycol ethers and urethanes (polyols) at the Pernis facility, and operates a polypropylene plant owned by Basell.
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. In June 2003, a new 50,000 tonnes per year polymer polyols plant came on stream at Pernis, anticipated to make SNC a major producer of flexible polymer polyols once the plant reaches full production capacity.
Shell Chemicals Europe B.V. (SCE), which started its activities during November 2002, is responsible for all chemicals sales contracts, supply chain management, and procurement of feedstocks and process chemicals across Western Europe other than in respect of joint ventures in which Group companies have an interest. This structure was designed to improve speed, efficiency and overall ease of doing business for customers and suppliers.
United Kingdom Shell U.K. Ltd. operates the plants of Shell Chemicals U.K. Ltd. (SCUK) (both Group interest 100%) at Stanlow, which produce propylene, benzene, toluene, and higher olefins and derivatives. The isopropyl alcohol plant was closed in December 2003. In Carrington, Basell manufactures polypropylene and low-density polyethylene, and operates SCUK’s plants to produce derivatives from ethylene oxide and propylene oxide. 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 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. When it comes on stream in late 2005, the complex will 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 a year ethylene cracker and downstream plants capable of producing 3.6 million tonnes a year of crude industrial ethanol, ethylene dichloride, caustic soda, styrene, and methyl tertiary butyl ether. The 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. CRII catalyst manufacturing locations are at Martinez, Pittsburgh, and Azusa, in California; Lafayette, Louisiana; 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, Inc., a 50:50 joint venture between SCCL and SGF Chimie, a subsidiary of the Société Générale de Financement du Québec, built a world-scale polytrimethylene terephthalate plant near Montreal. The 95,000 tonnes per year plant is expected to start production in 2004. The Group markets PTT under the trademark CORTERRATM Polymers, with their main use in carpet and textile fibres.
Basell, a 50:50 joint venture between Group companies and BASF, operates the isopropyl alcohol plant at Sarnia on behalf of Shell Chemicals Canada Ltd. Basell also owns and operates a polypropylene unit both at Varennes, Quebec, and at Sarnia.
Criterion Catalysts & Technologies Canada Inc, a CRI International 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 a day refinery producing feedstock for the Deer Park, TX and Norco, LA chemical plants. The facility also produces gasoline, diesel, jet fuel and residual fuels, which are primarily being used in Puerto Rico.
5 Renewables
Shell Solar moved into the top five global players with the acquisition of Siemens Solar in April 2002, and remained a leading player in 2003. 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, industrial, rural and consumer markets.
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 2003 the company developed two wind parks in the USA in Texas and Colorado, more than doubling its US capacity to 550MW. In addition the first commercial European asset was added through acquisition in Spain. Shell WindEnergy’s total capacity now amount to more than 650MW, making it one of the world’s 10 largest wind players.
6 Other activities
7 Research
| Research and development expenditure | $ million | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Total (including depreciation) | 584 | 472 | 387 | 389 | 505 | |||||||||||||||
Exploration and Production
In-house capabilities are used in the research, development and application of proprietary E&P technologies in conjunction with service industry or academic capabilities where applicable.
Primary technology focus areas of the division are: enhanced sub-surface imaging, complex reservoir performance modelling, recovery of unconventional hydrocarbons, enhanced well construction, and smaller, more efficient production facilities both onshore and offshore including subsea.
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 catalytic partial oxidation technology continues to be followed up commercially with the shorter-term focus on stationary applications.
Chemicals
F Personnel
| Employees by segmenta(average numbers) | thousands | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Exploration and Production | 17 | 17 | 14 | 13 | 14 | |||||||||||||||
| Gas & Power | 2 | 2 | 2 | 2 | 1 | |||||||||||||||
| Oil Products | 82 | 75 | 58 | 58 | 57 | |||||||||||||||
| Chemicals | 9 | 9 | 9 | 14 | 18 | |||||||||||||||
| Corporate and Other | 9 | 8 | 7 | 8 | 9 | |||||||||||||||
| 119 | 111 | 90 | 95 | 99 | ||||||||||||||||
| Employees by geographical areaa | |||||||||||||||||||||
| (average numbers) | thousands | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||||
| Europe | |||||||||||||||||||||
| Netherlands | 11 | 11 | 10 | 10 | 9 | ||||||||||||||||
| UK | 8 | 9 | 10 | 10 | 11 | ||||||||||||||||
| Others | 27 | 26 | 18 | 21 | 22 | ||||||||||||||||
| 46 | 46 | 38 | 41 | 42 | |||||||||||||||||
| Other Eastern Hemisphere | 28 | 27 | 24 | 24 | 25 | ||||||||||||||||
| USA | 30 | 23 | 12 | 14 | 15 | ||||||||||||||||
| Other Western Hemisphere | 15 | 15 | 16 | 16 | 17 | ||||||||||||||||
| 119 | 111 | 90 | 95 | 99 | |||||||||||||||||
| Employees by segmenta(at December 31) | thousands | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Exploration and Production | 17 | 17 | 15 | 13 | 13 | |||||||||||||||
| Gas & Power | 2 | 2 | 2 | 2 | 1 | |||||||||||||||
| Oil Products | 82 | 80 | 58 | 58 | 56 | |||||||||||||||
| Chemicals | 9 | 9 | 9 | 10 | 17 | |||||||||||||||
| Corporate and Other | 9 | 8 | 7 | 7 | 9 | |||||||||||||||
| 119 | 116 | 91 | 90 | 96 | ||||||||||||||||
| Employee emoluments | $ million | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Remuneration | 7,477 | 6,096 | 4,651 | 4,560 | 4,980 | |||||||||||||||
| Social law taxes | 660 | 518 | 395 | 390 | 467 | |||||||||||||||
| Pensions and similar obligations | 538 | (201 | ) | (580 | ) | (577 | ) | (10 | ) | |||||||||||
| 8,675 | 6,413 | 4,466 | 4,373 | 5,437 | ||||||||||||||||
| 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. |
Selected Financial Data
| Royal Dutch (Netherlands GAAP) | per€0.56 ordinary sharea | |||||||||||||||||||
| 2002 | 2001 | 2000 | 1999 | |||||||||||||||||
| 2003 | As restated | As restated | As restated | As restated | ||||||||||||||||
Net assets – € | 18.38 | 18.68 | 20.64 | 20.25 | 17.63 | |||||||||||||||
Total assets – € | 18.39 | 18.69 | 20.65 | 20.26 | 17.63 | |||||||||||||||
Basic earnings – €b | 3.20 | 2.97 | 3.32 | 3.94 | 2.27 | |||||||||||||||
Diluted earnings – €b | 3.20 | 2.97 | 3.32 | 3.94 | 2.27 | |||||||||||||||
Dividends declared – € | 1.76 | c | 1.72 | 1.66 | 1.59 | 1.51 | ||||||||||||||
| Dividends – equivalent payment in dollars | 2.06 | c | 1.80 | 1.50 | 1.40 | 1.47 | ||||||||||||||
| 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 and 1999 were 2,144,296,352 ordinary shares and 1,500 priority shares, at the end of 2001 were 2,126,647,800 ordinary shares and 1,500 priority shares, at the end of 2002 were 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. The issued and paid-up share capital at the end of 2000 and 1999 was€1,216,979,748b, at the end of 2001 was€1,206,969,043b, at the end of 2002 was€1,176,271,600 and at the end of 2003 was€1,167,432,000. |
| 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 2003 calculation uses a weighted-average number of 2,036,687,755 shares of (2002: 2,057,657,737 (2001: 2,095,731,261; 2000: 2,128,592,305; 1999: 2,132,712,920). 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 22 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 674,120 for 2003 (2002: 442,580; 2001: 1,124,897; 2000: 1,394,975; 1999: 987,827). These numbers relate to stock options schemes as mentioned above. |
| c | Includes interim dividend of€0.74 ($0.85) made payable in September 2003 and a second interim dividend of€1.02 ($1.21) made payable in May 2004. This will together constitute the total dividend for 2003, subject to finalisation by the General Meeting of Shareholders which is held prior to filing. |
| Shell Transport | per 25p Ordinary sharea | |||||||||||||||||||
| 2002 | 2001 | 2000 | 1999 | |||||||||||||||||
| 2003 | As restated | As restated | As restated | As restated | ||||||||||||||||
| Net assets – pence | 174.0 | 161.6 | 169.6 | 165.0 | 140.6 | |||||||||||||||
| Total assets – pence | 183.9 | 171.1 | 178.8 | 174.1 | 149.3 | |||||||||||||||
Adjusted basic earnings (pro forma) – penceb | 31.2 | 26.6 | 29.5 | 35.5 | 21.5 | |||||||||||||||
Adjusted diluted earnings (pro forma) – penceb | 31.2 | 26.6 | 29.5 | 35.4 | 21.4 | |||||||||||||||
| Dividends declared – pence | 15.75 | c | 15.25 | 14.80 | 14.60 | 13.50 | ||||||||||||||
| 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 9,528,797,724 (2002: 9,608,614,760; 2001: 9,758,574,437; 2000: 9,882,388,055; 1999: 9,881,501,981). The basic earnings per share calculation has been restated to exclude shares held by Group companies for share options and other incentive compensation plans (see Note 22 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 2,722,083 for 2003 (2002: 4,661,292; 2001: 12,602,362; 2000: 17,170,048; 1999: 28,844,995). These numbers relate to share option schemes as mentioned above. | |
| c | Includes an interim dividend of 6.10p paid on September 17, 2003, and a second interim dividend of 9.65p paid on May 6, 2004. The directors do not propose to recommend any further distribution in respect of 2003. |
| The number of issued and paid up Ordinary shares, First Preference shares and Second Preference shares of Shell Transport at the end of 1999-2003 inclusive was: |
| Number of issued shares | ||||||||||||
| 2002-2003 | 2001 | 1999-2000 | ||||||||||
| Ordinary share | 9,667,500,000 | 9,748,625,000 | 9,943,509,726 | |||||||||
| First Preference | 2,000,000 | 2,000,000 | 2,000,000 | |||||||||
| Second Preference | 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 1999-2003 inclusive was: |
| Issued and paid up capital (£) | ||||||||||||
| 2002-2003 | 2001 | 1999-2000 | ||||||||||
| 2,428,875,000 | 2,449,156,250 | 2,497,877,432 | ||||||||||
| Shell Transport | per New York Sharea | |||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| Dividends and tax credits – equivalent payment in dollars | 1.62 | 1.44 | 1.29 | 1.24 | 1.31 | |||||||||||||||
| 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. The tax credit was 1/4 of the net dividend for dividends paid in years prior to 1999. US portfolio shareholders are subject to tax on the gross dividend (net dividend plus tax credit) with credit for the UK withholding tax. The dividends paid in 1998 (1997 final and 1998 interim) were foreign income dividends and, as such, carried no tax credit and were not subject to 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. Additional information on dividends is given under Royal Dutch Petroleum Company – Articles of Association (page 73) and The “Shell” Transport and Trading Company, Public Limited Company – Memorandum and Articles of Association (page 84).
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 2003, 2002 and 2001 respectively amounts to€6,513 million,€6,093 million (as restated) and€6,930 million (as restated). The dividends distributed from Group companies to Royal Dutch for the years 2003, 2002 and 2001 were respectively€2,868 million (including dividends yet to be distributed),€3,317 million and€6,148 million. When interest income has been added and administrative expenses deducted, after-tax net income for the year 2003 amounted to€6,520 million compared with€6,108 million for 2002 and€6,947 million for 2001.
Royal Dutch’s 60% interest in the Group net assets, expressed in dollars, has been translated into a euro amount at the year-end rate ($1 = €0.7928 at December 31, 2003). The amount thus obtained, which appears in the Balance Sheet on page R3, should be regarded as a reflection of the dollar value of Royal Dutch’s interest in the Group’s assets and liabilities. Consequently, changes in the dollar/euro rate lead to translation effects in the Royal Dutch Financial Statements. The movements in the value of the dollar, between $1 = €0.9556 at December 31, 2002 and $1 = €0.7928 at December 31, 2003, led to a negative translation effect of€6,475 million, compared with a negative translation effect of€6,226 million in 2002. These effects are dealt with separately from the “Translation effect arising from movements in dollar/euro rate”, as shown in Note 6 on pages R5 and R6. The translation effects are dealt with in the Balance Sheet items “Investments in companies of the Royal Dutch/Shell Group” and “Investment reserves”.
In May 2004 a second interim dividend of€1.02 was made payable on each of the shares outstanding (excluding shares acquired and held by the Company in its own capital). It was proposed to the General Meeting held on June 28, 2004 that the second interim dividend and the interim dividend of€0.74 made payable in September 2003 together constitute the total dividend for 2003 of€1.76 on each of the said shares (compared with€1.72 and€1.66 per ordinary share for the years 2002 and 2001, respectively).
As further described in Note 2 to the Financial Statements, the Group Financial Statements have been restated for certain periods.
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.
Euro reporting
Share buyback and cancellation of shares
The General Meeting of Shareholders renewed the authorisation of the Board of Management, with effect from July 1, 2003, and for a period of 18 months, for the acquisition by the Company, with due observance of the 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 the Company at Euronext Amsterdam on the day of the acquisition or, in the absence of such a price, the last previous price quoted there.
In 2003 the Company did not repurchase any shares.
Since the beginning of the programme until June 14, 2004, a total number of 62,571,352 ordinary shares were acquired by the Company, of which 60,796,352 were cancelled.
Since the year end the Company has purchased 1,775,000 shares on the market as at June 14, 2004.
It was proposed at the General Meeting of Shareholders held on June 28, 2004, to approve the cancellation of the shares acquired by the Company since the year end and to renew the authorisation of the Board of Management for the acquisition by the Company of its own shares for a period of 18 months with effect from July 1, 2004.
The “Shell” Transport and Trading Company, Public Limited Company
Shell Transport’s earnings for the year 2003 amounted to £2,974.6 million (£2,560.3 million in 2002; £2,877.0 million in 2001). The amount available for distribution (inclusive of distributions from companies of the Royal Dutch/Shell Group) was £1,362.4 million in 2003 (£1,404.0 million in 2002; £2,547.3 million in 2001).
Shell Transport’s net assets at December 31, 2003 were £16,560.1 million, in comparison with £15,442.4 million (restated) at the end of 2002. Of these two amounts, £16,279.2 million and £15,000.8 million (restated) respectively represented Shell Transport’s share in the net assets of companies of the Royal Dutch/Shell Group.
A second interim dividend of 9.65p per 25p Ordinary share has been paid for 2003. Dividends totalling 15.75p per 25p Ordinary share were paid in respect of 2003, in comparison with dividends paid of 15.25p and 14.8p for 2002 and 2001, respectively.
As further described in Note 2 to the Shell Transport Financial Statements, the Group Financial Statements have been restated for certain periods.
Share buyback
Royal Dutch/Shell Group of Companies
| Summarised Financial Data (US GAAP)c | ||||||||||||||||||||
| Income data | $ million | |||||||||||||||||||
| 2002a | 2001a | 2000a | 1999a | |||||||||||||||||
| 2003 | As restated | As restated | As restated | As restated | ||||||||||||||||
Sales proceeds | ||||||||||||||||||||
Oil and gasb | 248,569 | 207,342 | 153,075 | 165,563 | 127,906 | |||||||||||||||
| Chemicals | 19,459 | 14,659 | 13,767 | 15,658 | 13,408 | |||||||||||||||
| Other | 864 | 767 | 589 | 481 | 826 | |||||||||||||||
Gross proceedsb | 268,892 | 222,768 | 167,431 | 181,702 | 142,140 | |||||||||||||||
| Sales taxes, excise duties and similar levies | 67,164 | 56,167 | 42,070 | 42,365 | 44,340 | |||||||||||||||
Net proceedsb | 201,728 | 166,601 | 125,361 | 139,337 | 97,800 | |||||||||||||||
Earnings by industry segment | ||||||||||||||||||||
| Exploration and Production | 9,105 | 6,796 | 7,963 | 9,931 | 4,749 | |||||||||||||||
| Gas & Power | 2,289 | 774 | 1,226 | 112 | 398 | |||||||||||||||
| Oil Products | 2,860 | 2,627 | 1,970 | 2,681 | 3,587 | |||||||||||||||
| Chemicals | (209 | ) | 565 | 127 | 1,033 | 1,148 | ||||||||||||||
| Other industry segments | (267 | ) | (110 | ) | (287 | ) | (12 | ) | (28 | ) | ||||||||||
Total operating segments | 13,778 | 10,652 | 10,999 | 13,745 | 9,854 | |||||||||||||||
| Corporate | (917 | ) | (751 | ) | (320 | ) | (825 | ) | (538 | ) | ||||||||||
| Minority interests | (365 | ) | (179 | ) | (329 | ) | (54 | ) | (265 | ) | ||||||||||
Net income | 12,496 | 9,722 | 10,350 | 12,866 | 9,051 | |||||||||||||||
Assets and liabilities data(at December 31) $ million | ||||||||||||||||||||
| Total fixed and other long-term assets | 124,480 | 111,803 | 80,936 | 76,949 | 83,837 | |||||||||||||||
| Net current assets/(liabilities) | (10,813 | ) | (13,546 | ) | (2,750 | ) | 3,778 | (2,730 | ) | |||||||||||
| Total debt | 20,127 | 19,691 | 5,820 | 7,427 | 12,931 | |||||||||||||||
Parent Companies’ interest in Group net assets | 72,848 | 60,444 | 56,244 | 57,669 | 56,602 | |||||||||||||||
| Minority interests | 3,428 | 3,582 | 3,476 | 2,904 | 2,855 | |||||||||||||||
Capital employed | 96,403 | 83,717 | 65,540 | 68,000 | 72,388 | |||||||||||||||
Cash flow data$ million | ||||||||||||||||||||
Cash flow provided by operating activities | 21,719 | 16,283 | 16,905 | 18,278 | 11,053 | |||||||||||||||
| Capital expenditure (including acquisitions) | 12,252 | 21,027 | 9,598 | 6,128 | 7,403 | |||||||||||||||
Cash flow used in investing activities | 8,252 | 20,633 | 9,080 | 1,490 | 3,017 | |||||||||||||||
| Dividends paid | 6,548 | 7,189 | 9,627 | 5,501 | 5,611 | |||||||||||||||
Cash flow used in financing activities | 12,586 | 53 | 11,562 | 9,125 | 6,256 | |||||||||||||||
Increase/(decrease) in cash and cash equivalents | 396 | (5,114 | ) | (4,761 | ) | 7,388 | 1,326 | |||||||||||||
Other statistics | ||||||||||||||||||||
Total debt ratioc | 20.9% | 23.5% | 8.9% | 10.9% | 17.9% | |||||||||||||||
| a | The Group Financial Statements have been restated. See Note 2 to the Group Financial Statements. |
| b | Certain prior period amounts have been reclassified, resulting in a reduction in sales proceeds and a corresponding reduction in cost of sales following the implementation of US accounting guidance EITF Issue No. 02-03. |
| 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. |
| Capital investment | $ million | ||||||||||||||||||||
| 2002 | 2001 | 2000 | 1999 | ||||||||||||||||||
| 2003 | As restated | As restated | As restated | As restated | |||||||||||||||||
Capital expenditurea | |||||||||||||||||||||
Exploration and Productionb | 8,129 | 13,064 | 6,847 | 3,720 | 4,131 | ||||||||||||||||
| Gas & Power | 1,021 | 471 | 313 | 288 | 470 | ||||||||||||||||
| Oil Products | 2,367 | 7,653 | 1,462 | 1,258 | 1,338 | ||||||||||||||||
| Chemicals | 470 | 680 | 685 | 726 | 1,178 | ||||||||||||||||
| Other | 265 | 494 | 291 | 136 | 286 | ||||||||||||||||
| 12,252 | 22,362 | 9,598 | 6,128 | 7,403 | |||||||||||||||||
| Exploration expense(excluding depreciation and release of currency translation differences) | 1,059 | 997 | 885 | 834 | 1,068 | ||||||||||||||||
New equity investments in associated companies | 758 | 684 | 704 | 605 | 630 | ||||||||||||||||
New loans to associated companies | 225 | 605 | 370 | 556 | 394 | ||||||||||||||||
Other investments | – | – | 224 | 414 | – | ||||||||||||||||
Total capital investment* | 14,294 | 24,648 | 11,781 | 8,537 | 9,495 | ||||||||||||||||
| *comprising | |||||||||||||||||||||
| Exploration and Production | 9,195 | 14,082 | 8,000 | 4,839 | 5,390 | ||||||||||||||||
| Gas & Power | 1,483 | 682 | 810 | 483 | 675 | ||||||||||||||||
| Oil Products | 2,398 | 7,945 | 1,518 | 1,565 | 1,356 | ||||||||||||||||
| Chemicals | 587 | 839 | 751 | 941 | 1,384 | ||||||||||||||||
| Other segments | 406 | 495 | 332 | 153 | 296 | ||||||||||||||||
| New loans to associated companies | 225 | 605 | 370 | 556 | 394 | ||||||||||||||||
| 14,294 | 24,648 | 11,781 | 8,537 | 9,495 | |||||||||||||||||
| Quarterly income data | $ million | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2003 | As restated | As restated | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Q4 | Q3 | Q2 | Q1 | Year | Q4 | Q3 | Q2 | Q1 | Year | Q4 | Q3 | Q2 | Q1 | Year | ||||||||||||||||||||||||||||||||||||||||||||||
| Gross proceeds | 68,562 | 66,116 | 64,862 | 69,352 | 268,892 | 60,496 | 59,289 | 55,111 | 47,872 | 222,768 | 38,721 | 41,169 | 43,586 | 43,955 | 167,431 | |||||||||||||||||||||||||||||||||||||||||||||
| less:Sales taxes, excise duties and similar levies | 18,131 | 16,669 | 16,804 | 15,560 | 67,164 | 15,734 | 14,518 | 13,221 | 12,694 | 56,167 | 10,670 | 10,430 | 10,170 | 10,800 | 42,070 | |||||||||||||||||||||||||||||||||||||||||||||
| Net proceeds | 50,431 | 49,447 | 48,058 | 53,792 | 201,728 | 44,762 | 44,771 | 41,890 | 35,178 | 166,601 | 28,051 | 30,739 | 33,416 | 33,155 | 125,361 | |||||||||||||||||||||||||||||||||||||||||||||
| Cost of sales | 41,909 | 41,477 | 40,323 | 43,791 | 167,500 | 36,749 | 37,219 | 35,168 | 28,861 | 137,997 | 23,041 | 24,403 | 25,007 | 24,940 | 98,381 | |||||||||||||||||||||||||||||||||||||||||||||
| Gross profit | 8,522 | 7,970 | 7,735 | 10,001 | 34,228 | 8,013 | 7,552 | 6,722 | 6,317 | 28,604 | 5,010 | 6,336 | 7,419 | 8,215 | 26,980 | |||||||||||||||||||||||||||||||||||||||||||||
| Operating profit | 4,210 | 4,925 | 4,798 | 7,875 | 21,808 | 4,351 | 5,227 | 4,327 | 4,421 | 18,326 | 1,500 | 4,599 | 6,186 | 6,902 | 19,187 | |||||||||||||||||||||||||||||||||||||||||||||
| Net income | 1,917 | 2,453 | 2,604 | 5,522 | 12,496 | 2,307 | 2,617 | 2,335 | 2,463 | 9,722 | 635 | 2,424 | 3,512 | 3,779 | 10,350 | |||||||||||||||||||||||||||||||||||||||||||||
| a | Includes the acquisitions in 2002. 2002 also included $1.3 billion for DEA (paid in July 2003). |
| b | Includes capital expenditure on the Athabasca oil sands project. |
| US dollar exchange ratesa | €1 = $ | ||||||||||||||||||
| Averageb | High | Low | Period end | ||||||||||||||||
| Year: | |||||||||||||||||||
1998c | 0.8996 | ||||||||||||||||||
| 1999 | 1.0588 | ||||||||||||||||||
| 2000 | 0.9209 | ||||||||||||||||||
| 2001 | 0.8909 | ||||||||||||||||||
| 2002 | 0.9495 | ||||||||||||||||||
| 2003 | 1.1411 | ||||||||||||||||||
| Month: | |||||||||||||||||||
| 2003 | July | 1.1580 | 1.1164 | ||||||||||||||||
| August | 1.1390 | 1.0871 | |||||||||||||||||
| September | 1.1650 | 1.0845 | |||||||||||||||||
| October | 1.1833 | 1.1609 | |||||||||||||||||
| November | 1.1995 | 1.1454 | |||||||||||||||||
| December | 1.2597 | 1.1956 | |||||||||||||||||
| 2004 | January | 1.2853 | 1.2395 | ||||||||||||||||
| February | 1.2848 | 1.2426 | |||||||||||||||||
| March | 1.2431 | 1.2088 | |||||||||||||||||
| April | 1.2358 | 1.1802 | |||||||||||||||||
| May | 1.2274 | 1.1801 | |||||||||||||||||
| As at June 14, 2004 | 1.2073 | ||||||||||||||||||
| £1 = $ | |||||||||||||||||||
| Averageb | High | Low | Period end | ||||||||||||||||
| Year: | |||||||||||||||||||
| 1998 | 1.6602 | ||||||||||||||||||
| 1999 | 1.6146 | ||||||||||||||||||
| 2000 | 1.5138 | ||||||||||||||||||
| 2001 | 1.4382 | ||||||||||||||||||
| 2002 | 1.5084 | ||||||||||||||||||
| 2003 | 1.6450 | ||||||||||||||||||
| Month: | |||||||||||||||||||
| 2003 | July | 1.6718 | 1.5867 | ||||||||||||||||
| August | 1.6170 | 1.5728 | |||||||||||||||||
| September | 1.6642 | 1.5732 | |||||||||||||||||
| October | 1.7025 | 1.6598 | |||||||||||||||||
| November | 1.7219 | 1.6693 | |||||||||||||||||
| December | 1.7842 | 1.7200 | |||||||||||||||||
| 2004 | January | 1.8511 | 1.7902 | ||||||||||||||||
| February | 1.9045 | 1.8182 | |||||||||||||||||
| March | 1.8680 | 1.7943 | |||||||||||||||||
| April | 1.8564 | 1.7674 | |||||||||||||||||
| May | 1.8369 | 1.7544 | |||||||||||||||||
| As at June 14, 2004 | 1.8148 | ||||||||||||||||||
| 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-dollar exchange rates prior to the fixing of the euro conversion rate in January 1999 are derived from guilders-per-dollar exchange rates and the fixed guilders-per-euro conversion rate of 2.20371. |
Overview
Group strategy
The Group’s strategic direction has four main elements:
| – | increasing the proportion of the portfolio in the upstream businesses (Exploration and Production and Gas & Power), and whilst also increasing the share of natural gas production relative to oil production. This is expected to be achieved primarily through the allocation of capital investment over time; |
| – | maintaining profitable growth in downstream businesses, focusing on areas of strength. This provides balance in the portfolio, reducing exposure to volatile commodity prices, and provides cash generation to support investment in the upstream businesses; |
| – | generation of new income streams; these include activities arising from new technology such as oil sands production and gas to liquids conversion, from provision of oil and gas processing services, and from new energy sources such as wind and solar power; and |
| – | focusing on geographical opportunities; in the upstream businesses on areas of resource opportunity such as Russia and West Africa, and in Oil Products in growing markets (such as China) and in North America, where the Group has increased its presence, and in Chemicals in China. |
Exploration and Production
Volatility in oil prices and potential cost increases are the key challenges and risks in the exploration and production business. The geographic balance of the portfolio, and the recent globalisation of the business are the main mitigators of these risks. Around one half of current production is relatively less sensitive to the oil price, as it is either gas price related or because the structure of the fiscal or related contracts provides some protection against lower prices. The reorganisation of the business on a global basis is aimed at more efficient allocation of resources, and the continuous reduction of costs over time.
Gas & Power
The increase in gas prices in 2003 benefited results, as did a series of sales of interests in non-core gas distribution assets. LNG sales volumes continued to grow to a record 9.3 million tonnes. The Group continues to invest in LNG and expects to increase its equity LNG capacity by approximately 70% over the next four years through the addition of five new LNG trains.
Principal challenges and risks in the Gas & Power business are to ensure assets are developed in each part of the LNG value chain in alignment with market growth, and the attractiveness of the power generation markets, particularly in North America. The Group is addressing the first challenge through the development of a number of supply, shipping and importation facilities in the various key markets, and the latter challenge through focus on current operations rather than new development in power, supplemented by asset divestments.
Oil Products
2003 saw stronger refining conditions globally and increases in refining and marketing margins. In the USA, a key challenge is to achieve a stronger competitive position following the acquisitions of the Texaco assets and Pennzoil Quaker State Inc. in 2002. In mature markets such as the US and Western Europe, portfolio rationalisation and optimisation have been industry trends that are likely to continue, while Central and Eastern Europe and Asian markets present opportunities for growth. In the USA the announced closure of the Bakersfield refinery and the divestment of the Delaware City refinery illustrate the ongoing effort to eliminate under-performing downstream assets. Also in the USA, the Group is building on its strength in consumer-led businesses, including restructuring retail operations to implement the global business model. From January 2004, all lubricants business activities were consolidated into a single global organisation.
The key challenges and uncertainties in oil products are volatility in refining margins and competitive costs. Approximately two thirds of the Group’s Oil Products earnings derive from marketing activities, and continuous cost reduction remains a key management objective.
Chemicals
Financial framework
The dividend policy is to grow dividends in the Parent Company currencies by at least inflation over time. In 2003 the dividends paid out to shareholders exceeded $6 billion, and the US dollar amount paid out does depend on exchange rates between the euro, sterling and the US dollar. A Group share of capital investment of around $13 billion is required each year to grow the capital base in line with the dividend promise, taking into account an expected $2 billion of divestments per year. After dividends and capital investment, the priority for use of cash generated is the maintenance of a prudent balance sheet, most likely through debt reduction.
Recent Developments
Reserves Restatement and Financial Restatement
In view of the inappropriate overstatement of unaudited proved reserves information, it was determined to restate the financial statements of the Group and each of the Parent Companies as at December 31, 2002 and 2001 and for each of the years ended December 31, 2002, 2001 (the Financial Restatement) to reflect the impact of the Reserves Restatement on those financial statements (as announced on April 19, 2004). The financial statements have also been 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 and 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 Financial Restatement also includes 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.
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 and 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 resigned from her position as Group Chief Financial Officer, Group Managing Director and Executive Director of Shell Transport on April 18, 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 has been appointed non-executive Chairman of Shell Transport and Chairman of Conference; and Malcolm Brinded has been appointed Chief Executive of Exploration and 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 and has been appointed as a Managing Director of Shell Transport; he remains Chief Executive of Gas & Power. Tim Morrison, currently Group Controller, has also been appointed Acting Chief Financial Officer. On June 23, 2004, Peter Voser was appointed Group Chief Financial Officer and a Director of Shell Transport with effect from October 4, 2004.
Summary of Group results
| Earnings (US GAAP) | $ million | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
Net income | 12,496 | 9,722 | 10,350 | |||||||||
Change from previous year | +29% | -6% | -20% | |||||||||
2003 compared to 2002
Exploration and Production earnings were 34% higher than last year at $9,105 million. Total hydrocarbon production1
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 reserves replacement ratio in 2003 was 63%, including the impact of the Reserves Restatement. The Group’s total proved reserves at the end of 2003 were 14.35 billion barrels of oil equivalent. (More detailed information on reserves is available on pages 47, 48 and 50.)
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 liquefied natural gas 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 reflect asset impairment and restructuring charges totalling $478 million.
Total capital investment2 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 ratio3 was 20.9%. Cash and cash equivalents amounted to $2.0 billion.
All Group financial information contained in this section is presented in accordance with accounting principles generally accepted in the United States. The restatements described below are reflected in prior period information where applicable.
In view of the inappropriate overstatement of unaudited proved reserves information, it has been decided to restate the Financial Statements of the Group, and each of the Parent Companies, for prior periods (the Financial Restatement) to reflect the impact of the Reserves Restatement on those Financial Statements (as announced on April 19, 2004).
In addition, the Financial Statements have been restated to reflect the correction of inappropriate accounting policies relating to the treatment of exploration costs and certain contracts for the sale and delivery of own natural gas production. The Financial Statements have also been restated to reflect a change in accounting policy relating to certain inventories in North America from the last-in first-out (LIFO) to the first-in first-out (FIFO) method.
See page 67 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 Restatement.
2002 compared to 2001
| 1 | Includes oil sands. |
| 2 | Capital investment is capital expenditure, exploration expense and investments in associated companies. |
| 3 | 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. |
Four major acquisitions were completed: Enterprise Oil (Enterprise) in the UK, DEA Oil (DEA) in Germany, and Pennzoil-Quaker State and the Texaco downstream assets in the USA. Total investment in these acquisitions, including acquired debt, was over $16 billion.
Total capital investment for the year amounted to $24.6 billion including acquisitions. Excluding major acquisitions, capital investment totalled $14.2 billion. At the end of the year, the debt ratio was 23.5% (2001: 8.9%) and cash, cash equivalents and short-term securities amounted to $1.6 billion.
Hydrocarbon production was the highest in recent history at four million barrels of oil equivalent per day. Brent crude oil prices averaged $25.05 a barrel compared with $24.45 a barrel in 2001. Production constraints in some countries led to a steady price increase in the first three quarters of the year. Crude oil prices subsequently weakened only to rebound to $30 a barrel at the end of the year when Venezuelan supply was disrupted. In 2004, the Group restated oil and gas volumes to remove volumes from the proved category.
In Gas & Power, the LNG business continued to grow, delivering record volumes, although lower realised gas prices led to a decline in earnings. Global demand for LNG remained firm. In Oil Products, industry refining margins over the year were poor, at their lowest for a decade, while marketing margins were squeezed by rising crude oil prices.
Chemicals saw some signs of improvement in the business environment but it was still a very challenging year due to difficult trading conditions, particularly in the USA. Industry utilisation rates remained flat in Europe but improved in the USA from historically low levels in 2001. Cracker margins in both regions were down from a year ago.
Exploration and Production
| Earnings (US GAAP) | $ million | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Net proceeds (including inter-segment sales) | 32,725 | 26,581 | 25,847 | |||||||||
| Purchases (including change in inventories) | (1,536 | ) | (1,050 | ) | (1,444 | ) | ||||||
| Exploration | (1,476 | ) | (1,073 | ) | (910 | ) | ||||||
| Depreciation | (7,087 | ) | (5,492 | ) | (3,875 | ) | ||||||
| Operating expenses | (7,252 | ) | (6,751 | ) | (5,474 | ) | ||||||
| Operating profit of Group companies | 15,374 | 12,215 | 14,144 | |||||||||
| Group share of operating profit of associated companies | 1,876 | 1,322 | 1,550 | |||||||||
| Operating profit | 17,250 | 13,537 | 15,694 | |||||||||
| Other income/(expense) | 72 | 72 | 48 | |||||||||
| Taxation | (8,472 | ) | (6,813 | ) | (7,779 | ) | ||||||
| Cumulative effect of a change in accounting principle | 255 | – | – | |||||||||
Segment earnings | 9,105 | 6,796 | 7,963 | |||||||||
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 $27.43 a barrel compared with $23.54 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)2.
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
| 1 | Includes oil sands. |
| 2 | For this purpose, the Group has converted natural gas to crude oil equivalent using a factor of 5,800 standard cubic feet per barrel. |
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.
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 north-west 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.
We expect total hydrocarbon production for 2004 to remain broadly flat with a dip in 2005. Factors impacting production include divestment and the effect of oil and gas prices on economic entitlements. We expect production to increase again from 2006 onwards, as the development of new growth positions in offshore Nigeria, Russia, Qatar and Kazakhstan gain momentum.
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 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 see ongoing opportunities for growth. They include North America, north-west 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 an exciting new market. The Group’s leading position in LNG is being maintained through a range of investments in Nigeria, Oman, Malaysia and Australia, as well as a commitment with Shell Gas & Power to the Sakhalin II project in the far east of Russia. Investment in deepwater projects 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 and 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 Shell reached an agreement for the sale of its 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
March 18, 2004 and April 19, 2004. The total Reserves Restatement, relative to the proved reserves originally stated as at December 31, 2002, represents 4.47 billion boe of proved reserves at that date. Furthermore, additions to proved reserves during 2003 have been reduced by approximately 400 million boe relative to the figures announced on February 5, 2004.
The impact of the Reserves Restatement, when taken together with production in 2003 (1.408 billion boe) and net additions to reserves in 2003 (some 0.885 billion boe) leads to proved reserves of 14.35 billion boe at December 31, 2003. The Reserves Restatement was based on a review of the Group’s proved reserves inventory conducted between late 2003 and April 2004, the latter part with the assistance of external consultants.
As at December 31, 2002, 88% of the de-booked proved reserves volumes had originally been disclosed in the “proved undeveloped” reserves category; the balance was a reduction in the “proved developed” reserves category. Approximately two-thirds of the de-booked volumes relate to crude oil and natural gas liquids with the remaining one-third relating to natural gas.
As at December 31, 2002, proved reserves, excluding the impact of the Reserves Restatement, had been equivalent to 13.3 years of production. Including the impact of the Reserves Restatement, the figure was 10.3 years. At December 31, 2003, following the Reserves Restatement, proved reserves were equivalent to 10.2 years of production.
Reserves replacement
The 885 million boe addition in 2003 comprises revisions (-211 million boe, or approximately 190 million boe before the restatement reductions), improved recovery (153 million boe), extensions and discoveries (1,211 million boe) and acquisitions and divestments
(-268 million boe). Increases in minority interests represent approximately 220 million boe of the total additions.
The overall proved reserves replacement ratio for the five years from 1999 to 2003 amounts to 66% taking into account all effects of the Reserves Restatement. This is clearly a concern and reflects the exploration strategy in the 1990s, and our relatively low investment in the post 1998 period. Exploration has since been refocused and investment levels increased. It is vital that our reserves replacement ratio improves significantly in the coming years.
Outlook and strategy
The concerns noted above on recent reserves replacement performance highlight the importance of replenishing the portfolio through successful and increased exploration efforts and through business development opening up new opportunities such as LNG, unconventional resources such as oil sands, and deep water. Such organic business revitalisation is essential and will be sustained by significant capital investment (some $12 billion in the “upstream” Exploration and Production and Gas & Power businesses in 2004). The scale and reach of the Exploration and Production business provides significant scope for improved global resource allocation, best practice application of processes, standardisation and contracting leverage. A key step in unlocking value was the introduction of a new “global operating model” in 2003, which will allow us to realise efficiencies by operating from regional hubs, to strengthen our technical and operational excellence and further enhance our global growth capability.
Over the past 20 years the Brent crude oil price has averaged around $20 a barrel and over the past three years the price averaged almost $26 a barrel. We expect that crude oil prices in 2004 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. 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 2004 is uncertain and impacted by developments in the Middle East and Venezuela. The Group evaluates investments using multiple price conditions, including price conditions of less than $20 a barrel to assess the resilience of investments at low-price conditions.
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 2003, 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.
2002 compared to 2001
Earnings
In 2002, the Group’s realised gas prices in the USA averaged $3.31 per thousand standard cubic feet compared with $4.44 in 2001. Outside the USA, realised gas prices were also lower than in 2001 and averaged $2.15 per thousand standard cubic feet, representing a 7% reduction from 2001 price of $2.30. Declines in market gas prices during 2002 contributed to the Group’s lower realised gas prices. In 2002, Henry Hub gas prices averaged $3.33 per million Btu, compared to $4.10 in the previous year when gas prices spiked to around $10 per million Btu during the 2000/2001 winter. The first three quarters of 2002 showed lower gas prices compared to 2001 due to the build up of storage.
In 2002, the Group’s realised oil prices for world outside USA averaged $23.54 a barrel compared with $23.19 in 2001, while USA realised oil prices averaged $22.72 a barrel compared with $22.14 in 2001. In 2002, Brent crude oil prices averaged $25.05 a barrel compared with $24.45 in the previous year. This was in line with sensitivity analyses developed in 2001, when end year crude oil prices were at around $20 a barrel after September 11 but tightening of the global supply/demand balance was expected to increase prices. Brent crude oil prices recovered steadily in the first three quarters of the year from below $20 to exceed $30 a barrel reflecting production constraints in certain countries. Prices subsequently weakened only to rebound to $30 a barrel at the end of the year when supply from Venezuela was disrupted. Overall, levels of realised crude oil and gas prices in 2002 decreased segment earnings (after taxes) by approximately $600 million compared to 2001.
In addition to the lower gas price realisations, costs and depreciation were higher, with significant impacts related to the Enterprise Oil acquisition and approximately $170 million in feasibility study costs in the Sakhalin project (Russia). The increase in operating expenses also reflects unfavourable exchange rate movements of the US dollar against other major currencies, including the euro and the Pound sterling.
Segment earnings in 2002 were also negatively impacted by some $300 million of provisions for deferred taxation, resulting from a non-recurring charge due to fiscal changes in the UK.
Total hydrocarbon production for 2002 rose by 6%, comprising a 7% increase in oil production and a 4% increase in gas production. Oil production benefited from the acquisitions of Enterprise, an additional interest in the Draugen field in Norway and new fields in the USA and Denmark. These increases were partly offset by lower OPEC production quotas, normal field declines, and divestments in New Zealand and elsewhere. Gas production also increased as a result of the acquisition of Enterprise and from new fields in the USA. These increases were partly offset by decreases in production as a result of lower demand due to warmer weather in Europe; normal field declines in the USA and divestments in New Zealand. Excluding the contribution of Enterprise volumes, total hydrocarbon production was 1% higher in 2002 than 2001.
Portfolio actions
These new assets provided an immediate boost to global production and are contributing an additional 240,000 boe/day. The portfolio was further enhanced by the acquisition of an increased stake in the Norwegian Draugen field where Group interest was increased by 10% to 26.2%. The North American gas portfolio was improved through the acquisition of new fields in the Pinedale, Wyoming area. The exploration portfolio was refreshed and achieved an exploration and appraisal global success-rate of some 55% including significant discoveries in the USA Gulf of Mexico, such as Great White, Deimos and Tahiti. In Kazakhstan, the Kashagan Field (Group interest 16.7%) was declared commercial, however, in the restated proved reserves figures contained herein, no proved reserves have been reflected pending government approval for the development. The more recent discovery of the Kalamkas field further underlines the immense potential of the Kazakhstan region. Major discoveries were also made in Brazil, Ireland and Nigeria. New exploration licences were acquired in geographic areas where the Group has strategic interests such as USA Gulf of Mexico and Norway.
| 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. |
The result of these portfolio actions, together with the Group’s ability to develop and implement technology strengthens the Group’s portfolio.
Capital investment
Reserves
The impact of the Reserves Restatement, when taken together with production in 2002 (1.444 billion boe) and net additions to reserves in 2002 (1.754 billion boe) leads to proved reserves of 14.87 billion boe at December 31, 2002. The Reserves Restatement was based on a review of the Group’s proved reserves inventory conducted between late 2003 and April 2004, the latter part with the assistance of external consultants.
As at December 31, 2002, 88% of the hydrocarbon volumes de-booked had originally been disclosed in the “proved undeveloped” reserves category; the balance was a reduction in the “proved developed” reserves category. Approximately two-thirds of the de-booked volumes relate to crude oil and natural gas liquids with the remaining one-third relating to natural gas.
As at December 31, 2002, proved reserves, excluding the impact of the Reserves Restatement, had been equivalent to 13.3 years of production. Including the impact of the Reserves Restatement, the figure was 10.3 years.
Reserves replacement
The overall proved reserves replacement ratio for the five years from 1998 to 2002 amounts to 80% taking into account all effects of the Reserves Restatement. This is clearly a concern and reflects the exploration strategy in the 1990s, and our relatively low investment in the post 1998 period. Exploration has since been refocused and investment levels increased. It is vital that our reserves replacement ratio improves significantly in the coming years.
Gas & Power
| Earnings (US GAAP) | $ million | |||||||||||
| 2003 | 2002 | 2001 | ||||||||||
Net proceeds (including inter-segment sales)a | 8,248 | 4,898 | 6,656 | |||||||||
Purchases (including change in inventories)a | (6,437 | ) | (3,730 | ) | (5,191 | ) | ||||||
| Depreciation | (128 | ) | (128 | ) | (106 | ) | ||||||
| Operating expenses | (1,163 | ) | (933 | ) | (821 | ) | ||||||
| Operating profit of Group companies | 520 | 107 | 538 | |||||||||
| Group share of operating profit of associated companies | 889 | 751 | 941 | |||||||||
| Operating profit | 1,409 | 858 | 1,479 | |||||||||
| Other income/(expense) | 1,343 | 124 | 132 | |||||||||
| Taxation | (463 | ) | (208 | ) | (385 | ) | ||||||
Segment earnings | 2,289 | 774 | 1,226 | |||||||||
| a | Certain prior period amounts have been reclassified, resulting in a reduction in sales proceeds and a corresponding reduction in cost of sales, following the implementation of US accounting guidance EITF Issue No. 02–03, see Note 3 on page G11. |
2003 compared to 2002
Group share LNG sales of 9.3 million tonnes. The increase in volumes of 3% versus last year was mainly a result of strong market demand and the build up of the third production train (liquefaction plant) in Nigeria LNG (Group interest 26%), offset by exit from the Malaysia LNG Satu company (Group interest 15%).
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 value 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. Both are planned to be important strategic assets, delivering many years of sustained cashflow.
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 is a growing market for imported LNG. Access has been gained to the East Coast gas market as a result of the reopening of the Cove Point LNG regasification 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 (now under construction) for the power market in Mexico; the Group interest in this project was reduced to 75% in the first quarter of 2004. We also announced a joint project (Group interest 50%) which plans to construct an LNG receiving terminal at Baja California, Mexico to supply Mexico and the USA. We aim 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. We 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. In the growing Asian market, construction is underway on a new LNG terminal in Hazira providing access to markets in north-west India; in 2004 we announced the sale of a 26% interest, subject to approvals.
We further strengthened our leadership position in LNG 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 to the USA and Europe from trains 4 and 5. In support of growing LNG supply and trading activities, we 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 the year was 10.5GW (InterGen net equity interest).
In Europe, restructuring of our operations continued with the establishment of Shell Energy Europe, which is designed to grow our pan-European transport, marketing and trading gas business. We also sold our indirect interests in Ruhrgas, our direct interest in Thyssengas and interests in other gas transport companies in Germany. In early 2004 the sale of an indirect interest in VNG, a German gas transport and marketing company, was also completed.
Outlook and strategy
In Asia Pacific strong long-term LNG growth in emerging gas markets like China and India is expected to complement renewed growth in the world’s largest LNG market, Japan, especially if nuclear power generation does not materialise. In the short term, economic weakness and uncertainty may continue to constrain gas growth in some markets and success in emerging markets may at times be slow and not without economic risk. However, over the longer term, the abundance and flexibility of gas is expected to make it the preferred fuel for power generation, heating, and in the production of ultra-clean liquid fuels.
In close alignment with Exploration and Production, Gas & Power will develop opportunities provided by the growing penetration of natural gas in world energy markets. The Gas & Power business focuses on accessing gas markets in order to accelerate the monetisation of existing fields and secure new upstream resources. We will continue to strengthen and develop our leading role in LNG mainly through associated companies, building on our strong commercial relationships and cost leadership. Over the next four years, five new LNG trains in associated companies will increase the Group share of worldwide LNG capacity. New technologies such as Gas to Liquids will be developed to provide additional income streams. As a number of power markets continue to face near-term oversupply, parts of our portfolio may see depressed returns. Over the long term, selective power investments and midstream opportunities (pipeline and gas storage) that enable or add value to gas monetisation remain an appropriate part of our strategy. Our marketing and trading businesses will be used to secure customers for short, medium and long-term sales agreements and to increase the return from our gas and power sales.
2002 compared to 2001
Our average realised LNG prices were 11% lower than 2001 as a result of the time-lagged effect on LNG prices of the decline in crude oil prices during the second half of 2001 and the first quarter of 2002 and a higher proportion of LNG sales on the spot market (which generally experienced lower prices than in the contract market) compared to 2001. This reduction more than offsets the record Group share LNG sales of 9.1 million tonnes, which was 3% higher than 2001. Increased sales came mainly from uncommitted capacity available from the Oman LNG plant (Group interest 30%) and from continued higher demand in Japan.
Results from trading activities were lower by $177 million (after taxes) primarily due to gas and power trading losses in North America. The power generation business saw increased capacity, improved operations and lower costs (mainly relating to assets outside the USA with long-term sales contracts) but these favourable impacts were more than offset by a $150 million write-down related to the Group’s carrying value of InterGen (an associated company, Group interest 68%) due to a reassessment of the impact of continued poor merchant power market conditions in the USA and UK.
Earnings included $163 million of gains from the sale of Shell’s direct and indirect interests in Midstream assets in Europe and the USA and a share of the Group’s interest in Brunei Shell Tankers.
Capital investment
Actions by associated companies
In addition, the Group is actively progressing access to the North American market through LNG terminal capacity at Cove Point and Elba Island in the USA, and other potential sites. Gas & Power’s other businesses also progressed during 2002. In the Middle East, significant progress was made towards the development of world-scale Gas to Liquids facilities.
In power, InterGen (Group interest 68%), a joint venture with Bechtel, started operations at projects in Turkey, Egypt and Mexico, increasing InterGen’s operational capacity by 70% during the year to 5.2 Gigawatts. There were long-term power purchase agreements in place for this new capacity.
Portfolio actions
Oil Products
| Earnings (US GAAP) | $ million | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Net proceeds (including inter-segment sales) | 165,577 | 138,624 | 95,625 | |||||||||
| Purchases (including change in inventories) | (144,639 | ) | (120,493 | ) | (83,037 | ) | ||||||
| Gross margin | 20,938 | 18,131 | 12,588 | |||||||||
| Depreciation | (2,863 | ) | (2,406 | ) | (1,617 | ) | ||||||
| Operating expenses | (14,870 | ) | (12,537 | ) | (8,490 | ) | ||||||
| Operating profit of Group companies | 3,205 | 3,188 | 2,481 | |||||||||
| Group share of operating profit of associated companies | 911 | 556 | 241 | |||||||||
| Operating profit | 4,116 | 3,744 | 2,722 | |||||||||
| Other income/(expense) | (4 | ) | (50 | ) | (62 | ) | ||||||
| Taxation | (1,252 | ) | (1,067 | ) | (690 | ) | ||||||
Segment earnings | 2,860 | 2,627 | 1,970 | |||||||||
2003 compared to 2002
Gross margin (calculated as net proceeds minus purchases) increased by $2,807 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 contrasts 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 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 $2,333 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 69% in 2002, to 71% in 2003. The weakening 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. Within the USA, operating expenses declined one percentage point of gross margin in 2003. This reflected continued progress in reducing personnel levels and marketing costs, both of which are associated with the 2002 acquisition of the Texaco downstream assets. Offsetting these reductions however, were higher provisions for anticipated environmental and legal settlements associated primarily with prior year MTBE (an additive used in gasoline) use. Future developments may require additional provisions.
There was increased income from associated companies of $355 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 $457 million, due primarily to portfolio actions taken during the year. Charges were higher due to the decision taken to close the Bakersfield refinery in the USA as a result of declining local crude supply ($213 million) and to impair assets in certain Latin American countries due to local economic conditions ($66 million). The impairment decisions were taken as part of an ongoing effort to address underlying portfolio performance issues. Continued focus on divesting non-performing or non-strategic assets may lead to future charges of a similar magnitude to 2003. Additionally, depreciation charges increased due to the full-year consolidation of Pennzoil-Quaker State (acquired in the fourth quarter, 2002).
Potential risks to future earnings centre around refinery reliability, particularly in the USA. Continued improvement in this key area of operational performance will have a significant effect on our ability to deliver sustained future earnings. In other areas, the January 2004 launch of Global Lubricants and the 2003 alliance with Coles Myer in Australia (both described overleaf) will be important factors to continued earnings growth, as will the continued economic recovery in Argentina and Brazil.
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 has been 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 have been reduced by over 2,000 as business structures have been simplified. Progress on integrating the US acquisitions is going according to plan and is expected to be concluded by the end of 2004. 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, we 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, we reached an agreement with retailer Coles Myer to operate Shell retail sites across the country providing improved service and choice for customers. Under our differentiated fuels strategy, premium fuels continued to be launched in key markets, including V-Power in Germany. In January 2004, we launched our new Global Lubricants business. Operating in more than 120 countries with an extensive network of base oils and blending plants, the business produces a large range of high-quality lubricants. These initiatives will help to improve our retail efficiency and grow higher value product sales.
We 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, we completed the sale of our interest in the Excel Paralubes base oil plant, sold a number of retail sites in Germany in order to meet the regulatory requirements for the DEA acquisition and announced the 2004 closure of the Bakersfield refinery in California. Shell Gas Italia announced the planned sale of its non-automotive LPG interests to Liquigas. We also announced our intention to sell AB Svenska Shell in Sweden. In May 2004 Motiva Enterprises LLC (Group interest 50%) completed the sale of its Delaware City refinery. In 2004 we also announced plans to restructure operations in Venezuela which will include transferring our role as wholesaler to local entrepreneurs during 2004.
Outlook and strategy
The high refining margins in 2003 resulted from a number of exceptional factors. We expect the level of refining margins in 2004 will ultimately depend on the pace of global economic expansion, the severity of the northern hemisphere winter, OPEC supply policy, and potential product supply disruptions as specification changes in the USA are introduced. Marketing margins will continue to be influenced by oil price volatility and exchange rates and will be subject to intense competition in the mature markets.
We will retain our focus on improving and developing products and services for our customers, including the continued development of new products such as differentiated retail fuels. Improvements to supply chain management will be one of our main priorities. We will continue to upgrade our portfolio and to strive for operational excellence across all our business assets.
2002 compared to 2001
Earnings
In 2002, net proceeds increased by some $1 billion outside the USA and some $42 billion in the USA. This increase in the USA largely reflects a $43 billion change in proceeds associated with the acquisition of Texaco’s interests in Equilon Enterprises (previously accounted for as an associated company) and the fourth quarter acquisition on PQS. Gross margin (calculated as net proceeds minus purchases) similarly increased by some $5 billion in large part due to the US acquisitions in 2002.
Operating expenses increased by $4,047 million and depreciation by $789 million primarily in the USA as a result of the consolidation of the 2002 acquisitions. As a percentage of gross margin, operating expenses increased by two percentage points while depreciation remained fairly flat. The increase in operating expenses and depreciation in the USA was offset slightly by lower restructuring charges in 2002, as 2001 included $219 million (after taxes) charge related to the acquisition of the Texaco downstream assets (which acquisition was agreed to in 2001 and completed in February 2002).
Capital investment
Portfolio actions
In January 2002, Oil Products formed a 50:50 joint venture in Germany with RWE-DEA and in July the Group took ownership of 100% of the venture for cash consideration of $1.3 billion, payable in July 2003.
The acquisition of the Texaco downstream assets in the USA was completed in February 2002. Business structures have been streamlined and some 800 of the Texaco stations have been rebranded to Shell at the end of 2002, which reflects approximately 10% of the rebranding programme that is expected to be completed by the end of 2004. As part of the upgrading of the quality of the overall retail network in the USA, the total number of combined Texaco and Shell sites will be reduced by some 30%.
The purchase of PQS in the USA was completed in October 2002 after regulatory clearance. The transaction has a total equity value of $1.9 billion and the Group has also taken on $1.3 billion of debt. The acquisition will make Shell a leader in both the US and global lubricants markets. The transaction resulted in the recognition of $1.7 billion of goodwill, reflecting strong positions in a variety of market channels.
Chemicals
| Earnings (US GAAP) | $ million | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Net proceeds (including inter-segment sales) | 20,817 | 15,207 | 14,250 | |||||||||
| Purchases (including change in inventories) | (16,952 | ) | (12,035 | ) | (11,041 | ) | ||||||
| Depreciation | (678 | ) | (401 | ) | (404 | ) | ||||||
| Other cost of sales | (2,234 | ) | (1,518 | ) | (1,866 | ) | ||||||
| Operating expenses | (1,065 | ) | (815 | ) | (973 | ) | ||||||
| Operating profit of Group companies | (112 | ) | 438 | (34 | ) | |||||||
| Group share of operating profit of associated companies | (165 | ) | 213 | (27 | ) | |||||||
| Operating profit | (277 | ) | 651 | (61 | ) | |||||||
| Other income/(expense) | (43 | ) | (13 | ) | (4 | ) | ||||||
| Taxation | 111 | (73 | ) | 192 | ||||||||
Segment earnings | (209 | ) | 565 | 127 | ||||||||
2003 compared to 2002
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, we 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 our position as a supplier to manufacturers of polyurethane foams. In the Gulf Coast region of the USA, we completed a project to improve the quality of heavy olefin feed. The joint venture butadiene extraction plant in Texas started production in the first quarter of 2004.
We invested to upgrade and improve existing plants to ensure their ongoing efficiency and competitiveness. We 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. We also began work to upgrade the Aubette steam cracker at the Berre complex in the south of France. This upgrade will improve integration with the adjacent refinery as well as make it possible to reduce sulphur dioxide emissions by 25% versus the 2000 level.
We 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.
Outlook and strategy
Over the medium term we aim to be among the best performers in petrochemicals, in line with the industry’s top quartile performers. We will focus on crackers and first-line derivatives, delivering bulk petrochemicals to large industrial customers. The key strategic actions that we believe will help us to achieve those aims and partially mitigate medium-term risks are to focus on upgrading our portfolio and further streamlining global processes. Capital investment will be centred on our US crackers and on the successful start up of the Nanhai petrochemicals complex. Further standardisation of our business processes is expected to bring improvements in cost-effectiveness and in the way we respond to our customers.
2002 compared to 2001
Earnings
Operating profit from Group companies increased by $472 million primarily due to lower fixed costs and higher sales volumes, partly offset by a decline in unit margins (defined as proceeds less cost of feedstock, energy and distribution divided by sales volumes). In addition for certain inventories in North America, Shell has changed the method of inventory costing from the last-in first-out to the first-in first-out method. The cumulative impact on operating profit in 2002 relative to 2001 was an increase of $275 million. Industry utilisation remained flat in Europe, but improved in the USA from historically low levels in 2001. Lower gas feedstock prices relative to
crude oil prices in the USA made the economics of cracking liquid feedstocks less favourable. Fixed costs decreased from 2001 and reflected portfolio changes including the effects of prior year divestments (approximately $60 million), lower planned asset maintenance expenditure (approximately $40 million) and reduced information technology costs (approximately $35 million). Total unit costs, excluding feedstock costs, improved by 7% versus 2001 mainly as a result of higher volumes and lower fixed costs. The benefit of volume growth, mainly from new production capacity coming on stream, was partially negated by depressed unit margins thus making a net contribution of some $50 million to operating profit. In 2002, Chemicals earnings include $62 million of charges for asset rationalisation, mainly related to plant closures.
Group share of operating profit from associated companies increased by $240 million. This reflected a recovery in polyolefins margins relative to 2001, when margins were very depressed and margin improvements from low cost supply positions in the Middle East. In addition, associate earnings benefited from cost reductions, primarily in Basell, the 50:50 joint venture with BASF.
Taxation for the year included a credit of $102 million (2001: $65 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. Excluding these and the effects of divestments in 2001, the higher tax rate in 2002 was associated with the incidence and the nature of taxable gains and losses generated by the Chemicals business.
Capital investment
Portfolio actions
The final investment decision on the Nanhai petrochemicals project in Guangdong in China was taken. The Group has a 50% share in this $4.3 billion project, which constitutes its largest ever single Chemicals investment. Construction work is due to start in 2003, with the plant scheduled to be completed in late 2005. A key challenge for Chemicals is the management of the uncertainties inherent in projects as large and complex as those it typically undertakes. Project management processes are used on projects of this type, whereby risks are closely monitored and actions taken to mitigate as appropriate.
In 2002, Chemicals brought on-line some 2 million tonnes of new production capacity, which is approximately equal to 9% of the Group’s operated production capacity in that year. Successful completion of a fourth olefins and alcohols unit at Geismar in the USA consolidated the Group’s position as one of the world’s largest suppliers of higher olefins and detergent alcohols. The $500 million Ellba Eastern complex in Singapore started operation. This is a 50:50 joint venture with BASF to produce styrene monomer, propylene oxide and polyolefins.
A new benzene unit in the Netherlands was completed ahead of schedule. The plant uses new technology to minimise environmental impact and help reduce transportation of benzene in the Group’s European businesses. The unit will take benzene-rich streams from the Moerdijk cracker and other Shell European locations and the output will be used for styrene monomer/propylene oxide production on the same site.
Construction started at the new polymer polyol plant at Pernis in the Netherlands. The plant, which is expected to be completed in 2003, will be the largest in Europe and will consolidate the Group’s position as a leader in the global polyols market. A joint venture (Group interest 50%) was established with SGF Chimie to build and operate a polytrimethylene terephthalate plant in Montreal, Canada. These products are used in carpeting and textiles.
The drive to simplify and streamline business processes and to make it easy to do business with Shell Chemical companies continued. A single marketing and supply company for Europe was established in order to improve speed and efficiency for customers and suppliers.
Other industry segments
| Earnings (US GAAP) | $ million | |||||||||||
| 2003 | 2002 | 2001 | ||||||||||
Segment earnings | (267 | ) | (110 | ) | (287 | ) | ||||||
2003 compared to 2002
in 2003 the industry faced persistent production overcapacity, strong competition and uncertain market circumstances. The remaining losses were realised across all business lines in the segment and reflected the current year operating results of developing future business opportunities.
The sale of the main forestry operations was completed in 2003. Certain support services were transferred from Other industry segments to Corporate with effect from 2003.
With increased political and consumer support, growth in wind energy and solar power is expected to continue at more than 20% a year.
2002 compared to 2001
Renewables
Our WindEnergy business continued to grow with the construction of two new wind parks in Colorado and Texas. The park at Colorado Green will supply power to 52,000 households and is our largest wind installation so far. When combined with the Brazos wind park, Texas, this more than doubles our wind capacity in the USA to 550MW.
Shell Consumer
The launch of Shell Drive in Düsseldorf in Germany is an example of an entry into an exciting and innovative new business. Shell Drive offers urban residents, who are occasional car drivers, easy and convenient access to a vehicle. Cars are booked over the telephone or internet and are rented by the hour, day or week. They can then be picked up at a convenient location using a card access. The response so far from customers has been very positive with take-up ahead of target.
Shell Hydrogen
The first fully Shell-branded hydrogen station was opened in Iceland. This currently supplies a small fleet of public buses, but if the trial proves successful, private hydrogen vehicles could be introduced to meet the Icelandic Government’s aim of eventually replacing all fossil fuels with hydrogen.
We continue to work with governments and a range of leading business partners to develop hydrogen as an attractive and commercially viable fuel. We are building a distinctive portfolio of operational, technical and commercial knowledge to grow significant shareholder value as the markets for hydrogen fuel develop over the coming years.
Corporate
| Earnings (US GAAP) | $ million | |||||||||||
| 2003 | 2002 | 2001 | ||||||||||
Segment earnings | (917 | ) | (751 | ) | (320 | ) | ||||||
2003 compared to 2002
2002 compared to 2001
Liquidity and capital resources
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 reflects an increase of $2.9 billion in proceeds from sales of assets, including the Group’s interest in Ruhrgas, to $4.5 billion.
Outlook
Because the contribution of Exploration and Production to earnings is significantly larger than the Group’s other businesses, changes affecting Exploration and Production, particularly changes in realised crude oil and natural gas prices and production levels, have a significant impact on overall Group results. While Exploration and 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) will be 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 crude oil price changes flow through into operating costs and the impacts of natural gas prices (for example, in 2002, average realised crude oil prices rose, while average realised natural gas prices fell). Accordingly, 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 and Production.
In Oil Products, our second largest business, decreases in crude oil and natural gas prices can generally be expected to lead to short-term increases in refining and marketing margins at the time the change occurs, while increases generally result in lower margins. However, this relationship is complex, and the impact and timing of any particular change will depend upon whether and when prices of specific grades of refined products follow benchmark crude oil prices, as well as local market factors including the actions of competitors and the availability of supply of particular grades of refined oil products in the relevant market. In addition, there do not exist commonly agreed benchmarks for refinery and marketing margins, to the same extent that Brent crude oil prices and Henry Hub natural gas prices, in the USA, serve as benchmarks in the Exploration and 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 and Production, which in turn will affect the Group’s cash flow provided by operating activities and net income. After giving effect to the Reserves Restatement, the Group’s five year reserves replacement ratio for the period 1999-2003 was 66%. The field decline rate for Exploration and Production’s existing business is approximately 6 to 8 percent 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 appropriate acquisitions. The Group strives to offset the effects of field decline through these measures and, as a result, production increased in 2001 and 2002. 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 dip 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 and Production and the associated cash flow provided by operating activities. As a result of its financial strength and debt capacity, the risk associated with failure or delay 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, acquire assets 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 effect on cash flow provided by operating activities. The amount of divestments will depend on market opportunities and therefore all related assets have not yet been recorded as assets held for sale. In April 2004 Shell reached an agreement for the sale of its 50% interest in offshore Block 18 in Angola for some $600 million.
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 2003 the Brent crude oil price has averaged around $20 a barrel, from 1994 through 2003 it averaged approximately $21 a barrel and from 1999 through 2003 the price averaged approximately $25 a barrel.
As described in Note 2 to the Group Financial Statements the treatment of exploration costs has been changed such that certain costs that had previously been capitalised for longer than 12 months following the completion of exploratory drilling are now expensed. In connection with this change in accounting treatment, certain costs were reclassified from capital expenditures to exploration expense. This change in accounting treatment does not impact cash flows and is not anticipated to affect the future levels of exploration investment. In addition, this change in accounting treatment will mean that in future years drilling costs for some exploratory wells will be expensed earlier than in the past. The effect of this change on net income and depreciation, depletion and amortisation will depend on the actual exploration success and the timing of the progression of development projects associated with exploratory drilling.
Financial condition and liquidity
The Group currently maintains $2.3 billion of committed bank facilities, as well as internally-available liquidity (some $1 billion), to provide back-up coverage of commercial paper maturing within 30 days.
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 2004 could range up to $8.0 billion.
A debt covenant (interest cover ratio) on $1.3 billion of non-recourse debt owed by a Group company (interest 64%) was breached in 2001. This breach is continuing and the company is in default on the full principal balance of $1.3 billion. As this debt is non-recourse, the breach has had no impact on the Group’s other borrowing arrangements.
Total debt at the end of 2003 amounted to $20.1 billion and the Group’s total debt ratio decreased from 23.5% in 2002 to 20.9% in 2003. The level of the debt ratio remains in accordance with the medium-term gearing philosophy of the Group, which establishes a target gearing of between 20% and 30% inclusive of certain off-balance sheet obligations of a financing nature. The total debt outstanding (excluding capital leases) at December 31, 2003 will mature as follows: 56% in 2004, 6% in 2005, 8% in 2006, 11% in 2007 and 19% in 2008 and beyond.
Credit ratings
The Group, having locked in long-term debt for periods of up to five years, will notice an increase in its funding cost only as the debt matures and is replaced with new issues. The average maturity profile is approximately two and a half years. If the $5 billion long-term debt borrowed under the borrowing programmes to which the ratings apply is fully refinanced, our annual pre-tax borrowing cost is expected to increase by approximately $5 million. In light of the unchanged short-term credit ratings, it is expected that there will be no impact on the cost of commercial paper borrowing.
Capital investment and dividends
Exploration and Production expenditures of $9.2 billion (2002: $14.1 billion) accounted for more than half this total. Gas & Power accounted for $1.5 billion (2002: $0.7 billion). Oil Products investment amounted to $2.4 billion (2002: $7.9 billion). Chemicals investment was $0.6 billion (2002: $0.8 billion). Investment in Other industry segments was $0.2 billion (2002: $0.4 billion).
A Group share of capital investment of around $13 billion is required on average each year to grow the capital base, taking into account an expected $2 billion of divestments each year. After dividends and capital investment, the priority for use of cash generated is the maintenance of a prudent balance sheet, most likely through debt reduction. Both the medium and long-term focus will remain on improvement of underlying operational performance in order to continue to deliver consistently strong cash flows.
Group share of capital investment in 2004 is estimated to be in the range of $14.5 billion to $15 billion, with Exploration and Production continuing to account for the majority of this amount. The Parent Companies have decided to implement a share buyback programme of approximately $2 billion for the year 2004, including the purchase of shares for hedging of employee stock options. 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. The US dollar dividend amount is based on exchange rates between the euro, sterling and the dollar.
2002 compared to 2001
Cash inflow during 2002 has been deployed mainly in investments, with capital expenditure and new investments in associated companies of $13.4 billion and acquisition expenditures accounting for a further $9 billion, comprising the purchases of Enterprise Oil ($5 billion cash consideration), Pennzoil-Quaker State ($2 billion cash consideration) and Texaco’s downstream assets in the USA ($2 billion cash consideration). Capital expenditure and new investments in associated companies in 2001 was $10.7 billion and included acquisitions of Exploration and Production companies Fletcher Challenge Energy ($1.0 billion) and McMurry ($0.3 billion).
Other major uses of funds were dividends paid to Parent Companies ($7.0 billion in 2002 compared to $9.4 billion in 2001) and net purchases of Parent Company shares for stock option and other incentive compensation programs of $0.9 billion. Royal Dutch and Shell Transport paid dividends to their shareholders totaling $5.5 billion and executed share buybacks of $1.3 billion in 2002 compared to $5.1 billion and $4.0 billion, respectively, in 2001. The net effect of the flow of funds for 2002 was a decrease of $5.1 billion in cash and cash equivalents and a net increase in short and long-term debt of $6.7 billion.
Financial condition and liquidity
Guarantees and other off-balance sheet obligations
At December 31, 2002, the Group had operating leases under which total minimum payments were $8.6 billion, long-term purchase obligations associated with financing programs requiring aggregate payments of $3.6 billion and certain power generation contracts
(referred to as tolling agreements) amounting to $6.9 billion (of which approximately $700 million is conditional upon the exercise of a renewal option by the owner of one of the plants).
Contractual obligations
| $ billion | ||||||||||||||||||||
| Within | 2-3 years | 4-5 years | After 5 years | |||||||||||||||||
| 1 year | (2005/ | (2007/ | (beyond | |||||||||||||||||
| Total | (2004) | 2006) | 2008) | 2008) | ||||||||||||||||
Long-term debta | 10.3 | 1.8 | 2.7 | 2.6 | 3.2 | |||||||||||||||
Capital leasesb | 1.1 | 0.1 | 0.2 | 0.1 | 0.7 | |||||||||||||||
| Operating leases | 10.0 | 1.8 | 2.1 | 1.4 | 4.7 | |||||||||||||||
Purchase obligationsc | 131.1 | 46.3 | 26.1 | 18.5 | 40.2 | |||||||||||||||
| Other long-term contractual liabilities | 0.8 | 0.2 | 0.3 | 0.1 | 0.2 | |||||||||||||||
Total | 153.3 | 50.2 | 31.4 | 22.7 | 49.0 | |||||||||||||||
| a | Comprised of $9.1 billion as disclosed on the Group balance sheet, plus long term debt due within one year, less capitalised lease payments (see Note 15). |
| b | Includes executory costs and interest. |
| c | Raw material and finished products account for 86% of total purchase obligations. |
In addition to the amounts presented in the above table, contributions to defined benefit pension plans during 2004 are estimated to be $1.3 billion. Interest expense related to long term debt is estimated to be $0.4 billion in 2004. The Group also has other obligations connected with asset retirements (see Note 23 to the Group Financial Statements) that are not contractually fixed as to timing and amount.
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, the Group’s primary control mechanisms are 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 performance appraisal.
Examples of specific risk management mechanisms include:
| – | regular review of significant risks by the Committee of Managing Directors and the Conference (meetings between the members of the Supervisory Board and the Board of Management of Royal Dutch and the Directors of Shell Transport); |
| – | 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. |
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 upon 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 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 have determined, based largely on the investigation and report to the GAC, 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.
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 instrument is given on pages G56 to G67 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 2003 for Group companies, based on allocations and managerial judgment, is $1.3 billion (2002: $1.1 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 the preceding, estimated environmental capital expenditures made by companies with major capital programmes during 2003 were $0.7 billion (2002: $0.8 billion). Those Group companies are expected to incur environmental capital costs of at least $0.7 billion during 2004 and $0.5 billion during 2005.
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 2003, the total liabilities being carried for environmental clean-up were $972 million (2002: $797 million). In 2003, there were payments of $175 million and increases in provisions of $252 million. The Group has introduced US accounting standard FAS 143 (Asset Retirement Obligations) with effect from January 1, 2003 (see Note 3 to the Group Financial Statements on page G11). The fair value of the obligations being carried for expenditures on decommissioning and site restoration, including oil and gas platforms, at December 31, 2003 amounted to $4,044 million (2002: $3,599 million using a cost-accumulation measurement approach).
Employees
Research and development costs
International Financial Reporting Standards
The Group expects to follow the Committee of European Securities Regulators’ recommendations regarding disclosures during the period leading up to publication of the 2005 financial statements, including impact analysis in the 2004 financial statements and quarterly information in accordance with IFRS during 2005.
Cautionary statement
CRITICAL ACCOUNTING ESTIMATES
In order to prepare the Group Financial Statements in conformity with generally accepted accounting principles in the Netherlands and the United States, management of the Group has to make estimates and judgements. The matters described below are considered to be the most critical in understanding the judgements that are involved in preparing the Group Financial Statements and the uncertainties that could impact the amounts reported on the results of operations, financial condition and cash flows. Accounting policies are described in Note 3 to the Group Financial Statements.
Estimation of oil and gas reserves
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, i.e., 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 judgement 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 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. Some of our Deepwater Gulf of Mexico proved undeveloped reserves may not have had a production flow test to surface. In such situations, we have used other technologies that we believe are reliable to establish economic producibility. As those fields are further developed, new information may lead to revisions.
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. This review lead to the Reserves Restatement described herein. As at December 31, 2003, after giving effect to the Reserves Restatement, the proportion of the Group’s total proved reserves that was categorised as proved developed reserves was 56%, the remaining 44% 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 G44. The Reserves Restatement resulted in a 9% reduction in the standardised measure at end 2002. Apart from the effects of the Reserves Restatement, 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 G54.
Changes to our estimates of proved reserves, particularly proved developed reserves, also affect the amount of depreciation, depletion and amortisation recorded in our financial statements for fixed assets related to hydrocarbon production activities. These changes most often result from production and revisions. However, the Reserves Restatement 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.
Although the possibility exists for changes in reserves to have a critical effect on depreciation, depletion and amortisation charges and, therefore, net income, it is expected that in the normal course of business the diversity of the Shell portfolio will constrain the likelihood of this occurring. In 2003, after giving effect to the Reserves Restatement, revisions equaled 3.8% of the proved developed reserves of Group companies.
Exploration costs
Recoverability of assets
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 measure 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 2000 ($1,785 million pre-tax) and in 2003 ($1,375 million pre-tax). The changes in estimates that most precipitated those impairments were in relation to future commodity prices or margins, and portfolio transactions. The outlook for oil refinery margins in Asia Pacific was reduced in 2000 and significant portfolio actions occurred in both years, particularly a Gas and Power transaction in 2000 and the closure of Bakersfield refinery announced in 2003. Certain asset-specific impairments occurred in the Exploration and Production, Chemicals and Renewables businesses in 2003.
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 is higher than in 1998 and 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 2003 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 judgement 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, 2003, was 6%.
As further described in Note 27 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, 2003 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
The amounts reported for the Group’s employee retirement plans are disclosed in Note 20 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 20 to the Group Financial Statements, and have remained relatively constant over the last three years, with the main change being a 0.3% reduction in the discount rate in 2003 reflecting lower long-term interest rates.
Pension cost under FAS 87 primarily represents the increase in actuarial present value of the obligation for benefits based 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 $450 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
As of the end of the period covered by this Report, the management of each of the Parent Companies (with the participation in the case of Royal Dutch of its President and Managing Director and the Acting Group Chief Financial Officer and, in the case of Shell Transport its Managing Director and the Acting Group Chief Financial Officer) conducted an evaluation pursuant to Rule 13a-15 promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), of the effectiveness of the design and operation of the disclosure controls and procedures of the Parent Companies and the Group. Based on this evaluation, the President and Managing Director of Royal Dutch, the Managing Director of Shell Transport and the Acting Group Chief Financial Officer concluded that, except as described below under “Deficiencies Relating to Reserves Reporting”, as of the end of the period covered by this report, such disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by each of the Parent Companies in reports they file or submit under the Exchange Act is recorded, processed, summarised and reported, within the time periods specified in the rules and forms of the SEC.
In making the evaluation, the Companies have considered matters relating to the Reserves Restatement, including action taken within the past year to identify and enhance the effectiveness of disclosure controls and procedures.
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 and 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 resigned from her position as Group Chief Financial Officer, Group Managing Director and Executive Director of Shell Transport on April 18, 2004.
Jeroen van der Veer, President and Managing Director of Royal Dutch, has succeeded Sir Philip Watts as Chairman of the Group’s Committee of Managing Directors; Lord Oxburgh has been appointed non-executive Chairman of Shell Transport and Chairman of Conference; and Malcolm Brinded has been appointed Chief Executive of Exploration and Production, a Director of Shell Transport and Vice Chairman of the Committee of Managing Directors. Mr. Brinded has resigned from his position as a Managing Director of Royal Dutch; he remains Chief Executive of Gas and Power. Tim Morrison, currently Group Controller, has also been appointed Acting Chief Financial Officer. On June 23, 2004, Peter Voser was appointed Group Chief Financial Officer and a Director of Shell Transport with effect from October 4, 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 judgements. |
| – | 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. |
| – | There was a control environment that did not emphasise the paramount importance of the compliance element of proved reserves decisions. |
Remedial Actions
| – | Global Reserves Committee.In the 2003, the Group established the Global Exploration and 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 are being revised with the assistance of independent petroleum engineers and counsel to conform fully these guidelines 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 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. | |
| – | 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 and Production but rather to the Director of Technology. More staff 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 will be responsible for the revision and ongoing maintenance and application of the Group’s Guidelines, and as such will be 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 will also have 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.More staff will also be dedicated to the Group Reserve Auditor function 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 will now report to the Group Chief Internal Auditor to increase the independence of the Group Reserves Auditor function. The Group Reserves Auditor will also regularly use 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 and Production reserve booking decisions more effectively as parts of the Group internal audit function. |
| – | Removal of reserves from scorecards.Reserves bookings have been removed from performance scorecards (used internally to gauge the performance of the Group’s businesses against identified goals for purposes of management evaluation and for calculating management bonuses) 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 Committee of Managing Directors will collectively approve the reserve bookings and de-bookings taken by Exploration and Production. Following this approval, a review of the overall outcome will be 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 will also enable 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 are being reinforced as follows: |
| – | clarifying 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; | |
| – | placing business and financial responsibility on the local Chief Executive Officer and Chief Financial Officer, respectively, for the decisions of their Chief Reservoir Engineer; | |
| – | clarifying that ultimate responsibility for booking and de-booking decisions rests with the Chief Financial Officer of Exploration and Production and the Director of technology of Exploration and Production, working together with the Group Reserves Co-ordinator; | |
| – | providing for the endorsement of these decisions by the Group’s Committee of Managing Directors; and | |
| – | finally, providing for 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 Committee of Managing Directors, 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. The legal function has been given responsibility for actively identifying training needs in areas of disclosure, reporting obligations and corporate governance and devise training programs to address those needs. |
| – | Enhancement of the Disclosure Committee.The Group’s existing Disclosure Committee has been enhanced to require that the Group Legal Director be a member. The Disclosure Committee has also been given quarterly access to the Group’s Committee of Managing Directors to assess the adequacy of disclosures and ensure the awareness and approval of the Group’s Committee of Managing Directors 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 will examine 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 is being prepared to be put into place. Following implementation, this policy will be widely disseminated. |
| – | Promoting Communication and Compliance.Group-wide communications programs are being planned in which the Group’s senior management will emphasise 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. |
2004 Disclosure Controls Review
Principal Accountants Fees and Services
The following table sets forth the fees paid to KPMG and PricewaterhouseCoopers LLP, the Group’s independent public accountants for each of the years for which audited financial statements appear in this Report, by the Group (including its consolidated subsidiaries):
| Group | $ million | |||||||||||
| 2002 | ||||||||||||
| 2003 | As restated | 2001 | ||||||||||
| Audit fees | 32 | 27 | 18 | |||||||||
Audit-related feesa | 11 | 17 | 12 | |||||||||
Tax feesb | 7 | 6 | 3 | |||||||||
Fees for all other non-audit servicesc | 6 | 12 | 17 | |||||||||
| 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, Royal Dutch’s independent public accountants for each of the years for which audited financial statements appear in this Report:
| Royal Dutch | € thousand | |||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Audit fees | 245 | 140 | 116 | |||||||||
| Audit-related fees | — | — | — | |||||||||
| Tax fees | — | — | — | |||||||||
| Fees for all other non-audit services | — | — | — | |||||||||
The following table sets forth the fees paid by Shell Transport to PricewaterhouseCoopers LLP, Shell Transport’s independent public accountants for each of the years for which audited financial statements appear in this Report:
| Shell Transport | £ thousand | |||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Audit fees | 129 | 31 | 25 | |||||||||
Audit-related feesd | 32 | 23 | 30 | |||||||||
| Tax fees | — | — | — | |||||||||
| Fees for all other non-audit services | — | — | — | |||||||||
| 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. |
Royal Dutch Petroleum Company
Control of Registrant
Ordinary shares and priority shares
Royal Dutch has 1,500 priority shares outstanding. Each of the members of the Supervisory Board and each Managing Director is the holder of six priority shares. Taken together, the members of the Supervisory Board and the Managing Directors hold 54 priority shares. The other 1,446 priority shares were held, as at June 14, 2004, by the Royal Dutch Priority Shares Foundation. The Board of the Foundation consists of all the members of the Supervisory Board and the Managing Directors of Royal Dutch. The important special rights attaching to these shares are as follows:
| – | 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. |
These rights serve the interest of a careful selection of suitable nominees and a careful consideration of proposals to amend the Articles of Association. Furthermore, the priority shares can be considered an anti-takeover measure. There are no additional anti-takeover measures.
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.
As announced on 17 June 2004, Royal Dutch will propose to its General Meeting of Shareholders in 2005 to abolish the priority shares.
Nature of Trading Market
Royal Dutch ordinary shares are issuable in bearer or registered form.
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 June 14, 2004, there were outstanding 513,969,157 shares of New York Registry representing approximately 24.7% of the ordinary share capital of Royal Dutch, held by approximately 17,800 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 | $ | $ | |||||||||||||
| € | € | |||||||||||||||
| 1999 | 64.10 | 34.90 | 67.38 | 39.56 | ||||||||||||
| 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 | ||||||||||||
| Period | ||||||||||||||||
| Euronext | New York | |||||||||||||||
| Amsterdam | Stock Exchange | |||||||||||||||
| High | Low | |||||||||||||||
| High | Low | $ | $ | |||||||||||||
| € | € | |||||||||||||||
2002 | ||||||||||||||||
| 1st Quarter | 62.80 | 52.50 | 55.48 | 46.62 | ||||||||||||
| 2nd Quarter | 63.20 | 51.95 | 56.34 | 50.48 | ||||||||||||
| 3rd Quarter | 58.80 | 39.21 | 57.30 | 38.60 | ||||||||||||
| 4th Quarter | 46.30 | 40.23 | 44.93 | 39.76 | ||||||||||||
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 | ||||||||||||
| Period | ||||||||||||||||
| Euronext | New York | |||||||||||||||
| Amsterdam | Stock Exchange | |||||||||||||||
| High | Low | |||||||||||||||
| High | Low | $ | $ | |||||||||||||
| € | € | |||||||||||||||
2003 | ||||||||||||||||
| July | 41.34 | 39.96 | 46.79 | 43.18 | ||||||||||||
| August | 41.61 | 37.90 | 46.20 | 42.84 | ||||||||||||
| September | 42.09 | 37.45 | 46.48 | 43.88 | ||||||||||||
| October | 40.47 | 37.55 | 46.90 | 43.95 | ||||||||||||
| November | 39.45 | 37.01 | 45.34 | 44.03 | ||||||||||||
| December | 41.85 | 37.62 | 52.70 | 45.37 | ||||||||||||
2004 | ||||||||||||||||
| January | 42.43 | 37.43 | 54.00 | 46.66 | ||||||||||||
| February | 40.08 | 36.59 | 49.72 | 46.39 | ||||||||||||
| March | 42.10 | 37.44 | 51.20 | 45.79 | ||||||||||||
| April | 41.90 | 38.02 | 50.30 | 47.48 | ||||||||||||
| May | 42.15 | 39.92 | 51.05 | 47.81 | ||||||||||||
Articles of Association
General
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. |
| (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 approval.
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
(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 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
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.
The Managing Directors, members of the Supervisory Board and officers of Royal Dutch at June 14, 2004, were:
Biographies
Aad Jacobs ø
Maarten van den Bergh #
Wim Kok #
Jonkheer Aarnout Loudon + #
Professor Hubert Markl +
Lawrence Ricciardi ø
Henny de Ruiter ø +
Jeroen van der Veer
Rob Routs
Company Secretary, Royal Dutch
Key to Committee membership
ø Group Audit Committee
+ Remuneration and Succession Review Committee
# Social Responsibility Committee
Nominations
The Supervisory Board and the Board of Directors proposed to the General Meeting of Shareholders of Royal Dutch, held on June 28, 2004, to appoint Christine Morin-Postel to the Supervisory Board of Royal Dutch with effect from July 1, 2004.
Maarten van den Bergh will retire by rotation as member of the Supervisory Board effective July 1, 2004, but it was recommended to the General Meeting of Shareholders that he be re-elected.
Henny de Ruiter will retire as member of the Supervisory Board effective July 1, 2004.
Relationships between members of the Board of Management, members of the Supervisory Board and officers
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 | – | – | ||||||
| Lawrence Ricciardi | – | 10,000 | ||||||
| Henny de Ruiter | – | – | ||||||
Managing Directors | ||||||||
| Jeroen van der Veer | 519,600 | 10,512 | ||||||
| Rob Routs | 302,466 | – | ||||||
| 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, 2003 | during the yeara | at awardb | during the yearc | during the yeard | December 31, 2003 | |||||||||||||||||||
| € | € | |||||||||||||||||||||||
Jeroen van der Veere | ||||||||||||||||||||||||
| 2003 award | – | 11,188 | 36.66 | 507 | 39.04 | 11,695 | ||||||||||||||||||
| 2002 award | 3,549 | – | 60.09 | 161 | 39.04 | 3,710 | ||||||||||||||||||
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.
| 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 Managing Directors table on page R16. |
| 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 2002 final and 2003 interim annual dividends paid during the year:€37.60 and€40.47, respectively. |
| e | During the period January 1, 2004 to June 14, 2004 the total number of shares under award of the 2002 award and the 2003 award of Jeroen van der Veer increased by 92 and 290 dividend shares respectively as a result of the final 2003 dividend pay-out. This leads to a total of his awards of 3,802 and 11,986 respectively. |
Group Audit Committee
of information and communication technologies in particular. This is part of the general responsibilities of the Board of Management and Supervisory Board respectively. The committee has established an internal, global procedure for employees to raise in confidence accounting, controls and auditing concerns. The secretary to the committee is the designated recipient of any such concerns.
During 2003, the Group Audit Committee reviewed its role in the light of governance developments and at its meeting in February 2004 concluded that two discrete sub-committees should be established 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,inter alia, 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 will determine the extent of the Independent Auditors’ involvement in the content and publication of financial reports other than the Annual Accounts. The sub-committee will assess the performance of the Independent Auditors, advise (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 provide 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 non-audit services may be contracted so long as the fee value for each contract does not exceed $500,000. These include 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 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.
Current membership of the Group Audit Committee is shown in the table below.
| Appointed by the Supervisory Board of Royal Dutch | ||
| Aad Jacobs | Chairman of the committee with effect from March 2003 | |
| Lawrence Ricciardi | ||
| Henny de Ruiter | ||
| 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 2003 there were a total of six meetings of the Group Audit Committee. Attendance at these meetings is shown in the table below.
| Attendance | |||
| Members | Attendance | ||
| Aad Jacobs | 6 | ||
| Sir Peter Burt | 5 | ||
| Luis Giusti | 6 | ||
| Nina Henderson | 6 | ||
Lawrence Ricciardia | 2 | ||
| Henny de Ruiter | 4 | ||
| a | Lawrence Ricciardi was appointed a member during the year and attended all meetings following his appointment. |
A copy of the revised Terms of Reference of the Group Audit Committee (including the Royal Dutch sub-committee) is available from Investor Relations and can be found on the Shell website (www.shell.com/investor).
Remuneration and Succession Review Committee
Social Responsibility Committee
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 | ||
| Lord Oxburgh | Chairman of the committee | |
| Teymour Alireza | ||
| Dr Eileen Buttle | ||
During 2003 the committee met twice. Attendance at these meetings is shown in the table below.
| Attendance | |||
| Members | Attendance | ||
| Lord Oxburgh | 2 | ||
| Teymour Alireza | 2 | ||
| Maarten van den Bergh | 2 | ||
| Dr Eileen Buttle | 2 | ||
Wim Koka | 0 | ||
| Jonkheer Aarnout Loudon | 2 | ||
| a | Wim Kok was appointed a member during the year and was unable to attend the one meeting 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 is available at www.shell.com/shellreport.
Code of Ethics
Compensation of Directors and officers
Shares under option and share purchase plan
companies. Options granted under these plans are for terms of not more than ten years at an exercise price of not less than the fair market value on the date of granting the option.
The securities of Royal Dutch involved in the plans as of June 14, 2004, are 61,295,632 issued and outstanding ordinary shares.
The number of ordinary shares of Royal Dutch under option at June 14, 2004, and the option prices of the shares at the dates the options were granted, per share and in total, were as follows:
| Plan | ||||||||||||||||
| Exercise pricea | ||||||||||||||||
| Average | ||||||||||||||||
| Number of shares | per | Total | Term | |||||||||||||
| under option | share | (expiration dates) | ||||||||||||||
| Shell Petroleum N.V. | 23,003,383 | €50.13 | €1,153,239,655 | 10 years (10/12/07–06/05/14 | ) | |||||||||||
| The Shell Petroleum Company Limited | 11,199,498 | €50.17 | €561,886,281 | 10 years (01/03/2010–21/12/2010 | ) | |||||||||||
| Shell Oil Company | 3,078,397 | $ | 53.03 | $163,255,833 | 10 years (01/03/10–21/12/10 | ) | ||||||||||
| Shell Petroleum Inc. | 23,986,810 | $ | 50.30 | $1,206,469,503 | 10 years (01/03/2010–07/05/2014 | ) | ||||||||||
| Shell Solar Employment Services Inc. | 27,544 | $ | 46.43 | $1,278,981 | 10 years (25/05/2010–07/05/2014 | ) | ||||||||||
| 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. Group Managing Directors are not eligible to participate in the plans. A maximum of 250,000 Royal Dutch shares (or equivalent value in Shell Transport 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 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, provided that the individual has remained in employment. The total number of outstanding ordinary shares of Royal Dutch under the restricted stock plans as of June 14, 2004 is 190,889, of which 5,848 shares relate to dividend shares up to date. The total monetary value outstanding under the earlier versions of these plans – under which grants were defined as a monetary value with the number of shares determined by the share price at the end of the restricted period rather than the award date and with no dividend roll up either – is€501,180. In the USA, a total of 9,800 Royal Dutch Shares have been granted under restricted stock agreements as of June 14, 2004, subject to a three-year restriction period with no adjustment for cash dividends.
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 Royal Dutch conditionally awarded under the long-term incentive plans as of June 14, 2004 is 347,255, of which 8,719 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 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 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%. Group Managing Directors are not eligible to participate in the Global Employee Share Purchase Plan. At June 14, 2004, Group companies held 1,138,253 Royal Dutch ordinary shares in connection with this plan.
No issue of new shares is involved under any of the plans mentioned above.
The “Shell” Transport and Trading Company, Public Limited Company
Control of Registrant
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 June 14, 2004, there were outstanding 69,584,433 New York Shares representing approximately 4.32% of the Ordinary share capital of Shell Transport, held by 2,100 holders of record.
At June 14, 2004 there were 3,229,863 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 | |||||||||||||
| £ | £ | $ | $ | |||||||||||||
| 1999 | 5.41 | 3.04 | 52.56 | 30.50 | ||||||||||||
| 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 | ||||||||||||
| Period | ||||||||||||||||
| London | New York | |||||||||||||||
| High | Low | High | Low | |||||||||||||
| £ | £ | $ | $ | |||||||||||||
2002 | ||||||||||||||||
| 1st Quarter | 5.26 | 4.51 | 44.87 | 38.48 | ||||||||||||
| 2nd Quarter | 5.41 | 4.67 | 47.03 | 41.99 | ||||||||||||
| 3rd Quarter | 5.09 | 3.70 | 46.70 | 34.59 | ||||||||||||
| 4th Quarter | 4.28 | 3.81 | 40.02 | 35.56 | ||||||||||||
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 | ||||||||||||
| Period | ||||||||||||||||
| London | New York | |||||||||||||||
| High | Low | High | Low | |||||||||||||
| £ | £ | $ | $ | |||||||||||||
2003 | ||||||||||||||||
| July | 4.09 | 3.84 | 40.25 | 37.30 | ||||||||||||
| August | 4.15 | 3.83 | 40.20 | 37.52 | ||||||||||||
| September | 4.14 | 3.69 | 39.87 | 37.51 | ||||||||||||
| October | 4.00 | 3.63 | 40.30 | 37.50 | ||||||||||||
| November | 3.82 | 3.65 | 38.94 | 37.58 | ||||||||||||
| December | 4.17 | 3.68 | 45.19 | 38.84 | ||||||||||||
2004 | ||||||||||||||||
| January | 4.19 | 3.56 | 46.17 | 39.33 | ||||||||||||
| February | 3.74 | 3.46 | 42.09 | 39.12 | ||||||||||||
| March | 3.91 | 3.52 | 43.45 | 39.20 | ||||||||||||
| April | 4.02 | 3.47 | 43.14 | 39.85 | ||||||||||||
| May | 4.10 | 3.88 | 44.54 | 41.94 | ||||||||||||
At June 14, 2004 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 the same date there were 1,300 Second Preference shares of £1 each representing approximately 0.01% of the issued shares of the class held by 7 holders of record registered with an address in the USA. (Reference is made to Note 7 on page S9 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; |
| (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
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
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.
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.
(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 84 and 85) 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
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 is 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
Stamp Duty Reserve Tax
Management
On June 23, 2004 Peter Voser was appointed a Director of The “Shell” Transport and Trading Company, p.l.c with effect from October 4, 2004.
The Directors, Managing Directors, and officers of Shell Transport at June 14, 2004 were:
Teymour Alireza #
Sir Peter Burt FRSE ø •
Dr Eileen Buttle CBE #
Luis Giusti ø
Mary (Nina) Henderson ø +
Sir Peter Job KBE + •
Sir John Kerr GCMG + •
Sir Mark Moody-Stuart KCMG
Malcolm Brinded CBE FREng
Company Secretary, Shell Transport
Key to Committee membership
| ø | Group Audit Committee |
| + | Remuneration and Succession Review Committee |
| # | Social Responsibility Committee |
| • | Shell Transport Nomination Committee |
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 | 77,948 | ||||||
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 | – | 1,866 | ||||||
| Sir John Kerr | – | 10,000 | ||||||
| Sir Mark Moody-Stuart | 806,050 | 600,000 | ||||||
| Lord Oxburgh | – | 6,214 | ||||||
| a | Additional information is included in the “Remuneration Report – Stock options” on page S19. |
| b | Excluding 6,885 Royal Dutch ordinary shares as per June 14, 2004, resulting from his participation in the Deferred Bonus Plan for Group Managing Directors in 2003 through the deferral of part of his 2002 bonus. |
Group Audit Committee
During 2003, the Group Audit Committee reviewed its role in the light of governance developments and at its meeting in February 2004 concluded that two discrete sub-committees should be established 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 Terms of Reference were revised in February 2004 to reflect these changes.
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 non-audit services may be contracted so long as the fee value for each contract does not exceed $500,000. These include 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 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 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 | Chairman of the committee | |
| Lawrence Ricciardi | Appointed to the committee on July 1, 2003 | |
| Henny de Ruiter | ||
| Jan Timmer | Retired from the committee on June 30, 2003 | |
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 UK and Dutch corporate governance requirements as a director with “appropriate and recent relevant financial experience”, as does Mr. Jacobs.
A copy of the revised Terms of Reference of the Group Audit Committee (including the Shell Transport Audit sub-committee) is available from the Company Secretary and can be found on the Shell website (www.shell.com/investment).
Non-audit services (Code Provision C.3.7)
Remuneration and Succession Review Committee
Social Responsibility Committee
The members appointed by the Board of Shell Transport are currently Teymour Alireza, Dr Eileen Buttle and Lord Oxburgh (Chairman of the Committee). The members appointed by the Supervisory Board of Royal Dutch are currently Maarten van den Bergh, Wim Kok and Jonkheer Aarnout Loudon.
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 2003 which reviews how Group companies are living up to the Group’s Business Principles and contributing to sustainable development is available at www.shell.com/shellreport.
Code of Ethics
Compensation of Directors and officers
December 31, 2003, was £2,848,442. The aggregate amount set aside to provide pension, retirement and similar benefits for Directors, Managing Directors and officers of Shell Transport by Shell Transport and companies of the Royal Dutch/ Shell Group of Companies during the fiscal year ended December 31, 2003, was nil.
Sir Philip Watts’ severance payment following his resignation as a director of Shell Transport, and as an employee of The Shell Petroleum Company Limited in March 2004 consisted of a lump sum payment of £1,057,971. This amount was based on his salary as an employee until his normal employment retirement date in June 2005 after 35 years’ service. No Director’s fees are being paid for this period. Sir Philip received no performance-related annual bonus in respect of 2003 or 2004, and forfeited certain stock options and share grants. Sir Philip will retain 2,847,000 stock options under a shortened exercise term consistent with the Group’s general practice of allowing employees to continue to hold options after leaving employment by mutual agreement. Sir Philip also has the legal right to a pension of £584,070 per annum under the Shell pension scheme to which he has contributed.
Reference is made to the information given in the Remuneration section on pages S12 to S22 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
The securities of Shell Transport involved in the plans as of June 14, 2004, are 177,489,670 issued and outstanding Ordinary shares.
The number of Ordinary shares under option at June 14, 2004, 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. | 54,156,306 | £4.49 | £243,228,990 | 10 years | ||||||||||||
| (10/12/07 – 06/05/14 | ) | |||||||||||||||
| The Shell Petroleum Company Limited | 123,333,364 | £4.54 | £560,184,090 | 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 plans. A maximum of 250,000 Royal Dutch shares (or equivalent value in Shell Transport 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 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 provided that the individual has remained in employment. The total number of outstanding ordinary shares of Shell Transport under the restricted stock plans as of June 14, 2004 is 781,129, of which 15,668 shares relate to directed sales up to date. The total monetary value outstanding under the earlier versions of these plans – under which grants were defined as a monetary value with the number of shares determined by the share price at the end of the restricted period rather than the award date and with no dividend roll up is £145,000.
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 June 14, 2004 is 890,421, of which 15,482 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 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 June 14, 2004, 2,357,768 Shell Transport Ordinary shares were held by Group companies in connection with this Plan.
Shell Sharesave Scheme
At June 14, 2004 there were 12,418,402 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 £5.69, of which there were 161,148 issued and outstanding Ordinary shares of SPNV.
No issue of new shares is involved under any of the plans or schemes mentioned above.
Index to the Financial Statements and Exhibits
| (A) Financial Data* | Page | |||
Royal Dutch Petroleum Company: | ||||
Report of Independent Public Accountants | R1 | |||
Financial Statements | ||||
| Profit and Loss Account | R2 | |||
| Statement of Appropriation of Profit | R2 | |||
| Earnings per ordinary share | R2 | |||
| Balance Sheet | R3 | |||
| Statement of Cash Flows | R3 | |||
| Notes to the Financial Statements | R4 | |||
| Remuneration | R10 | |||
The “Shell” Transport and Trading Company, Public Limited Company: | ||||
Report of Independent Public Accountants | S1 | |||
Financial Statements | ||||
| Profit and Loss Account | S2 | |||
| Earnings per 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 | |||
| Remuneration Report | S12 | |||
Royal Dutch/ Shell Group of Companies: | ||||
Report of Independent Public Accountants | 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 US GAAP Financial Statements | G5 | |||
Netherlands GAAP Financial Statements | G36 | |||
| Statement of Income | G36 | |||
| Statement of Assets and Liabilities | G37 | |||
| Notes to Netherlands GAAP Financial Statements | G38 | |||
Report of Independent Public Accountants | G43 | |||
Supplementary information – Oil and Gas (unaudited) | ||||
| Reserves | G44 | |||
| Standardised measure of discounted future cash flows | G54 | |||
Supplementary information – Derivatives and other Financial Instruments and Derivative Commodity Instruments | G56 | |||
(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, 2003 | 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 | |||
| * | 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”. |
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, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in accordance with accounting principles generally accepted in the Netherlands.
The report of the independent public accountants on the 2003, 2002 and 2001 Financial Statements of the Royal Dutch/Shell Group of Companies, which form part of the Financial Statements of Royal Dutch Petroleum Company, appears on page G43.
As discussed in Note 2 on page R4 the Company has restated its Financial Statements for the two years ended December 31, 2002 and made certain changes in its accounting principles.
As discussed in Note 12 on page R7, the Company has restated its Financial Statements for the two years ended December 31, 2002 to change its method of accounting for earnings per share.
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 16 on page R9.
/s/ KPMG ACCOUNTANTS N.V.
KPMG Accountants N.V., The Hague
May 22, 2004
Financial Statements
| Profit and Loss Account | € million | |||||||||||||||
| 2002 | 2001 | |||||||||||||||
| Note | 2003 | As restated | As restated | |||||||||||||
| Share in the net income of companies of the Royal Dutch/Shell Group | 4 | 6,513 | 6,093 | 6,930 | ||||||||||||
lessAdministrative expenses | 8 | 5 | 6 | |||||||||||||
| 6,505 | 6,088 | 6,924 | ||||||||||||||
| Interest income | 18 | 28 | 33 | |||||||||||||
| Profit before taxation | 6,523 | 6,116 | 6,957 | |||||||||||||
lessTaxation | 5 | 3 | 8 | 10 | ||||||||||||
Profit after taxation | 6,520 | 6,108 | 6,947 | |||||||||||||
| Statement of Appropriation of Profit | € million | |||||||||||||||
| 2002 | 2001 | |||||||||||||||
| Note | 2003 | As restated | As restated | |||||||||||||
| Profit after taxation | 6,520 | 6,108 | 6,947 | |||||||||||||
| Taken from/(to) Statutory investment reserve | 6 | (3,645 | ) | (2,776 | ) | (782 | ) | |||||||||
| Undistributed profit at beginning of year | 3,650 | 4,712 | 4,674 | |||||||||||||
| Final dividend distributed | (2,084 | ) | (2,042 | ) | (1,973 | ) | ||||||||||
| (Repurchase)/cancellation of share capital | 9 | (847 | ) | (2,654 | ) | |||||||||||
| Unclaimed dividends forfeited | 1 | 1 | 1 | |||||||||||||
| Available for distribution | 4,451 | 5,156 | 6,213 | |||||||||||||
lessInterim dividenda | 1,542 | 1,506 | 1,501 | |||||||||||||
Undistributed profit at end of yearb | 2,909 | 3,650 | 4,712 | |||||||||||||
| Earnings per share | € | |||||||||||||||
| 2002 | 2001 | |||||||||||||||
| Note | 2003 | As restated | As restated | |||||||||||||
| Basic earnings per ordinary share | 12 | 3.20 | 2.97 | 3.32 | ||||||||||||
| Diluted earnings per ordinary share | 12 | 3.20 | 2.97 | 3.32 | ||||||||||||
| a | Including 4% cumulative preference dividend for 2003 amounting to€26,880 on priority shares (2002: €26,880; 2001:€27,227). | |
| b | Before second interim dividend of€2,125 million (proposed final dividend 2002:€2,084 million; 2001:€2,042 million). The Supervisory Board and the Board of Management propose to the General Meeting of Shareholders to be held on June 28, 2004 that it be resolved that the interim dividend made payable in September 2003 and the second interim dividend made payable in May 2004 will together constitute the total dividend for 2003. |
| Balance Sheet(before appropriation of profit) | € million | ||||||||||||
| Dec 31, | |||||||||||||
| Dec 31, | 2002 | ||||||||||||
| Note | 2003 | As restated | |||||||||||
Fixed assets | |||||||||||||
| Financial fixed assets | |||||||||||||
| Investments in companies of the Royal Dutch/ Shell Group | 6 | 34,516 | 34,586 | ||||||||||
Current assets | |||||||||||||
| Receivables | |||||||||||||
| Dividends receivable from companies of the Royal Dutch/ Shell Group | 2,449 | 2,982 | |||||||||||
| Other receivables from companies of the Royal Dutch/ Shell Group | 363 | 582 | |||||||||||
| Other receivables | 7 | 36 | 36 | ||||||||||
| Cash and cash equivalents | 8 | 7 | |||||||||||
| 2,856 | 3,607 | ||||||||||||
Current liabilities | |||||||||||||
| Other liabilities | 8 | 10 | 11 | ||||||||||
Current assets less current liabilities | 2,846 | 3,596 | |||||||||||
Total assets less current liabilities | 37,362 | 38,182 | |||||||||||
Shareholders’ equity | |||||||||||||
| Paid-up capital | 9 | ||||||||||||
| Ordinary shares | 1,166 | 1,175 | |||||||||||
| Priority shares | 1 | 1 | |||||||||||
| 1,167 | 1,176 | ||||||||||||
| Share premium reserve | 1 | 1 | |||||||||||
| Investment reserves | 6 | ||||||||||||
| Statutory | 22,874 | 23,148 | |||||||||||
| Currency translation differences | 486 | (2,370 | ) | ||||||||||
| Other | 9,910 | 12,562 | |||||||||||
| 33,270 | 33,340 | ||||||||||||
| Other statutory reserves | 10 | 15 | 15 | ||||||||||
| Undistributed profit | 2,909 | 3,650 | |||||||||||
| 37,362 | 38,182 | ||||||||||||
| Statement of Cash Flows | € million | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
Returns on investments and servicing of finance | ||||||||||||
| Dividends received from Group companies | 3,401 | 4,446 | 6,342 | |||||||||
| Interest received | 18 | 32 | 30 | |||||||||
| Other | 212 | (587 | ) | (5 | ) | |||||||
| Net cash inflow/(outflow) from returns on investments and servicing of finance | 3,631 | 3,891 | 6,367 | |||||||||
Taxation | ||||||||||||
| Tax (paid)/recovered | (4 | ) | (8 | ) | (14 | ) | ||||||
Financing | ||||||||||||
| Repurchase of share capital, including expenses | – | (889 | ) | (2,700 | ) | |||||||
| Dividends paid | (3,626 | ) | (3,536 | ) | (3,459 | ) | ||||||
Increase/(decrease) in cash and cash equivalents | 1 | (542 | ) | 194 | ||||||||
| Cash at January 1 | 7 | 549 | 355 | |||||||||
| Cash at December 31 | 8 | 7 | 549 | |||||||||
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 G36 and G37 and the Notes thereto on pages G5 to G35, G38 to G42 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.
2 Restatement and changes in accounting principles
From January 1, 2003 the 60% share of Royal Dutch in the book value of Shell Transport shares held by Group companies is eliminated, thus eliminating in full the shares of both Parent Companies held by Group companies. In this way, the euro book value of Royal Dutch investments is directly aligned to 60% of the Royal Dutch/Shell Group’s net assets translated at the year-end dollar/euro rate of exchange. The change reduces Shareholders’ equity by€496 million as at December 31, 2002 (December 31, 2001:€347 million), see Note 6.
Furthermore, as from January 1, 2003, changes in generally accepted accounting principles in the Netherlands require that proposed dividends which are subject to finalisation at the General Meeting of Shareholders no longer be accounted for as liabilities in the balance sheet, but as undistributed profit, a part of Shareholders’ equity, until they are finally approved. This change increases Shareholders’ equity by€2,084 million as at December 31, 2002 (December 31, 2001:€2,042 million).
Prior year amounts related to these accounting changes have been restated to conform with current year presentation.
The effect on profit after taxation and the Shareholders’ equity of Royal Dutch is as follows:
| € million | |||||||||||||
| Shareholders’ | |||||||||||||
| Profit after taxation | equity | ||||||||||||
| Dec 31, | |||||||||||||
| 2002 | 2001 | 2002 | |||||||||||
| As previously reported | 6,004 | 7,282 | 36,446 | ||||||||||
| Reserves restatement | (69 | ) | (28 | ) | (176 | ) | |||||||
| Changes in accounting principles of the Royal Dutch/Shell Group of Companies | |||||||||||||
| Valuation of inventories | 324 | (299 | ) | 537 | |||||||||
| Goodwill amortisation | (76 | ) | (76 | ) | |||||||||
| Exploration costs | (39 | ) | (9 | ) | (99 | ) | |||||||
| Valuation of certain gas contracts | (25 | ) | (25 | ) | |||||||||
| Currency translation effect | (11 | ) | 1 | (13 | ) | ||||||||
| Changes in accounting principles of Royal Dutch | |||||||||||||
| Accounting for Shell Transport shares | (496 | ) | |||||||||||
| Accounting for proposed dividend | 2,084 | ||||||||||||
As restated | 6,108 | 6,947 | 38,182 | ||||||||||
3 Accounting principles
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 30 to the Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies on page G38.
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 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.
4 Share in the net income of companies of the Royal Dutch/Shell Group
The dividend for 2003 distributed and yet to be distributed by Group companies to Royal Dutch amounted to€2,868 million, the equivalent of $3,396 million (2002:€3,317 million, the equivalent of $3,261 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 dollar/euro rate is included in currency translation differences.
The difference of€33,270 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.
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-dollar companies to 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 35 to the Netherlands GAAP Financial Statements of the Royal Dutch/Shell Group of Companies on pages G41 and G42).
| 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, 2001 (as previously reported) | 38,431 | 25,485 | (4,306 | ) | 16,006 | 37,185 | ||||||||||||||||||||||||
| Deduct: 60% of the book value of Shell Transport shares held by Group companies at December 31, 2001 | (347 | ) | (347 | ) | (347 | ) | ||||||||||||||||||||||||
| 33,696 | 1.13 | 38,084 | 25,485 | (4,306 | ) | 15,659 | 36,838 | |||||||||||||||||||||||
| Restatement December 31, 2001a | 50 | 1.13 | 56 | 50 | 7 | (1 | ) | 56 | ||||||||||||||||||||||
Balance at December 31, 2001 (as restated) | 33,746 | 1.13 | 38,140 | 25,535 | (4,299 | ) | 15,658 | 36,894 | ||||||||||||||||||||||
Movements during the year 2002 | ||||||||||||||||||||||||||||||
| Share in the net income of Group companies (as restated) | 5,761 | 1.06 | 6,093 | |||||||||||||||||||||||||||
| Distribution to Royal Dutch | (3,261 | ) | 1.02 | (3,317 | ) | |||||||||||||||||||||||||
| Undistributed net income of Group companies (as restated) | 2,500 | 1.11 | 2,776 | 2,776 | 2,776 | |||||||||||||||||||||||||
| Net (increase)/decrease in Parent Companies’ shares held by Group companies | (507 | ) | 1.06 | (538 | ) | (538 | ) | (538 | ) | |||||||||||||||||||||
| Other comprehensive income, net of tax (as restated) | 455 | 0.96 | 434 | (831 | ) | 1,265 | 434 | |||||||||||||||||||||||
| Translation effect arising from movements in dollar/euro rate (as restated) | (6,226 | ) | (4,332 | ) | 664 | (2,558 | ) | (6,226 | ) | |||||||||||||||||||||
| Share of Group net assets at December 31, 2002 (as restated) | 36,194 | 0.96 | 34,586 | 23,148 | (2,370 | ) | 12,562 | 33,340 | ||||||||||||||||||||||
| Add: 60% of the book value of Shell Transport shares held by Group companies at December 31, 2002 | 496 | 496 | 496 | |||||||||||||||||||||||||||
| Balance at December 31, 2002 (as restated) | 35,082 | 23,148 | (2,370 | ) | 13,058 | 33,836 | ||||||||||||||||||||||||
| Deduct: 60% of the book value of Shell Transport shares held by Group companies at December 31, 2002 | (496 | ) | (496 | ) | (496 | ) | ||||||||||||||||||||||||
Balance at January 1, 2003 (as restated) | 36,194 | 0.96 | 34,586 | 23,148 | (2,370 | ) | 12,562 | 33,340 | ||||||||||||||||||||||
| Cumulative effect of change in accounting for asset retirement obligationsb | 153 | 0.96 | 146 | 146 | 146 | |||||||||||||||||||||||||
| 36,347 | 0.96 | 34,732 | 23,294 | (2,370 | ) | 12,562 | 33,486 | |||||||||||||||||||||||
Movements during the year 2003 | ||||||||||||||||||||||||||||||
| Share in the net income of Group companies | 7,244 | 0.90 | 6,513 | |||||||||||||||||||||||||||
| Distribution to Royal Dutch | (3,396 | ) | 0.84 | (2,868 | ) | |||||||||||||||||||||||||
| Undistributed net income of Group companies | 3,848 | 0.95 | 3,645 | 3,645 | 3,645 | |||||||||||||||||||||||||
| 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 | 3,721 | 0.79 | 2,951 | 499 | 2,452 | 2,951 | ||||||||||||||||||||||||
| Translation effect arising from movements in dollar/euro rate | (6,476 | ) | (4,563 | ) | 404 | (2,317 | ) | (6,476 | ) | |||||||||||||||||||||
Balance at December 31, 2003 | 43,537 | 0.79 | 34,516 | 22,874 | 486 | 9,910 | 33,270 | |||||||||||||||||||||||
| a | See Notes 31 and 35 to the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of 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 and 2001, respectively. |
The movements during the year in the value of the Group reporting currency (dollar) against the Royal Dutch reporting currency (euro) lead to currency translation differences.
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.
| 7 Other receivables | € million | |||||||
| Dec 31, | Dec 31, | |||||||
| 2003 | 2002 | |||||||
| Dividend tax receivable | 36 | 35 | ||||||
| Other receivables | 0 | 1 | ||||||
| 36 | 36 | |||||||
| 8 Other liabilities | € million | |||||||
| Dec 31, | Dec 31, | |||||||
| 2003 | 2002 | |||||||
| Dividends | 8 | 8 | ||||||
| Accounts payable | 2 | 1 | ||||||
| Corporation tax | 0 | 2 | ||||||
| 10 | 11 | |||||||
9 Share capital
| Share capital | |||||||||
| Number of shares | € | ||||||||
Ordinary shares of N.fl.1.25/€0.56 | |||||||||
| At December 31, 2001 | 2,126,647,800 | 1,206,288,373 | |||||||
Redenomination to€0.56 | (15,365,605 | ) | |||||||
| Cancelled during 2002 | (27,362,800 | ) | (15,323,168 | ) | |||||
| 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 | |||||||
Priority shares of N.fl.1,000/€448 | |||||||||
| At December 31, 2001 | 1,500 | 680,670 | |||||||
Redenomination to€448 | (8,670 | ) | |||||||
| At December 31, 2002 | 1,500 | 672,000 | |||||||
At December 31, 2003 | 1,500 | 672,000 | |||||||
Total ordinary and priority shares | |||||||||
| At December 31, 2002 | 2,099,286,500 | 1,176,271,600 | |||||||
At December 31, 2003 | 2,083,501,500 | 1,167,432,000 | |||||||
10 Other statutory reserves
11 Royal Dutch shares held by Group companies
| Number of shares | € million | |||||||||||
| Royal Dutch | ||||||||||||
| 60% | ||||||||||||
| interest | ||||||||||||
| in the | ||||||||||||
| Book value | book value | |||||||||||
At December 31, 2002 | 39,115,193 | 2,118 | 1,271 | |||||||||
| Purchases | 11,431,478 | 435 | 261 | |||||||||
| Deliveries and other movements | (266,589 | ) | (159 | ) | (96 | ) | ||||||
At December 31, 2003 | 50,280,082 | 2,394 | 1,436 | |||||||||
These movements relate to the granting and exercise of stock options and to other incentive compensation plans as mentioned in Note 22 to the Financial Statements of the Royal Dutch/ Shell Group of Companies.
12 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 674,210 for 2003 (2002: 442,580; 2001: 1,124,897). These numbers relate to share options schemes as mentioned above.
Basic earnings per share reported in previous years have been restated reflecting (i) a correction in the weighted number of outstanding shares for the number of shares held by Group companies in respect of stock options, which shares were erroneously not deducted in the calculation of the weighted average number of shares, and (ii) the Reserves Restatement and changes in accounting principles.
Quantitative information concerning the effect of the above restatement and changes in accounting principles is set forth in the table below and additional information regarding the nature of these items is contained in Note 2.
| € | |||||||||
| 2002 | 2001 | ||||||||
Basic earnings per ordinary share (as previously reported) | 2.87 | 3.44 | |||||||
| Adjustments | |||||||||
| Correction number of weighted shares | 0.05 | 0.03 | |||||||
| Reserves restatement | (0.03 | ) | (0.01 | ) | |||||
| Valuation of inventories | 0.16 | (0.14 | ) | ||||||
| Amortisation of goodwill | (0.04 | ) | |||||||
| Exploration costs | (0.02 | ) | – | ||||||
| Valuation of certain gas contracts | (0.01 | ) | |||||||
| Currency translation effect | (0.01 | ) | – | ||||||
Basic earnings per ordinary share (as restated) | 2.97 | 3.32 | |||||||
Diluted earnings per ordinary share | 2.97 | 3.32 | |||||||
Royal Dutch’s 60% interest in line items as derived from the
| € million | $ million | |||||||
Balance Sheet | ||||||||
2003: | ||||||||
| Current assets | 20,744 | 26,166 | ||||||
| Non current assets | 59,076 | 74,516 | ||||||
| Current liabilities | 25,889 | 32,655 | ||||||
| Non current liabilities | 17,786 | 22,434 | ||||||
| Minority interests in Group companies (60% of Group amount on page G37 translated at year end rate on page R6) | 1,629 | 2,056 | ||||||
| Royal Dutch share of Group net assets (see pages R6-Euro & G41-$) | 34,516 | 43,537 | ||||||
| Other assets and liabilities of Royal Dutch | 2,846 | |||||||
| Net Assets | 37,362 | |||||||
2002: | ||||||||
| Current assets | 23,883 | 24,993 | ||||||
| Non current assets | 65,795 | 68,852 | ||||||
| Current liabilities | 31,650 | 33,120 | ||||||
| Non current liabilities | 21,387 | 22,380 | ||||||
| Minority interests in Group companies (60% of Group amount on page G37 translated at year end rate on page R6) | 2,055 | 2,149 | ||||||
| Royal Dutch share of Group net assets (see page R6 — Euro & G41-$ | 34,586 | 36,194 | ||||||
| Other assets and liabilities of Royal Dutch | 3,596 | |||||||
| Net Assets | 35,182 | |||||||
Profit and Loss account | ||||||||
2003: | ||||||||
| Sales proceeds (Revenue) | 145,044 | 161,336 | ||||||
| Operating profit | 11,673 | 12,984 | ||||||
| Net income for the year | 6,513 | 7,245 | ||||||
| Distribution for the year | 2,868 | 3,396 | ||||||
2002: | ||||||||
| Sales proceeds (Revenue) | 141,358 | 133,661 | ||||||
| Operating profit | 11,553 | 10,923 | ||||||
| Net income for the year | 6,093 | 5,762 | ||||||
| Distribution for the year | 3,317 | 3,261 | ||||||
2001: | ||||||||
| Sales proceeds (Revenue) | 112,105 | 100,458 | ||||||
| Operating profit | 12,847 | 11,512 | ||||||
| Net income for the year | 6,930 | 6,210 | ||||||
| Distribution for the year | 6,148 | 5,498 | ||||||
13 List of companies of the Royal Dutch/ Shell Group
14 Remuneration of members of the Supervisory Board and Managing Directors
For the amounts borne in 2003 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 R19. 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. In 2003, an amount of€797,569 (2002:€463,004) has been added to the provision for retirement benefits of former Managing Directors.
The breakdown of these charges per former Managing Director is as follows:
| € | ||||||||
| 2003 | 2002 | |||||||
| Drs M.A. van den Bergh | 145,893 | 71,779 | ||||||
| A.P. Bénard | 42,165 | 31,188 | ||||||
| Ir. J.H. Choufoer | 55,381 | 35,094 | ||||||
| Ir. J.M.H. van Engelshoven | 80,712 | 47,368 | ||||||
| R.M. Hart | 80,399 | 52,006 | ||||||
| Drs C.A.J. Herkströter | 101,043 | 52,580 | ||||||
| Ir. H. de Ruiter | 124,019 | 68,670 | ||||||
| Ir. K. Swart | 19,664 | 14,292 | ||||||
| Ir. L.C. van Wachem | 115,672 | 66,422 | ||||||
| Ir. E.G.G. Werner | 32,621 | 23,605 | ||||||
Totala | 797,569 | 463,004 | ||||||
| a | These amounts differ from actual relevant pensions paid. |
15 Employee numbers
| 16 Reconciliation between Netherlands GAAP and US GAAP | € million | |||||||||||||||||||||||||||||||
| Basic earnings per ordinary share | Net income | Net assets | ||||||||||||||||||||||||||||||
| 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | |||||||||||||||||||||||||
| In accordance with Netherlands GAAP: | ||||||||||||||||||||||||||||||||
Adjustments for US GAAP: | 3.20 | 2.97 | 3.32 | 6,520 | 6,108 | 6,947 | 34,516 | 34,586 | ||||||||||||||||||||||||
| Amortisation of goodwill | 0.04 | 0.04 | – | 90 | 76 | – | 137 | 69 | ||||||||||||||||||||||||
| Asset retirement obligations | 0.07 | – | – | 138 | – | – | – | – | ||||||||||||||||||||||||
| In accordance with US GAAP | 3.31 | 3.01 | 3.32 | 6,748 | 6,184 | 6,947 | 34,653 | 34,655 | ||||||||||||||||||||||||
The difference 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 above) and US GAAP is that under US GAAP, commencing in 2002, goodwill is no longer amortised but instead 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.
In addition, under US GAAP, a change in accounting for asset retirement obligations in 2003, as described on page G11, has been 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 has been reported as an adjustment to the opening balance of net assets and, due to the absence of comparative date, net income for prior years has not been restated.
17 Contingencies and litigation
Remuneration
About this report
This report contains the following sections:
| – | The Remuneration and Succession Review Committee; |
| – | Remuneration policy; |
| – | 2003 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 | |
| Hubert Markl | Appointed to the committee on December 3, 2003 | |
| Joachim Milberg | Retired from the committee on October 1, 2003 | |
| Henny de Ruiter | ||
| Appointed by the Board of Shell Transport | ||
| Nina Henderson | ||
| Sir Peter Job | ||
| Sir John Kerr | Appointed to the committee on October 21, 2003 | |
| Sir Mark Moody-Stuart | Retired from the committee on October 21, 2003 | |
The Chairman of the committee is currently Aarnout Loudon. Of the Royal Dutch members of the committee only Henny de Ruiter is not an independent member of the Royal Dutch Supervisory Board, as he serves as a Director of the Group Holding Companies. He will retire from the Supervisory Board of Royal Dutch and as such from REMCO on June 30, 2004. The Shell Transport members of the committee are currently all independent non-executive Directors. Biographical details of the REMCO members are shown on page 78 and 89.
REMCO’s responsibilities
As a joint committee of two independent boards, REMCO cannot formally determine the remuneration package of individual Managing Directors. The committee makes recommendations to the Supervisory Board of Royal Dutch and the Board of Shell Transport.
| 1 | Malcolm Brinded resigned as a Managing Director of the Company on March 3, 2004. He was appointed a Managing Director of Shell Transport on the same date. Walter van de Vijver resigned as a Managing Director of the Company on March 3, 2004. |
REMCO reviewed its Terms of Reference in light of corporate governance developments and they were subsequently revised 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 2003 REMCO met eight times; attendance figures for the individual committee members are shown below:
| Attendance | ||||
| Members | Attendance | |||
| Aarnout Loudon | 8 | |||
| Nina Henderson | 8 | |||
| Sir Peter Job | 7 | |||
| Sir John Kerr | 2 | New member since October 21, 2003 | ||
| Hubert Markl | – | New member since December 3, 2003 | ||
Joachim Milberga | 1 | Retired on October 1, 2003 | ||
| Sir Mark Moody-Stuart | 5 | Retired on October 21, 2003 | ||
| Henny de Ruiter | 7 | |||
| a | Joachim Milberg’s attendance was affected by personal circumstances and he retired from the Supervisory Board and the committee in October. |
In addition to fulfilling these responsibilities, REMCO also discussed a number of other issues during the year. These included:
| – | institutional investor relations and communications; |
| – | corporate governance; |
| – | a new long-term incentive plan1; and |
| – | REMCO’s Terms of Reference. |
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 Group Managing Directors for exceptional performance that enhances the value of the Group; and |
| – | desire to align Group Managing Directors’ interests with those of shareholders. |
The Group’s remuneration policy is based on the following working principles:
Performance driven
| 1 | This plan was approved by the General Meetings of Shareholders of both Royal Dutch and Shell Transport in April 2003 (see Remuneration policy – Long-Term Incentive Plan (LTIP) on page R13 for information on the plan). |
Competitiveness
Consistency
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. Progression of an individual Group Managing Director’s salary to the target position is usually over a three-year period from appointment.
Annual incentive
As part of the annual Group 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. The financial objectives relate to Total Shareholder Return (TSR3) relative to other major integrated oil companies (see the industry peer group table on page R14), and to Return on Average Capital Employed (ROACE). The operational objectives relate to portfolio value growth with key targets for each business. The sustainable development objectives focus on people, health, safety, environment and reputation. The 2003 Scorecard weightings are 60% for financial objectives, each factor equally weighted, 20% for operational objectives and 20% for sustainable development objectives. The same approach has been adopted for 2004.
Targets are set at stretching but realistic levels. At the end of the financial year the Group results are translated into an overall Group score, which can range anywhere between zero and two, the minimum and maximum, respectively. When determining the final outcome, the results on the non-financial targets are not taken into account if the results on the financial targets are below target. Bonus awards are based on the score multiplied by the target bonus level with REMCO using its judgment in making its final recommendations. The target level for 2004 will be 100% of base pay, in line with market practice.
Deferred bonus
The deferred bonus shares, together with shares equivalent to the value of dividends payable on the deferred bonus shares (dividend shares), are released three years after deferral. Provided the participants remain in Group employment for three years following the deferral, or reach normal retirement within the three-year period, they will also receive one additional share for every two deferred bonus and dividend shares accumulated. There is no further performance test for the additional matching shares beyond that governing performance in the relevant bonus year. The plan does not result in dilution of shareholder equity.
Long-term incentives
| 1 | AEX10: the 10 largest companies by way of market capitalisation in the Amsterdam Exchange index, a market capitalisation weighted index of stocks traded on the Amsterdam Exchange, now a part of the Euronext Exchange. This group is established at the beginning of the relevant performance period. |
| 2 | FTSE20: the 20 largest companies by way of market capitalisation in the Financial Times Stock Exchange 100 index, a market capitalisation weighted index of stocks traded on the London Stock Exchange. This group is established at the beginning of the relevant performance period. |
| 3 | TSR is measured by the average weighted share price performance plus dividend of Royal Dutch and Shell Transport over the 10-day period at the beginning and end of the relevant financial year. |
that Group Managing Directors share the interests of shareholders. The Group’s business and performance is oriented to the long-term and, accordingly, long-term incentives comprise more than half of Group Managing Directors’ remuneration.
Expected value models are used in the determination of appropriate long-term incentive levels. Option valuations have been modelled by Towers Perrin and Kepler Associates using the Black-Scholes model, which is a commonly accepted approach to calculate the expected value of stock options. A standard valuation approach, provided by Towers Perrin and Kepler Associates1, has been adopted to determine the expected value of the conditional award of shares under the Long-Term Incentive Plan (LTIP). The expected value based on these methods is equal to 22% of the face value of the grant for stock options and 43% of the face value of the award of shares under the LTIP.
Stock options
Stock options granted to Group Managing Directors in 2003 and beyond are 100% performance-linked. The current financial performance criteria are TSR and ROACE; these will be calculated as the average result of the three financial years prior to grant. TSR is measured against the other major integrated oil companies (see the industry peer group table on page R14). These financial targets have been chosen as they represent a balanced test of the Group’s long-term external performance and internal operating efficiency. These same performance criteria will be used in 2004. At the end of the financial year, the three-year results on the performance criteria will be translated into an overall performance rating, which can range anywhere between zero and two. The levels of the stock option grants are based on this rating multiplied by the target grant level. Target grant levels will reflect competitive market practice.
The value of the stock options depends on both the performance on the criteria at the time of grant and the future share price performance. This approach reflects the long-term nature of value creation in the Group, where both past and future performance are of significant impact. Given the global nature of the Group’s business and executive cadre, this approach balances the market practices with regard to stock options in the majority of countries in which the Group operates.
Long-Term Incentive Plan (LTIP)
The performance targets are linked to relative TSR over the three-year performance period. Relative TSR has been chosen as the performance test that most closely aligns the interests of Group Managing Directors and senior executives with those of shareholders. TSR is measured relative to two separate groups of comparator companies, as REMCO considers that it is appropriate to test performance against both major home markets and industry competitors. The first comparator group consists of the AEX10 together with the FTSE20. The second comparator group consists of the five major integrated oil companies. (See the peer group tables on R14.) 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.
| 1 | Their models take into account the threshold and maximum levels of performance and the proportion of shares that will be released at these points, as well as the nature of the comparator groups against which performance is measured. Risk of forfeiture and dividends are also taken into account. |
Home markets peer group for base pay and for LTIP
| as at January 1, 2003 | as at January 1, 2004 | |
| ABN AMRO | ABN AMRO | |
| AEGON | AEGON | |
| Ahold | Ahold | |
| Akzo Nobel | Fortis | |
| Heineken | Heineken | |
| ING Group | ING Group | |
| KPN | KPN | |
| Philips | Philips | |
| Royal Dutch | Royal Dutch | |
| Unilever N.V. | Unilever N.V. | |
FTSE20 listed companiesa
| as at January 1, 2003 | as at January 1, 2004 | |
| Anglo American | Anglo American | |
| AstraZeneca | AstraZeneca | |
| Aviva | Barclays | |
| Barclays | BHP Billiton | |
| BG Group | BP | |
| BP | British American Tobacco | |
| British American Tobacco | British Sky Broadcasting | |
| BT | BT | |
| Diageo | Diageo | |
| GlaxoSmithKline | GlaxoSmithKline | |
| HBOS | HBOS | |
| HSBC | HSBC | |
| Lloyds TSB | Lloyds TSB | |
| National Grid Transco | National Grid Transco | |
| Rio Tinto | Rio Tinto | |
| Royal Bank of Scotland | Royal Bank of Scotland | |
| Shell Transport | Shell Transport | |
| Tesco | Tesco | |
| Unilever PLC | Unilever PLC | |
| Vodafone | 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. |
Industry peer group for base pay, annual bonus, stock options and LTIP
| as at January 1, 2003, and January 1, 2004 | ||
| BP | ||
| ChevronTexaco | ||
| ExxonMobil | ||
| Royal Dutch/ Shell Group | ||
| Total | ||
Pension policy
For the Dutch Managing Directors of Royal Dutch the principal source of their pensions is the Stichting Shell Pensioenfonds (SSPF). This is a defined benefit fund to which Managing 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 principal source of pension for the British Managing Director of Royal Dutch1 is the Shell Overseas Contributory Pension Fund (SOCPF). This is a defined benefit fund to which the Managing Director contributes the same percentage of relevant earnings as other employees. Contributions to the fund are based upon actuarial advice. Neither the annual bonus nor the deferred bonuses are pensionable.
| 1 | Malcolm Brinded resigned as a Managing Director of the Company on March 3, 2004. He was appointed a Managing Director of Shell Transport on the same date. |
Managing Directors retire on June 30, following their 60th birthday. There are provisions in both pension funds for a surviving dependant benefit, in the case of SSPF of 70% or, in the case of SOCPF of 60%, 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, or, in case of SOCPF, three times annual pensionable pay.
Other benefits policy
All-employee share schemes
Contracts policy
External appointments
Shareholdings
2003 actual remuneration1
Base pay
Annual incentive
Stock options
Stock options granted in March 2001 were due to vest in March 2004. The performance period for the options was January 1, 2001 to December 31, 2003. The Royal Dutch/ Shell Group ranked fifth in TSR against the industry peer group (three-year average over the period 2001 to 2003). REMCO recommended that the options granted under performance conditions should not vest (50% of the grant). Therefore only the remaining 50% of the options granted in March 2001, which vest over time, vested in March 2004.
Long-Term Incentive Plan
| 1 | The information in the tables on pages R16 to R19 has been subjected to audit, except for the Expected value columns in the Stock options table and in the Long-Term Incentive Plan table on pages R16 and R17, which are unaudited. |
| Emoluments of Managing Directors in office during 2003 | € | |||||||||||||||
| Annual | Other | |||||||||||||||
| Salaries | bonusa | benefitsb | Total | |||||||||||||
| Jeroen van der Veer | ||||||||||||||||
2003 | 1,120,000 | 0 | 11,502 | 1,131,502 | ||||||||||||
| 2002 | 1,013,729 | 1,230,500 | c | 4,768 | 2,248,997 | |||||||||||
| 2001 | 923,929 | 619,450 | c | 4,620 | 1,547,999 | d | ||||||||||
| Malcolm Brinded | ||||||||||||||||
2003 | 800,000 | 0 | 23,707 | 823,707 | ||||||||||||
2002e | 372,500 | 428,375 | c | 2,210 | f | 803,085 | ||||||||||
| Rob Routs | ||||||||||||||||
2003g | 405,000 | 0 | 55,612 | 460,612 | ||||||||||||
| Walter van de Vijver | ||||||||||||||||
2003 | 842,500 | 0 | 26,060 | 868,560 | ||||||||||||
| 2002 | 735,095 | 902,750 | 18,091 | h | 1,655,936 | |||||||||||
2001i | 342,536 | 221,330 | 2,162 | 566,028 | ||||||||||||
| 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, where applicable, other benefits stated at a value employed by the Fiscal Authorities in the Netherlands. |
| c | Of which one-third was deferred under the Deferred Bonus Plan. |
| d | The total for 2001 as stated in the Annual Report and Accounts 2002 was€1,841,439 and included an amount for realised share option gains upon exercise of€293,440. In 2002, there were no realised share option gains upon exercise. From 2003 these gains will be shown in the Stock options table. The total for 2001, as reported here, has been restated to reflect this change. |
| e | Malcolm Brinded was appointed a Managing Director with effect from July 1, 2002, therefore, where appropriate, the 2002 emoluments are prorated. |
| f | Exclusive of deferred payment in shares amounting to £386,000 granted in 1999. |
| g | Rob Routs was appointed a Managing Director with effect from July 1, 2003, therefore, where appropriate, the 2003 emoluments are prorated. |
| h | Exclusive of deferred payment in shares amounting to€688,839 granted in 1999. |
| i | Walter van de Vijver was appointed a Managing Director with effect from July 1, 2001, therefore, where appropriate, the 2001 emoluments are prorated. |
| Stock options | ||||||||||||||||||||||||||||||||||||||||
| Options Royal Dutch | ||||||||||||||||||||||||||||||||||||||||
| Number of options | ||||||||||||||||||||||||||||||||||||||||
| Exercised | Expected | Realised | ||||||||||||||||||||||||||||||||||||||
| (cancelled/ | value of | Realisable | gains on | |||||||||||||||||||||||||||||||||||||
| Granted | lapsed) | the 2003 | gains as at | stock | ||||||||||||||||||||||||||||||||||||
| At Jan 1, | during | during | At Dec 31, | Exercise | Exercisable | Expiry | stock options | Dec 31, | options | |||||||||||||||||||||||||||||||
| 2003 | the year | the year | 2003 | pricea | from date | date | grantb | 2003c | exercised | |||||||||||||||||||||||||||||||
| € | € | € | ||||||||||||||||||||||||||||||||||||||
| Jeroen van der Veer | 40,850 | – | – | 40,850 | 41.16 | 22.12.01 | 21.12.08 | – | 26,144 | – | ||||||||||||||||||||||||||||||
| 45,000 | – | (11,250 | ) | 33,750 | 59.54 | 23.03.03 | 22.03.10 | – | 0 | – | ||||||||||||||||||||||||||||||
| 80,000 | – | – | 80,000 | 62.60 | 26.03.04 | 25.03.11 | – | – | – | |||||||||||||||||||||||||||||||
| 105,000 | – | – | 105,000 | 62.10 | 21.03.05 | 20.03.12 | – | – | – | |||||||||||||||||||||||||||||||
| – | 150,000 | – | 150,000 | 36.81 | 19.03.06 | 18.03.13 | 1,214,730 | – | – | |||||||||||||||||||||||||||||||
| 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 | 931,293 | – | – | |||||||||||||||||||||||||||||||
| Rob Routs | 20,000 | – | – | 20,000 | 41.16 | 22.12.01 | 21.12.08 | – | 12,800 | – | ||||||||||||||||||||||||||||||
| 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 | 400,051 | – | – | |||||||||||||||||||||||||||||||
| – | 50,066 | d | – | 50,066 | 40.95 | 19.08.06 | 18.08.13 | 451,045 | – | – | ||||||||||||||||||||||||||||||
| Walter van de Vijver | 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 | – | 12,800 | – | |||||||||||||||||||||||||||||||
| 32,000 | – | (8,000 | ) | 24,000 | 59.54 | 23.03.03 | 22.03.10 | – | 0 | – | ||||||||||||||||||||||||||||||
| 10,000 | – | (2,500 | ) | 7,500 | 68.73 | 23.08.03 | 22.08.10 | – | 0 | – | ||||||||||||||||||||||||||||||
| 40,000 | – | – | 40,000 | 62.60 | 26.03.04 | 25.03.11 | – | – | – | |||||||||||||||||||||||||||||||
| 75,000 | – | – | 75,000 | 62.10 | 21.03.05 | 20.03.12 | – | – | – | |||||||||||||||||||||||||||||||
| – | 115,000 | – | 115,000 | 36.81 | 19.03.06 | 18.03.13 | 931,293 | – | – | |||||||||||||||||||||||||||||||
Maarten van den Berghe | 37,950 | – | – | 37,950 | 41.16 | 22.12.01 | 29.06.05 | – | 24,288 | – | ||||||||||||||||||||||||||||||
Options Shell Transport | £ | £ | ||||||||||||||||||||||||||||||||||||||
| Malcolm Brinded | 37,500 | – | – | 37,500 | 4.39 | 11.12.00 | 10.12.07 | – | 0 | – | ||||||||||||||||||||||||||||||
| 139,200 | – | – | 139,200 | 3.63 | 22.12.01 | 21.12.08 | – | 73,080 | – | |||||||||||||||||||||||||||||||
| 245,000 | – | (61,250 | ) | 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 | – | – | 278,200 | 5.52 | 26.03.04 | 25.03.11 | – | – | – | |||||||||||||||||||||||||||||||
| 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 2003 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 or Shell Transport shares, respectively, at December 31, 2003, and multiplied by the number of shares under option at December 31, 2003. The actual gain, if any, a Managing Director will realise, will depend on the market price of the Royal Dutch or Shell Transport shares at the time of exercise. |
| d | In 2003, 259 active employees who received Texaco Stock Appreciation Rights (SARs) while employed by the former alliance with Texaco in the USA, were offered a three-for-two replacement of Texaco SARs with Royal Dutch stock options. As a result of his previous employment with the alliance Rob Routs held 33,337 Texaco SARs which were replaced by 50,066 Royal Dutch stock options under the Group Stock Options Plan in August 2003. The exercise price of these options was the average share price over a period of five trading days prior to and including the day on which the options were granted. The options will vest three years after grant and remain exercisable until 10 years after grant. |
| e | Maarten van den Bergh holds share options relating to his former service with the Group. |
| Long-Term Incentive Plan (LTIP) | ||||||||||||||||||||||||||||
| Performance shares | Expected value | |||||||||||||||||||||||||||
| conditionally | Market price at | Start of | End of | of the 2003 | ||||||||||||||||||||||||
| At Jan 1, | awarded during | At Dec 31, | date of | performance | performance | performance | ||||||||||||||||||||||
| 2003 | the year | 2003 | awarda | period | period | shares awardb | ||||||||||||||||||||||
| € | € | |||||||||||||||||||||||||||
| Jeroen van der Veer | – | 57,142 | 57,142 | 40.95 | 01.01.03 | 31.12.05 | 1,006,185 | |||||||||||||||||||||
| Malcolm Brinded | – | 41,758 | 41,758 | 40.95 | 01.01.03 | 31.12.05 | 735,296 | |||||||||||||||||||||
| Rob Routs | – | 39,560 | 39,560 | 40.95 | 01.01.03 | 31.12.05 | 696,592 | |||||||||||||||||||||
| Walter van de Vijver | – | 43,956 | 43,956 | 40.95 | 01.01.03 | 31.12.05 | 773,999 | |||||||||||||||||||||
| 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 2003 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. The end of the performance period is not until December 31, 2005, however, if the agreed performance criteria were to be applied at December 31, 2003, none of the shares would qualify for release. |
| 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, 2003 | during the yeara | at awardb | during the yearc | during the yeard | December 31, 2003 | |||||||||||||||||||
| € | € | |||||||||||||||||||||||
| Jeroen van der Veer | ||||||||||||||||||||||||
| 2003 award | – | 11,188 | 36.66 | 507 | 39.04 | 11,695 | ||||||||||||||||||
| 2002 award | 3,549 | – | 60.09 | 161 | 39.04 | 3,710 | ||||||||||||||||||
| Malcolm Brinded | ||||||||||||||||||||||||
| 2003 award | – | 6,426 | 36.66 | 292 | 39.04 | 6,718 | ||||||||||||||||||
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.
| 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 Managing Directors table on page R16. |
| 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 2002 final and 2003 interim annual dividends paid during the year:€37.60 and€40.47, respectively. |
| Pensions | ||||||||||||||||||||||||
| Increase | Accumulated | Pension | Pension | |||||||||||||||||||||
| Years of | in accrued | annual | premium 2003 | premium 2002 | ||||||||||||||||||||
| Group | pension | pension as at | paid by | paid by | ||||||||||||||||||||
| Age as at | service as at | during 2003 | Dec 31, 2003 | employer | employer | |||||||||||||||||||
| Dec 31, 2003 | Dec 31, 2003 | € thousand | € thousand | € thousand | € thousand | |||||||||||||||||||
| Jeroen van der Veer | 56 | 32 | 76 | 675 | 171 | 0 | ||||||||||||||||||
| Malcolm Brinded | 50 | 29 | 54 | a | 472 | b | 622 | c | 37 | |||||||||||||||
Rob Routsd | 57 | 25 | 8 | 452 | 81 | – | ||||||||||||||||||
| Walter van de Vijver | 48 | 24 | 61 | 375 | 129 | 0 | ||||||||||||||||||
| a | Includes an accrued pension increase and the movement in the exchange rate between sterling and the euro over the period disclosed; sterling converted to euro at the average quarterly rate of exchange. |
| b | Sterling converted to euro against year-end rate of exchange. |
| c | 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. |
| d | As from July 1, 2003. REMCO considered it important to apply the policy of treating Dutch Managing Directors of Royal Dutch in a cohesive and consistent manner, which implied participation in the Dutch pension plan. Rob Routs accrued the majority of his pension rights during his previous employment with Shell Canada. Taking into account his retirement during 2007, it has been decided to provide the same pension entitlements that he would have received had he remained in the Canadian plan. A transfer of his accrued Canadian rights to the Stichting Shell Pensioenfonds required a net additional cash funding by the Group of€3,074 thousand (partly to offset Canadian tax withholdings of 25%), resulting in five additional years of service. This was the most cost-effective resolution within the various relevant national legal and tax regimes. |
Pensions
Managing Directors’ contracts of service
Supervisory Board members
Policy
Fees
| Emoluments of the members of the Supervisory Board | ||||||||||||
| € | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
Aad Jacobs | ||||||||||||
| Chairman’s fee | 15,000 | 5,750 | – | |||||||||
| Supervisory Board fees | 55,000 | 46,000 | 45,378 | |||||||||
| Committee fees | 7,000 | 7,000 | 6,807 | |||||||||
| 77,000 | 58,750 | 52,185 | ||||||||||
Maarten van den Bergh | ||||||||||||
| Supervisory Board fees | 55,000 | 46,000 | 45,378 | |||||||||
| Committee fees | 7,000 | 7,000 | 6,807 | |||||||||
Holding Company feesa | 27,711 | 29,021 | 29,148 | |||||||||
| 89,711 | 82,021 | 81,333 | ||||||||||
Wim Kokb | ||||||||||||
| Supervisory Board fees | 27,500 | – | – | |||||||||
| Committee fees | 3,500 | – | – | |||||||||
| 31,000 | – | – | ||||||||||
Aarnout Loudon | ||||||||||||
| Supervisory Board fees | 55,000 | 46,000 | 45,378 | |||||||||
| Committee fees | 14,000 | 14,000 | 13,613 | |||||||||
| 69,000 | 60,000 | 58,991 | ||||||||||
Hubert Markl | ||||||||||||
| Supervisory Board fees | 55,000 | 23,000 | – | |||||||||
| Committee fees | – | – | – | |||||||||
| 55,000 | 23,000 | – | ||||||||||
Joachim Milbergc | ||||||||||||
| Supervisory Board fees | 41,250 | 46,000 | 45,378 | |||||||||
| Committee fees | 5,250 | 7,000 | 6,807 | |||||||||
| 46,500 | 53,000 | 52,185 | ||||||||||
Lawrence Ricciardi | ||||||||||||
| Supervisory Board fees | 55,000 | 46,000 | 22,689 | |||||||||
| Committee fees | 3,500 | – | – | |||||||||
| Intercontinental travel fees | 21,375 | – | – | |||||||||
| 79,875 | 46,000 | 22,689 | ||||||||||
Henny de Ruiter | ||||||||||||
| Supervisory Board fees | 55,000 | 46,000 | 45,378 | |||||||||
| Committee fees | 14,000 | 10,500 | 6,807 | |||||||||
Holding Company feesa | 27,711 | 29,021 | 29,148 | |||||||||
| 96,711 | 85,521 | 81,333 | ||||||||||
Jan Timmerd | ||||||||||||
| Supervisory Board fees | 27,500 | 46,000 | 45,378 | |||||||||
| Committee fees | 7,000 | 14,000 | 13,613 | |||||||||
| 34,500 | 60,000 | 58,991 | ||||||||||
| The information in this table has been subjected 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, 2003. | |
| c | Retired on October 1, 2003. | |
| d | Retired on June 30, 2003. |
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 and no dilution of shareholder equity is involved. Shares to be delivered by a Group company under these plans are generally bought in the market at the time the commitment is made.
Group Stock Option Plans
Stock options 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 Group Managing Directors and the most senior executives 100% of options granted in 2003 and in subsequent years will be subject to performance conditions.
Restricted Stock Plan
Group Long-Term Incentive Plan (LTIP)
Global Employee Share Purchase Plan
Shell 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 22 of the Group Financial Statements. |
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 2003, 2002 and 2001 appearing on pages S2 to S11. The preparation of the Financial Statements is the responsibility of the Company’s Directors. Our responsibility is to express an opinion on those 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, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with the accounting principles generally accepted in the United Kingdom.
As discussed in Note 2 on page S5, the Company has restated its Financial Statements for the two years ended December 31, 2002, and made certain changes in its accounting principles.
As discussed in Note 5 on page S7, the Company has restated its Financial Statements for the two years ended December 31, 2002 due to a change in its method of accounting for earnings per share.
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 12 on page S10.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP, London
May 23, 2004
Financial Statements
| Profit and Loss Account | £ million | |||||||||||||||
| Note | 2003 | 2002 | 2001 | |||||||||||||
| Income from shares in companies of the Royal Dutch/Shell Group | 3 | 1,361.5 | 1,403.2 | 2,545.6 | ||||||||||||
| Interest and other income | 5.6 | 5.4 | 5.8 | |||||||||||||
| 1,367.1 | 1,408.6 | 2,551.4 | ||||||||||||||
| Administrative expenses | 4.4 | 4.2 | 3.4 | |||||||||||||
| Profit on ordinary activities before taxation | 1,362.7 | 1,404.4 | 2,548.0 | |||||||||||||
| Tax on profit on ordinary activities | 4 | 0.3 | 0.4 | 0.7 | ||||||||||||
| Distributable profit for the year | 1,362.4 | 1,404.0 | 2,547.3 | |||||||||||||
| As | As | ||||||||||||||||||
| restated | restated | ||||||||||||||||||
| Distributable profit for the year | 1,362.4 | 1,404.0 | 2,547.3 | ||||||||||||||||
| Share of earnings retained by companies of the Royal Dutch/Shell Group | 2,6 | 1,612.2 | 1,156.3 | 329.7 | |||||||||||||||
| Earnings for the year attributable to shareholders | 2,974.6 | 2,560.3 | 2,877.0 | ||||||||||||||||
| Aggregate dividends paid and proposed | 1,523.1 | 1,475.0 | 1,440.6 | ||||||||||||||||
All results relate to continuing operations.
| pence | |||||||||||||||||||
| Earnings per 25p Ordinary sharea | |||||||||||||||||||
| 2002 | 2001 | ||||||||||||||||||
| 2003 | As | As | |||||||||||||||||
| restated | restated | ||||||||||||||||||
Distributable profit for the year | 5 | 14.3 | 14.6 | 26.1 | |||||||||||||||
| Distributable profit for the year | 14.3 | 14.6 | 26.1 | ||||||||||||||||
| Share of earnings retained by companies of the Royal Dutch/Shell Group | 2 | 16.9 | 12.0 | 3.4 | |||||||||||||||
| Earnings for the year attributable to shareholders | 31.2 | 26.6 | 29.5 | ||||||||||||||||
| 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, | 2002 | |||||||||||||
| Note | 2003 | As restated | ||||||||||||
Fixed assets | ||||||||||||||
| Investments | ||||||||||||||
| Shares (unlisted) in companies of the Royal Dutch/ Shell Group | 6 | 16,279.2 | 15,000.8 | |||||||||||
Current assets | �� | |||||||||||||
| Debtors: | ||||||||||||||
| Dividends receivable from companies of the Royal Dutch/Shell Group | 1,140.3 | 1,263.7 | ||||||||||||
| Other debtors | 0.1 | 0.1 | ||||||||||||
| 1,140.4 | 1,263.8 | |||||||||||||
| Cash at bank: | ||||||||||||||
| Short-term deposits | 86.8 | 89.9 | ||||||||||||
| Cash | 0.3 | 0.4 | ||||||||||||
| 1,227.5 | 1,354.1 | |||||||||||||
Creditors: amounts due within one year | ||||||||||||||
| Amounts due to companies of the Royal Dutch/ Shell Group | 0.8 | 1.1 | ||||||||||||
| Corporation tax | 0.2 | 0.2 | ||||||||||||
| Unclaimed dividends | 10.2 | 9.5 | ||||||||||||
| Other creditors and accruals | 2.2 | 2.3 | ||||||||||||
| Preference dividends accrued | 0.3 | 0.3 | ||||||||||||
| Ordinary dividend proposed | 932.9 | 899.1 | ||||||||||||
| 946.6 | 912.5 | |||||||||||||
Net current assets | 280.9 | 441.6 | ||||||||||||
Total assets less current liabilities | 16,560.1 | 15,442.4 | ||||||||||||
Capital and reserves | ||||||||||||||
| Equity interests: | ||||||||||||||
| Called-up share capital; Ordinary shares | 7 | 2,416.9 | 2,416.9 | |||||||||||
| Capital redemption reserve | 8 | 69.0 | 69.0 | |||||||||||
| Revaluation reserve | 6 | 13,779.5 | 12,501.1 | |||||||||||
| Profit and Loss Account | 282.7 | 443.4 | ||||||||||||
| 16,548.1 | 15,430.4 | |||||||||||||
| Non-equity interests | ||||||||||||||
| Called-up share capital: | 7 | |||||||||||||
| First Preference shares | 2.0 | 2.0 | ||||||||||||
| Second Preference shares | 10.0 | 10.0 | ||||||||||||
| 12.0 | 12.0 | |||||||||||||
Shareholders’ funds | 9 | 16,560.1 | 15,442.4 | |||||||||||
Lord Oxburgh
| Statement of Total Recognised Gains and Losses | £ million | |||||||||||||||
| 2002 | 2001 | |||||||||||||||
| Note | 2003 | As restated | As restated | |||||||||||||
| Distributable profit for the year | 1,362.4 | 1,404.0 | 2,547.3 | |||||||||||||
| Unrealised surplus/(deficit) on revaluation of investments in companies of the Royal Dutch/ Shell Group | 6 | 1,278.4 | (515.2 | ) | 82.3 | |||||||||||
| Total recognised gains and losses relating to the year | 2,640.8 | 888.8 | 2,692.6 | |||||||||||||
| Prior year adjustment | 2 | (631.5 | ) | – | – | |||||||||||
| Total recognised gains and losses since last annual report | 2,009.3 | 888.8 | 2,629.6 | |||||||||||||
| Statement of Retained Profit | £ million | |||||||||||||||||
| 2003 | 2002 | 2001 | ||||||||||||||||
| Distributable profit for the year | 1,362.4 | 1,404.0 | 2,547.3 | |||||||||||||||
| Distributable retained profit at beginning of year | 443.4 | 884.0 | 876.3 | |||||||||||||||
| 1,805.8 | 2,288.0 | 3,423.6 | ||||||||||||||||
| Dividends on non-equity shares: | 7 | |||||||||||||||||
| First Preference shares | 0.1 | 0.1 | 0.1 | |||||||||||||||
| Second Preference shares | 0.7 | 0.7 | 0.7 | |||||||||||||||
| 0.8 | 0.8 | 0.8 | ||||||||||||||||
| 1,805.0 | 2,287.2 | 3,422.8 | ||||||||||||||||
| Dividends on equity shares: | 7 | |||||||||||||||||
| 25p Ordinary shares | ||||||||||||||||||
| Interim of 6.10p in 2003, 5.95p in 2002 and 5.85p in 2001 | 589.7 | 578.0 | 574.4 | |||||||||||||||
| Second interim of 9.65p in 2003, final of 9.30p in 2002 and 8.95p in 2001 | 932.9 | 899.1 | 872.5 | |||||||||||||||
| Reduction due to share buyback and unclaimed dividends | (0.3 | ) | (2.9 | ) | (7.1 | ) | ||||||||||||
| 1,522.3 | 1,474.2 | 1,439.8 | ||||||||||||||||
| Share repurchase including expenses | – | 369.6 | 1,099.0 | |||||||||||||||
| Distributable retained profit at end of year | 282.7 | 443.4 | 884.0 | |||||||||||||||
| Statement of Cash Flows | £ million | |||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Returns on investments and servicing of finance | ||||||||||||
| Dividends received from companies of the Royal Dutch/Shell Group | 1,484.9 | 1,838.8 | 2,586.9 | |||||||||
| Interest received | 5.6 | 5.6 | 5.5 | |||||||||
| Preference dividends paid | (0.8 | ) | (0.8 | ) | (0.8 | ) | ||||||
| Other | (3.8 | ) | (3.7 | ) | (2.6 | ) | ||||||
| Net cash inflow from returns on investments and servicing of finance | 1,485.9 | 1,839.9 | 2,589.0 | |||||||||
Taxation | ||||||||||||
| Tax paid | (0.3 | ) | (0.6 | ) | (0.5 | ) | ||||||
Equity dividends paid | ||||||||||||
| Ordinary shares | (1,488.5 | ) | (1,447.6 | ) | (1,452.3 | ) | ||||||
| Management of liquid resources (short-term deposits) | ||||||||||||
| Net cash inflow/(outflow) from management of liquid resources | 3.1 | (22.4 | ) | (38.0 | ) | |||||||
Financing | ||||||||||||
| Repurchase of share capital, including expenses | – | (369.6 | ) | (1,099.0 | ) | |||||||
| Net (decrease)/increase in amounts due to companies of the Royal Dutch/Shell Group | (0.3 | ) | 0.1 | 0.5 | ||||||||
Increase/(Decrease) in cash | (0.1 | ) | (0.2 | ) | (0.3 | ) | ||||||
| Cash at January 1 | 0.4 | 0.6 | 0.9 | |||||||||
| Cash at December 31 | 0.3 | 0.4 | 0.6 | |||||||||
Net debts, being amounts due to the companies of the Royal Dutch/ Shell Group less cash, decreased during 2003 from £0.7 million to £0.5 million (2002: net debts increased from £0.4 million to £0.7 million).
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, 2003 the Company had £86.8 million (2002: £89.9 million) on short-term deposit with third-party banks. The fixed interest rate earned on these sterling deposits at year-end was 3.4% (2002: 4.4%). The carrying amount and fair value of these deposits are the same.
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.
2 Accounting policies and convention
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 Group accounting policies, is included in the Company’s Financial 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.
With effect from 2003 the Group Financial Statements are presented in accordance with US GAAP with separate information presented under Netherlands GAAP. The accounting policies under Netherlands GAAP in the Group Financial Statements, in respect of inventory accounting, the amortisation of goodwill, exploration costs, and certain contracts for the sale and delivery of own natural gas production, have been revised in 2003. The Netherlands GAAP basis of presentation in the Group Financial Statements is more closely aligned with UK GAAP, particularly in the requirements to amortise goodwill. In addition, following a European Union directive, both UK and Netherlands GAAP are converging towards International Financial Reporting Standards for adoption in 2005. Therefore, from 2003 the Company has changed its accounting policy to present its investments in the Group, at a Directors’ valuation based on 40% of the revised separate Netherlands GAAP information, presented by the Group.
Having regard to changes in UK accounting principles following the introduction of Urgent Issues Task Force Abstract No. 37 ‘Purchase and sale of own shares’, 40% of the carrying value of Parent Companies’ shares held by Group companies are now excluded from the valuation of the Company’s investments.
These are changes in accounting policy, and prior period amounts have been restated accordingly. The Group Financial Statements also include a restatement of the Group’s depreciation, depletion, amortisation and other charges arising from the overstatement of unaudited proved oil and gas reserves. This is not significant to the Directors’ valuation of the Company’s investments in Group companies and has been treated as a prior period adjustment so that the impact can be separately identified. The effect of the above changes on the Company’s investments is as follows:
| £ million | |||||||||
| 2002 | 2001 | ||||||||
| Investments as previously stated | 15,632.3 | 16,032.2 | |||||||
| Reduction to exclude Parent Companies’ shares held by Group companies | (695.6 | ) | (538.7 | ) | |||||
| Impact of changes in the presentation of the Group Financial Statements: | |||||||||
| Effect of changes in accounting policies under Netherlands GAAP | 132.8 | 68.9 | |||||||
| Oil and gas reserves related adjustments | (68.7 | ) | (46.4 | ) | |||||
| (631.5 | ) | (516.2 | ) | ||||||
| Restated investments | 15,000.8 | 15,516.0 | |||||||
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.
3 Share in the income and assets of Group companies
| £ million | ||||||||
| 2002 | ||||||||
| 2003 | As restateda | |||||||
| Fixed assets | 25,787.0 | 26,713.2 | ||||||
| Current assets including other long-term assets | 11,861.5 | 12,182.4 | ||||||
| Current liabilities | 12,210.6 | 13,727.4 | ||||||
| Long-term liabilities | 3,400.0 | 3,994.0 | ||||||
| Provisions | 4,989.1 | 5,282.0 | ||||||
| £ million | ||||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restateda | As restateda | ||||||||||
| Sales proceeds | 66,225.3 | 59,380.8 | 46,513.5 | |||||||||
| Sales taxes, excise duties and similar levies | 16,541.8 | 14,971.8 | 11,687.4 | |||||||||
Net proceeds | 49,683.5 | 44,409.0 | 34,826.1 | |||||||||
| Operating profit after net currency gains/losses | 5,275.2 | 4,846.8 | 5,322.0 | |||||||||
| Interest and other income | 486.0 | 202.1 | 294.2 | |||||||||
| Interest expense | 340.1 | 363.6 | 314.8 | |||||||||
Income before taxation | 5,421.1 | 4,685.3 | 5,301.4 | |||||||||
| Taxation | 2,357.5 | 2,078.1 | 2,334.7 | |||||||||
| Minority interests | 89.9 | 47.7 | 91.4 | |||||||||
Net income for the year | 2,973.7 | 2,559.5 | 2,875.3 | |||||||||
| $ million | ||||||||||||
Net income for the yearb | 4,830 | 3,841 | 4,140 | |||||||||
| a | Restated to exclude Parent Companies’ shares from fixed assets and reflect information presented under Netherlands GAAP. | |
| b | Refer to Note 35 in 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 30. 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, 2003 would not be significant, although current assets including other long-term assets would increase by approximately £0.4 billion (2002: £0.3 billion), fixed assets would decrease by approximately £0.8 billion (2002: £0.8 billion), long-term liabilities would decrease by approximately £0.2 billion (2002: £0.1 billion) and provisions would decrease by approximately £0.6 billion (2002: £0.9 billion). The impact on net income for the year is not significant. Shell Transport’s distributions from Group companies were as follows:
| £ million | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Distributions from Group companies | 1,361.5 | 1,403.2 | 2,545.6 | |||||||||
| $ million | ||||||||||||
Distributions from Group companiesa | 2,264 | 2,174 | 3,665 | |||||||||
| a | Refer to Note 35 in the Group Financial Statements. |
4 Tax on profit on ordinary activities
| £ million | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Corporation tax at 30% (2002 and 2001: 30%) in respect of interest income less administrative expenses | 0.3 | 0.4 | 0.7 | |||||||||
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 3.
5 Earnings per share
6 Investments in Group companies
At the start of the year Shell Transport held 1,600 Class “B” shares of $1 each in Shell Petroleum Inc., which is incorporated in the State of Delaware, USA. These shares, together with the 2,400 Class “A” shares of $1 each in that company held by Royal Dutch, carried voting control of Shell Petroleum Inc. but were restricted in regards to dividends to 12% of their par value per annum. Shell Petroleum N.V. held the remaining 1,000 shares of $1 each in Shell Petroleum Inc., which were unrestricted in regard to dividends. During the year the share capital of Shell Petroleum Inc. was reorganised and Royal Dutch and Shell Transport contributed their respective holdings to Shell Petroleum N.V. in return for the issue of new shares in Shell Petroleum N.V. Accordingly Shell Petroleum Inc. became a wholly-owned subsidiary of Shell Petroleum N.V. which is entitled to exercise all voting rights over shares in Shell Petroleum Inc. and to receive all dividends paid by Shell Petroleum Inc. In 2003 the share capital of Shell Petroleum N.V. was also reorganised in connection with the contribution to it by Shell Transport and Royal Dutch of the shares in Shell Petroleum Inc. and the redenomination of the nominal value of its share capital in euro. No change occurred as a result of these changes in the level of interest of Shell Transport in Shell Petroleum N.V., which continues to be 40%.
From 2003, 40% of the carrying amount of Parent Companies’ shares held by Group companies are excluded from the valuation of the investments in Group 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 January 1, 2002 | 22,498 | 0.69 | 15,516.0 | 13,016.3 | |||||||||||||
| Movements during the year 2002: | |||||||||||||||||
| Share in the net income of Group companies | 3,841 | 0.67 | 2,559.5 | 2,559.5 | |||||||||||||
| Distribution to Shell Transport | (2,174 | ) | 0.65 | (1,403.2 | ) | (1,403.2 | ) | ||||||||||
| Undistributed net income of Group companies | 1,667 | 0.69 | 1,156.3 | 1,156.3 | |||||||||||||
| Net (increase)/decrease in Parent Companies’ shares held by Group companies | (337 | ) | 0.70 | (234.9 | ) | (234.9 | ) | ||||||||||
| Other comprehensive incomeb | 302 | 0.62 | 188.3 | 188.3 | |||||||||||||
| Translation effect arising from movements in the dollar/ sterling rate | (1,624.9 | ) | (1,624.9 | ) | |||||||||||||
| Balance at December 31, 2002 | 24,130 | 0.62 | 15,000.8 | 12,501.1 | |||||||||||||
Cumulative effect of change in accounting policyc | 102 | 0.56 | 57.2 | 57.2 | |||||||||||||
| Balance at January 1, 2003 | 24,232 | 15,058.0 | 12,558.3 | ||||||||||||||
| Movements during the year 2003: | |||||||||||||||||
| Share in the net income of Group companies | 4,830 | 0.62 | 2,973.7 | 2,973.7 | |||||||||||||
| Distribution to Shell Transport | (2,264 | ) | 0.60 | (1,361.5 | ) | (1,361.5 | ) | ||||||||||
| Undistributed net income of Group companies | 2,566 | 0.63 | 1,612.2 | 1,612.2 | |||||||||||||
| Net (increase)/decrease in Parent Companies’ shares held by Group companies | (253 | ) | 0.62 | (156.0 | ) | (156.0 | ) | ||||||||||
| Other comprehensive incomeb | 2,479 | 0.60 | 1,498.6 | 1,498.6 | |||||||||||||
| Translation effect arising from movements in the dollar/ sterling rate | (1,733.6 | ) | (1,733.6 | ) | |||||||||||||
| Balance at December 31, 2003 | 29,024 | 0.56 | 16,279.2 | 13,779.5 | |||||||||||||
| $ million | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Shell Transport’s 40% interest in Group net assets at December 31 (see Note 35 to the Group Financial Statements) | 29,024 | 24,130 | 22,498 | |||||||||
| £ million | |||||||||||||
| 2002 | 2001 | ||||||||||||
| 2003 | 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 | 18,434.8 | 16,765.4 | 15,609.1 | ||||||||||
| Parent Companies’ shares held, net of dividends received | (892.4 | ) | (736.4 | ) | (501.5 | ) | |||||||
| Cumulative other comprehensive incomeb | (81.1 | ) | (1,579.7 | ) | (1,768.0 | ) | |||||||
| Currency translation differences | (1,360.5 | ) | 373.1 | 1,998.0 | |||||||||
| 16,279.2 | 15,000.8 | 15,516.0 | |||||||||||
| £/$ exchange rate at December 31 | 0.56 | 0.62 | 0.69 | ||||||||||
| a | The Group Financial Statements have been restated (see Note 2 to the Group Financial Statements and pages G2 to G42). | |
| 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 Notes 31 and 35 to the Netherlands GAAP Financial Statements. |
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, a taxation liability of approximately £1.2 billion would arise (restated 2002: £0.9 billion).
7 Share capital and dividends
The allotted, called up and fully paid share capital at December 31, 2003 was as follows:
| Number of shares | £ | ||||||||
| Equity shares | 9,667,500,000 | 2,416,875,000 | |||||||
| 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 | |||||||
| 9,679,500,000 | 2,428,875,000 | ||||||||
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, 2003 was 94.25 pence per share (2002: 97.6 pence per share) for the First Preference shares and 137.75 pence per share (2002: 135.0 pence per share) for the Second Preference shares.
Ordinary dividends paid and proposed are as follows:
| £ million | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Interim of 6.10p in 2003, 5.95p in 2002 and 5.85p in 2001 | 589.7 | 578.0 | 574.4 | |||||||||
| Second interim of 9.65p in 2003, final of 9.30p in 2002 and final of 8.95p in 2001 | 932.9 | 899.1 | 872.5 | |||||||||
| Reduction due to share buyback and unclaimed dividends | (0.3 | ) | (2.9 | ) | (7.1 | ) | ||||||
| 1,522.3 | 1,474.2 | 1,439.8 | ||||||||||
8 Capital redemption reserve
| £ million | ||||||||
| 2003 | 2002 | |||||||
| As at January 1 | 69.0 | 48.7 | ||||||
| Movement relating to shares bought by Shell Transport and cancelled | – | 20.3 | ||||||
| As at December 31 | 69.0 | 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.
9 Reconciliation of movements in Shareholders’ funds
| £ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Distributable profit for the year | 1,362.4 | 1,404.0 | ||||||
| Dividends | (1,523.1 | ) | (1,475.0 | ) | ||||
| Repurchase of share capital, including expenses | – | (369.6 | ) | |||||
| Unrealised surplus/(deficit) on revaluation of investments in companies of the Royal Dutch/Shell Group (Note 6) | 1,278.4 | (515.2 | ) | |||||
| Net addition/(reduction) to Shareholders’ funds | 1,117.7 | (955.8 | ) | |||||
| Shareholders’ funds as at January 1 (originally £16,073.9 million before adjusting for the effect of the prior year adjustment as described in Note 2 of £631.5 million) | 15,442.4 | 16,398.2 | ||||||
| Shareholders’ funds as at December 31 | 16,560.1 | 15,442.4 | ||||||
10 Auditors’ remuneration
11 Aggregate Directors’ emoluments
| £ | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Salaries, fees and benefits | 2,436,181 | 1,716,378 | 1,979,253 | |||||||||
Performance-related elementa | – | 1,506,500 | 1,025,050 | |||||||||
| 2,436,181 | 3,222,878 | 3,004,303 | ||||||||||
Excess retirement benefitsb | 40,165 | 23,495 | 41,800 | |||||||||
| Realised share option gains | – | 16,476 | 1,653,429 | |||||||||
| Of the emoluments disclosed, £687,311 in 2003, (2002: £458,162; 2001: £326,783) were borne by Shell Transport and charged in the Profit and Loss Account. |
| a | Prior year amounts have been restated to exclude the Deferred Bonus Plan entitlement in respect of 2002 and 2001 (refer to footnotes d and g on page S18). | |
| b | 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. |
12 Reconciliation between US GAAP and UK GAAP
| £million | ||||||||||||||||||||||||||||||||
| pence | ||||||||||||||||||||||||||||||||
| Earnings per share | Net income | Net assets | ||||||||||||||||||||||||||||||
| 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | |||||||||||||||||||||||||
| In accordance with UK GAAP: | 14.3 | 14.6 | 26.1 | 1,362.4 | 1,404.0 | 2,547.3 | 16,560.1 | 15,442.4 | ||||||||||||||||||||||||
Less: Income from shares in companies of the Royal Dutch/Shell Group | (14.3 | ) | (14.6 | ) | (26.1 | ) | (1,361.5 | ) | (1,403.2 | ) | (2,545.6 | ) | ||||||||||||||||||||
| Share in the Netherlands GAAP net income of companies of the Royal Dutch/Shell Group | 31.2 | 26.6 | 29.5 | 2,973.7 | 2,559.5 | 2,875.3 | ||||||||||||||||||||||||||
Retirement obligation accounting policy change | 0.7 | – | – | 64.1 | – | – | ||||||||||||||||||||||||||
Amortisation of Goodwill | 0.4 | 0.4 | – | 42.0 | 33.3 | – | 64.4 | 29.8 | ||||||||||||||||||||||||
| Share in the US GAAP net income of companies of the Royal Dutch/Shell Group | 32.3 | 27.0 | 29.5 | 3,079.8 | 2,592.8 | 2,875.3 | ||||||||||||||||||||||||||
| In accordance with US GAAP | 32.3 | 27.0 | 29.5 | 3,080.7 | 2,593.6 | 2,877.0 | 16,624.5 | 15,472.2 | ||||||||||||||||||||||||
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 revised separate Netherlands GAAP information presented by the Group. This is not in accordance with US GAAP which, in the circumstances of Shell Transport, would require equity accounting.
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, commencing in 2002, goodwill is no longer amortised but instead 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, as described in Note 3 to the Group Financial Statements, has been 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 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. |
The adjustment to net assets represents the effect of adopting equity accounting.
40% interest of Shell Transport in line items as derived from the Netherlands GAAP Group Financial Statements
| £ million | $ million | |||||||
Balance Sheet | ||||||||
2003: | ||||||||
| Current assets | 9,784.6 | 17,444 | ||||||
| Non current assets | 27,863.3 | 49,677 | ||||||
| Current liabilities | 12,210.6 | 21,770 | ||||||
| Non current liabilities | 8,389.1 | 14,956 | ||||||
| Minority interests in Group companies (40% of Group amount on page G37 translated at year end rate on page S8) | 769.0 | 1,371 | ||||||
| Shell Transport share of Group net assets (pages S8-£ & G41-$) | 16,279.2 | 29,024 | ||||||
| Other assets and liabilities of Shell Transport | 280.9 | |||||||
| Net Assets | 16,560.1 | |||||||
2002: | ||||||||
| Current assets | 10,358.8 | 16,662 | ||||||
| Non current assets | 28,536.1 | 45,901 | ||||||
| Current liabilities | 13,727.4 | 22,080 | ||||||
| Non current liabilities | 9,276.0 | 14,920 | ||||||
| Minority interests in Group companies (40% of Group amount on page G37 translated at year end rate on page S8) | 890.7 | 1,433 | ||||||
| Shell Transport share of Group net assets (pages S8-£ & G41-$) | 15,000.8 | 24,130 | ||||||
| Other assets and liabilities of Shell Transport | 441.6 | |||||||
| Net Assets | 15,442.4 | |||||||
Profit and Loss account | ||||||||
2003: | ||||||||
| Sales proceeds (Revenue) | 66,225.3 | 107,557 | ||||||
| Operating profit | 5,329.9 | 8,656 | ||||||
| Net income for the year | 2,973.7 | 4,830 | ||||||
| Distribution for the year | 1,361.5 | 2,264 | ||||||
2002: | ||||||||
| Sales proceeds (Revenue) | 59,380.8 | 89,107 | ||||||
| Operating profit | 4,853.0 | 7,282 | ||||||
| Net income for the year | 2,559.5 | 3,841 | ||||||
| Distribution for the year | 1,403.2 | 2,174 | ||||||
2001: | ||||||||
| Sales proceeds (Revenue) | 46,513.5 | 66,972 | ||||||
| Operating profit | 5,330.3 | 7,675 | ||||||
| Net income for the year | 2,875.3 | 4,140 | ||||||
| Distribution for the year | 2,545.6 | 3,665 | ||||||
13 Contingencies and litigation
Remuneration Report
Directors’ Remuneration Report
This report contains the following sections:
| – | The Remuneration and Succession Review Committee; |
| – | Remuneration policy; |
| – | 2003 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 | ||
| Sir John Kerr | Appointed to the committee on October 21, 2003 | |
| Sir Mark Moody-Stuart | Retired from the committee on October 21, 2003 | |
| Appointed by the Supervisory Board of Royal Dutch | ||
| Aarnout Loudon | Chairman of the committee | |
| Hubert Markl | Appointed to the committee on December 3, 2003 | |
| Joachim Milberg | Retired from the committee on October 1, 2003 | |
| Henny de Ruiter | ||
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 Royal Dutch members of the committee only Henny de Ruiter is not an independent member of the Royal Dutch Supervisory Board, as he serves as a Director of the Group Holding Companies. He will retire from the Supervisory Board of Royal Dutch and as such from REMCO on June 30, 2004. Biographical details of the REMCO members are shown on pages 78 and 89.
REMCO’s responsibilities
| 1 | Sir Philip Watts resigned as a Managing Director of the Company on March 3, 2004. Malcolm Brinded was appointed a Managing Director of the Company on March 3, 2004. Judith Boynton resigned as a Managing Director of the Company on April 18, 2004. |
As a joint committee of two independent boards, REMCO cannot formally determine the remuneration package of individual Managing Directors. The committee makes recommendations to the Board of Shell Transport and the Supervisory Board of Royal Dutch.
REMCO reviewed its Terms of Reference in light of corporate governance developments and they were subsequently revised 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 2003 REMCO met eight times; attendance figures for the individual committee members are shown below:
| Attendance | ||||
| Members | Attendance | |||
| Aarnout Loudon | 8 | |||
| Nina Henderson | 8 | |||
| Sir Peter Job | 7 | |||
| Sir John Kerr | 2 | New member since October 21, 2003 | ||
| Hubert Markl | – | New member since December 3, 2003 | ||
Joachim Milberga | 1 | Retired on October 1, 2003 | ||
| Sir Mark Moody-Stuart | 5 | Retired on October 21, 2003 | ||
| Henny de Ruiter | 7 | |||
| a | Joachim Milberg’s attendance was affected by personal circumstances and he retired from the Supervisory Board and the committee in October. |
In addition to fulfilling these responsibilities, REMCO also discussed a number of other issues during the year. These included:
| – | institutional investor relations and communications; |
| – | corporate governance; |
| – | a new long-term incentive share plan1; and |
| – | REMCO’s Terms of Reference. |
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 Group Managing Directors for exceptional performance that enhances the value of the Group; and |
| – | desire to align Group Managing Directors’ interests with those of shareholders. |
The Group’s remuneration policy is based on the following working principles:
| 1 | This plan was approved by the Annual General Meetings of Shareholders of both Royal Dutch and Shell Transport in April 2003 (see Remuneration policy – Long-term Incentive Plan (LTIP) on page S15 for information on the plan). |
| 2 | Sir Philip Watts resigned from the Company on March 3, 2004. |
Performance driven
Competitiveness
Consistency
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. Progression of an individual Group Managing Director’s salary to the target position is usually over a three-year period from appointment.
Annual incentive
As part of the annual Group 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. The financial objectives relate to Total Shareholder Return (TSR3) relative to other major integrated oil companies (see the industry peer group table on page S16), and to Return on Average Capital Employed (ROACE). The operational objectives relate to portfolio value growth with key targets for each business. The sustainable development objectives focus on people, health, safety, environment and reputation. The 2003 Scorecard weightings are 60% for financial objectives, each factor equally weighted, 20% for operational objectives and 20% for sustainable development objectives. The same approach has been adopted for 2004.
Targets are set at stretching but realistic levels. At the end of the financial year the Group results are translated into an overall Group score, which can range anywhere between zero and two, the minimum and maximum, respectively. When determining the final outcome, the results on the non-financial targets are not taken into account if the results on the financial targets are below target. Bonus awards are based on the score multiplied by the target bonus level with REMCO using its judgment in making its final recommendations. The target level for 2004 will be 100% of base pay, in line with market practice.
Deferred bonus
The deferred bonus shares, together with shares equivalent to the value of dividends payable on the deferred bonus shares (dividend shares), are released three years after deferral. Provided the participants remain in Group employment for three years following the deferral, or reach normal retirement within the three-year period, they will also receive one additional share for every two deferred bonus
| 1 | FTSE20: the 20 largest companies by way of market capitalisation in the Financial Times Stock Exchange 100 index, a market capitalisation weighted index of stocks traded on the London Stock Exchange. This group is established at the beginning of the relevant performance period. |
| 2 | AEX10: the 10 largest companies by way of market capitalisation in the Amsterdam Exchange index, a market capitalisation weighted index of stocks traded on the Amsterdam Exchange, now a part of the Euronext Exchange. This group is established at the beginning of the relevant performance period. |
| 3 | TSR is measured by the average weighted share price performance plus dividend of Royal Dutch and Shell Transport over the 10-day period at the beginning and end of the relevant financial year. |
and dividend shares accumulated. There is no further performance test for the additional matching shares beyond that governing performance in the relevant bonus year. The plan does not result in dilution of shareholder equity.
Long-term incentives
Expected value methods are used in the determination of appropriate long-term incentive levels. Option valuations have been modelled by Towers Perrin and Kepler Associates using the Black-Scholes model, which is a commonly accepted approach to calculate the expected value of stock options. A standard valuation approach, provided by Towers Perrin and Kepler Associates1, has been adopted to determine the expected value of the conditional award of shares under the Long-Term Incentive Plan (LTIP). The expected value based on these methods is equal to 22% of the face value of the grant for stock options and 43% of the face value of the award of shares under the LTIP.
Stock options
Stock options granted to Group Managing Directors in 2003 and beyond are 100% performance-linked. The current financial performance criteria are TSR and ROACE; these will be calculated as the average result of the three financial years prior to grant. TSR is measured against the other major integrated oil companies (see the industry peer group table on page S16). These financial targets have been chosen as they represent a balanced test of the Group’s long-term external performance and internal operating efficiency. These same performance criteria will be used in 2004. At the end of the financial year, the three-year results on the performance criteria will be translated into an overall performance rating, which can range anywhere between zero and two. The levels of the stock option grants are based on this rating multiplied by the target grant level. Target grant levels will reflect competitive market practice.
The value of the stock options depends on both the performance on the criteria at the time of grant and the future share price performance. This approach reflects the long-term nature of value creation in the Group, where both past and future performance are of significant impact. Given the global nature of the Group’s business and executive cadre, this approach balances the market practices with regard to stock options in the majority of countries in which the Group operates.
Long-Term Incentive Plan (LTIP)
The performance targets are linked to relative TSR over the three-year performance period. Relative TSR has been chosen as the performance test that most closely aligns the interests of Group Managing Directors and senior executives with those of shareholders. TSR is measured relative to two separate groups of comparator companies, as REMCO considers that it is appropriate to test performance against both major home markets and industry competitors. The first comparator group consists of the FTSE20 together with the AEX10. The second comparator group consists of the five major integrated oil companies (see the peer group tables on page S16). 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.
| 1 | Their models take into account the threshold and maximum levels of performance and the proportion of shares that will be released at these points, as well as the nature of the comparator groups against which performance is measured. Risk of forfeiture and dividends are also taken into account. |
Home markets peer group for base pay and LTIP
| as at January 1, 2003 | as at January 1, 2004 | |
| Anglo American | Anglo American | |
| AstraZeneca | AstraZeneca | |
| Aviva | Barclays | |
| Barclays | BHP Billiton | |
| BG Group | BP | |
| BP | British American Tobacco | |
| British American Tobacco | British Sky Broadcasting | |
| BT | BT | |
| Diageo | Diageo | |
| GlaxoSmithKline | GlaxoSmithKline | |
| HBOS | HBOS | |
| HSBC | HSBC | |
| Lloyds TSB | Lloyds TSB | |
| National Grid Transco | National Grid Transco | |
| Rio Tinto | Rio Tinto | |
| Royal Bank of Scotland | Royal Bank of Scotland | |
| Shell Transport | Shell Transport | |
| Tesco | Tesco | |
| Unilever PLC | Unilever PLC | |
| Vodafone | Vodafone | |
AEX10 listed companiesa
| as at January 1, 2003 | as at January 1, 2004 | |
| ABN AMRO | ABN AMRO | |
| AEGON | AEGON | |
| Ahold | Ahold | |
| Akzo Nobel | Fortis | |
| Heineken | Heineken | |
| ING Group | ING Group | |
| KPN | KPN | |
| Philips | Philips | |
| Royal Dutch | Royal Dutch | |
| Unilever N.V. | Unilever N.V. | |
| 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. |
Industry peer group for base pay, annual bonus, stock options and LTIP
| as at January 1, 2003, and January 1, 2004 | ||
| BP | ||
| ChevronTexaco | ||
| ExxonMobil | ||
| Royal Dutch/ Shell Group | ||
| Total | ||
Pension policy
For the British Shell Transport Managing Directors 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 Managing Directors contribute the same percentage of relevant earnings as other employees. Neither the annual bonus nor the deferred bonuses are pensionable. The latest date on which Managing Directors retire is June 30, following their 60th birthday, and the maximum pension is two-thirds of their 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 salary.
For the American Shell Transport Managing Director1 the principal sources of pension include pension plans and savings plans. Pension plans are the Shell Expatriate Employment US (SEEUS) Past Service Pension Plan, the Shell Pension Plan for US employees, and the Shell Pension Plan Benefits Restoration Plan. These are defined benefit plans which are non-contributory. Savings plans are the Shell
| 1 | Judith Boynton resigned as Managing Director of Shell Transport on April 18, 2004. |
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 or normal retirement date in the USA, pensions include provisions to allow for retirement at age 60, which is the Shell normal retirement age. 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
External appointments
Shareholdings
Performance graph
Five-year historical TSR performance
2003 actual remuneration1
Base pay
Annual incentive
Stock options
Stock options granted in March 2001 were due to vest in March 2004. The performance period for the options was January 1, 2001 to December 31, 2003. The Royal Dutch/ Shell Group ranked fifth on TSR against the industry peer group (three-year average over the period 2001 to 2003). REMCO recommended that the options granted under performance conditions should not vest (50% of the grant). Therefore only the remaining 50% of the options granted in March 2001, which vest over time, vested in March 2004.
Long-Term Incentive Plan
| Emoluments of Executive Directors in office during 2003 | £ | |||||||||||||||||||
| Salaries | Annual | Car | Other | |||||||||||||||||
| and fees | bonusa | benefitb | benefits | Total | ||||||||||||||||
| Sir Philip Watts | ||||||||||||||||||||
2003 | 843,021 | 0 | 21,876 | 0 | 864,897 | |||||||||||||||
| 2002 | 745,969 | 874,000 | c | 21,922 | 0 | 1,641,891 | d | |||||||||||||
| 2001 | 607,398 | 455,000 | c | 20,089 | 0 | 1,082,487 | d | |||||||||||||
Judith Boyntone | ||||||||||||||||||||
2003 | 381,833 | 0 | 0 | 18,937 | 400,770 | |||||||||||||||
Paul Skinnerf | ||||||||||||||||||||
2003 | 646,409 | 0 | 9,435 | 0 | 655,844 | |||||||||||||||
| 2002 | 553,830 | 632,500 | 13,181 | 0 | 1,199,511 | g | ||||||||||||||
| 2001 | 504,703 | 338,000 | c | 14,924 | 0 | 857,627 | g | |||||||||||||
| 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 | Of which one-third was deferred under the Deferred Bonus Plan. The deferred bonus shares, dividend shares and conditional matching shares in respect of such deferral are disclosed for 2001 and 2002 in the Deferred Bonus Plan table on page S20. |
| d | The totals for 2002 and 2001 as stated in the Annual Report and Accounts 2002 included amounts for realised share option gains and deferred bonus plan adjustments, and were £1,802,198 and £1,666,488, respectively. The realised share option gains in 2002 and 2001 were £8,238 and £508,167, respectively. From 2003 these are shown in the Stock options table. The deferred bonus plan adjustments were £152,069 and £75,834, respectively. From 2003 these will now appear in the Deferred Bonus Plan table as conditional shareholdings, in accordance with Schedule 7A of the Companies Act 1985. The totals for 2002 and 2001, as reported here, have been restated to reflect these changes. |
| e | Judith Boynton was appointed to the Board on July 1, 2003, therefore, where appropriate, the 2003 emoluments are prorated. She is a beneficiary of the Group expatriate policies, which includes the provision of a housing allowance. She also received executive company travel benefits of which the gross value has been included. |
| f | Paul Skinner retired as a Managing Director on September 30, 2003. His salaries and fees include a taxable, non-pensionable full service bonus of £151,250 (25% of base pay), in line with company policy applicable to all UK employees with qualifying service. His salaries and fees also include a discretionary payment of £43,329 to reflect the fact that he did not receive any additional shares under the Deferred Bonus Plan. He was granted the right to purchase his company car on the same terms as other employees. |
| g | The totals for 2002 and 2001 as stated in the Annual Report and Accounts 2002 included amounts for realised share option gains and deferred bonus plan adjustments and were £1,212,505 and £1,419,863, respectively. The realised share option gains in 2002 and 2001 were £8,238 and £505,902, respectively. From 2003 these are shown in the Stock options table. The deferred bonus plan adjustments were £4,756 and £56,334, respectively. From 2003 these will now appear in the Deferred Bonus Plan table as conditional shareholdings, in accordance with Schedule 7A of the Companies Act 1985. The totals for 2002 and 2001, as reported here, have been restated to reflect these changes. |
| 1 | The information in the tables on pages S18 to S22 in this section has been subjected to audit, except for the Expected value columns in the Stock options table and in the Long- Term Incentive Plan table on page S19, which are unaudited. |
| Stock options | ||||||||||||||||||||||||||||||||||||
| Options Shell Transport | ||||||||||||||||||||||||||||||||||||
| Number of 25p Ordinary shares under option | ||||||||||||||||||||||||||||||||||||
| Exercised | Expected | |||||||||||||||||||||||||||||||||||
| (cancelled/ | value of | Realisable | ||||||||||||||||||||||||||||||||||
| Granted | lapsed) | the 2003 | gains at | Realised | ||||||||||||||||||||||||||||||||
| during | during | At Dec 31, | Exercise | Exercisable | Expiry | stock options | Dec 31, | gains on | ||||||||||||||||||||||||||||
| At Jan 1, | the year | the year | 2003 | pricea | from date | date | grantb | 2003c | stock options | |||||||||||||||||||||||||||
| 2003 | £ | £ | £ | exercised | ||||||||||||||||||||||||||||||||
Sir Philip Wattsd | 308,750 | – | – | 308,750 | 3.63 | 22.12.01 | 21.12.08 | – | 162,094 | – | ||||||||||||||||||||||||||
| 341,000 | – | (85,250 | ) | 255,750 | 5.05 | 23.03.03 | 22.03.10 | – | 0 | – | ||||||||||||||||||||||||||
| 465,000 | – | – | 465,000 | 5.52 | 26.03.04 | 25.03.11 | – | – | – | |||||||||||||||||||||||||||
| 3,251 | e | – | – | 3,251 | 5.09 | 01.02.07 | 31.07.07 | – | – | – | ||||||||||||||||||||||||||
| 885,000 | – | – | 885,000 | 5.23 | 21.03.05 | 20.03.12 | – | – | – | |||||||||||||||||||||||||||
| – | 1,165,000 | – | 1,165,000 | 3.66 | 19.03.06 | 18.03.13 | 938,058 | – | – | |||||||||||||||||||||||||||
Sir Mark Moody- Stuartf | 440,800 | – | – | 440,800 | 3.63 | 22.12.01 | 29.06.06 | – | 231,420 | – | ||||||||||||||||||||||||||
| 487,000 | – | (121,750 | ) | 365,250 | 5.05 | 23.03.03 | 29.06.06 | – | 0 | – | ||||||||||||||||||||||||||
Paul Skinnerg | 139,200 | – | – | 139,200 | 4.39 | 11.12.00 | 10.12.07 | – | 0 | – | ||||||||||||||||||||||||||
| 194,700 | – | – | 194,700 | 3.63 | 22.12.01 | 29.09.08 | – | 102,218 | – | |||||||||||||||||||||||||||
| 341,000 | – | (85,250 | ) | 255,750 | 5.05 | 23.03.03 | 29.09.08 | – | 0 | – | ||||||||||||||||||||||||||
| 465,000 | – | – | 465,000 | 5.52 | 26.03.04 | 29.09.08 | – | – | – | |||||||||||||||||||||||||||
| 1,305 | e | – | – | 1,305 | 5.09 | 01.10.03 | 31.03.04 | – | 0 | – | ||||||||||||||||||||||||||
| 660,000 | – | – | 660,000 | 5.23 | 21.03.05 | 29.09.08 | – | – | – | |||||||||||||||||||||||||||
| – | 800,000 | – | 800,000 | 3.66 | 19.03.06 | 29.09.08 | 644,160 | – | – | |||||||||||||||||||||||||||
| Options Royal Dutch | € and $ | $ | ||||||||||||||||||||||||||||||||||
| Judith Boynton | 80,000 | – | – | 80,000 | €62.02 | 21.08.04 | 20.08.11 | – | – | – | ||||||||||||||||||||||||||
| 60,000 | – | – | 60,000 | €62.10 | 21.03.05 | 20.03.12 | – | – | – | |||||||||||||||||||||||||||
| – | 70,500 | – | 70,500 | $40.64 | 19.03.04 | 18.03.13 | 630,326 | – | – | |||||||||||||||||||||||||||
The stock options listed above relate to Shell Transport Ordinary shares, with the exception of those stock options held by Judith Boynton. Other than the Shell Sharesave Scheme options, they have a 10-year term and are not exercisable within three years of grant. Of the stock options granted to Managing 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 are subject to performance conditions. Details of these performance conditions can be found in Remuneration policy – Stock options on page S15. The price range of the Shell Transport Ordinary shares during the year was £3.32 to £4.40 and the market price at year-end was £4.16.
The stock options listed above for Judith Boynton, granted to her before she became a Managing Director, relate to Royal Dutch ordinary shares and have a 10-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€33.35 to€44.58 and the market price at year end was€41.80. The price range of the Royal Dutch ordinary shares listed at the NYSE during the year was $36.69 to $52.70 and the market price at year end was $52.39.
There were no other changes in the above interests in share options during the period from December 31, 2003 to May 11, 2004.
| 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 Shell 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 2003 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, 2003, multiplied by the number of shares under option at December 31, 2003. 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 | As for other employees who receive stock options under the same Group plans, Group Managing Directors may, at the discretion of the company, continue to hold and exercise the options for a further five years after leaving employment. Upon Sir Philip Watts’ resignation on March 3, 2004, the exercise dates of his options remain unchanged if the original expiry date was earlier than five years after this date, and change to March 2, 2009, if the original expiry date was later than five years after this date. |
| e | These options are held under the Shell Sharesave Scheme of The Shell Petroleum Company Limited. |
| f | Sir Mark Moody-Stuart holds share options relating to his former service with the Group. |
| g | The exercise dates of Paul Skinner’s stock option grants have been adjusted in accordance with plan rules to reflect his retirement. |
| Long-Term Incentive Plan (LTIP) | ||||||||||||||||||||||||||
| Performance shares | Expected value | |||||||||||||||||||||||||
| conditionally | Start of | End of | of the 2003 | |||||||||||||||||||||||
| awarded during | At Dec 31, | Market price at | performance | performance | performance | |||||||||||||||||||||
| At Jan 1, | the year | 2003 | date of awarda | period | period | shares awardb | ||||||||||||||||||||
| 2003 | £ | £ | ||||||||||||||||||||||||
Sir Philip Wattsc | – | 427,872 | 427,872 | 4.09 | 01.01.03 | 31.12.05 | 752,498 | |||||||||||||||||||
Judith Boyntond | – | 266,475 | 266,475 | 4.09 | 01.01.03 | 31.12.05 | 468,650 | |||||||||||||||||||
100% of the performance shares awarded in 2003 are subject to performance conditions. Details of these conditions can be found in Remuneration policy – Long-Term Incentive Plan (LTIP) on page S15.
| 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 2003 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 | Upon Sir Philip Watts’ resignation on March 3, 2004, the agreed performance conditions were applied to the 2003 award and none of the shares qualified for release. |
| d | As part of her remuneration prior to her appointment as a Managing Director, Judith Boynton received 17,000 conditional Royal Dutch ordinary shares on October 1, 2002; these will be released on October 1, 2005. |
| Deferred Bonus Plan | ||||||||||||||||||||||||||||||||
| Market price | Average market | |||||||||||||||||||||||||||||||
| Total number of | Deferred | Matching shares | of deferred | price of | Total number | |||||||||||||||||||||||||||
| shares under | bonus shares | conditionally | bonus and | Dividend shares | dividend shares | of shares | ||||||||||||||||||||||||||
| award as at | awarded | awarded | matching shares | accrued during | paid during | Released/ lapsed | under award | |||||||||||||||||||||||||
| January 1, 2003a | during the yearb | during the year | at awardc | the yeard | the yeare | during yearf | as at | |||||||||||||||||||||||||
| £ | £ | December 31, 2003 | ||||||||||||||||||||||||||||||
Sir Philip Wattsg | ||||||||||||||||||||||||||||||||
| 2003 award | – | 79,697 | 39,849 | 3.66 | 4,781 | 3.91 | – | 124,327 | ||||||||||||||||||||||||
| 2002 award | 44,042 | – | – | 5.33 | 1,761 | 3.91 | – | 45,803 | ||||||||||||||||||||||||
Paul Skinnerh | ||||||||||||||||||||||||||||||||
| 2002 award | 32,717 | – | – | 5.33 | 1,309 | 3.91 | (34,026 | )i | – | |||||||||||||||||||||||
Awards made in 2002 and 2003 refer to the portion of the 2001 and 2002 annual bonus deferred in respect of 2001 and 2002 and their related accrued dividends and matching shares.
| a | The opening balances of shares under award at January 1, 2003, have been restated to include the matching shares on the 2002 interim dividend shares accrued, but not recorded in 2002. These were 213 for Sir Philip Watts and 158 for Paul Skinner, respectively. |
| b | 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 Executive Directors table on page S18. |
| c | 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. |
| d | 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. |
| e | The market price shown is the average at the date of the 2002 final and 2003 interim annual dividends paid during the year: £3.81 and £4.01, respectively. |
| f | Awards vest three years from date of award as follows: 2002 award – March 11, 2005; 2003 award – March 3, 2006. |
| g | Following his resignation Sir Philip Watts retained his current bonus share entitlements under the Deferred Bonus Plan, together with the dividend shares accrued up to date of resignation. All of his matching shares lapsed. |
| h | Paul Skinner’s current bonus share entitlements under the Deferred Bonus Plan have been transferred to him following his retirement, together with the dividend shares accrued up to date of retirement. |
| i | Comprised of deferred bonus and dividend shares that were released (22,683) and matching shares (11,343) that lapsed. The share price at the date of release was £3.75. |
| Pensions | £ thousand | |||||||||||||||||||||||||||
| Accrued pension | Transfer values of accrued benefits | |||||||||||||||||||||||||||
| Increase in | ||||||||||||||||||||||||||||
| accrued pension | ||||||||||||||||||||||||||||
| Increase | Increase | over the year | ||||||||||||||||||||||||||
| over the year | over the year | (excluding inflation) | ||||||||||||||||||||||||||
| At Dec 31, | Increase | (excluding | At Dec 31, | At Dec 31, | less Director’s | less Director’s | ||||||||||||||||||||||
| 2003 | over the year | inflation) | 2002 | 2003 | contributions | contributions | ||||||||||||||||||||||
| Sir Philip Watts | 568.48 | 88.79 | 75.40 | 7,913.00 | 10,007.80 | 2,063.30 | 1,295.20 | |||||||||||||||||||||
Judith Boyntona | 53.13 | 26.07 | b | 25.47 | b | 252.82 | c | 404.99 | c | 192.94 | b | 194.17 | ||||||||||||||||
Paul Skinnerd | 442.35 | e | 37.49 | 26.20 | 6,586.50 | 8,420.00 | f | 1,833.50 | 498.70 | |||||||||||||||||||
| a | For Judith Boynton, the Company contributed £79,109 based on the 12-month average exchange rate to the Shell Savings Plans, which are money purchase schemes, during the period January 1, 2003 to December 31, 2003. |
| b | 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 12-month average rate of exchange. |
| c | US dollar converted to sterling at the year-end rate of exchange. |
| d | Paul Skinner retired on September 30, 2003 within the rules of the plan and no adjustments have been made. He took a reduced pension to reflect his early retirement. In addition, he also commuted pension of £88,421 p.a. in return for a lump sum of £1,240,898. |
| e | The figure shown here is the annual pension payable at December 31, 2003, assuming that Paul Skinner did not commute any pension. |
| f | This is the transfer value of the pension at December 31, 2003, including the pension commuted to a lump sum. |
Pensions
Company contributions were not required for the SEEUS Past Service Pension Plan nor for the Shell Pension Plan Benefits Restoration Plan during 2003. The employing company contribution rate for the Shell Pension Plan was 5% in 2003. Managing Directors are not required to contribute to these plans.
During 2003 two British Managing Directors accrued retirement benefits under defined benefit plans (2002: two; 2001: three). No British Managing Director has accrued benefits under a money purchase benefit scheme. In 2003 one American Managing Director accrued retirement benefits under defined benefit plans as well as benefits under a money purchase benefit scheme (2002 and 2001: 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.
Managing Directors’ service contracts
Sir Philip Watts’ employment contract was effective from July 1, 2002, and provided entitlement to notice in line with the standard policy applicable to other senior staff in the UK, namely three months. The contract would have expired on June 30, 2005. There were no predetermined termination compensation arrangements in place for Sir Philip Watts. He resigned from the company on March 3, 2004.
Judith Boynton’s employment contract is effective from July 1, 2003 and is governed by US law. Employment is on an “at-will” basis and may therefore be terminated at any time without notice, either by Judith Boynton or the employer. She is eligible to a termination arrangement in case of a company-initiated severance for reasons other than gross misconduct. During the first five years of her employment (2001 to 2006), the severance pay would be equal to the sum of the applicable annual pensionable base pay and the most recent annual bonus, but in no event less than $1,000,000; after five years it would be equal to the applicable annual pensionable base pay, but in no event less than $600,000.
Paul Skinner retired as a Director of the Company, and from Group service, on September 30, 2003. His contract was effective from January 1, 2000, and would have expired on June 30, 2005. The terms of the contract were similar to those for Sir Philip Watts as given above.
No payments on termination were made to retiring or past Directors during the year under review other than those referred to in the Emoluments of Executive Directors table on page S18 in respect of Paul Skinner.
Non-executive Directors
Remuneration policy
Appointments
Fees
| Remuneration of non-executive Directors | £ | |||||||||||
| Directors’ fees | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Teymour Alireza | 63,500 | 45,375 | 28,750 | |||||||||
| Sir Peter Burt | 50,000 | 21,795 | – | |||||||||
| Dr Eileen Buttle | 50,000 | 39,375 | 31,875 | |||||||||
| Luis Giusti | 63,500 | 45,375 | 26,875 | |||||||||
| Nina Henderson | 63,500 | 45,375 | 17,516 | |||||||||
| Sir Peter Job | 50,000 | 39,375 | 11,042 | |||||||||
| Sir John Kerr | 50,000 | 21,795 | – | |||||||||
Sir Mark Moody-Stuarta | 69,170 | 57,689 | – | |||||||||
| Lord Oxburgh | 55,000 | 42,800 | 32,475 | |||||||||
| The information in this table has been subjected 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 2003 and 2002; they amounted to £19,170 and £18,314, respectively. In 2001, he served as a Managing Director of Shell Transport. His 2001 salaries and fees were £583,401 and his 2001 annual bonus was £232,050, which together amounted to £815,451. He realised £639,360 of share options gains, which brought his total 2001 emoluments to £1,454,811. |
| Terms of Appointment | ||||
| Term of Appointmenta | ||||
| Teymour Alireza | 2006 | |||
| Sir Peter Burt | 2009 | |||
| Dr Eileen Buttle | 2006 | |||
| Luis Giusti | 2007 | |||
| Nina Henderson | 2007 | |||
| Sir Peter Job | 2008 | |||
| Sir John Kerr | 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. |
Signed on behalf of the Board
Jyoti Munsiff
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 and no dilution of shareholder equity is involved. Shares to be delivered by a Group company under these plans are generally bought in the market at the time the commitment is made. |
Group Stock Option Plans
Stock options 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 Group Managing Directors and the most senior executives 100% of options granted in 2003 and in subsequent years will be subject to performance conditions.
Restricted Stock Plan
Group Long-Term Incentive Plan (LTIP)
Global Employee Share Purchase Plan
Shell 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 22 of the Group Financial Statements. |
Royal Dutch/Shell Group of Companies
We have audited the Financial Statements appearing on pages G2 to G35 of the Royal Dutch/ Shell Group of Companies for the years 2003, 2002 and 2001. The preparation of 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, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in accordance with generally accepted accounting principles in the United States.
As discussed in Note 2 “Restatement of Previously Issued Financial Statements”, the Group has restated its Financial Statements for the two years ended December 31, 2002 to correct for inappropriate departures from US GAAP.
As discussed in Note 2, the Group has restated its Financial Statements for the two years ended December 31, 2002 to change its method of accounting for certain inventories in North America from the last-in first-out method to the first-in first-out method.
As discussed in Note 3, 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.
KPMG Accountants N.V., The Hague
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP, London
May 22, 2004
Financial Statements
| Statement of Income | $ million | |||||||||||||||
| 2002 | 2001 | |||||||||||||||
| Note | 2003 | As restated | As restated | |||||||||||||
Sales proceedsa | 268,892 | 222,768 | 167,431 | |||||||||||||
| Sales taxes, excise duties and similar levies | 67,164 | 56,167 | 42,070 | |||||||||||||
Net proceedsa | 201,728 | 166,601 | 125,361 | |||||||||||||
Cost of salesa | 167,500 | 137,997 | 98,381 | |||||||||||||
Gross profit | 34,228 | 28,604 | 26,980 | |||||||||||||
| Selling and distribution expenses | 11,941 | 9,954 | 7,898 | |||||||||||||
| Administrative expenses | 1,903 | 1,601 | 1,244 | |||||||||||||
| Exploration | 1,476 | 1,073 | 910 | |||||||||||||
| Research and development | 584 | 472 | 387 | |||||||||||||
| Operating profit of Group companies | 18,324 | 15,504 | 16,541 | |||||||||||||
| Share of operating profit of associated companies | 6 | 3,484 | 2,822 | 2,646 | ||||||||||||
Operating profit | 21,808 | 18,326 | 19,187 | |||||||||||||
| Interest and other income | 7 | 1,973 | 758 | 1,059 | ||||||||||||
| Interest expense | 8 | 1,381 | 1,364 | 1,133 | ||||||||||||
| Currency exchange gains/(losses) | (222 | ) | (23 | ) | (30 | ) | ||||||||||
Income before taxation | 22,178 | 17,697 | 19,083 | |||||||||||||
| Taxation | 9 | 9,572 | 7,796 | 8,404 | ||||||||||||
| Income after taxation | 12,606 | �� | 9,901 | 10,679 | ||||||||||||
| Income applicable to minority interests | 365 | 179 | 329 | |||||||||||||
| Income before cumulative effect of a change in accounting principle | 12,241 | 9,722 | 10,350 | |||||||||||||
| Cumulative effect of a change in accounting principle, net of tax | 3 | 255 | – | – | ||||||||||||
Net income | 12,496 | 9,722 | 10,350 | |||||||||||||
| Statement of Comprehensive Income and Parent Companies’ | |||||||||||||||||
| interest in Group net assets | $ million | ||||||||||||||||
| 2002 | 2001 | ||||||||||||||||
| Note | 2003 | As restated | As restated | ||||||||||||||
Net income | 12,496 | 9,722 | 10,350 | ||||||||||||||
| Other comprehensive income, net of tax: | 5 | ||||||||||||||||
| currency translation differences | 19 | 5,102 | 2,432 | (1,686 | ) | ||||||||||||
| unrealised gains/(losses) on securities | 689 | 25 | (143 | ) | |||||||||||||
| unrealised gains/(losses) on cash flow hedges | 51 | (225 | ) | (14 | ) | ||||||||||||
| minimum pension liability adjustments | 358 | (1,475 | ) | (127 | ) | ||||||||||||
Comprehensive income | 18,696 | 10,479 | 8,380 | ||||||||||||||
| Distributions to Parent Companies | (5,660 | ) | (5,435 | ) | (9,163 | ) | |||||||||||
| Increase in Parent Companies’ shares held, net of dividends received | 22 | (631 | ) | (844 | ) | (642 | ) | ||||||||||
| Loss on sale of Parent Companies’ shares | (1 | ) | – | – | |||||||||||||
| Parent Companies’ interest in Group net assets at January 1 | 60,444 | 56,244 | 57,669 | ||||||||||||||
Parent Companies’ interest in Group net assets at December 31 | 4 | 72,848 | 60,444 | 56,244 | |||||||||||||
| a | Certain prior period amounts have been reclassified, resulting in a reduction in sales proceeds and a corresponding reduction in cost of sales, following the implementation of US accounting guidance EITF Issue No. 02-03, see Note 3. |
The Notes on pages G5 to G35 are an integral part of these statements
| Statement of Assets and Liabilities | $ million | |||||||||||||
| Dec 31, | ||||||||||||||
| Dec 31, | 2002 | |||||||||||||
| Note | 2003 | As restated | ||||||||||||
Fixed assets | ||||||||||||||
| Tangible assets | 10 | 87,701 | 78,687 | |||||||||||
| Intangible assets | 10 | 4,735 | 4,696 | |||||||||||
| Investments: | ||||||||||||||
| associated companies | 6 | 19,384 | 17,948 | |||||||||||
| securities | 14 | 2,317 | 1,719 | |||||||||||
| other | 1,086 | 1,420 | ||||||||||||
Total fixed assets | 115,223 | 104,470 | ||||||||||||
Other long-term assets | 11 | 9,257 | 7,333 | |||||||||||
Current assets | ||||||||||||||
| Inventories | 12 | 12,690 | 11,338 | |||||||||||
| Accounts receivable | 13 | 28,969 | 28,761 | |||||||||||
| Cash and cash equivalents | 14 | 1,952 | 1,556 | |||||||||||
Total current assets | 43,611 | 41,655 | ||||||||||||
Current liabilities:amounts due within one year | ||||||||||||||
| Short-term debt | 15 | 11,027 | 12,874 | |||||||||||
| Accounts payable and accrued liabilities | 17 | 32,347 | 32,189 | |||||||||||
| Taxes payable | 9 | 5,927 | 4,985 | |||||||||||
| Dividends payable to Parent Companies | 5,123 | 5,153 | ||||||||||||
Total current liabilities | 54,424 | 55,201 | ||||||||||||
Net current assets/(liabilities) | (10,813 | ) | (13,546 | ) | ||||||||||
Total assets less current liabilities | 113,667 | 98,257 | ||||||||||||
Long-term liabilities:amounts due after more than one year | ||||||||||||||
| Long-term debt | 15 | 9,100 | 6,817 | |||||||||||
| Other | 18 | 6,054 | 6,174 | |||||||||||
| 15,154 | 12,991 | |||||||||||||
Provisions | ||||||||||||||
| Deferred taxation | 9 | 13,355 | 12,696 | |||||||||||
| Pensions and similar obligations | 20 | 4,927 | 5,016 | |||||||||||
| Decommissioning and restoration costs | 23 | 3,955 | 3,528 | |||||||||||
| 22,237 | 21,240 | |||||||||||||
Group net assets before minority interests | 76,276 | 64,026 | ||||||||||||
| Minority interests | 3,428 | 3,582 | ||||||||||||
Net assets | 72,848 | 60,444 | ||||||||||||
The Notes on G5 to G35 are an integral part of these statements
| Statement of Cash Flows(see Note 19) | $ million | ||||||||||||||||||
| 2002 | 2001 | ||||||||||||||||||
| Note | 2003 | As restated | As restated | ||||||||||||||||
Cash flow provided by operating activities | |||||||||||||||||||
| Net income | 12,496 | 9,722 | 10,350 | ||||||||||||||||
| Adjustments to reconcile net income to cash flow provided by operating activities | |||||||||||||||||||
| Depreciation, depletion and amortisation | 10 | 11,422 | 8,621 | 6,201 | |||||||||||||||
| Profit on sale of assets | (2,141 | ) | (367 | ) | (133 | ) | |||||||||||||
| Movements in: | |||||||||||||||||||
| inventories | (236 | ) | (2,079 | ) | 1,375 | ||||||||||||||
| accounts receivable | 1,834 | (5,830 | ) | 8,518 | |||||||||||||||
| accounts payable and accrued liabilities | (212 | ) | 6,989 | (7,785 | ) | ||||||||||||||
| taxes payable | (218 | ) | (735 | ) | (1,443 | ) | |||||||||||||
| Associated companies: dividends more/(less) than net income | 6 | 501 | 115 | 666 | |||||||||||||||
| Deferred taxation and other provisions | (504 | ) | 473 | (165 | ) | ||||||||||||||
| Long-term liabilities and other | (1,588 | ) | (805 | ) | (1,008 | ) | |||||||||||||
| Income applicable to minority interests | 365 | 179 | 329 | ||||||||||||||||
Cash flow provided by operating activities | 21,719 | 16,283 | 16,905 | ||||||||||||||||
Cash flow used in investing activities | |||||||||||||||||||
| Capital expenditure (including capitalised leases) | 10 | (12,252 | ) | (12,102 | ) | (9,598 | ) | ||||||||||||
| Acquisitions (Enterprise Oil, Pennzoil-Quaker State and additional shares in Equilon) | 10 | (8,925 | ) | ||||||||||||||||
| Proceeds from sale of assets | 2,286 | 1,099 | 1,265 | ||||||||||||||||
| New investments in associated companies | 6 | (983 | ) | (1,289 | ) | (1,074 | ) | ||||||||||||
| Disposals of investments in associated companies | 708 | 501 | 507 | ||||||||||||||||
| Proceeds from sale and other movements in investments | 1,989 | 83 | (180 | ) | |||||||||||||||
Cash flow used in investing activities | (8,252 | ) | (20,633 | ) | (9,080 | ) | |||||||||||||
Cash flow used in financing activities | |||||||||||||||||||
| Long-term debt (including short-term part): | |||||||||||||||||||
| new borrowings | 572 | 5,267 | 180 | ||||||||||||||||
| repayments | (2,740 | ) | (5,610 | ) | (1,115 | ) | |||||||||||||
| (2,168 | ) | (343 | ) | (935 | ) | ||||||||||||||
| Net increase/(decrease) in short-term debt | (2,507 | ) | 7,058 | (794 | ) | ||||||||||||||
| Change in minority interests | (1,363 | ) | 421 | (206 | ) | ||||||||||||||
| Dividends paid to: | |||||||||||||||||||
| Parent Companies | (6,248 | ) | (6,961 | ) | (9,406 | ) | |||||||||||||
| minority interests | (300 | ) | (228 | ) | (221 | ) | |||||||||||||
Cash flow used in financing activities | (12,586 | ) | (53 | ) | (11,562 | ) | |||||||||||||
Parent Companies’ shares: net sales/(purchases) and dividends received | (633 | ) | (864 | ) | (773 | ) | |||||||||||||
| Currency translation differences relating to cash and cash equivalents | 148 | 153 | (251 | ) | |||||||||||||||
Increase/(decrease) in cash and cash equivalents | 396 | (5,114 | ) | (4,761 | ) | ||||||||||||||
| Cash and cash equivalents at January 1 | 1,556 | 6,670 | 11,431 | ||||||||||||||||
| Cash and cash equivalents at December 31 | 1,952 | 1,556 | 6,670 | ||||||||||||||||
The Notes on G5 to G35 are an integral part of these statements
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.
2 Restatement of previously issued Financial Statements
Please refer to “Supplementary information – Oil and Gas (unaudited)” on pages G44 to G55 for additional information regarding the Reserves Restatement.
Following the January 9, 2004 announcement of the reserves recategorisation described above, 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, have determined that the principal causes that permitted the initial booking and maintenance of the volumes impacted by the 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. |
Financial Restatement
Treatment of exploration costs
Treatment of certain gas contracts
Change in accounting policy for inventories
The impact on the information included in these Financial Statements is summarised in the tables below:
| Statement of Income | $ million | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Restated | Restated | |||||||||||||||||||||||||||||||||||||||||||||||||||
| As | prior to | As | prior to | |||||||||||||||||||||||||||||||||||||||||||||||||
| previously | Reserves | Exploration | Gas | Inventory | As | previously | Reserves | Exploration | Inventory | As | ||||||||||||||||||||||||||||||||||||||||||
| reported | restatement | costs | contracts | Adjustment | Inventories | restated | reported | restatement | costs | Adjustment | Inventories | restated | ||||||||||||||||||||||||||||||||||||||||
| Net proceeds | 166,717 | a | (52 | ) | – | (64 | ) | 166,601 | – | 166,601 | 125,441 | a | (80 | ) | – | 125,361 | – | 125,361 | ||||||||||||||||||||||||||||||||||
| Cost of sales | 138,500 | a | 114 | – | – | 138,614 | (617 | ) | 137,997 | 98,069 | a | 4 | – | 98,073 | 308 | 98,381 | ||||||||||||||||||||||||||||||||||||
| Exploration | 991 | – | 82 | – | 1,073 | – | 1,073 | 882 | 7 | 21 | 910 | – | 910 | |||||||||||||||||||||||||||||||||||||||
| Other operating expenses | 12,027 | – | – | – | 12,027 | – | 12,027 | 9,529 | – | – | 9,529 | – | 9,529 | |||||||||||||||||||||||||||||||||||||||
| Share of operating profit of associated companies | 2,624 | – | – | – | 2,624 | 198 | 2,822 | 3,041 | 18 | – | 3,059 | (413 | ) | 2,646 | ||||||||||||||||||||||||||||||||||||||
Operating profit | 17,823 | (166 | ) | (82 | ) | (64 | ) | 17,511 | 815 | 18,326 | 20,002 | (73 | ) | (21 | ) | 19,908 | (721 | ) | 19,187 | |||||||||||||||||||||||||||||||||
| Net interest expense and currency exchange gains/losses | 629 | – | – | – | 629 | – | 629 | 104 | – | – | 104 | – | 104 | |||||||||||||||||||||||||||||||||||||||
Income before taxation | 17,194 | (166 | ) | (82 | ) | (64 | ) | 16,882 | 815 | 17,697 | 19,898 | (73 | ) | (21 | ) | 19,804 | (721 | ) | 19,083 | |||||||||||||||||||||||||||||||||
| Taxation | 7,617 | (65 | ) | (21 | ) | (25 | ) | 7,506 | 290 | 7,796 | 8,694 | (27 | ) | (7 | ) | 8,660 | (256 | ) | 8,404 | |||||||||||||||||||||||||||||||||
| Minority interests | 158 | 7 | – | – | 165 | 14 | 179 | 352 | (4 | ) | – | 348 | (19 | ) | 329 | |||||||||||||||||||||||||||||||||||||
Net income | 9,419 | (108 | ) | (61 | ) | (39 | ) | 9,211 | 511 | 9,722 | 10,852 | (42 | ) | (14 | ) | 10,796 | (446 | ) | 10,350 | |||||||||||||||||||||||||||||||||
a Including the effect of reclassification of certain amounts following implementation of US accounting guidance EITF Issue No. 02-03 (see Note 3), which had no impact on net income.
| Earnings by industry segment | $ million | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Restated | Restated | |||||||||||||||||||||||||||||||||||||||||||||||||||
| As | prior to | As | prior to | |||||||||||||||||||||||||||||||||||||||||||||||||
| previously | Reserves | Exploration | Gas | Inventory | As | previously | Reserves | Exploration | Inventory | As | ||||||||||||||||||||||||||||||||||||||||||
| reported | restatement | costs | contracts | Adjustment | Inventories | restated | reported | restatement | costs | Adjustment | Inventories | restated | ||||||||||||||||||||||||||||||||||||||||
| Exploration and Production | 6,997 | (101 | ) | (61 | ) | (39 | ) | 6,796 | – | 6,796 | 8,023 | (46 | ) | (14 | ) | 7,963 | – | 7,963 | ||||||||||||||||||||||||||||||||||
| Gas & Power | 774 | – | – | – | 774 | – | 774 | 1,226 | – | – | 1,226 | – | 1,226 | |||||||||||||||||||||||||||||||||||||||
| Oil Products | 2,178 | – | – | – | 2,178 | 449 | 2,627 | 2,332 | – | – | 2,332 | (362 | ) | 1,970 | ||||||||||||||||||||||||||||||||||||||
| Chemicals | 489 | – | – | – | 489 | 76 | 565 | 230 | – | – | 230 | (103 | ) | 127 | ||||||||||||||||||||||||||||||||||||||
| Corporate and Other | (861 | ) | – | – | – | (861 | ) | – | (861 | ) | (607 | ) | – | – | (607 | ) | – | (607 | ) | |||||||||||||||||||||||||||||||||
| Minority interests | (158 | ) | (7 | ) | – | – | (165 | ) | (14 | ) | (179 | ) | (352 | ) | 4 | – | (348 | ) | 19 | (329 | ) | |||||||||||||||||||||||||||||||
Net income | 9,419 | (108 | ) | (61 | ) | (39 | ) | 9,211 | 511 | 9,722 | 10,852 | (42 | ) | (14 | ) | 10,796 | (446 | ) | 10,350 | |||||||||||||||||||||||||||||||||
| Statement of Assets and Liabilities | $ million | ||||||||||||||||||||||||||||
| December 31, 2002 | |||||||||||||||||||||||||||||
| Restated | |||||||||||||||||||||||||||||
| prior to | |||||||||||||||||||||||||||||
| As previously | Reserves | Exploration | Gas | Inventory | As | ||||||||||||||||||||||||
| reported | restatement | costs | contracts | Adjustment | Inventories | restated | |||||||||||||||||||||||
| Fixed assets | |||||||||||||||||||||||||||||
| Tangible | 79,390 | (467 | ) | (236 | ) | – | 78,687 | – | 78,687 | ||||||||||||||||||||
| Intangible | 4,696 | – | – | – | 4,696 | – | 4,696 | ||||||||||||||||||||||
| Investments | 20,760 | 2 | – | – | 20,762 | 325 | 21,087 | ||||||||||||||||||||||
| Other long-term assets | 7,299 | – | – | 34 | 7,333 | – | 7,333 | ||||||||||||||||||||||
| Inventories | 10,298 | – | – | – | 10,298 | 1,040 | 11,338 | ||||||||||||||||||||||
| Other current assets | 30,248 | – | – | 69 | 30,317 | – | 30,317 | ||||||||||||||||||||||
| Current liabilities | 55,115 | – | – | 86 | 55,201 | – | 55,201 | ||||||||||||||||||||||
| Long-term liabilities | 12,935 | – | – | 56 | 12,991 | – | 12,991 | ||||||||||||||||||||||
| Provisions | |||||||||||||||||||||||||||||
| Deferred taxation | 12,471 | (186 | ) | (81 | ) | – | 12,204 | 492 | 12,696 | ||||||||||||||||||||
| Pensions and decommissioning | 8,544 | – | – | – | 8,544 | – | 8,544 | ||||||||||||||||||||||
| Minority interests | 3,562 | (3 | ) | – | – | 3,559 | 23 | 3,582 | |||||||||||||||||||||
Net assets | 60,064 | (276 | ) | (155 | ) | (39 | ) | 59,594 | 850 | 60,444 | |||||||||||||||||||
| Parent Companies’ interest in Group net assets | $ million | |||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||
| As previously reported at December 31 | 60,064 | 56,160 | ||||||||||||||||||||
| Effect of the adjustments: | ||||||||||||||||||||||
| Interest at the beginning of the year | ||||||||||||||||||||||
| Cumulative effect of reserves restatement | (164 | ) | (122 | )a | ||||||||||||||||||
| Cumulative effect of exploration costs change | (91 | ) | (78 | )a | ||||||||||||||||||
| Total before inventory adjustment | 59,809 | 55,960 | ||||||||||||||||||||
| Cumulative effect of change in policy for inventories | 339 | 783 | a | |||||||||||||||||||
| 60,148 | 56,743 | |||||||||||||||||||||
| Net income for the year | ||||||||||||||||||||||
| Reserves restatement | (108 | ) | (42 | ) | ||||||||||||||||||
| Exploration costs change | (61 | ) | (14 | ) | ||||||||||||||||||
| Gas contracts change | (39 | ) | – | |||||||||||||||||||
| Total before inventory adjustment | 59,940 | 56,687 | ||||||||||||||||||||
| Change in policy for inventories | 511 | (446 | ) | |||||||||||||||||||
| 60,451 | 56,241 | |||||||||||||||||||||
| Currency translation differences for the year | (7 | ) | 3 | |||||||||||||||||||
As restated at December 31 | 60,444 | 56,244 | ||||||||||||||||||||
a Cumulative effect as at January 1, 2001.
Amounts relating to prior periods have been restated in the following notes where applicable.
3 Accounting policies
common whilst maintaining its separate identity. The Financial Statements reflect an aggregation in US dollars of the accounts of companies in which Royal Dutch and Shell Transport together, either directly or indirectly, have control either through a majority of the voting rights or the right to exercise a controlling influence or to obtain the majority of the benefits and be exposed to the majority of the risks.
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 gas production activities are taken up in the Financial Statements in proportion to the relevant Group interest.
With effect from 2003, the Financial Statements are presented in accordance with US GAAP, with separate Financial Statements presented under Netherlands GAAP beginning on page G36.
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.
Currency translation
The 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 and Production and Gas & Power title typically passes (and revenues are recognised) when a 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.
Depreciation, depletion and amortisation
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
See Note 2 regarding a change in treatment of exploration costs.
Research and development
Deferred taxation
Leasing
Interest capitalisation
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.
See Note 2 regarding a change in treatment for certain gas contracts.
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
Stock-based compensation plans
Decommissioning and restoration costs
reserves, the liability, once an obligation, whether legal or constructive, crystallises, is recognised in the period when a reasonable estimate of the fair value can be made. The obligation is reflected under provisions in the Statement of Assets and Liabilities. The effects of changes resulting from revisions to the timing or the amount of the original estimate of the liability are incorporated on a prospective basis.
Acquisitions
Reclassifications
Changes in accounting policy
US accounting standard FAS 143 (Asset Retirement Obligations) requires that the fair value of a liability for an asset retirement obligation be recognised in the period in which it is incurred if a reasonable estimate of the fair value can be made. The associated asset retirement costs are capitalised as part of the carrying amount of the fixed asset. This standard 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 as a cumulative effect of a change in accounting principle. The main impacts on net assets were an increase in tangible fixed assets ($0.5 billion) and an increase in deferred tax liabilities ($0.3 billion).
On January 1, 2003 the Group completed implementation of US accounting guidance EITF Issue No. 02-03 (Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities). This requires that gains and losses on all derivative instruments within the scope of US accounting standard FAS 133 be shown net in the Statement of Income if the derivative instruments are held for trading purposes. The effect of this reclassification was a reduction in both sales proceeds and cost of sales of $12.7 billion in 2002 and $9.8 billion in 2001.
The Group has changed its accounting policy for those inventories in North America for which cost was previously determined on the basis of the LIFO method. With effect from 2003, in order to implement a globally consistent accounting policy, the cost is determined by the FIFO method and prior periods have been restated. The rationale and the effect of this change are described in Note 2.
4 Parent Companies’ interest in Group net assets
| $ million | |||||||||||||
| 2002 | 2001 | ||||||||||||
| 2003 | As restated | As restated | |||||||||||
| Invested by Parent Companies | 741 | 741 | 741 | ||||||||||
| Retained earnings of Group companies | 75,257 | 68,422 | 64,135 | ||||||||||
| Parent Companies’ shares held, net of dividends received (Note 22) | (3,428 | ) | (2,797 | ) | (1,953 | ) | |||||||
| Cumulative currency translation differences | 1,208 | (3,894 | ) | (6,326 | ) | ||||||||
| Unrealised gains/(losses) on: | |||||||||||||
| securities (Note 14) | 700 | 11 | (14 | ) | |||||||||
| cash flow hedges | (188 | ) | (239 | ) | (14 | ) | |||||||
| Minimum pension liability adjustments | (1,442 | ) | (1,800 | ) | (325 | ) | |||||||
| Balance at December 31 | 72,848 | 60,444 | 56,244 | ||||||||||
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 $25,561 million at December 31, 2003 (2002: $18,227 million; 2001: $21,699 million). Provision has not been made for taxes on possible future distribution of these undistributed earnings as these earnings have been, or will be, substantially reinvested by the companies concerned. It is not, therefore, meaningful to provide for these taxes nor is it practicable to estimate their full amount or the withholding tax element.
5 Other comprehensive income
| 2003 | $ million | |||||||||||
| Net credit/(charge) | ||||||||||||
| Pre-tax | Tax | After tax | ||||||||||
| Currency translation differences | 5,418 | (360 | ) | 5,058 | ||||||||
| Reclassifications | 44 | – | 44 | |||||||||
| Currency translation differences net of reclassifications | 5,462 | (360 | ) | 5,102 | ||||||||
| Unrealised gains/(losses) on securities | 746 | (16 | ) | 730 | ||||||||
| Reclassifications | (41 | ) | – | (41 | ) | |||||||
| Unrealised gains/(losses) on securities net of reclassifications | 705 | (16 | ) | 689 | ||||||||
| Unrealised gains/(losses) on cash flow hedges | 51 | (3 | ) | 48 | ||||||||
| Reclassifications | 3 | – | 3 | |||||||||
| Unrealised gains/(losses) on cash flow hedges net of reclassifications | 54 | (3 | ) | 51 | ||||||||
| Minimum pension liability adjustments | 669 | (311 | ) | 358 | ||||||||
| Other comprehensive income | 6,890 | (690 | ) | 6,200 | ||||||||
| 2002 (as restated) | $ million | |||||||||||
| Net credit/(charge) | ||||||||||||
| Pre-tax | Tax | After tax | ||||||||||
| Currency translation differences | 2,773 | (303 | ) | 2,470 | ||||||||
| Reclassifications | (38 | ) | – | (38 | ) | |||||||
| Currency translation differences net of reclassifications | 2,735 | (303 | ) | 2,432 | ||||||||
| Unrealised gains/(losses) on securities | 26 | 10 | 36 | |||||||||
| Reclassifications | (12 | ) | 1 | (11 | ) | |||||||
| Unrealised gains/(losses) on securities net of reclassifications | 14 | 11 | 25 | |||||||||
| Unrealised gains/(losses) on cash flow hedges | (209 | ) | (7 | ) | (216 | ) | ||||||
| Reclassifications | (9 | ) | – | (9 | ) | |||||||
| Unrealised gains/(losses) on cash flow hedges net of reclassifications | (218 | ) | (7 | ) | (225 | ) | ||||||
| Minimum pension liability adjustments | (2,446 | ) | 971 | (1,475 | ) | |||||||
| Other comprehensive income | 85 | 672 | 757 | |||||||||
| 2001 (as restated) | $ million | |||||||||||
| Net credit/(charge) | ||||||||||||
| Pre-tax | Tax | After tax | ||||||||||
| Currency translation differences | (1,654 | ) | 95 | (1,559 | ) | |||||||
| Reclassifications | (127 | ) | – | (127 | ) | |||||||
| Currency translation differences net of reclassifications | (1,781 | ) | 95 | (1,686 | ) | |||||||
| Unrealised gains/(losses) on securities | (114 | ) | (9 | ) | (123 | ) | ||||||
| Reclassifications | (32 | ) | 12 | (20 | ) | |||||||
| Unrealised gains/(losses) on securities net of reclassifications | (146 | ) | 3 | (143 | ) | |||||||
| Unrealised gains/(losses) on cash flow hedges | (1 | ) | (13 | ) | (14 | ) | ||||||
| Reclassifications | – | – | – | |||||||||
| Unrealised gains/(losses) on cash flow hedges net of reclassifications | (1 | ) | (13 | ) | (14 | ) | ||||||
| Minimum pension liability adjustments | (209 | ) | 82 | (127 | ) | |||||||
| Other comprehensive income | (2,137 | ) | 167 | (1,970 | ) | |||||||
| 2003 | 2002 | |||||||||||
| Rates of exchange at December 31 were: | €/$ | 0.79 | 0.96 | |||||||||
| £/$ | 0.56 | 0.62 | ||||||||||
6 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 | ||||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Net proceeds | 44,470 | 33,522 | 55,767 | |||||||||
| Cost of sales | 37,065 | 26,738 | 47,538 | |||||||||
| Gross profit | 7,405 | 6,784 | 8,229 | |||||||||
| Other operating expenses | 3,921 | 3,962 | 5,583 | |||||||||
| Operating profit | 3,484 | 2,822 | 2,646 | |||||||||
| Interest and other income | 228 | 102 | 98 | |||||||||
| Interest expense | 540 | 451 | 503 | |||||||||
| Currency exchange gains/(losses) | (3 | ) | (15 | ) | (20 | ) | ||||||
| Income before taxation | 3,169 | 2,458 | 2,221 | |||||||||
| Taxation | 1,478 | 1,002 | 1,087 | |||||||||
| Net income | 1,691 | 1,456 | 1,134 | |||||||||
As stated in Note 2, the Group changed its accounting for certain North American inventories from LIFO to FIFO. This change has been reflected in the restated 2002 and 2001 comparative information.
| Income by segment | $ million | |||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Exploration and Production | 810 | 543 | 757 | |||||||||
| Gas & Power | 650 | 589 | 746 | |||||||||
| Oil Products | 632 | 448 | 43 | |||||||||
| Chemicals | (169 | ) | 153 | (26 | ) | |||||||
| Corporate and Other | (232 | ) | (277 | ) | (386 | ) | ||||||
| 1,691 | 1,456 | 1,134 | ||||||||||
(b) Investments
| $ million | ||||||||||||||||
| 2003 | 2002 | |||||||||||||||
| As restated | ||||||||||||||||
| Shares | Loans | Total | Total | |||||||||||||
| At January 1 | 15,320 | 2,628 | 17,948 | 18,332 | ||||||||||||
| New investments | 758 | 225 | 983 | 1,289 | ||||||||||||
| Net asset transfers to/(from) associates, disposals and other movements | 206 | (379 | ) | (173 | ) | (2,409 | ) | |||||||||
| Net income | 1,691 | – | 1,691 | 1,456 | ||||||||||||
| Dividends | (2,192 | ) | – | (2,192 | ) | (1,571 | ) | |||||||||
| Currency translation differences | 1,029 | 98 | 1,127 | 851 | ||||||||||||
| At December 31 | 16,812 | 2,572 | 19,384 | 17,948 | ||||||||||||
Net income for 2003 includes a $286 million write-down in the carrying value of Basell (Chemicals) reflecting a reassessment of the outlook for the business, a $200 million write-down in the carrying value 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 value of the Cuiaba power assets in South America (Gas & Power) in light of a reappraisal of the commercial outlook. Net income for 2002 includes a $150 million write-down in the carrying amount of InterGen (Gas & Power).
In 2002, the net asset transfers to/from associates, disposals and other movements mainly relates to the effects of the reclassification of Equilon from an associate to a Group company upon the acquisition of the outstanding 44% interest.
A summarised Statement of Assets and Liabilities with respect to the Group share of investments in associated companies is set out below:
| $ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Fixed assets | 30,921 | 27,613 | ||||||
| Current assets | 8,248 | 7,029 | ||||||
| Total assets | 39,169 | 34,642 | ||||||
| Current liabilities | 8,745 | 7,107 | ||||||
| Long-term liabilities | 11,040 | 9,587 | ||||||
| Net assets | 19,384 | 17,948 | ||||||
An analysis by segment is shown in Note 24.
The Group’s major investments in associated companies at December 31, 2003 comprised:
| Segment | |||||||||
| Name | Group interest | Country of incorporation | |||||||
| Exploration and 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 | 50% | Japan | |||||||
| Chemicals | |||||||||
| Basell | 50% | The Netherlands | |||||||
| Saudi Petrochemical | 50% | Saudi Arabia | |||||||
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 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 | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Charges to associated companies | 18,155 | 10,573 | 13,415 | |||||||||
| Charges from associated companies | 8,608 | 5,623 | 5,053 | |||||||||
Balances outstanding at December 31, 2003 and 2002 in respect of the above transactions are shown in Notes 13 and 17.
7 Interest and other income
| $ million | |||||||||||||
| 2003 | 2002 | 2001 | |||||||||||
| Group companies | |||||||||||||
| Interest income | 326 | 491 | 784 | ||||||||||
| Other income | 1,419 | 165 | 177 | ||||||||||
| 1,745 | 656 | 961 | |||||||||||
| Associated companies | 228 | 102 | 98 | ||||||||||
| 1,973 | 758 | 1,059 | |||||||||||
Other income in 2003 includes a $1.3 billion gain from the disposal of the Group’s interest in Ruhrgas.
8 Interest expense
| $ million | |||||||||||||
| 2003 | 2002 | 2001 | |||||||||||
| Group companies | |||||||||||||
| Interest incurred | 885 | 956 | 662 | ||||||||||
lessinterest capitalised | 44 | 43 | 32 | ||||||||||
| 841 | 913 | 630 | |||||||||||
| Associated companies | 540 | 451 | 503 | ||||||||||
| 1,381 | 1,364 | 1,133 | |||||||||||
9 Taxation
| $ million | |||||||||||||
| 2002 | 2001 | ||||||||||||
| 2003 | As restated | As restated | |||||||||||
| Group companies | |||||||||||||
| Current tax charge | 8,290 | 6,727 | 7,722 | ||||||||||
| Deferred tax charge/(credit) | (196 | ) | 67 | (405 | ) | ||||||||
| 8,094 | 6,794 | 7,317 | |||||||||||
| Associated companies | 1,478 | 1,002 | 1,087 | ||||||||||
| 9,572 | 7,796 | 8,404 | |||||||||||
Reconciliations of the expected tax charge of Group companies to the actual tax charge are as follows:
| $ million | ||||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Expected tax charge at statutory rates | 9,125 | 6,646 | 7,439 | |||||||||
| Adjustments in respect of prior years | 173 | (251 | ) | (258 | ) | |||||||
| Other reconciling items | (1,204 | ) | 399 | 136 | ||||||||
| Taxation charge of Group companies | 8,094 | 6,794 | 7,317 | |||||||||
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 and 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 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 UK upstream corporate tax rate during the year. From 2003, this increase is reflected in a higher statutory rate.
(b) Taxes payable
| $ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Taxes on activities of Group companies | 2,148 | 1,988 | ||||||
| Sales taxes, excise duties and similar levies and social law taxes | 3,779 | 2,997 | ||||||
| 5,927 | 4,985 | |||||||
(c) Provision for deferred taxation
| $ million | |||||||||
| 2002 | |||||||||
| 2003 | As restated | ||||||||
| Tangible and intangible fixed assets | 17,627 | 16,837 | |||||||
| Pensions | 2,118 | 1,379 | |||||||
| Other items | 2,649 | 2,125 | |||||||
| Total deferred tax liabilities | 22,394 | 20,341 | |||||||
| Tax losses carried forward | (3,876 | ) | (2,171 | ) | |||||
Foreign tax creditsa | (1,633 | ) | (1,089 | ) | |||||
US trademarkb | (309 | ) | (375 | ) | |||||
| Provisions | |||||||||
| Pensions and similar obligations | (1,329 | ) | (1,293 | ) | |||||
| Decommissioning and restoration costs | (1,934 | ) | (1,700 | ) | |||||
| Environmental and other provisions | (334 | ) | (445 | ) | |||||
| Other items | (3,421 | ) | (3,046 | ) | |||||
| Total deferred tax assets | (12,836 | ) | (10,119 | ) | |||||
| Asset valuation allowance | 3,797 | 2,474 | |||||||
| Deferred tax assets net of valuation allowance | (9,039 | ) | (7,645 | ) | |||||
| Net deferred tax liability | 13,355 | 12,696 | |||||||
| 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 2003 and 2002. |
| 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 $11,137 million at December 31, 2003. Of these, $8,399 million can be carried forward indefinitely. The remaining $2,738 million expires in the following years:
| $ million | ||||
| 2004 | 225 | |||
| 2005 | 314 | |||
| 2006 | 191 | |||
| 2007 | 637 | |||
| 2008 – 2012 | 740 | |||
| 2013 – 2018 | 631 | |||
10 Tangible and intangible fixed assets
| $ million | |||||||||||||||||||||||||
| 2003 | |||||||||||||||||||||||||
| 2002 | |||||||||||||||||||||||||
| As restated | |||||||||||||||||||||||||
| Other | Total | Total | Total | ||||||||||||||||||||||
| Tangible | Goodwill | intangibles | intangibles | Group | Group | ||||||||||||||||||||
Cost | |||||||||||||||||||||||||
| At January 1 | 157,499 | 3,500 | 2,958 | 6,458 | 163,957 | 119,956 | |||||||||||||||||||
| Capital expenditure | 12,005 | 33 | 214 | 247 | 12,252 | 12,102 | |||||||||||||||||||
| Assets assumed on acquisitions (Enterprise Oil, Pennzoil-Quaker State and DEA and additional shares in Equilon) | (28 | ) | 418 | (266 | ) | 152 | 124 | 23,285 | |||||||||||||||||
Sales, retirements and other movementsa | (1,805 | ) | (51 | ) | (38 | ) | (89 | ) | (1,894 | ) | (1,306 | ) | |||||||||||||
| Currency translation differences | 14,014 | 111 | 130 | 241 | 14,255 | 9,920 | |||||||||||||||||||
| At December 31 | 181,685 | 4,011 | 2,998 | 7,009 | 188,694 | 163,957 | |||||||||||||||||||
Depreciation | |||||||||||||||||||||||||
| At January 1 | 78,812 | 1,176 | 586 | 1,762 | 80,574 | 68,090 | |||||||||||||||||||
| Depreciation, depletion and amortisation charge | 11,000 | 129 | 293 | 422 | 11,422 | 8,621 | |||||||||||||||||||
| Sales, retirements and other movements | (3,680 | ) | (29 | ) | (2 | ) | (31 | ) | (3,711 | ) | (1,524 | ) | |||||||||||||
| Currency translation differences | 7,852 | 60 | 61 | 121 | 7,973 | 5,387 | |||||||||||||||||||
| At December 31 | 93,984 | 1,336 | 938 | 2,274 | 96,258 | 80,574 | |||||||||||||||||||
Net 2003 | 87,701 | b | 2,675 | 2,060 | 4,735 | 92,436 | |||||||||||||||||||
| 2002 | 78,687 | b | 2,324 | 2,372 | 4,696 | 83,383 | |||||||||||||||||||
| a | Sales, retirements and other movements in 2003 include the effect of a change in accounting policy for certain long-term agreements (see Note 2). |
| b | Tangible fixed assets at December 31, 2003 include rights and concessions of $12.0 billion (2002: $13.1 billion). A new accounting pronouncement is pending that may in the future consider these to be intangible fixed assets. A reclassification of these items from tangible to intangible fixed assets would not impact the Group’s Statements of Income and Cash Flows. |
Other intangible fixed assets at December 31, 2003 include $0.8 billion (2002: $1.1 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 acquisitions and new investments in associated companies, and the depreciation, depletion and amortisation charges are shown in Note 24, classified, consistent with oil and 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 | |||||||||
| 2002 | |||||||||
| 2003 | As restated | ||||||||
| Capitalised costs in respect of assets not yet used in operations | |||||||||
| Unproved properties | 4,576 | 4,443 | |||||||
| Proved properties under development and other assets in the course of construction | 12,680 | 6,814 | |||||||
| 17,256 | 11,257 | ||||||||
Depreciation, depletion and amortisation charges for the year in the table above are included within the following expense headings in the Statement of Income:
| $ million | ||||||||||||
| 2002 | 2001 | |||||||||||
| 2003 | As restated | As restated | ||||||||||
| Cost of sales | 9,574 | 7,351 | 5,071 | |||||||||
| Selling and distribution expenses | 1,288 | 1,095 | 1,007 | |||||||||
| Administrative expenses | 121 | 62 | 53 | |||||||||
| Exploration | 411 | 80 | 42 | |||||||||
| Research and development | 28 | 33 | 28 | |||||||||
| 11,422 | 8,621 | 6,201 | ||||||||||
Depreciation, depletion and amortisation charges for 2003 include $1,248 million (2002: $191 million; 2001: $88 million) relating to the impairment of tangible fixed assets, and $127 million (2002: $6 million; 2001: nil) 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 (2003: $1,168 million; 2002: $105 million; 2001: nil) and to assets held for sale (2003: $207 million; 2002: $92 million; 2001: $88 million).
For 2003, the impairments were incurred in Exploration and Production ($697 million, mainly due to lower production outlooks in the UK and South America), in Oil Products ($331 million, mainly due to the 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. For 2001, the impairment charges (in total $88 million) were mainly in Chemicals, reflecting plans to close the Taft polymer plant and close a catalyst production line in the USA, and in Renewables based on bids received for their South American forestry assets.
Depreciation, depletion and amortisation charges for 2003 also included $366 million relating to the write-off of various exploration properties, mainly in Brazil and Ireland. In both these countries, new information from 2003 exploratory work confirmed lower than expected volume projections.
2002 acquisitions
Oil Products
The Group formed DEA, a joint venture with RWE AG, in the first quarter of 2002 to provide the Group with an enhanced position in Germany, the largest oil products market in Europe. Under the relevant governing agreements and constitutive documents, the Group has controlled DEA since its formation and as a result has included DEA in the Group’s consolidated results throughout 2002. The Group acquired the remaining shares in DEA in the third quarter of 2002 for an aggregate cash consideration of $1.3 billion, payable in July 2003.
The Group acquired all the outstanding shares of Pennzoil-Quaker State Company (PQS) in the fourth quarter of 2002 for aggregate cash consideration of $1.9 billion and assumed debt of $1.3 billion, aligned with the Group’s strategy to become a leader in the global lubricants market by strengthening its position in the USA.
The following table sets forth the fair values of assets acquired and liabilities assumed in these acquisitions, including for Enterprise Oil $6.6 billion of rights and concessions and for PQS $1.1 billion of trademarks and $1.7 billion of goodwill (of which $0.3 billion is tax-deductible) recognised as a reflection of the value of growth opportunities.
| 2002(as restated) | $ million | ||||||||||||
| Exploration | |||||||||||||
| and | Oil | ||||||||||||
| Production | Products | Total | |||||||||||
| Tangible and intangible fixed assets | 11,286 | 11,999 | 23,285 | ||||||||||
including: | |||||||||||||
PQS goodwill | 1,743 | 1,743 | |||||||||||
PQS trademarks | 1,101 | 1,101 | |||||||||||
| Other assets | 736 | 5,772 | 6,508 | ||||||||||
| Total assets acquired | 12,022 | 17,771 | 29,793 | ||||||||||
| Current liabilities (excluding debt) | 252 | 3,609 | 3,861 | ||||||||||
| Debt | 2,359 | 3,608 | 5,967 | ||||||||||
| Deferred taxation | 3,771 | 638 | 4,409 | ||||||||||
| Other long-term liabilities and provisions | 346 | 2,220 | 2,566 | ||||||||||
| Total liabilities assumed | 6,728 | 10,075 | 16,803 | ||||||||||
Less: Existing equity in Equilon | 2,730 | 2,730 | |||||||||||
Purchase considerationa | 5,294 | 4,966 | 10,260 | ||||||||||
| a | Includes $1.3 billion relating to DEA, paid during 2003. |
The acquisition of PQS took place in the fourth quarter, 2002 and the purchase price allocation was not finalised until 2003 due in particular to completion of the valuation of the trademarks; the main effect in 2003 was a decrease in trademarks of $0.3 billion with a corresponding increase in goodwill.
Pro forma information (unaudited)
| $ million | |||||||||||||||||
| Net proceeds | Net income | ||||||||||||||||
| 2002 | 2001 | 2002 | 2001 | ||||||||||||||
| As restated (see Note 2) | 166,601 | 125,361 | 9,722 | 10,350 | |||||||||||||
| Results before financing costs: | |||||||||||||||||
| Enterprise Oil | 403 | 2,002 | (32 | ) | 94 | ||||||||||||
| Equilon | – | 44,463 | – | 45 | |||||||||||||
| DEA | – | 6,422 | (27 | ) | 153 | ||||||||||||
| PQS | 1,691 | 2,315 | 81 | 117 | |||||||||||||
| Financing costs (after tax) | (165 | ) | (461 | ) | |||||||||||||
| Pro forma | 168,695 | 180,563 | 9,579 | 10,298 | |||||||||||||
| $ | ||||||||||||||||
| 2002 | 2001 | |||||||||||||||
| As restated | As restated | |||||||||||||||
| (see Note 2) | Pro forma | (see Note 2) | Pro forma | |||||||||||||
| Basic earnings per share attributable to Royal Dutch | 2.83 | 2.79 | 2.96 | 2.95 | ||||||||||||
| Diluted earnings per share attributable to Royal Dutch | 2.83 | 2.79 | 2.96 | 2.95 | ||||||||||||
| Basic earnings per ADR attributable to Shell Transport | 2.43 | 2.39 | 2.55 | 2.53 | ||||||||||||
| Diluted earnings per ADR attributable to Shell Transport | 2.43 | 2.39 | 2.54 | 2.53 | ||||||||||||
The pro forma information above is based on the following:
| – | the preparation of this information has required use of certain estimates, utilising both pre- and post-acquisition data, in particular for fully-integrated businesses; |
| – | where applicable, pro forma amounts have been calculated taking into account additional depreciation, depletion or amortisation resulting from fair value accounting, and have been adjusted on to the basis of Group accounting policies. Group accounting policies as in effect for 2002 have been applied, adjusted to reflect changes in 2003 which have resulted in restatement of prior period information; |
| – | financing costs comprise additional interest charges on the purchase considerations, plus the acquired companies’ interest charges on their existing debt up to the date of acquisition; |
| – | taxes have been calculated using the relevant statutory rate for each of the jurisdictions involved. A tax rate of 35% has been applied to calculate the tax relief on the interest charge on Group debt incurred to finance the acquisitions; |
| – | for 2001, pro forma data is provided for all acquisitions for the entire year. Both Equilon and DEA were included in Group results for all of 2002. For Enterprise Oil, the first quarter of 2002 is on a pro forma basis and for PQS the first three quarters of 2002 are reported on a pro forma basis; |
| – | PQS trademarks are being amortised over 40 years, with no residual value expected; and |
| – | restructuring costs incurred have remained in the period originally recorded. The Equilon acquisition resulted in a restructuring expense of approximately $300 million (pre-tax) in 2001. |
11 Other long-term assets
12 Inventories
| $ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Inventories of oil and chemicals | 11,742 | 10,423 | ||||||
| Inventories of materials | 948 | 915 | ||||||
| 12,690 | 11,338 | |||||||
| Prior period information has been restated for a change in inventory costing (see Note 2). |
13 Accounts receivable
| $ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Trade receivables | 17,523 | 15,475 | ||||||
| Amounts owed by associated companies | 2,094 | 4,834 | ||||||
| Other receivables | 3,602 | 3,458 | ||||||
| Deferred charges and prepayments | 5,750 | 4,994 | ||||||
| 28,969 | 28,761 | |||||||
Provisions for doubtful items deducted from accounts receivable amounted to $557 million at December 31, 2003 (2002: $415 million). Deferred charges and prepayments include amounts in respect of risk management activities.
14 Securities
$125 million of these total 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 $638 million at December 31, 2003 (2002: $689 million) are debt securities. Of the available for sale securities, the maturities of $7 million fall within one year, $365 million fall between one year and five years, and $266 million exceed five years.
The carrying amount of securities classified as cash equivalents, is $107 million at December 31, 2003 (2002: $44 million), all of which are debt securities classified as available for sale.
Total securities at December 31, 2003 amounting to $1,557 million (2002: $1,033 million) are listed on recognised stock exchanges.
15 Debt
| $ million | ||||||||
| 2003 | 2002 | |||||||
| Debentures and other loans | 8,181 | 9,963 | ||||||
| Amounts due to banks and other credit institutions (including long-term debt due within one year) | 2,737 | 2,846 | ||||||
| 10,918 | 12,809 | |||||||
| Capitalised lease obligations | 109 | 65 | ||||||
Short-term debt | 11,027 | 12,874 | ||||||
| less long-term debt due within one year | 1,874 | 2,253 | ||||||
| Short-term debt excluding long-term debt due within one year | 9,153 | 10,621 | ||||||
Short-term debt at December 31, 2003 includes $1.3 billion (2002: $1.3 billion) of non-recourse debt owed by a Group company (interest 64%) for which a debt covenant (the interest cover ratio) was breached in 2001. The covenant breach is continuing and the company is in default on the full outstanding balance of $1.3 billion.
The following relates only to short-term debt excluding long-term debt due within one year:
| $ million | |||||||||
| 2003 | 2002 | ||||||||
| Maximum amount outstanding at the end of any quarter | 9,159 | 13,098 | |||||||
| Average amount outstanding | 8,554 | 8,153 | |||||||
| Amounts due to banks and other credit institutions | 2,657 | 2,378 | |||||||
| Unused lines of short-term credit | 3,916 | 3,625 | |||||||
| Approximate average interest rate on: | |||||||||
| average amount outstanding | 3% | 3% | |||||||
| amount outstanding at December 31 | 2% | 3% | |||||||
The amount outstanding at December 31, 2003 includes $5,754 million of fixed rate and $1,543 million of variable rate dollar debt at an average interest rate of 1% and 4% respectively.
(b) Long-term debt
| $ million | ||||||||
| 2003 | 2002 | |||||||
| Debentures and other loans | 4,868 | 5,523 | ||||||
| Amounts due to banks and other credit institutions | 3,724 | 794 | ||||||
| 8,592 | 6,317 | |||||||
| Capitalised lease obligations | 508 | 500 | ||||||
Long-term debt | 9,100 | 6,817 | ||||||
addlong-term debt due within one year | 1,874 | 2,253 | ||||||
| Long-term debt including long-term debt due within one year | 10,974 | 9,070 | ||||||
The increase in long-term debt during 2003 mainly reflects a change in accounting for certain power generation contracts (“tolling agreements”) which were previously accounted for as executory contracts and marked to market.
The following relates to long-term debt including the short-term part but excluding capitalised lease obligations.
The amount at December 31, 2003 of $10,357 million (2002: $8,505 million) comprises:
| Average | |||||||||
| $ million | interest rate | ||||||||
| Dollar denominated debt | |||||||||
| Fixed rate | 5,369 | 6% | |||||||
| Variable rate | 766 | 4% | |||||||
| Non-dollar denominated debt | |||||||||
| Fixed rate | 2,213 | 4% | |||||||
| Variable rate | 2,009 | 3% | |||||||
| 10,357 | |||||||||
The approximate weighted average interest rate in 2003 was 3% for dollar debt and 4% for total debt.
The aggregate maturities of long-term debts are:
| $ million | ||||
| 2004 | 1,765 | |||
| 2005 | 1,212 | |||
| 2006 | 1,526 | |||
| 2007 | 2,067 | |||
| 2008 | 561 | |||
| 2009 and after | 3,226 | |||
| 10,357 | ||||
During 2003, the Medium Term Note and Commercial Paper Facilities have been increased to a total level of $28.0 billion. As at December 31, 2003, debt outstanding under central borrowing programmes, which includes these facilities, totalled $11.9 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 28.
16 Commitments
| $ million | ||||||||
| Operating | Capital | |||||||
| leases | leases | |||||||
| 2004 | 1,760 | 76 | ||||||
| 2005 | 1,190 | 85 | ||||||
| 2006 | 915 | 66 | ||||||
| 2007 | 766 | 62 | ||||||
| 2008 | 666 | 58 | ||||||
| 2009 and after | 4,684 | 707 | ||||||
| Total minimum payments | 9,981 | 1,054 | ||||||
lessexecutory costs and interest | 437 | |||||||
| Present value of net minimum capital lease payments | 617 | |||||||
The figures above for operating lease payments represent minimum commitments existing at December 31, 2003 and are not a forecast of future total rental expense.
Total rental expense for all operating leases was as follows:
| $ million | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Minimum rentals | 2,135 | 1,557 | 1,377 | |||||||||
| Contingent rentals | 60 | 104 | 105 | |||||||||
| Sub-lease rentals | (198 | ) | (300 | ) | (174 | ) | ||||||
| 1,997 | 1,361 | 1,308 | ||||||||||
(b) Long-term purchase obligations
| $ million | ||||
| 2004 | 405 | |||
| 2005 | 255 | |||
| 2006 | 243 | |||
| 2007 | 225 | |||
| 2008 | 219 | |||
| 2009 and after | 1,914 | |||
| 3,261 | ||||
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 $252 million in 2003 (2002: $441 million).
17 Accounts payable and accrued liabilities
| $ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Trade payables | 14,110 | 13,049 | ||||||
| Amounts due to associated companies | 1,829 | 2,075 | ||||||
| Pensions and similar obligations | 261 | 250 | ||||||
| Other payables | 8,832 | 10,699 | ||||||
| Accruals and deferred income | 7,315 | 6,116 | ||||||
| 32,347 | 32,189 | |||||||
Other payables include amounts in respect of risk management activities and, at December 31, 2002, $1.3 billion for the acquisition of DEA, paid during 2003.
18 Long-term liabilities – Other
19 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-dollar Group companies to 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.
| 2003 | $ 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 | (533 | ) | 6,282 | 3,304 | 9,053 | |||||||||||
| Investments | (792 | ) | 1,238 | 1,254 | 1,700 | |||||||||||
| Other long-term assets | 601 | 804 | 519 | 1,924 | ||||||||||||
| Inventories | 236 | 1,158 | (42 | ) | 1,352 | |||||||||||
| Accounts receivable | (1,834 | ) | 2,120 | (78 | ) | 208 | ||||||||||
| Cash and cash equivalents | 248 | 148 | – | 396 | ||||||||||||
| Short-term debt | 2,507 | (913 | ) | (126 | ) | 1,468 | ||||||||||
| Short-term part of long-term debt | 612 | (233 | ) | – | 379 | |||||||||||
| Accounts payable and accrued liabilities | 212 | (221 | ) | (149 | ) | (158 | ) | |||||||||
| Taxes payable | 218 | (687 | ) | (473 | ) | (942 | ) | |||||||||
| Long-term debt | 1,961 | (676 | ) | (3,568 | ) | (2,283 | ) | |||||||||
| Other long-term liabilities | 467 | (376 | ) | 29 | 120 | |||||||||||
| Deferred taxation | 388 | (1,066 | ) | 19 | (659 | ) | ||||||||||
| Other provisions | 116 | (740 | ) | 286 | (338 | ) | ||||||||||
| Minority interests | 1,298 | (171 | ) | (973 | ) | 154 | ||||||||||
| Other items | (91 | ) | 91 | – | – | |||||||||||
| Distributions to Parent Companies | 588 | (558 | ) | – | 30 | |||||||||||
| Adjustment for Parent Companies’ shares and Other comprehensive income excluding currency translation differences | 633 | (1,098 | ) | (2 | ) | – | ||||||||||
| – | ||||||||||||||||
| Movement in retained earnings of Group companies (Note 4) | 6,835 | |||||||||||||||
| Movement in cumulative currency translation differences (Note 5) | 5,102 | |||||||||||||||
| Movement in net assets (Note 4) | 12,404 | |||||||||||||||
Income taxes paid by Group companies totalled $8.6 billion in 2003 (2002: $6.7 billion; 2001: $9.3 billion). Interest paid by Group companies was $0.9 billion in 2003 (2002: $1.0 billion; 2001: $0.7 billion).
The main non-cash movements reflect a change in accounting policy for certain power generation contracts (“tolling agreements”, see Note 2) and acquisition of minority interests in DEA.
20 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.
In accordance with US accounting pronouncement FAS 106-1, the Group has elected to defer accounting for the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). Measures of the impact of the Act are not reflected in the following disclosures of Other Benefits Obligations and Net Periodic Benefit Cost of Other Benefits in the USA. Specific authoritative guidance on the accounting for the federal subsidy under the Act is pending, and that guidance, when issued, could require the Group to change previously disclosed information.
| $ million | |||||||||||||||||||||||||||||||||
| Other benefits | |||||||||||||||||||||||||||||||||
| Pension benefits | 2003 | 2002 | |||||||||||||||||||||||||||||||
| 2003 | 2002 | USA | Other | Total | USA | Other | Total | ||||||||||||||||||||||||||
Change in benefit obligation | |||||||||||||||||||||||||||||||||
| Obligations for benefits based on employee service to date at January 1 | 39,109 | 32,239 | 2,068 | 377 | 2,445 | 906 | 344 | 1,250 | |||||||||||||||||||||||||
| Increase in present value of the obligation for benefits based on employee service during the year | 991 | 899 | 37 | 15 | 52 | 32 | 7 | 39 | |||||||||||||||||||||||||
| Interest on the obligation for benefits in respect of employee service in previous years | 2,333 | 2,001 | 141 | 24 | 165 | 111 | 21 | 132 | |||||||||||||||||||||||||
| Benefit payments made | (2,034 | ) | (1,780 | ) | (95 | ) | (25 | ) | (120 | ) | (72 | ) | (21 | ) | (93 | ) | |||||||||||||||||
| Currency translation effects | 5,333 | 3,938 | – | 78 | 78 | – | 45 | 45 | |||||||||||||||||||||||||
| Other componentsa | 744 | 1,812 | 369 | 43 | 412 | 1,091 | (19 | ) | 1,072 | ||||||||||||||||||||||||
| Obligations for benefits based on employee service to date at December 31 | 46,476 | 39,109 | 2,520 | 512 | 3,032 | 2,068 | 377 | 2,445 | |||||||||||||||||||||||||
| Change in plan assets | |||||||||||||||||||||||||||||||||
| Plan assets held in trust at fair value at January 1 | 33,035 | 36,420 | |||||||||||||||||||||||||||||||
| Actual return on plan assets | 6,598 | (5,943 | ) | ||||||||||||||||||||||||||||||
| Employer contributions | 1,275 | 227 | |||||||||||||||||||||||||||||||
| Plan participants’ contributions | 40 | 17 | |||||||||||||||||||||||||||||||
| Benefit payments made | (2,034 | ) | (1,780 | ) | |||||||||||||||||||||||||||||
| Currency translation effects | 4,911 | 3,709 | |||||||||||||||||||||||||||||||
| Other componentsa | 135 | 385 | |||||||||||||||||||||||||||||||
| Plan assets held in trust at fair value at December 31 | 43,960 | 33,035 | |||||||||||||||||||||||||||||||
| Plan assets in excess of/(less than) the present value of obligations for benefits at December 31 | (2,516 | ) | (6,074 | ) | (2,520 | ) | (512 | ) | (3,032 | ) | (2,068 | ) | (377 | ) | (2,445 | ) | |||||||||||||||||
| Unrecognised net (gains)/losses remaining from the adoption of current method of determining pension costs | 5 | 9 | |||||||||||||||||||||||||||||||
| Unrecognised net (gains)/losses since adoption | 7,295 | 9,125 | 876 | 149 | 1,025 | 692 | 93 | 785 | |||||||||||||||||||||||||
| Unrecognised prior service cost/(credit) | 1,258 | 1,254 | (82 | ) | – | (82 | ) | (26 | ) | – | (26 | ) | |||||||||||||||||||||
| Net amount recognised | 6,042 | 4,314 | (1,726 | ) | (363 | ) | (2,089 | ) | (1,402 | ) | (284 | ) | (1,686 | ) | |||||||||||||||||||
| Amounts recognised in the Statement of Assets and Liabilities: | |||||||||||||||||||||||||||||||||
| Intangible assets | 326 | 420 | |||||||||||||||||||||||||||||||
| Prepaid benefit costs | 6,516 | 4,506 | |||||||||||||||||||||||||||||||
| Accrued benefit liabilities: | |||||||||||||||||||||||||||||||||
| Short-term | (182 | ) | (177 | ) | (51 | ) | (28 | ) | (79 | ) | (51 | ) | (22 | ) | (73 | ) | |||||||||||||||||
| Long-term | (2,917 | ) | (3,403 | ) | (1,675 | ) | (335 | ) | (2,010 | ) | (1,351 | ) | (262 | ) | (1,613 | ) | |||||||||||||||||
| 3,743 | 1,346 | (1,726 | ) | (363 | ) | (2,089 | ) | (1,402 | ) | (284 | ) | (1,686 | ) | ||||||||||||||||||||
| Amount recognised in Parent Companies’ interest in Group net assets: | |||||||||||||||||||||||||||||||||
| Accumulated other comprehensive income | 2,299 | 2,968 | |||||||||||||||||||||||||||||||
| Net amount recognised | 6,042 | 4,314 | (1,726 | ) | (363 | ) | (2,089 | ) | (1,402 | ) | (284 | ) | (1,686 | ) | |||||||||||||||||||
| a | Other components comprise mainly the effect of acquisitions and changes in actuarial assumptions. |
Additional information on pension benefits
| $ million | |||||||||
| 2003 | 2002 | ||||||||
| Obligation for pension benefits in respect of unfunded plans | 2,155 | 1,964 | |||||||
| Accumulated benefit obligation | 41,865 | 34,766 | |||||||
| For employee retirement plans with projected benefit obligation in excess of plan assets, the respective amounts are: | |||||||||
| Projected benefit obligation | 30,291 | 25,698 | |||||||
| Plan assets | 28,176 | 21,072 | |||||||
| For employee retirement plans with accumulated benefit obligation in excess of plan assets, the respective amounts are: | |||||||||
| Accumulated benefit obligation | 10,452 | 10,907 | |||||||
| Plan assets | 9,356 | 9,330 | |||||||
Employer contributions to defined benefit pension plans during 2004 are estimated to be $1.3 billion.
Benefit costs for the year comprise:
| $ million | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other benefits | ||||||||||||||||||||||||||||||||||||||||||||||||
| Pension benefits | 2003 | 2002 | 2001 | |||||||||||||||||||||||||||||||||||||||||||||
| 2003 | 2002 | 2001 | USA | Other | Total | USA | Other | Total | USA | Other | Total | |||||||||||||||||||||||||||||||||||||
| Service cost | 991 | 899 | 681 | 37 | 15 | 52 | 32 | 7 | 39 | 10 | 3 | 13 | ||||||||||||||||||||||||||||||||||||
| Interest cost | 2,333 | 2,001 | 1,784 | 141 | 24 | 165 | 111 | 21 | 132 | 61 | 15 | 76 | ||||||||||||||||||||||||||||||||||||
| Expected return on plan assets | (3,547 | ) | (3,339 | ) | (3,005 | ) | ||||||||||||||||||||||||||||||||||||||||||
| Other components | 303 | (100 | ) | (216 | ) | 66 | 4 | 70 | 76 | 7 | 83 | (2 | ) | 2 | – | |||||||||||||||||||||||||||||||||
| Cost of defined benefit plans | 80 | (539 | ) | (756 | ) | 244 | 43 | 287 | 219 | 35 | 254 | 69 | 20 | 89 | ||||||||||||||||||||||||||||||||||
| Payments to defined contribution plans | 171 | 84 | 87 | |||||||||||||||||||||||||||||||||||||||||||||
| 251 | (455 | ) | (669 | ) | 244 | 43 | 287 | 219 | 35 | 254 | 69 | 20 | 89 | |||||||||||||||||||||||||||||||||||
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 | 2003 | 2002 | 2001 | |||||||||||||||||||||||||||||||||
| 2003 | 2002 | 2001 | USA | Other | USA | Other | USA | Other | ||||||||||||||||||||||||||||
| Assumptions used to determine benefit obligations at December 31 | ||||||||||||||||||||||||||||||||||||
| Discount rate | 5.6% | 5.9% | 6.0% | 6.0% | 5.6% | 6.5% | 5.6% | 7.0% | 6.0% | |||||||||||||||||||||||||||
| Projected rate of remuneration growth | 3.9% | 4.0% | 4.0% | |||||||||||||||||||||||||||||||||
| Assumptions used to determine benefit costs for year ended December 31 | ||||||||||||||||||||||||||||||||||||
| Discount rate | 5.9% | 6.0% | 6.1% | 6.5% | 5.6% | 7.0% | 6.0% | 7.5% | 6.3% | |||||||||||||||||||||||||||
| Expected rate of return on plan assets | 7.9% | 8.0% | 7.8% | |||||||||||||||||||||||||||||||||
| Projected rate of remuneration growth | 4.0% | 4.0% | 4.0% | |||||||||||||||||||||||||||||||||
Healthcare cost trend rates | ||||||||||||||||||||||||||||||||||||
| Healthcare cost trend rate in year after reporting year | 10.0% | 3.9% | 7.8% | 4.6% | ||||||||||||||||||||||||||||||||
| Ultimate healthcare cost trend rate | 5.0% | 2.9% | 5.0% | 2.9% | ||||||||||||||||||||||||||||||||
| Year ultimate healthcare cost trend rate is applicable | 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 $41 million/($30 million) and the accumulated postretirement benefit obligation by approximately $422 million/($361 million).
Weighted-average plan asset allocations by asset category and the target allocation for December 31, 2003 for the principal pension plans in the Group are:
| Target | Percentage of plan | |||||||||||
| allocation | assets at December 31 | |||||||||||
| 2003 | 2003 | 2002 | ||||||||||
| Equity securities | 72% | 73% | 71% | |||||||||
| Debt securities | 23% | 22% | 23% | |||||||||
| Real estate | 2% | 2% | 3% | |||||||||
| Other | 3% | 3% | 3% | |||||||||
| Total | 100% | 100% | 100% | |||||||||
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.
21 Employee emoluments and numbers
| $ million | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Remuneration | 7,477 | 6,096 | 4,651 | |||||||||
| Social law taxes | 660 | 518 | 395 | |||||||||
| Pensions and similar obligations (Note 20) | 538 | (201 | ) | (580 | ) | |||||||
| 8,675 | 6,413 | 4,466 | ||||||||||
(b) Average numbers
| thousands | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Exploration and Production | 17 | 17 | 14 | |||||||||
| Gas & Power | 2 | 2 | 2 | |||||||||
| Oil Products | 82 | 75 | 58 | |||||||||
| Chemicals | 9 | 9 | 9 | |||||||||
| Corporate and Other | 9 | 8 | 7 | |||||||||
| 119 | 111 | 90 | ||||||||||
(c) Year-end numbers
| thousands | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Exploration and Production | 17 | 17 | 15 | |||||||||
| Gas & Power | 2 | 2 | 2 | |||||||||
| Oil Products | 82 | 80 | 58 | |||||||||
| Chemicals | 9 | 9 | 9 | |||||||||
| Corporate and Other | 9 | 8 | 7 | |||||||||
| 119 | 116 | 91 | ||||||||||
In addition to remuneration above, there were charges for redundancy of $291 million in 2003 (2002: $215 million; 2001: $110 million).
The charges relate to 2,000 employees in 2003 (mainly in the Exploration and Production and Oil Products segments), 2,600 employees in 2002 (mainly in the Exploration and Production and Oil Products segments) and 1,300 employees in 2001 (mainly in the Oil Products, Chemicals and Other industry segments). The liabilities for redundancies at December 31, 2003 and 2002, and movements during 2003 and 2002, are given in the following table. Other movements in 2002 mainly relate to liabilities assumed on acquisitions.
| $ million | ||||||||
| 2003 | 2002 | |||||||
| At January 1 | 395 | 222 | ||||||
| Charges | 291 | 215 | ||||||
| Payments | (245 | ) | (170 | ) | ||||
| Other movements and currency translation effects | 53 | 128 | ||||||
| At December 31 | 494 | 395 | ||||||
22 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.
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 2002 and 2003, 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) | ($) | |||||||||||||||||||
| Under option at January 1, 2002 | 20,401 | 54.10 | 65,012 | 7.30 | 3,616 | 17.89 | ||||||||||||||||||
| Granted | 13,792 | 59.71 | 39,210 | 8.45 | 1,567 | 28.36 | ||||||||||||||||||
| Exercised | (180 | ) | 47.12 | (796 | ) | 6.21 | (394 | ) | 14.45 | |||||||||||||||
| Expired | (632 | ) | 54.50 | (1,979 | ) | 7.53 | (12 | ) | 25.21 | |||||||||||||||
Under option at December 31, 2002b | 33,381 | 59.86 | 101,447 | 8.26 | 4,777 | 21.71 | ||||||||||||||||||
| Granted | 15,643 | 45.13 | 41,893 | 6.74 | 1,674 | 35.65 | ||||||||||||||||||
| Exercised | – | – | (192 | ) | 6.47 | (505 | ) | 22.88 | ||||||||||||||||
| Expired | (1,003 | ) | 64.03 | (2,813 | ) | 8.92 | (73 | ) | 26.03 | |||||||||||||||
Under option at December 31, 2003b | 48,021 | 60.09 | 140,335 | 8.44 | 5,873 | 29.43 | ||||||||||||||||||
| a | Unissued. |
| b | The underlying weighted average exercise prices for Royal Dutch and Shell Transport shares under option at December 31, 2003 were€47.64 (2002:€57.21) and £4.73 (2002: £5.14) respectively. |
The following tables provide further information about the options outstanding at December 31, 2003:
| Royal Dutch shares | ||||||||||||||||||||
| Options outstanding | Options exercisable | |||||||||||||||||||
| Weighted | ||||||||||||||||||||
| average | Weighted | Weighted | ||||||||||||||||||
| remaining | average | average | ||||||||||||||||||
| contractual | exercise | exercise | ||||||||||||||||||
| Number | life | price | Number | price | ||||||||||||||||
| Range of exercise prices | (thousands) | (years) | ($) | (thousands) | ($) | |||||||||||||||
| $40 to $45 | 6,849 | 9.1 | 42.24 | 49 | 41.33 | |||||||||||||||
| $45 to $50 | 8,791 | 9.2 | 47.24 | 7 | 47.98 | |||||||||||||||
| $50 to $55 | 10,820 | 6.9 | 53.44 | 6,530 | 52.71 | |||||||||||||||
| $55 to $60 | 660 | 6.4 | 56.43 | 647 | 56.45 | |||||||||||||||
| $60 to $65 | 5,272 | 6.4 | 60.93 | 3,347 | 61.03 | |||||||||||||||
| $70 to $75 | 149 | 7.8 | 71.18 | – | – | |||||||||||||||
| $75 to $80 | 12,180 | 7.3 | 77.19 | 1,891 | 75.10 | |||||||||||||||
| $85 to $90 | 3,300 | 7.2 | 88.95 | 79 | 87.06 | |||||||||||||||
| $40 to $90 | 48,021 | 7.7 | 60.09 | 12,550 | 58.66 | |||||||||||||||
| Shell Transport shares | ||||||||||||||||||||
| Options outstanding | Options exercisable | |||||||||||||||||||
| Weighted | ||||||||||||||||||||
| average | Weighted | Weighted | ||||||||||||||||||
| remaining | average | average | ||||||||||||||||||
| contractual | exercise | exercise | ||||||||||||||||||
| Number | life | price | Number | price | ||||||||||||||||
| Range of exercise prices | (thousands) | (years) | ($) | (thousands) | ($) | |||||||||||||||
| $6 to $7 | 37,324 | 7.3 | 6.51 | 11,279 | 6.47 | |||||||||||||||
| $7 to $8 | 23,225 | 7.3 | 7.32 | 7,131 | 7.83 | |||||||||||||||
| $9 to $10 | 67,256 | 7.1 | 9.44 | 11,630 | 9.00 | |||||||||||||||
| $10 to $11 | 12,530 | 7.1 | 10.91 | 65 | 10.31 | |||||||||||||||
| $6 to $11 | 140,335 | 7.2 | 8.44 | 30,105 | 7.78 | |||||||||||||||
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 2002 and 2003, 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 | ||||||||
| 2003 | 2002 | |||||||
| Under option at January 1 | 18,680 | 17,549 | ||||||
| Granted | 4,975 | 6,898 | ||||||
| Exercised | (707 | ) | (4,911 | ) | ||||
| Expired | (7,859 | ) | (856 | ) | ||||
| Under option at December 31 | 15,089 | 18,680 | ||||||
Prior to 2000, a Group company (interest 100%) had incentive compensation plans containing stock appreciation rights linked to the value of Royal Dutch shares. During 2003 512,481 of these stock appreciation rights were exercised leaving a balance of 8,261,633 at December 31, 2003.
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, 2003, 4,754 (2002: 3,310) Royal Dutch shares and 19,742 (2002: 14,578) 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
| 2003 | 2002 | 2001 | ||||||||||||||||||||||
| As restated | As restated | |||||||||||||||||||||||
| As reported | Pro forma | (see Note 2) | Pro forma | (see Note 2) | Pro forma | |||||||||||||||||||
| Group net income ($ million) | 12,496 | 12,219 | 9,722 | 9,519 | 10,350 | 10,241 | ||||||||||||||||||
| Basic earnings per share attributable to Royal Dutch ($) | 3.68 | 3.60 | 2.83 | 2.78 | 2.96 | 2.93 | ||||||||||||||||||
| Diluted earnings per share attributable to Royal Dutch ($) | 3.68 | 3.60 | 2.83 | 2.78 | 2.96 | 2.93 | ||||||||||||||||||
| Basic earnings per ADR attributable to Shell Transport ($) | 3.15 | 3.08 | 2.43 | 2.38 | 2.55 | 2.52 | ||||||||||||||||||
| Diluted earnings per ADR attributable to Shell Transport ($) | 3.15 | 3.08 | 2.43 | 2.38 | 2.54 | 2.52 | ||||||||||||||||||
The fair value of the Group’s 2003 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 2.9%, 3.3% and 4.1%; dividend yield of 4.0%, 4.6% and 4.0%; volatility of 31.6%, 32.2% and 34.5% 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, 2003 and 2002. In addition, 33,600 shares of Royal Dutch were held by Group companies at December 31, 2003 and 2002.
The carrying amount of these and all Parent Company shares held in connection with the stock-based compensation plans at December 31, 2003 is $3,428 million (2002: $2,797 million).
23 Decommissioning and restoration costs
| 2003 | $ million | |||||||||||
| Short-term | Long-term | Total | ||||||||||
| At January 1 | 71 | 3,528 | 3,599 | |||||||||
| Cumulative effect of change in accounting policy (see Note 2) | 108 | (102 | ) | 6 | ||||||||
| Liabilities incurred | – | 174 | 174 | |||||||||
| Liabilities settled | (106 | ) | (37 | ) | (143 | ) | ||||||
| Accretion expense | – | 49 | 49 | |||||||||
| Reclassifications and other movements | 12 | 12 | 24 | |||||||||
| Currency translation differences | 4 | 331 | 335 | |||||||||
| At December 31 | 89 | 3,955 | 4,044 | |||||||||
For the purposes of calculating provisions for decommissioning and restoration costs, estimated total ultimate liabilities of $7.5 billion at December 31, 2003 (2002: $5.2 billion) were used. Such estimates are subject to various regulatory and technological developments.
24 Information by geographical area and by industry segment
| $ million | ||||||||||||||||||||||||
| 2002 | 2001 | |||||||||||||||||||||||
| 2003 | As restated | As restated | ||||||||||||||||||||||
| Net | Fixed | Net | Fixed | Net | Fixed | |||||||||||||||||||
| proceeds | assets | proceeds | assets | proceeds | assets | |||||||||||||||||||
| Europe | 71,864 | 38,052 | 63,761 | 36,668 | 62,259 | 19,223 | ||||||||||||||||||
| Other Eastern Hemisphere | 38,494 | 33,651 | 33,322 | 28,558 | 31,866 | 26,267 | ||||||||||||||||||
| USA | 75,669 | 30,355 | 55,411 | 27,268 | 15,924 | 17,849 | ||||||||||||||||||
| Other Western Hemisphere | 15,701 | 13,165 | 14,107 | 11,976 | 15,312 | 9,881 | ||||||||||||||||||
| Total Group | 201,728 | 115,223 | 166,601 | 104,470 | 125,361 | 73,220 | ||||||||||||||||||
(b) Industry segment
| 2003 | $ million | ||||||||||||||||||||||||
| Exploration | |||||||||||||||||||||||||
| Total | and | Gas & | Oil | Corporate | |||||||||||||||||||||
| Group | Production | Power | Products | Chemicals | and Other | ||||||||||||||||||||
| Sales | |||||||||||||||||||||||||
| third parties | 201,728 | 12,481 | 7,398 | 162,161 | 18,843 | 845 | |||||||||||||||||||
| inter-segment | 20,244 | 850 | 3,416 | 1,974 | 29 | ||||||||||||||||||||
Net proceeds | 32,725 | 8,248 | 165,577 | 20,817 | 874 | ||||||||||||||||||||
| Operating profit/(loss) | |||||||||||||||||||||||||
| Group companies | 18,324 | 15,374 | 520 | 3,205 | (112 | ) | (663 | ) | |||||||||||||||||
| Group share of associated companies | 3,484 | 1,876 | 889 | 911 | (165 | ) | (27 | ) | |||||||||||||||||
| 21,808 | 17,250 | 1,409 | 4,116 | (277 | ) | (690 | ) | ||||||||||||||||||
| Interest and other income | 1,973 | 89 | 1,366 | 8 | (29 | ) | 539 | ||||||||||||||||||
| Interest expense | 1,381 | 1,381 | |||||||||||||||||||||||
| Currency exchange gains/(losses) | (222 | ) | (17 | ) | (23 | ) | (12 | ) | (14 | ) | (156 | ) | |||||||||||||
| Taxation | 9,572 | 8,472 | 463 | 1,252 | (111 | ) | (504 | ) | |||||||||||||||||
| Income applicable to minority interests | 365 | ||||||||||||||||||||||||
| Cumulative effect of a change in accounting principle, net of tax | 255 | 255 | |||||||||||||||||||||||
Net income | 12,496 | 9,105 | 2,289 | 2,860 | (209 | ) | (1,184 | ) | |||||||||||||||||
Total assets at December 31 | 168,091 | 62,504 | 19,084 | 65,254 | 15,420 | 5,829 | |||||||||||||||||||
Total liabilities at December 31 | (91,815 | ) | (46,365 | ) | (13,149 | ) | (43,078 | ) | (8,009 | ) | 18,786 | ||||||||||||||
Tangible fixed assets at December 31 | |||||||||||||||||||||||||
| Cost | 181,685 | 105,540 | 6,934 | 53,556 | 14,028 | 1,627 | |||||||||||||||||||
| Accumulated depreciation | (93,984 | ) | (55,652 | ) | (985 | ) | (28,784 | ) | (7,851 | ) | (712 | ) | |||||||||||||
Goodwill at December 31 | 2,675 | – | 184 | 2,455 | 23 | 13 | |||||||||||||||||||
Investments in associated companies at December 31 | 19,384 | 4,121 | 4,924 | 5,965 | 4,017 | 357 | |||||||||||||||||||
| Capital expenditure and new investments in associated companies | 13,235 | 8,276 | 1,511 | 2,406 | 599 | 443 | |||||||||||||||||||
Depreciation, depletion and amortisation charge | |||||||||||||||||||||||||
| Impairment | 1,375 | 697 | – | 331 | 220 | 127 | |||||||||||||||||||
| Other | 10,047 | 6,801 | 128 | 2,532 | 458 | 128 | |||||||||||||||||||
| 2002 (as restated) | $ million | ||||||||||||||||||||||||
| Exploration | |||||||||||||||||||||||||
| Total | and | Gas & | Oil | Corporate | |||||||||||||||||||||
| Group | Production | Power | Products | Chemicals | and Other | ||||||||||||||||||||
| Sales | |||||||||||||||||||||||||
third partiesa | 166,601 | 11,901 | 4,278 | 135,544 | 14,125 | 753 | |||||||||||||||||||
| inter-segment | 14,680 | 620 | 3,080 | 1,082 | 17 | ||||||||||||||||||||
Net proceedsa | 26,581 | 4,898 | 138,624 | 15,207 | 770 | ||||||||||||||||||||
| Operating profit/(loss) | |||||||||||||||||||||||||
| Group companies | 15,504 | 12,215 | 107 | 3,188 | 438 | (444 | ) | ||||||||||||||||||
| Group share of associated companies | 2,822 | 1,322 | 751 | 556 | 213 | (20 | ) | ||||||||||||||||||
| 18,326 | 13,537 | 858 | 3,744 | 651 | (464 | ) | |||||||||||||||||||
| Interest and other income | 758 | 98 | 118 | 14 | 3 | 525 | |||||||||||||||||||
| Interest expense | 1,364 | 1,364 | |||||||||||||||||||||||
| Currency exchange gains/(losses) | (23 | ) | (26 | ) | 6 | (64 | ) | (16 | ) | 77 | |||||||||||||||
| Taxation | 7,796 | 6,813 | 208 | 1,067 | 73 | (365 | ) | ||||||||||||||||||
| Income applicable to minority interests | 179 | ||||||||||||||||||||||||
Net income | 9,722 | 6,796 | 774 | 2,627 | 565 | (861 | ) | ||||||||||||||||||
Total assets at December 31 | 153,458 | 57,315 | 16,057 | 60,549 | 14,172 | 5,365 | |||||||||||||||||||
Total liabilities at December 31 | (89,432 | ) | (45,336 | ) | (12,223 | ) | (41,826 | ) | (7,903 | ) | 17,856 | ||||||||||||||
Tangible fixed assets at December 31 | |||||||||||||||||||||||||
| Cost | 157,499 | 93,333 | 47,689 | 12,010 | 2,843 | 1,624 | |||||||||||||||||||
| Accumulated depreciation | (78,812 | ) | (46,752 | ) | (23,926 | ) | (6,711 | ) | (763 | ) | (660 | ) | |||||||||||||
Goodwill at December 31 | 2,324 | – | 184 | 1,989 | 22 | 129 | |||||||||||||||||||
| Investments in associated companies at December 31 | 17,948 | 3,594 | 4,679 | 5,344 | 4,154 | 177 | |||||||||||||||||||
| Capital expenditure, acquisitions and new investments in associated companies | 23,651 | 13,155 | 952 | 7,968 | 998 | 578 | |||||||||||||||||||
Depreciation, depletion and amortisation charge | |||||||||||||||||||||||||
| Impairment | 197 | 33 | 4 | 111 | 29 | 20 | |||||||||||||||||||
| Other | 8,424 | 5,540 | 124 | 2,295 | 372 | 93 | |||||||||||||||||||
| 2001 (as restated) | $ million | ||||||||||||||||||||||||
| Exploration | |||||||||||||||||||||||||
| Total | and | Gas & | Oil | Corporate | |||||||||||||||||||||
| Group | Production | Power | Products | Chemicals | and Other | ||||||||||||||||||||
| Sales | |||||||||||||||||||||||||
third partiesa | 125,361 | 12,057 | 5,951 | 93,517 | 13,260 | 576 | |||||||||||||||||||
| inter-segment | 13,790 | 705 | 2,108 | 990 | 2 | ||||||||||||||||||||
Net proceedsa | 25,847 | 6,656 | 95,625 | 14,250 | 578 | ||||||||||||||||||||
| Operating profit/(loss) | |||||||||||||||||||||||||
| Group companies | 16,541 | 14,144 | 538 | 2,481 | (34 | ) | (588 | ) | |||||||||||||||||
| Group share of associated companies | 2,646 | 1,550 | 941 | 241 | (27 | ) | (59 | ) | |||||||||||||||||
| 19,187 | 15,694 | 1,479 | 2,722 | (61 | ) | (647 | ) | ||||||||||||||||||
| Interest and other income | 1,059 | 52 | 128 | (12 | ) | 2 | 889 | ||||||||||||||||||
| Interest expense | 1,133 | 1,133 | |||||||||||||||||||||||
| Currency exchange gains/(losses) | (30 | ) | (4 | ) | 4 | (50 | ) | (6 | ) | 26 | |||||||||||||||
| Taxation | 8,404 | 7,779 | 385 | 690 | (192 | ) | (258 | ) | |||||||||||||||||
| Income applicable to minority interests | 329 | ||||||||||||||||||||||||
Net income | 10,350 | 7,963 | 1,226 | 1,970 | 127 | (607 | ) | ||||||||||||||||||
Total assets at December 31 | 111,653 | 39,477 | 11,815 | 38,007 | 12,145 | 10,209 | |||||||||||||||||||
Total liabilities at December 31 | (51,933 | ) | (23,990 | ) | (7,277 | ) | (21,367 | ) | (6,383 | ) | 7,084 | ||||||||||||||
Tangible fixed assets at December 31 | |||||||||||||||||||||||||
| Cost | 117,543 | 68,572 | 34,577 | 10,782 | 2,275 | 1,337 | |||||||||||||||||||
| Accumulated depreciation | (66,616 | ) | (38,819 | ) | (20,449 | ) | (6,064 | ) | (679 | ) | (605 | ) | |||||||||||||
Goodwill at December 31 | 365 | – | 189 | 154 | 22 | – | |||||||||||||||||||
Investments in associated companies at December 31 | 18,332 | 3,463 | 4,614 | 6,384 | 3,740 | 131 | |||||||||||||||||||
| Capital expenditure and new investments in associated companies | 10,672 | 7,136 | 908 | 1,527 | 760 | 341 | |||||||||||||||||||
Depreciation, depletion and amortisation charge | |||||||||||||||||||||||||
| Impairment | 88 | 8 | (8 | ) | (4 | ) | 40 | 52 | |||||||||||||||||
| Other | 6,113 | 3,910 | 114 | 1,621 | 364 | 104 | |||||||||||||||||||
| a | Certain prior period amounts have been reclassified, resulting in a reduction in sales proceeds and a corresponding reduction in cost of sales following the implementation of US accounting guidance EITF Issue No. 02-03, see Note 3. |
25 Oil and gas exploration and production activities
| $ million | ||||||||||||
| 2002a | 2001a | |||||||||||
| 2003 | As restated | As restated | ||||||||||
Cost | ||||||||||||
| Proved properties | 94,069 | b | 83,964 | 63,115 | ||||||||
| Unproved properties | 5,400 | 4,768 | 2,430 | |||||||||
| Support equipment and facilities | 3,128 | 2,352 | 1,718 | |||||||||
| 102,597 | 91,084 | 67,263 | ||||||||||
Depreciation | ||||||||||||
| Proved properties | 53,254 | b | 45,201 | 37,555 | ||||||||
| Unproved properties | 824 | 325 | 212 | |||||||||
| Support equipment and facilities | 1,443 | 1,224 | 1,051 | |||||||||
| 55,521 | 46,750 | 38,818 | ||||||||||
Net capitalised costs | 47,076 | 44,334 | 28,445 | |||||||||
| Oil sands: net capitalised costs | 2,811 | 2,246 | 1,309 | |||||||||
| a | Includes the impact of reclassifications between asset classes. | |
| b | Includes capitalised asset retirement costs. |
The Group share of associated companies’ net capitalised costs was $3,801 million at December 31, 2003 (2002: $3,183 million; 2001: $2,928 million).
(b) Costs incurred
| 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 (as restated) | $ 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 | ||||||||||||||||||||||
Developmentc | |||||||||||||||||||||||||||||
| Excluding oil sands | 1,605 | 1,370 | 442 | 685 | 1,465 | 407 | 5,974 | ||||||||||||||||||||||
| Oil sands | 931 | 931 | |||||||||||||||||||||||||||
| 2001 (as restated) | $ million | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | ||||||||||||||||||||||||||||
| Middle | |||||||||||||||||||||||||||||
| East, | |||||||||||||||||||||||||||||
| Asia | Russia, | ||||||||||||||||||||||||||||
| Europe | Africa | Pacific | CIS | USA | Other | Total | |||||||||||||||||||||||
| Acquisition of properties | |||||||||||||||||||||||||||||
| Proved | 5 | – | 839 | 82 | 290 | 9 | 1,225 | ||||||||||||||||||||||
| Unproved | 23 | 61 | 162 | 91 | 157 | (19 | ) | 475 | |||||||||||||||||||||
| Exploration | 114 | 163 | 119 | 203 | 303 | 203 | 1,105 | ||||||||||||||||||||||
Developmentc | |||||||||||||||||||||||||||||
| Excluding oil sands | 852 | 992 | 449 | 289 | 1,214 | 230 | 4,026 | ||||||||||||||||||||||
| Oil sands | 847 | 847 | |||||||||||||||||||||||||||
| a | These amounts do not include Sakhalin II project costs of $384 million reported in the Gas & Power segment. |
| b | Includes capitalised asset retirement costs. |
| c | Includes the impact of reclassifications between geographical regions and cost categories. |
The Group share of associated companies’ costs incurred was $417 million in 2003 (2002: $551 million; 2001: $415 million).
(c) Earnings
| 2003 | $ million | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | ||||||||||||||||||||||||||||
| Middle | |||||||||||||||||||||||||||||
| East, | |||||||||||||||||||||||||||||
| Asia | Russia, | ||||||||||||||||||||||||||||
| Europe | Africa | Pacific | CIS | USA | Other | Total | |||||||||||||||||||||||
| Sales: | |||||||||||||||||||||||||||||
| Third parties | 5,386 | 129 | 1,021 | 1,685 | 1,903 | 1,115 | 11,239 | ||||||||||||||||||||||
| Intra-group | 5,873 | 3,888 | 1,179 | 3,713 | 4,480 | 713 | 19,846 | ||||||||||||||||||||||
| Net proceeds | 11,259 | 4,017 | 2,200 | 5,398 | 6,383 | 1,828 | 31,085 | ||||||||||||||||||||||
Production costsa | 1,881 | 1,104 | 484 | 1,727 | 625 | 373 | 6,194 | ||||||||||||||||||||||
| Exploration expense | 189 | 231 | 99 | 122 | 275 | 143 | 1,059 | ||||||||||||||||||||||
| Depreciation, depletion and amortisation | 3,519 | 418 | 559 | 596 | 1,634 | 653 | 7,379 | ||||||||||||||||||||||
| Other income/(costs) | (557 | ) | (207 | ) | 230 | (131 | ) | 30 | (241 | ) | (876 | ) | |||||||||||||||||
| Earnings before taxation | 5,113 | 2,057 | 1,288 | 2,822 | 3,879 | 418 | 15,577 | ||||||||||||||||||||||
| Taxation | 1,784 | 1,451 | 262 | 2,239 | 1,501 | 199 | 7,436 | ||||||||||||||||||||||
| Earnings from operations | 3,329 | 606 | 1,026 | 583 | 2,378 | 219 | 8,141 | ||||||||||||||||||||||
| Earnings from oil sands | (101 | ) | (101 | ) | |||||||||||||||||||||||||
| 2002 (as restated) | $ million | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | ||||||||||||||||||||||||||||
| Middle | |||||||||||||||||||||||||||||
| East, | |||||||||||||||||||||||||||||
| Asia | Russia, | ||||||||||||||||||||||||||||
| Europe | Africa | Pacific | CIS | USA | Other | Total | |||||||||||||||||||||||
| Sales: | |||||||||||||||||||||||||||||
| Third parties | 5,472 | 73 | 969 | 1,764 | 1,997 | 892 | 11,167 | ||||||||||||||||||||||
| Intra-group | 4,572 | 2,538 | 1,186 | 3,087 | 2,863 | 433 | 14,679 | ||||||||||||||||||||||
| Net proceeds | 10,044 | 2,611 | 2,155 | 4,851 | 4,860 | 1,325 | 25,846 | ||||||||||||||||||||||
Production costsa | 1,826 | 754 | 477 | 1,515 | 589 | 298 | 5,459 | ||||||||||||||||||||||
| Exploration expense | 177 | 219 | 62 | 82 | 249 | 208 | 997 | ||||||||||||||||||||||
| Depreciation, depletion and amortisation | 2,233 | 374 | 593 | 794 | 1,351 | 226 | 5,571 | ||||||||||||||||||||||
| Other income/(costs) | (604 | ) | (162 | ) | 149 | (358 | ) | (330 | ) | (227 | ) | (1,532 | ) | ||||||||||||||||
| Earnings before taxation | 5,204 | 1,102 | 1,172 | 2,102 | 2,341 | 366 | 12,287 | ||||||||||||||||||||||
| Taxation | 2,365 | 799 | 332 | 1,638 | 791 | 106 | 6,031 | ||||||||||||||||||||||
| Earnings from operations | 2,839 | 303 | 840 | 464 | 1,550 | 260 | 6,256 | ||||||||||||||||||||||
| Earnings from oil sands | (3 | ) | (3 | ) | |||||||||||||||||||||||||
| 2001 (as restated) | $ million | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | ||||||||||||||||||||||||||||
| Middle | |||||||||||||||||||||||||||||
| East, | |||||||||||||||||||||||||||||
| Asia | Russia, | ||||||||||||||||||||||||||||
| Europe | Africa | Pacific | CIS | USA | Other | Total | |||||||||||||||||||||||
| Sales: | |||||||||||||||||||||||||||||
| Third parties | 4,971 | 98 | 1,013 | 1,322 | 2,771 | 836 | 11,011 | ||||||||||||||||||||||
| Intra-group | 3,723 | 2,759 | 1,171 | 3,201 | 2,306 | 630 | 13,790 | ||||||||||||||||||||||
| Net proceeds | 8,694 | 2,857 | 2,184 | 4,523 | 5,077 | 1,466 | 24,801 | ||||||||||||||||||||||
Production costsa | 1,276 | 820 | 406 | 1,362 | 496 | 268 | 4,628 | ||||||||||||||||||||||
| Exploration expense | 98 | 109 | 121 | 125 | 289 | 143 | 885 | ||||||||||||||||||||||
| Depreciation, depletion and amortisation | 1,279 | 317 | 475 | 518 | 1,072 | 257 | 3,918 | ||||||||||||||||||||||
| Other income/(costs) | (395 | ) | (97 | ) | (58 | ) | (74 | ) | (305 | ) | (247 | ) | (1,176 | ) | |||||||||||||||
| Earnings before taxation | 5,646 | 1,514 | 1,124 | 2,444 | 2,915 | 551 | 14,194 | ||||||||||||||||||||||
| Taxation | 2,476 | 1,034 | 404 | 1,849 | 1,028 | 196 | 6,987 | ||||||||||||||||||||||
| Earnings from operations | 3,170 | 480 | 720 | 595 | 1,887 | 355 | 7,207 | ||||||||||||||||||||||
| Earnings from oil sands | – | – | |||||||||||||||||||||||||||
| a | Includes certain royalties paid in cash amounting to $1,700 million in 2003 (2002: $1,449 million; 2001: $1,364 million). |
The Group share of associated companies’ earnings was $810 million in 2003 (2002: $543 million; 2001: $757 million) mainly in the USA $424 million (2002: $330 million; 2001: $303 million) and Asia Pacific $354 million (2002: $171 million; 2001: $428 million).
26 Auditors’ remuneration
| Remuneration of KPMG and | ||||||||||||
| PricewaterhouseCoopers LLP | $ million | |||||||||||
| 2002 | ||||||||||||
| 2003 | As restated | 2001 | ||||||||||
| Audit fees | 32 | 27 | 18 | |||||||||
Audit-related feesa | 11 | 17 | 12 | |||||||||
Tax feesb | 7 | 6 | 3 | |||||||||
| Fees for all other non-audit services | 6 | 12 | 17 | |||||||||
| 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. |
27 Contingencies and litigation
| $ billion | ||||
| In respect of debt | 1.8 | |||
| In respect of customs duties | 0.7 | |||
| Other | 0.9 | |||
| 3.4 | ||||
The $1.8 billion of guarantees in respect of debt relate to project finance, $1.2 billion of which expires by 2005. 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 other oil companies, 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 among other claims, product liability theories, and seek to recover damages from SOC and others, including clean-up costs. As of December 31, 2003, there were approximately 60 pending suits by such plaintiffs that asserted claims against SOC, which cases involve a number of defendants (including a number of other major energy and refining companies). A majority of these cases do not specify the damages sought and, in the cases where damages are specified, management of the Group believes that the amount of damages claimed is speculative and, therefore, not indicative of the range of possible outcomes. Management of the Group cannot currently predict the manner and timing of the resolution of pending oxygenate-related matters and is currently unable to estimate the range of possible additional losses or minimum losses from such matters because of the preliminary stage of the proceedings, the number of defendants involved in these cases and the related issue of determining the allocation of potential liability among defendants. However, based on the facts and circumstances currently known, management of the Group does not currently believe that the outcome of the oxygenate-related litigation pending as of December 31, 2003 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 dollar judgment in favour of 466 plaintiffs was rendered in 2002 by a Nicaraguan court against SOC and others, 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 (based on a predetermined formula) of an amount denominated in Nicaraguan cordobas is made into the Nicaraguan courts, the claims would be submitted to the US courts. SOC chose not to make this deposit and thereafter judgment was entered without giving effect to the provision of Special Law 364 that submits the matter to the US courts. Special Law 364 requires each defendant in a case to post a deposit equal to $100 thousand plus 300 million Nicaraguan cordobas. Since SOC was a defendant in one case, it was required to post a deposit equal to between $19 and $20 million ($100 thousand plus 300 million Nicaraguan cordobas at an exchange rate of between 15 and 16 cordobas per dollar). 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.
In 2003, an attempt by the plaintiffs to enforce the Nicaraguan judgment described above in the United States 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. SOC has also filed a declaratory judgment seeking ultimate adjudication of the non-enforceability of this Nicaraguan judgment in the U.S. District Court for the Central District of California. Subsequent to the year ending December 31, 2003, an additional Nicaraguan judgment was entered in the amount of $83 million in favour of 58 plaintiffs under facts and circumstances almost identical to those relating to the judgment described above. It is the opinion of management of the Group that these judgments do not meet due process standards in the United States and are unenforceable as a matter of law. No reserves have been established for these judgments.
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. Reserves 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, 2003, is not material. Management of the Group cannot currently predict when or how all polybutylene matters will be finally resolved.
Group companies are subject to a number of other loss contingencies arising out of litigation and claims brought by governmental and private parties. While it is not feasible to predict the outcome of pending litigation and claims with certainty, the management of the Group believes that any reasonably possible additional loss related to such matters, in excess of provisions made, would have no material adverse effect on the Group’s financial statements or cash flows as of December 31, 2003.
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 environmental protection, 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.
Subsequent to the year ended December 31, 2003, in connection with the recategorisation of certain hydrocarbon reserves announced on January 9, 2004, a number of shareholder class action complaints were filed in the United States District Court of New Jersey, the United States Securities and Exchange Commission has issued a formal order of private investigation, the United States Department of Justice has commenced a criminal investigation, the UK Financial Services Authority has served formal notice of investigation under the Financial Services and Markets Act 2000 and Euronext Amsterdam and the Dutch Authority Financial Markets 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, is currently unable to estimate the range of possible losses from such matters and does not currently believe the resolution of these pending matters 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.
28 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 | ||||||||||||||||
| 2003 | 2002 | |||||||||||||||
| Contract/ | Estimated | Contract/ | Estimated | |||||||||||||
| notional | fair | notional | fair value | |||||||||||||
| amount | value | amount | As restated | |||||||||||||
| Interest rate swaps/forward rate agreements | 4,322 | 121 | 5,557 | 169 | ||||||||||||
| Forward exchange contracts and currency swaps/options | 18,874 | 165 | 16,922 | (88 | ) | |||||||||||
| Commodity swaps, options and futures | 65,800 | 61 | 56,642 | 55 | ||||||||||||
| 88,996 | 347 | 79,121 | 136 | |||||||||||||
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.
29 Division of Group net assets between the Parent Companies and movements therein
The division of Group net assets and movements therein, including Group net income in accordance with Note 1, is as follows:
| Royal | Shell | |||||||||||
| Total | Dutch (60%) | Transport (40%) | ||||||||||
| At January 1, 2001 | 57,669 | 34,601 | 23,068 | |||||||||
| Movements during the year 2001 | ||||||||||||
| Group net income | 10,350 | 6,210 | 4,140 | |||||||||
| less: distributions to Parent Companies | (9,163 | ) | (5,498 | ) | (3,665 | ) | ||||||
| Undistributed net income | 1,187 | 712 | 475 | |||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (642 | ) | (385 | ) | (257 | ) | ||||||
| Other comprehensive income (Note 5) | (1,970 | ) | (1,182 | ) | (788 | ) | ||||||
| At December 31, 2001 | 56,244 | 33,746 | 22,498 | |||||||||
| Movements during the year 2002 | ||||||||||||
| Group net income | 9,722 | 5,833 | 3,889 | |||||||||
| less: distributions to Parent Companies | (5,435 | ) | (3,261 | ) | (2,174 | ) | ||||||
| Undistributed net income | 4,287 | 2,572 | 1,715 | |||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (844 | ) | (507 | ) | (337 | ) | ||||||
| Other comprehensive income (Note 5) | 757 | 455 | 302 | |||||||||
| At December 31, 2002 | 60,444 | 36,266 | 24,178 | |||||||||
| Movements during the year 2003 | ||||||||||||
| Group net income | 12,496 | 7,498 | 4,998 | |||||||||
| less: distributions to Parent Companies | (5,660 | ) | (3,396 | ) | (2,264 | ) | ||||||
| Undistributed net income | 6,836 | 4,102 | 2,734 | |||||||||
| 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 (Note 5) | 6,200 | 3,720 | 2,480 | |||||||||
At December 31, 2003 | 72,848 | 43,709 | 29,139 | |||||||||
The above table is based on the Group’s US GAAP results. See the “Reconciliation between US GAAP and Netherlands GAAP” table in Note 31 for the impact of differences between US GAAP and Netherlands GAAP on the Group’s net assets.
Restatement of previously issued Financial Statements
| Royal | Shell | |||||||||||||||||||||||||||||||||||
| Dutch (60%) | Transport (40%) | |||||||||||||||||||||||||||||||||||
| Previously reported | Adjustments | As restated | Previously reported | Adjustments | As restated | Previously reported | Adjustments | As restated | ||||||||||||||||||||||||||||
| At January 1, 2001 | 57,086 | 583 | 57,669 | 34,252 | 349 | 34,601 | 22,834 | 234 | 23,068 | |||||||||||||||||||||||||||
| Movements during the year 2001 | ||||||||||||||||||||||||||||||||||||
| Group net income | 10,852 | (502 | ) | 10,350 | 6,511 | (301 | ) | 6,210 | 4,341 | (201 | ) | 4,140 | ||||||||||||||||||||||||
| Less: distributions to Parent Companies | (9,163 | ) | — | (9,163 | ) | (5,498 | ) | — | (5,498 | ) | (3,665 | ) | — | (3,665 | ) | |||||||||||||||||||||
| Undistributed net income | 1,689 | (502 | ) | 1,187 | 1,013 | (301 | ) | 712 | 676 | (201 | ) | 475 | ||||||||||||||||||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (642 | ) | — | (642 | ) | (385 | ) | — | (385 | ) | (257 | ) | — | (257 | ) | |||||||||||||||||||||
| Other comprehensive income (Note 5) | (1,973 | ) | 3 | (1,970 | ) | (1,184 | ) | 2 | (1,182 | ) | (789 | ) | 1 | (788 | ) | |||||||||||||||||||||
| At December 31, 2001 | 56,160 | 84 | 56,244 | 33,696 | 50 | 33,746 | 22,464 | 34 | 22,498 | |||||||||||||||||||||||||||
| Movements during the year 2002 | ||||||||||||||||||||||||||||||||||||
| Group net income | 9,419 | 303 | 9,722 | 5,651 | 182 | 5,833 | 3,768 | 121 | 3,889 | |||||||||||||||||||||||||||
| Less: distributions to Parent Companies | (5,435 | ) | — | (5,435 | ) | (3,261 | ) | — | (3,261 | ) | (2,174 | ) | — | (2,174 | ) | |||||||||||||||||||||
| Undistributed net income | 3,984 | 303 | 4,287 | 2,390 | 182 | 2,572 | 1,594 | 121 | 1,715 | |||||||||||||||||||||||||||
| Movement in Parent Companies’ shares held by Group companies net of dividends received | (844 | ) | — | (844 | ) | (507 | ) | — | (507 | ) | (337 | ) | — | (337 | ) | |||||||||||||||||||||
| Other comprehensive income (Note 5) | 764 | (7 | ) | 757 | 459 | (4 | ) | 455 | 305 | (3 | ) | 302 | ||||||||||||||||||||||||
| At December 31, 2002 | 60,064 | 380 | 60,444 | 36,038 | 228 | 36,266 | 24,026 | 152 | 24,178 | |||||||||||||||||||||||||||
Netherlands GAAP Financial Statements
| Statement of Income | $ million | |||||||||||||||
| 2002 | 2001 | |||||||||||||||
| Note | 2003 | As restated | As restated | |||||||||||||
| Sales proceeds | 268,892 | 222,768 | 167,431 | |||||||||||||
| Sales taxes, excise duties and similar levies | 67,164 | 56,167 | 42,070 | |||||||||||||
Net proceeds | 201,728 | 166,601 | 125,361 | |||||||||||||
| Cost of sales | 167,667 | 138,117 | 98,381 | |||||||||||||
Gross profit | 34,061 | 28,484 | 26,980 | |||||||||||||
| Selling and distribution expenses | 11,941 | 9,954 | 7,898 | |||||||||||||
| Administrative expenses | 1,903 | 1,601 | 1,244 | |||||||||||||
| Exploration | 1,476 | 1,073 | 910 | |||||||||||||
| Research and development | 584 | 472 | 387 | |||||||||||||
| Operating profit of Group companies | 18,157 | 15,384 | 16,541 | |||||||||||||
| Share of operating profit of associated companies | 6 | 3,484 | 2,822 | 2,646 | ||||||||||||
Operating profit | 21,641 | 18,206 | 19,187 | |||||||||||||
| Interest and other income | 7 | 1,973 | 758 | 1,059 | ||||||||||||
| Interest expense | 8 | 1,381 | 1,364 | 1,133 | ||||||||||||
| Currency exchange gains/(losses) | (222 | ) | (23 | ) | (30 | ) | ||||||||||
Income before taxation | 22,011 | 17,577 | 19,083 | |||||||||||||
| Taxation | 9 | 9,572 | 7,796 | 8,404 | ||||||||||||
| Income after taxation | 12,439 | 9,781 | 10,679 | |||||||||||||
| Income applicable to minority interests | 365 | 179 | 329 | |||||||||||||
Net income | 12,074 | 9,602 | 10,350 | |||||||||||||
| Statement of Comprehensive Income and Parent Companies’ interest in Group net assets | $ million | ||||||||||||||||
| 2002 | 2001 | ||||||||||||||||
| Note | 2003 | As restated | As restated | ||||||||||||||
Net income | 35 | 12,074 | 9,602 | 10,350 | |||||||||||||
| Other comprehensive income, net of tax: | 5 | ||||||||||||||||
| currency translation differences | 19 | 5,102 | 2,432 | (1,686 | ) | ||||||||||||
| unrealised gains/(losses) on securities | 689 | 25 | (143 | ) | |||||||||||||
| unrealised gains/(losses) on cash flow hedges | 51 | (225 | ) | (14 | ) | ||||||||||||
| minimum pension liability adjustments | 358 | (1,475 | ) | (127 | ) | ||||||||||||
Comprehensive income | 18,274 | 10,359 | 8,380 | ||||||||||||||
| Distributions to Parent Companies | 35 | (5,660 | ) | (5,435 | ) | (9,163 | ) | ||||||||||
| Increase in Parent Companies’ shares held, net of dividends received | 22 | (631 | ) | (844 | ) | (642 | ) | ||||||||||
| Loss on sale of Parent Companies’ shares | (1 | ) | – | – | |||||||||||||
| Parent Companies’ interest in Group net assets: | |||||||||||||||||
| At January 1 | 60,324 | 56,244 | 57,669 | ||||||||||||||
| Cumulative effect of change in accounting policy | 255 | – | – | ||||||||||||||
| At January 1 after cumulative effect of change | 60,579 | 56,244 | 57,669 | ||||||||||||||
Parent Companies’ interest in Group net assets at December 31 | 35 | 72,561 | 60,324 | 56,244 | |||||||||||||
| Statement of Assets and Liabilities | $ million | |||||||||||||
| Dec 31, | ||||||||||||||
| Dec 31, | 2002 | |||||||||||||
| Note | 2003 | As restated | ||||||||||||
Fixed assets | ||||||||||||||
| Tangible assets | 32 | 87,701 | 81,757 | |||||||||||
| Intangible assets | 32 | 4,448 | 4,576 | |||||||||||
| Investments: | ||||||||||||||
| associated companies | 6 | 19,384 | 17,948 | |||||||||||
| securities | 14 | 2,317 | 1,719 | |||||||||||
| other | 1,086 | 1,420 | ||||||||||||
Total fixed assets | 114,936 | 107,420 | ||||||||||||
Other long-term assets | 11 | 9,257 | 7,333 | |||||||||||
Current assets | ||||||||||||||
| Inventories | 12 | 12,690 | 11,338 | |||||||||||
| Accounts receivable | 13 | 28,969 | 28,761 | |||||||||||
| Cash and cash equivalents | 14 | 1,952 | 1,556 | |||||||||||
Total current assets | 43,611 | 41,655 | ||||||||||||
Current liabilities:amounts due within one year | ||||||||||||||
| Short-term debt | 15 | 11,027 | 12,874 | |||||||||||
| Accounts payable and accrued liabilities | 17 | 32,347 | 32,189 | |||||||||||
| Taxes payable | 9 | 5,927 | 4,985 | |||||||||||
| Dividends payable to Parent Companies | 5,123 | 5,153 | ||||||||||||
Total current liabilities | 54,424 | 55,201 | ||||||||||||
Net current assets/(liabilities) | (10,813 | ) | (13,546 | ) | ||||||||||
Total assets less current liabilities | 113,380 | 101,207 | ||||||||||||
Long-term liabilities:amounts due after more than one year | ||||||||||||||
| Long-term debt | 33 | 9,100 | 9,887 | |||||||||||
| Other | 18 | 6,054 | 6,174 | |||||||||||
| 15,154 | 16,061 | |||||||||||||
Provisions | ||||||||||||||
| Deferred taxation | 9 | 13,355 | 12,696 | |||||||||||
| Pensions and similar obligations | 20 | 4,927 | 5,016 | |||||||||||
| Decommissioning and restoration costs | 23 | 3,955 | 3,528 | |||||||||||
| 22,237 | 21,240 | |||||||||||||
Group net assets before minority interests | 75,989 | 63,906 | ||||||||||||
| Minority interests | 3,428 | 3,582 | ||||||||||||
Net assets | 72,561 | 60,324 | ||||||||||||
Statement of Cash Flows
Notes to the Netherlands GAAP Financial Statements
30 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 below), 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, commencing in 2002, goodwill is no longer amortised but instead 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, 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; and |
| (iii) | long-term commitments: Under US GAAP, a change in accounting for certain power generation contracts (“tolling agreements”) and lease contracts was made in 2003, due to the implementation of FIN 46, as revised, “Consolidation of Variable Interest Entities” (FIN 46-R), as described in Note 3. Implementation did not have any effect on net income, but resulted in an increase in the Group’s tangible fixed assets and debt of $3.4 billion as of September 30, 2003. Under Netherlands GAAP, these commitments were accounted for in 2003 and prior years as capital leases upon inception, which is comparable with the accounting required under FIN 46-R. The Group’s balance sheet under Netherlands GAAP as of December 31, 2002 includes tangible fixed assets and debt of $3.1 billion relating to such agreements. |
31 Changes in accounting policies and restatement of comparative data
| (i) | the accounting for certain inventories in North America under the LIFO method, which in combination with the adoption of FIFO as the basis for accounting of the Group’s inventories in the rest of the world is not an acceptable method under Netherlands GAAP (note that the Group has also made a change in accounting policy under US GAAP in 2003 to eliminate the use of the LIFO method – see Note 2). Net income for 2002 has increased by $511 million (2001: decreased by $446 million). Net assets at December 31, 2002 have increased by $850 million; |
| (ii) | the failure to amortise goodwill, which is required under Netherlands GAAP. Net income for 2002, and net assets at December 31, 2002, have decreased by $120 million. There is no impact for 2001; and |
| (iii) | the failure to include certain assets and debt, relating principally to power generation contracts (“tolling agreements”) and lease contracts, in the Group’s balance sheet, as required under Netherlands GAAP (note that the Group has also made a change in accounting policy under US GAAP in 2003 to include these amounts in its balance sheet – see Note 2). There is no impact on prior period net income or net assets. |
The restatement of the Financial Statements also gives effect to changes in accounting policy relating to exploration costs and certain gas contracts, as discussed in Note 2 as corrections under US GAAP. This change aligns the Group accounting policy under Netherlands GAAP with oil and gas specific accounting standards applicable under US GAAP. The effect of the change for exploration costs is a reduction in previously reported net income for 2002 of $61 million (2001: $14 million), and a reduction in previously reported net assets at December 31, 2002 of $155 million. The effect of the change for certain gas contracts is a reduction in previously reported net income for 2002 and net assets at December 31, 2002 of $39 million.
In addition, errors in the depreciation, depletion and amortisation charge presented in previous Financial Statements, arising as a result of the overstatement of proved reserves as corrected by the Reserves Restatement, have been adjusted in the Netherlands GAAP financial statements through a restatement of the comparative results for the years ended December 31, 2002 and 2001.
Quantitative information concerning the effect of the above changes in accounting policies and adjustments is set forth in the tables below and additional information is contained in Note 2 on pages G5 to G7.
| Statement of Income | |||||||||||||||||||||||||||||||||
| 2002 | |||||||||||||||||||||||||||||||||
| Restated | |||||||||||||||||||||||||||||||||
| prior to | |||||||||||||||||||||||||||||||||
| As previously | Reserves | policy | Exploration | Gas | As | ||||||||||||||||||||||||||||
| reported | restatement | Inventories | Goodwill | elections | costs | contracts | restated | ||||||||||||||||||||||||||
| Net proceeds | 166,717 | a | (52 | ) | – | – | 166,665 | – | (64 | ) | 166,601 | ||||||||||||||||||||||
| Cost of sales | 138,500 | a | 114 | (617 | ) | 120 | 138,117 | – | – | 138,117 | |||||||||||||||||||||||
| Exploration | 991 | – | – | – | 991 | 82 | – | 1,073 | |||||||||||||||||||||||||
| Other operating expenses | 12,027 | – | – | – | 12,027 | – | – | 12,027 | |||||||||||||||||||||||||
| Share of operating profit of associated companies | 2,624 | – | 198 | – | 2,822 | – | – | 2,822 | |||||||||||||||||||||||||
Operating profit | 17,823 | (166 | ) | 815 | (120 | ) | 18,352 | (82 | ) | (64 | ) | 18,206 | |||||||||||||||||||||
| Net interest expense and currency exchange gains/ losses | 629 | – | – | – | 629 | – | – | 629 | |||||||||||||||||||||||||
Income before taxation | 17,194 | (166 | ) | 815 | (120 | ) | 17,723 | (82 | ) | (64 | ) | 17,577 | |||||||||||||||||||||
| Taxation | 7,617 | (65 | ) | 290 | – | 7,842 | (21 | ) | (25 | ) | 7,796 | ||||||||||||||||||||||
| Income applicable to minority interests | 158 | 7 | 14 | – | 179 | – | – | 179 | |||||||||||||||||||||||||
Net income | 9,419 | (108 | ) | 511 | (120 | ) | 9,702 | (61 | ) | (39 | ) | 9,602 | |||||||||||||||||||||
[Additional columns below]
[Continued from above table, first column(s) repeated]
| Statement of Income | $ million | ||||||||||||||||||||||||
| 2001 | |||||||||||||||||||||||||
| Restated | |||||||||||||||||||||||||
| prior to | |||||||||||||||||||||||||
| As previously | Reserves | policy | Exploration | As | |||||||||||||||||||||
| reported | restatement | Inventories | elections | costs | restated | ||||||||||||||||||||
| Net proceeds | 125,441 | a | (80 | ) | – | 125,361 | – | 125,361 | |||||||||||||||||
| Cost of sales | 98,069 | a | 4 | 308 | 98,381 | – | 98,381 | ||||||||||||||||||
| Exploration | 882 | 7 | – | 889 | 21 | 910 | |||||||||||||||||||
| Other operating expenses | 9,529 | – | – | 9,529 | – | 9,529 | |||||||||||||||||||
| Share of operating profit of associated companies | 3,041 | 18 | (413 | ) | 2,646 | – | 2,646 | ||||||||||||||||||
Operating profit | 20,002 | (73 | ) | (721 | ) | 19,208 | (21 | ) | 19,187 | ||||||||||||||||
| Net interest expense and currency exchange gains/ losses | 104 | – | – | 104 | – | 104 | |||||||||||||||||||
Income before taxation | 19,898 | (73 | ) | (721 | ) | 19,104 | (21 | ) | 19,083 | ||||||||||||||||
| Taxation | 8,694 | (27 | ) | (256 | ) | 8,411 | (7 | ) | 8,404 | ||||||||||||||||
| Income applicable to minority interests | 352 | (4 | ) | (19 | ) | 329 | – | 329 | |||||||||||||||||
Net income | 10,852 | (42 | ) | (446 | ) | 10,364 | (14 | ) | 10,350 | ||||||||||||||||
| a | Including the effect of reclassification of certain amounts following implementation of US accounting guidance EITF Issue No. 02–03 (see Note 3), which had no impact on the net income. |
| Statement of Assets and Liabilities | $ million | ||||||||||||||||||||||||||||||||||||
| December 31, 2002 | |||||||||||||||||||||||||||||||||||||
| Restated | |||||||||||||||||||||||||||||||||||||
| prior to | |||||||||||||||||||||||||||||||||||||
| As previously | Reserves | Long-term | policy | Exploration | Gas | As | |||||||||||||||||||||||||||||||
| reported | restatement | Inventories | Goodwill | commitments | elections | costs | contracts | restated | |||||||||||||||||||||||||||||
| Fixed assets | |||||||||||||||||||||||||||||||||||||
| Tangible assets | 79,390 | (467 | ) | – | – | 3,070 | 81,993 | (236 | ) | – | 81,757 | ||||||||||||||||||||||||||
| Intangible assets | 4,696 | – | – | (120 | ) | – | 4,576 | – | – | 4,576 | |||||||||||||||||||||||||||
| Investments | 20,760 | 2 | 325 | – | – | 21,087 | – | – | 21,087 | ||||||||||||||||||||||||||||
| Other long-term assets | 7,299 | – | – | – | – | 7,299 | – | 34 | 7,333 | ||||||||||||||||||||||||||||
| Inventories | 10,298 | – | 1,040 | – | – | 11,338 | – | – | 11,338 | ||||||||||||||||||||||||||||
| Other current assets | 30,248 | – | – | – | – | 30,248 | – | 69 | 30,317 | ||||||||||||||||||||||||||||
| Current liabilities | 55,115 | – | – | – | – | 55,115 | – | 86 | 55,201 | ||||||||||||||||||||||||||||
| Long-term liabilities | |||||||||||||||||||||||||||||||||||||
| Long-term debt | 6,817 | – | – | – | 3,070 | 6,817 | – | – | 9,887 | ||||||||||||||||||||||||||||
| Other | 6,118 | – | – | – | – | 9,188 | – | 56 | 6,174 | ||||||||||||||||||||||||||||
| Provisions | |||||||||||||||||||||||||||||||||||||
| Deferred taxation | 12,471 | (186 | ) | 492 | – | – | 12,777 | (81 | ) | – | 12,696 | ||||||||||||||||||||||||||
| Pensions and decommissioning | 8,544 | – | – | – | – | 8,544 | – | – | 8,544 | ||||||||||||||||||||||||||||
| Minority interests | 3,562 | (3 | ) | 23 | – | – | 3,582 | – | – | 3,582 | |||||||||||||||||||||||||||
Net assets | 60,064 | (276 | ) | 850 | (120 | ) | – | 60,518 | (155 | ) | (39 | ) | 60,324 | ||||||||||||||||||||||||
| Parent Companies’ interest in Group net assets | $ million | |||||||||
| 2002 | 2001 | |||||||||
| As previously reported at December 31 | 60,064 | 56,160 | ||||||||
| Effect of the adjustments: | ||||||||||
| Interest at the beginning of the year | ||||||||||
| Cumulative effect of reserves restatement | (164 | ) | (122 | )a | ||||||
| Cumulative effect of change in policy for inventories | 339 | 783 | a | |||||||
| Total before elective changes | 60,239 | 56,821 | ||||||||
| Cumulative effect of exploration costs change | (91 | ) | (78 | )a | ||||||
| 60,148 | 56,743 | |||||||||
| Net income for the year | ||||||||||
| Reserves restatement | (108 | ) | (42 | ) | ||||||
| Change in policy for inventories | 511 | (446 | ) | |||||||
| Goodwill change | (120 | ) | – | |||||||
| Total before elective changes | 60,431 | 56,255 | ||||||||
| Exploration costs change | (61 | ) | (14 | ) | ||||||
| Gas contracts change | (39 | ) | – | |||||||
| 60,331 | 56,241 | |||||||||
| Currency translation differences for the year | (7 | ) | 3 | |||||||
As restated at December 31 | 60,324 | 56,244 | ||||||||
| a | Cumulative effect as at January 1, 2001. |
Please refer to the Notes to the Financial Statements prepared in accordance with US GAAP on pages G5 to G35. The following table provides a reconciliation between US GAAP and Netherlands GAAP for Group net income and net assets.
| Reconciliation between US GAAP and Netherlands GAAP | $ million | |||||||||||||||||||
| Net Income | Net assets | |||||||||||||||||||
| Dec 31, | ||||||||||||||||||||
| 2002 | 2001 | Dec 31, | 2002 | |||||||||||||||||
| 2003 | As restated | As restated | 2003 | As restated | ||||||||||||||||
| In accordance with US GAAP | 12,496 | 9,722 | 10,350 | 72,848 | 60,444 | |||||||||||||||
Adjustment for Netherlands GAAP: | ||||||||||||||||||||
| Goodwill amortisation | (167 | ) | (120 | ) | – | (287 | ) | (120 | ) | |||||||||||
| Cumulative effect of change in accounting for asset retirement obligations | (255 | ) | – | – | – | – | ||||||||||||||
| Long-term commitments | – | – | – | – | – | |||||||||||||||
| In accordance with Netherlands GAAP | 12,074 | 9,602 | 10,350 | 72,561 | 60,324 | |||||||||||||||
Where applicable, differences between Netherlands GAAP and US GAAP affecting these Notes are disclosed below.
The above table should be used to understand the differences in the movements in the Group’s net assets found in Note 29 and 35 as the tables are prepared based on US GAAP and Netherlands GAAP respectively.
32 Tangible and intangible fixed assets
| $ million | |||||||||||||||||||||||||
| 2003 | 2002 | ||||||||||||||||||||||||
| As restated | |||||||||||||||||||||||||
| Other | Total | Total | Total | ||||||||||||||||||||||
| Tangible | Goodwill | intangibles | intangibles | Group | Group | ||||||||||||||||||||
Cost | |||||||||||||||||||||||||
| At January 1 | 160,569 | 3,500 | 2,958 | 6,458 | 167,027 | 122,185 | |||||||||||||||||||
| Capital expenditure | 12,005 | 33 | 214 | 247 | 12,252 | 12,102 | |||||||||||||||||||
| Assets assumed on acquisitions (Enterprise Oil, Pennzoil-Quaker State | |||||||||||||||||||||||||
| and DEA and additional shares in Equilon) | (28 | ) | 418 | (266 | ) | 152 | 124 | 23,285 | |||||||||||||||||
| Sales, retirements and other movements | (4,875 | ) | (51 | ) | (38 | ) | (89 | ) | (4,964 | ) | (465 | ) | |||||||||||||
| Currency translation differences | 14,014 | 111 | 130 | 241 | 14,255 | 9,920 | |||||||||||||||||||
| At December 31 | 181,685 | 4,011 | 2,998 | 7,009 | 188,694 | 167,027 | |||||||||||||||||||
Depreciation | |||||||||||||||||||||||||
| At January 1 | 78,812 | 1,296 | 586 | 1,882 | 80,694 | 68,090 | |||||||||||||||||||
| Depreciation, depletion and amortisation charge | 11,000 | 296 | 293 | 589 | 11,589 | 8,741 | |||||||||||||||||||
| Sales, retirements and other movements | (3,680 | ) | (29 | ) | (2 | ) | (31 | ) | (3,711 | ) | (1,524 | ) | |||||||||||||
| Currency translation differences | 7,852 | 60 | 61 | 121 | 7,973 | 5,387 | |||||||||||||||||||
| At December 31 | 93,984 | 1,623 | 938 | 2,561 | 96,545 | 80,694 | |||||||||||||||||||
Net 2003 | 87,701 | 2,388 | 2,060 | 4,448 | 92,149 | ||||||||||||||||||||
| 2002 | 81,757 | 2,204 | 2,372 | 4,576 | 86,333 | ||||||||||||||||||||
There is an increase in depreciation, depletion and amortisation for intangible fixed assets recorded in cost of sales in 2003 of $167 million (2002: $120 million), with a cumulative impact of $287 million at December 31, 2003, compared with Note 10 prepared under US GAAP. This relates to the amortisation of goodwill under Netherlands GAAP. The increase in the cost of tangible fixed assets at December 31, 2002 of $3.1 billion (2001: $2.2 billion) compared with Note 10 relates to the different treatment of certain long-term commitments prior to 2003. Goodwill arising on the acquisition of PQS 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.
33 Debt
(a) Long-term debt
| $ million | ||||||||
| 2002 | ||||||||
| 2003 | As restated | |||||||
| Debentures and other loans | 4,868 | 5,523 | ||||||
| Amounts due to banks and other credit institutions | 1,061 | 794 | ||||||
| 5,929 | 6,317 | |||||||
| Capitalised lease obligations | 3,171 | 3,570 | ||||||
Long-term debt | 9,100 | 9,887 | ||||||
addlong-term debt due within one year | 1,874 | 2,253 | ||||||
| Long-term debt including long-term debt due within one year | 10,974 | 12,140 | ||||||
(b) Capitalised lease obligations
| $ million | ||||
| Capital | ||||
| leases | ||||
| 2004 | 339 | |||
| 2005 | 382 | |||
| 2006 | 365 | |||
| 2007 | 365 | |||
| 2008 | 365 | |||
| 2009 and after | 5,362 | |||
| Total minimum payments | 7,178 | |||
lessexecutory costs and interest | 3,898 | |||
| Present value of net minimum capital lease payments | 3,280 | |||
34 Information by geographical area and by industry segment
35 Division of Group net assets between the Parent Companies and movements therein
| 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, 2001 | 57,669 | 34,601 | 23,068 | |||||||||
| Movements during the year 2001: | ||||||||||||
| Group net income | 10,350 | 6,210 | 4,140 | |||||||||
less:distributions to Parent Companies | (9,163 | ) | (5,498 | ) | (3,665 | ) | ||||||
| Undistributed net income | 1,187 | 712 | 475 | |||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (642 | ) | (385 | ) | (257 | ) | ||||||
| Other comprehensive income (see Note 5) | (1,970 | ) | (1,182 | ) | (788 | ) | ||||||
| At December 31, 2001 | 56,244 | 33,746 | 22,498 | |||||||||
| Movements during the year 2002: | ||||||||||||
| Group net income | 9,602 | 5,761 | 3,841 | |||||||||
less:distributions to Parent Companies | (5,435 | ) | (3,261 | ) | (2,174 | ) | ||||||
| Undistributed net income | 4,167 | 2,500 | 1,667 | |||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (844 | ) | (507 | ) | (337 | ) | ||||||
| Other comprehensive income (see Note 5) | 757 | 455 | 302 | |||||||||
| At December 31, 2002 | 60,324 | 36,194 | 24,130 | |||||||||
| Cumulative effect of a change in accounting policy | 255 | 153 | 102 | |||||||||
| At January 1, 2003 | 60,579 | 36,347 | 24,232 | |||||||||
| Movements during the year 2003: | ||||||||||||
| Group net income | 12,074 | 7,244 | 4,830 | |||||||||
less:distributions to Parent Companies | (5,660 | ) | (3,396 | ) | (2,264 | ) | ||||||
| Undistributed net income | 6,414 | 3,848 | 2,566 | |||||||||
| 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 5) | 6,200 | 3,721 | 2,479 | |||||||||
At December 31, 2003 | 72,561 | 43,537 | 29,024 | |||||||||
The above table is based on the Group’s Netherlands GAAP results. See the “Reconciliation between US GAAP and Netherlands GAAP” table in Note 31 for the impact of differences between US GAAP and Netherlands GAAP on the Group’s net assets.
| Parent Companies’ interest in Group net assets | $ million | ||||||||||||
| 2002 | 2001 | ||||||||||||
| 2003 | As restated | As restated | |||||||||||
| Invested by Parent Companies | 741 | 741 | 741 | ||||||||||
| Retained earnings of Group companies | 74,970 | 68,302 | 64,135 | ||||||||||
| Parent Companies’ shares held, net of dividends received (Note 22) | (3,428 | ) | (2,797 | ) | (1,953 | ) | |||||||
| Cumulative currency translation differences | 1,208 | (3,894 | ) | (6,326 | ) | ||||||||
| Unrealised gains/(losses) on: | |||||||||||||
| securities (Note 14) | 700 | 11 | (14 | ) | |||||||||
| cash flow hedges | (188 | ) | (239 | ) | (14 | ) | |||||||
| Minimum pension liability adjustments | (1,442 | ) | (1,800 | ) | (325 | ) | |||||||
| Balance at December 31 | 72,561 | 60,324 | 56,244 | ||||||||||
The reduction in retained earnings of Group companies at December 31, 2003 of $287 million (2002: $120 million) compared with Note 4 prepared in accordance with US GAAP, relates to the amortisation of goodwill under Netherlands GAAP.
Restatement of this information as presented in previously issued Financial Statements (see Note 31)
| $ million | ||||||||||||||||||||||||||||||||||||
| Total | Royal Dutch (60%) | Shell Transport (40%) | ||||||||||||||||||||||||||||||||||
| As previously | As | As previously | As | As previously | As | |||||||||||||||||||||||||||||||
| reported | Adjustments | restated | reported | Adjustments | restated | reported | Adjustments | restated | ||||||||||||||||||||||||||||
| At January 1, 2001 | 57,086 | 583 | 57,669 | 34,252 | 349 | 34,601 | 22,834 | 234 | 23,068 | |||||||||||||||||||||||||||
| Movements during the year 2001: | ||||||||||||||||||||||||||||||||||||
| Group net income | 10,852 | (502 | ) | 10,350 | 6,511 | (301 | ) | 6,210 | 4,341 | (201 | ) | 4,140 | ||||||||||||||||||||||||
less:distributions to Parent Companies | (9,163 | ) | – | (9,163 | ) | (5,498 | ) | – | (5,498 | ) | (3,665 | ) | – | (3,665 | ) | |||||||||||||||||||||
| Undistributed net income | 1,689 | (502 | ) | 1,187 | 1,013 | (301 | ) | 712 | 676 | (201 | ) | 475 | ||||||||||||||||||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (642 | ) | – | (642 | ) | (385 | ) | – | (385 | ) | (257 | ) | – | (257 | ) | |||||||||||||||||||||
| Other comprehensive income | (1,973 | ) | 3 | (1,970 | ) | (1,184 | ) | 2 | (1,182 | ) | (789 | ) | 1 | (788 | ) | |||||||||||||||||||||
| At December 31, 2001 | 56,160 | 84 | 56,244 | 33,696 | 50 | 33,746 | 22,464 | 34 | 22,498 | |||||||||||||||||||||||||||
| Movements during the year 2002: | ||||||||||||||||||||||||||||||||||||
| Group net income | 9,419 | 183 | 9,602 | 5,651 | 110 | 5,761 | 3,768 | 73 | 3,841 | |||||||||||||||||||||||||||
less:distributions to Parent Companies | (5,435 | ) | – | (5,435 | ) | (3,261 | ) | – | (3,261 | ) | (2,174 | ) | – | (2,174 | ) | |||||||||||||||||||||
| Undistributed net income | 3,984 | 183 | 4,167 | 2,390 | 110 | 2,500 | 1,594 | 73 | 1,667 | |||||||||||||||||||||||||||
| Movement in Parent Companies’ shares held by Group companies, net of dividends received | (844 | ) | – | (844 | ) | (507 | ) | – | (507 | ) | (337 | ) | – | (337 | ) | |||||||||||||||||||||
| Other comprehensive income | 764 | (7 | ) | 757 | 459 | (4 | ) | 455 | 305 | (3 | ) | 302 | ||||||||||||||||||||||||
| At December 31, 2002 | 60,064 | 260 | 60,324 | 36,038 | 156 | 36,194 | 24,026 | 104 | 24,130 | |||||||||||||||||||||||||||
Royal Dutch/Shell Group of Companies
We have audited the Netherlands GAAP Financial Statements of the Royal Dutch/ Shell Group of Companies for the year 2003, and the Notes thereto on pages G2 to G42. These Financial Statements are the responsibility of management. Our responsibility is to express an opinion on these Financial Statements based on our audit.
We conducted our audit 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 audit provides 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, 2003 and of the result and the cash flows for the year then ended in accordance with the accounting principles generally accepted in the Netherlands.
As discussed in Note 31 on pages G38 to G40, the Group has restated the comparative data for the two years ended December 31, 2002.
/s/ KPMG Accountants N.V.
KPMG Accountants N.V.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
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
| – | following the Reserves Review, 4,474 million barrels of oil equivalent (boe)1 previously booked at December 31, 2002 as proved reserves have been recategorised as not proved (this was the subject of the announcement made on January 9, 2004, as updated on March 18, 2004 and April 19, 2004 and herein); and |
| – | approximately 400 million boe of proved reserves additions that had been estimated for the year 2003, as announced on February 5, 2004, have not been made (this was also the subject of the announcement on March 18, 2004 as updated on April 19, 2004 and herein). |
The tables that follow include a restatement of the Group’s proved reserves for the two years ended December 31, 2001 and December 31, 2002, as well as a restatement of the standardised measure of discounted future cash flows (collectively, the Reserves Restatement), in order to give effect to the results of the Reserves Review. In addition, certain volumes identified for recategorisation in the Reserves Review have been reflected as revisions during 2003. The principal reasons for the Reserves Restatement and the 2003 revisions are discussed later in this section.
The Reserves Restatement also reflects changes in the timing of the initial booking of approximately 930 million boe of certain other proved reserves. These quantities, situated in the West Africa Deep Water province and Australia (North West Shelf) were compliant with proved reserves definitions as at December 31, 2002, but the Reserves Review has indicated that the original bookings in 2000 and prior years were made in advance of a sufficient investment commitment or assurance of market availability to support the booking. These changes bring the timing of these proved reserves additions into line with commitments to investment or contractual product sales, most of which were made in the period 1999 to 2002. Accordingly, these quantities do not change the total reduction in proved reserves as at December 31, 2002, because they qualified as proved reserves at that date, although they do affect the trend of reserves bookings over the period covered by this report and affect calculation of the reserves replacement ratio.
The Group has determined that during the periods prior to the Reserves Restatement, its reserves bookings were not fully consistent with the definition of proved reserves as set forth in Rule 4-10 of Regulation S-X under the U.S. Securities Exchange Act of 1934 (Rule 4-10), and the interpretations of that Rule by the staff of the Division of Corporation Finance of the US Securities and Exchange Commission (SEC). In particular, the Group has determined that its prior guidelines contained interpretations and allowed for reserve determinations that were not consistent with Rule 4-10 and SEC staff interpretations of Rule 4-10. The principal areas of variation are listed overleaf.
| 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. |
Investment commitment
Market assurance
Governmental or regulatory approval
Field performance and project delivery
Year-end pricing
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 in prior years 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 has been accounted for as a revision during the year 2003. It has not been included in the Reserves Restatement 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 has been 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. In some cases, volumes related to the successful implementation of improved recovery processes had been booked as proved reserves in the absence of sufficient proof, in accordance with SEC guidance, of “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 has been accounted for through restatement of proved reserves for prior years. |
| – | Forecasting methodology. In some cases, volumes booked on the basis of sophisticated computer modelling were not sufficiently supported by actual reservoir performance 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 has been 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
Effect of Reserves Restatement
All tables have been reformatted compared with previous years’ disclosures to provide further geographical detail. The “Europe” and “USA” groupings remain unchanged in terms of the definition of constituent countries, as does the “Western Hemisphere, Other” region. The previously reported “Eastern Hemisphere, Other” region has been divided into three new geographical groupings: “Africa”, “Asia Pacific” and “Middle East, Russia and Commonwealth of Independent States (CIS)”, the latter also being referred to as the “Middle East” below for convenience. Egypt is included in the “Middle East”, as are Sakhalin and states bordering the Caspian Sea. The revised geographical grouping is aligned with the division of the Group’s Exploration and Production business into regional directorates for internal management purposes.
The effect of the Reserves Restatement on proved reserves and the standardised measure is summarised as follows:
Year ended December 31, 2002
The Reserves Restatement gave rise to an estimated reduction of $5,340 million in the standardised measure of discounted future net cash flow for Group companies and a further $1,308 million for associated companies. Together, these effects equate to approximately 9% of the total standardised measure that was originally stated at that date. This effect is disproportionately low compared with the effect on proved reserves (23%) primarily due to the fact that 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 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.
Year ended December 31, 2001
The Reserves Restatement gave rise to an estimated reduction of $5,464 million in the standardised measure of discounted future net cash flow for Group companies and a further $1,005 million reduction for associated companies. Together, these effects equate to approximately 13% of the total standardised measure that was originally stated at that date.
Year ended December 31, 2000
The Reserves Restatement gave rise to an estimated reduction of $6,083 million in the standardised measure of discounted future net cash flow for Group companies and a further $1,153 million for associated companies. Together, these effects equate to approximately 10% of the total standardised measure that was originally stated at that date.
Years prior to 2000
| – | at December 31, 1999 (and January 1, 2000), the aggregated effect on proved reserves of the Reserves Restatement was 4,582 million boe, comprising 2,408 million barrels of crude oil and natural gas liquids and 12,608 thousand million standard cubic feet of gas. This amounts to 23% of the total proved reserves originally stated at that date (19,868 million boe). Of the total aggregated effect, 87% (4,006 million boe) was attributable to Group companies and the remainder was 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. Various properties in Nigeria accounted for 45% of the restated volume at that date, Australia accounted for 25% and the effect of applying year-end pricing accounted for a further 12% of the total. Various other properties in the rest of Asia Pacific contributed a further 9%. After giving effect to the Reserves Restatement, the proportion of total unaudited proved reserves volumes that was accounted for as proved developed reserves at December 31, 1999 increased from 49%, as originally stated, to 58%; |
| – | at December 31, 1998 (and January 1, 1999), the aggregate effect on proved reserves of the Reserves Restatement was 3,777 million boe, comprising 2,176 million barrels of crude oil and natural gas liquids and 9,285 thousand million standard cubic feet of gas. This amounts to 18% of the total proved reserves originally stated at that date (20,455 million boe). Of the total aggregate effect, 84% (3,167 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 13% of the total had been in the proved developed reserves category and 87% had been categorised as proved undeveloped reserves. Various properties in Nigeria and Australia together accounted for 90% of the restated volume at that date; and |
| – | at December 31, 1997 (January 1, 1998), the aggregate effect on proved reserves of the Reserves Restatement was 3,132 million boe, comprising 1,646 million barrels of crude oil and natural gas liquids and 8,619 thousand million standard cubic feet of gas. This amounts to 16% of the total proved reserves originally stated at that date (19,359 million boe). Of the total aggregate effect, 81% (2,553 million boe) was attributable to Group companies and the remainder was attributable to associated companies. 4% of the total had been in the proved developed reserves category and 96% had been categorised as proved undeveloped reserves. Various properties in Nigeria and Australia together accounted for 90% of the restated volume at that date. |
Reserves replacement ratio
The five-year (1999 – 2003) reserves replacement ratio is 66% (70% for oil, including natural gas liquids, and 60% for gas).
These figures include both Group and associated companies, they include minority interests in Group companies and they include the effects of acquisitions and divestment. They exclude any contribution from oil sands projects, which do not qualify as oil and gas producing activities.
Canadian reserves revision
Restatement of previously reported Supplementary information – Oil and Gas
| million barrels | thousand million standard cubic feeta | $ million | ||||||||||||||||||||||||||||||||||||||
| Reserves | Reserves | |||||||||||||||||||||||||||||||||||||||
| Crude oil and natural gas liquids | Natural gas | |||||||||||||||||||||||||||||||||||||||
| Standardised measure | ||||||||||||||||||||||||||||||||||||||||
| Proved developed and | Proved developed | Proved developed and | Proved developed | of discounted future | ||||||||||||||||||||||||||||||||||||
| undeveloped reserves | reserves | undeveloped reserves | reserves | cash flows | ||||||||||||||||||||||||||||||||||||
| 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | |||||||||||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||||||||||||||
| As previously reported at December 31 | 9,026 | 8,544 | 3,959 | 3,734 | 48,240 | 50,613 | 22,530 | 23,938 | 65,702 | 45,878 | ||||||||||||||||||||||||||||||
| Effect of the adjustment | ||||||||||||||||||||||||||||||||||||||||
| Amounts at beginning of year | (2,437 | ) | (2,658 | )b | (202 | ) | (255 | )b | (8,554 | ) | (9,389 | )b | (1,088 | ) | (1,299 | )b | (5,464 | ) | (6,083 | )b | ||||||||||||||||||||
| Movements during the year | (184 | ) | 221 | (73 | ) | 53 | 604 | 835 | (80 | ) | 211 | 124 | 619 | |||||||||||||||||||||||||||
| (2,621 | ) | (2,437 | ) | (275 | ) | (202 | ) | (7,950 | ) | (8,554 | ) | (1,168 | ) | (1,088 | ) | (5,340 | ) | (5,464 | ) | |||||||||||||||||||||
As restated at December 31 | 6,405 | 6,107 | 3,684 | 3,532 | 40,290 | 42,059 | 21,362 | 22,850 | 60,362 | 40,414 | ||||||||||||||||||||||||||||||
Group share of associated companies | ||||||||||||||||||||||||||||||||||||||||
| As previously reported at December 31 | 1,107 | 925 | 667 | 598 | 5,198 | 5,216 | 2,072 | 1,806 | 7,070 | 3,888 | ||||||||||||||||||||||||||||||
| Effect of the adjustment | ||||||||||||||||||||||||||||||||||||||||
| Amounts at beginning of year | (206 | ) | (186 | )b | (6 | ) | (6 | )b | (2,397 | ) | (2,209 | )b | (13 | ) | (14 | )b | (1,005 | ) | (1,153 | )b | ||||||||||||||||||||
| Movements during the year | 32 | (20 | ) | (2 | ) | – | 611 | (188 | ) | (212 | ) | 1 | (303 | ) | 148 | |||||||||||||||||||||||||
| (174 | ) | (206 | ) | (8 | ) | (6 | ) | (1,786 | ) | (2,397 | ) | (225 | ) | (13 | ) | (1,308 | ) | (1,005 | ) | |||||||||||||||||||||
As restated at December 31 | 933 | 719 | 659 | 592 | 3,412 | 2,819 | 1,847 | 1,793 | 5,762 | 2,883 | ||||||||||||||||||||||||||||||
| Geographical analysis of the effect of the adjustment | ||||||||||||||||||||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||||||||||||||
| Europe | (147 | ) | (27 | ) | (2 | ) | (2 | ) | (1,570 | ) | (1,195 | ) | (44 | ) | (44 | ) | (1,493 | ) | (869 | ) | ||||||||||||||||||||
| Africa | (1,409 | ) | (1,745 | ) | (235 | ) | (141 | ) | (1,259 | ) | (1,478 | ) | (528 | ) | (376 | ) | (1,146 | ) | (3,103 | ) | ||||||||||||||||||||
| Asia Pacific | (101 | ) | (116 | ) | (20 | ) | (29 | ) | (4,197 | ) | (5,159 | ) | (15 | ) | (128 | ) | (1,066 | ) | (909 | ) | ||||||||||||||||||||
| Middle East, Russia, CIS | (854 | ) | (494 | ) | 15 | (10 | ) | (499 | ) | (289 | ) | (254 | ) | (184 | ) | (1,392 | ) | (531 | ) | |||||||||||||||||||||
| USA | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
| Other Western Hemisphere | (110 | ) | (55 | ) | (33 | ) | (20 | ) | (425 | ) | (433 | ) | (327 | ) | (356 | ) | (243 | ) | (52 | ) | ||||||||||||||||||||
Total | (2,621 | ) | (2,437 | ) | (275 | ) | (202 | ) | (7,950 | ) | (8,554 | ) | (1,168 | ) | (1,088 | ) | (5,340 | ) | (5,464 | ) | ||||||||||||||||||||
Group share of associated companies | ||||||||||||||||||||||||||||||||||||||||
| Europe | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
| Africa | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
| Asia Pacific | (174 | ) | (205 | ) | (8 | ) | (6 | ) | (1,786 | ) | (2,397 | ) | (225 | ) | (13 | ) | (1,308 | ) | (1,005 | ) | ||||||||||||||||||||
| Middle East, Russia, CIS | – | (1 | ) | – | – | – | – | – | – | – | – | |||||||||||||||||||||||||||||
| USA | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
| Other Western Hemisphere | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Total | (174 | ) | (206 | ) | (8 | ) | (6 | ) | (1,786 | ) | (2,397 | ) | (225 | ) | (13 | ) | (1,308 | ) | (1,005 | ) | ||||||||||||||||||||
| a | These quantities have not been adjusted to standard heat content. |
| b | Cumulative effect of Reserves Restatement as at January 1, 2001. |
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Crude oil and natural gas liquids
| Proved developed and undeveloped reserves | million barrels | |||||||||||||||||||||||||||
| 2003 | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||
| Middle East, | ||||||||||||||||||||||||||||
| Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | ||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||
At January 1 | 1,488 | 1,828 | 338 | 1,484 | 720 | 547 | 6,405 | |||||||||||||||||||||
| Revisions and reclassifications | 141 | (6 | ) | 22 | (183 | ) | (54 | ) | (73 | ) | (153 | ) | ||||||||||||||||
| Improved recovery | 8 | 2 | 15 | 4 | 8 | 1 | 38 | |||||||||||||||||||||
| Extensions and discoveries | 13 | 62 | – | 169 | 9 | 1 | 254 | |||||||||||||||||||||
| Purchases of minerals in place | 1 | – | – | 3 | – | – | 4 | |||||||||||||||||||||
| Sales of minerals in place | (39 | ) | – | – | – | (23 | ) | – | (62 | ) | ||||||||||||||||||
| Production | (245 | ) | (133 | ) | (57 | ) | (181 | ) | (110 | ) | (37 | ) | (763 | ) | ||||||||||||||
At December 31 | 1,367 | 1,753 | 318 | 1,296 | 550 | 439 | 5,723 | |||||||||||||||||||||
Group share of associated companies | ||||||||||||||||||||||||||||
At January 1 | 2 | – | 400 | 118 | 413 | – | 933 | |||||||||||||||||||||
| Revisions and reclassifications | – | – | 4 | – | 41 | – | 45 | |||||||||||||||||||||
| Improved recovery | – | – | 12 | – | – | – | 12 | |||||||||||||||||||||
| Extensions and discoveries | – | – | 11 | 86 | – | – | 97 | |||||||||||||||||||||
| Purchases of minerals in place | – | – | – | – | – | – | – | |||||||||||||||||||||
| Sales of minerals in place | – | – | – | (117 | ) | – | – | (117 | ) | |||||||||||||||||||
| Production | – | – | (46 | ) | (1 | ) | (41 | ) | – | (88 | ) | |||||||||||||||||
At December 31 | 2 | – | 381 | 86 | 413 | – | 882 | |||||||||||||||||||||
Total | 1,369 | 1,753 | 699 | 1,382 | 963 | 439 | 6,605 | |||||||||||||||||||||
| Minority interests’ share of proved reserves of Group companies | ||||||||||||||||||||||||||||
| At December 31 | – | 29 | 1 | 155 | – | 54 | 239 | |||||||||||||||||||||
| Proved developed reserves | million barrels | |||||||||||||||||||||||||||
| 2003 | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||
| Middle East, | ||||||||||||||||||||||||||||
| Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | ||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||
At January 1 | 1,127 | 738 | 199 | 1,056 | 373 | 191 | 3,684 | |||||||||||||||||||||
| At December 31 | 1,056 | 879 | 194 | 898 | 293 | 192 | 3,512 | |||||||||||||||||||||
Group share of associated companies | ||||||||||||||||||||||||||||
At January 1 | 1 | – | 278 | 15 | 365 | – | 659 | |||||||||||||||||||||
| At December 31 | 1 | – | 306 | 1 | 364 | – | 672 | |||||||||||||||||||||
| Oil sandse | million barrels | |||||||
Group companies | ||||||||
At January 1 | 600 | 600 | ||||||
| Extensions and discoveries | 69 | 69 | ||||||
| Production | (17 | ) | (17 | ) | ||||
At December 31 | 652 | 652 | ||||||
Minority interests’ share of oil sands | ||||||||
| At December 31 | 143 | 143 | ||||||
| a | Excludes Egypt. |
| b | Excludes Sakhalin. |
| c | Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin. |
| d | As applicable, amounts relating to prior years have been restated. A summary of the changes is shown in the table on page G48. |
| e | Petroleum reserves from operations that do not qualify as oil and gas producing activities, in this case 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 conventional oil and gas reserves, which is found on page G54. The volumes quoted are “gross”, ie, including royalties. Calculation of royalties depends on price, production rates, capital costs and operating costs over the life of the Athabasca Oil Sands Project. At 2003 year-end pricing, net volumes would be approximately 90% of gross volumes. |
| million barrels | million barrels | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002d | 2001d | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Middle East, | Middle East, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | |||||||||||||||||||||||||||||||||||||||||||
| 1,078 | 1,671 | 445 | 1,717 | 675 | 521 | 6,107 | 1,152 | 1,711 | 436 | 1,572 | 611 | 530 | 6,012 | |||||||||||||||||||||||||||||||||||||||||||
| 98 | 69 | (25 | ) | (26 | ) | 77 | (34 | ) | 159 | 41 | 51 | (7 | ) | 302 | 31 | 39 | 457 | |||||||||||||||||||||||||||||||||||||||
| 15 | – | 6 | 45 | 51 | – | 117 | 67 | 1 | 12 | 19 | – | – | 99 | |||||||||||||||||||||||||||||||||||||||||||
| 1 | 209 | – | – | 33 | – | 243 | 17 | 28 | 5 | – | 139 | 1 | 190 | |||||||||||||||||||||||||||||||||||||||||||
| 551 | – | – | – | 7 | 93 | 651 | – | – | 69 | – | 3 | – | 72 | |||||||||||||||||||||||||||||||||||||||||||
| (1 | ) | (19 | ) | (19 | ) | (62 | ) | (3 | ) | – | (104 | ) | – | – | – | – | (1 | ) | (14 | ) | (15 | ) | ||||||||||||||||||||||||||||||||||
| (254 | ) | (102 | ) | (69 | ) | (190 | ) | (120 | ) | (33 | ) | (768 | ) | (199 | ) | (120 | ) | (70 | ) | (176 | ) | (108 | ) | (35 | ) | (708 | ) | |||||||||||||||||||||||||||||
| 1,488 | 1,828 | 338 | 1,484 | 720 | 547 | 6,405 | 1,078 | 1,671 | 445 | 1,717 | 675 | 521 | 6,107 | |||||||||||||||||||||||||||||||||||||||||||
| 1 | – | 362 | – | 356 | – | 719 | 1 | – | 353 | 100 | 441 | – | 895 | |||||||||||||||||||||||||||||||||||||||||||
| 1 | – | 78 | – | 65 | – | 144 | – | – | 41 | (92 | ) | (35 | ) | – | (86 | ) | ||||||||||||||||||||||||||||||||||||||||
| – | – | 4 | – | – | – | 4 | – | – | 13 | – | 1 | – | 14 | |||||||||||||||||||||||||||||||||||||||||||
| – | – | 6 | – | 33 | – | 39 | – | – | 4 | – | – | – | 4 | |||||||||||||||||||||||||||||||||||||||||||
| – | – | – | 121 | – | – | 121 | – | – | – | – | – | – | – | |||||||||||||||||||||||||||||||||||||||||||
| – | – | – | (1 | ) | – | – | (1 | ) | – | – | – | – | (9 | ) | – | (9 | ) | |||||||||||||||||||||||||||||||||||||||
| – | – | (50 | ) | (2 | ) | (41 | ) | – | (93 | ) | – | – | (49 | ) | (8 | ) | (42 | ) | – | (99 | ) | |||||||||||||||||||||||||||||||||||
| 2 | – | 400 | 118 | 413 | – | 933 | 1 | – | 362 | – | 356 | – | 719 | |||||||||||||||||||||||||||||||||||||||||||
| 1,490 | 1,828 | 738 | 1,602 | 1,133 | 547 | 7,338 | 1,079 | 1,671 | 807 | 1,717 | 1,031 | 521 | 6,826 | |||||||||||||||||||||||||||||||||||||||||||
| – | 26 | 1 | 126 | – | 64 | 217 | – | 31 | 1 | 116 | – | 69 | 217 | |||||||||||||||||||||||||||||||||||||||||||
| million barrels | million barrels | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002d | 2001d | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Middle East, | Middle East, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | |||||||||||||||||||||||||||||||||||||||||||
| 785 | 724 | 249 | 1,122 | 429 | 223 | 3,532 | 872 | 740 | 214 | 1,151 | 351 | 229 | 3,557 | |||||||||||||||||||||||||||||||||||||||||||
| 1,127 | 738 | 199 | 1,056 | 373 | 191 | 3,684 | 785 | 724 | 249 | 1,122 | 429 | 223 | 3,532 | |||||||||||||||||||||||||||||||||||||||||||
| 1 | – | 261 | – | 330 | – | 592 | 1 | – | 249 | 37 | 364 | – | 651 | |||||||||||||||||||||||||||||||||||||||||||
| 1 | – | 278 | 15 | 365 | – | 659 | 1 | – | 261 | – | 330 | – | 592 | |||||||||||||||||||||||||||||||||||||||||||
| million barrels | million barrels | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 600 | 600 | 600 | 600 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| – | – | – | – | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| – | – | – | – | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 600 | 600 | 600 | 600 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 134 | 134 | 133 | 133 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Natural gas
| Proved developed and undeveloped reserves | thousand million standard cubic feeta | |||||||||||||||||||||||||||
| 2003 | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||
| Middle East, | ||||||||||||||||||||||||||||
| Europe | Africab | Asia Pacificc | Russia, CISd | USA | Other | Total | ||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||
At January 1 | 22,046 | 1,844 | 8,994 | 1,118 | 3,874 | 2,414 | 40,290 | |||||||||||||||||||||
| Revisions and reclassifications | 1 | (5 | ) | (114 | ) | (21 | ) | (70 | ) | (531 | ) | (740 | ) | |||||||||||||||
| Improved recovery | 22 | 506 | 17 | – | 10 | 30 | 585 | |||||||||||||||||||||
| Extensions and discoveries | 485 | 1,361 | 7 | 2,795 | 305 | 34 | 4,987 | |||||||||||||||||||||
| Purchases of minerals in place | 6 | – | – | – | – | – | 6 | |||||||||||||||||||||
| Sales of minerals in place | (139 | ) | – | – | – | (389 | ) | (17 | ) | (545 | ) | |||||||||||||||||
| Production | (1,303 | ) | (128 | ) | (541 | ) | (258 | ) | (555 | ) | (197 | ) | (2,982 | ) | ||||||||||||||
At December 31 | 21,118 | 3,578 | 8,363 | 3,634 | 3,175 | 1,733 | 41,601 | |||||||||||||||||||||
Group share of associated companies | ||||||||||||||||||||||||||||
At January 1 | 44 | – | 3,347 | – | 21 | – | 3,412 | |||||||||||||||||||||
| Revisions and reclassifications | – | – | 133 | – | 9 | – | 142 | |||||||||||||||||||||
| Improved recovery | 1 | – | 11 | – | – | – | 12 | |||||||||||||||||||||
| Extensions and discoveries | 1 | – | – | – | – | – | 1 | |||||||||||||||||||||
| Purchases of minerals in place | – | – | – | – | – | – | – | |||||||||||||||||||||
| Sales of minerals in place | – | – | – | – | – | – | – | |||||||||||||||||||||
| Production | (7 | ) | – | (238 | ) | – | (3 | ) | – | (248 | ) | |||||||||||||||||
At December 31 | 39 | – | 3,253 | – | 27 | – | 3,319 | |||||||||||||||||||||
Total | 21,157 | 3,578 | 11,616 | 3,634 | 3,202 | 1,733 | 44,920 | |||||||||||||||||||||
| Minority interests’ share of proved reserves of Group companies | ||||||||||||||||||||||||||||
| At December 31 | – | – | 68 | 1,285 | – | 300 | 1,653 | |||||||||||||||||||||
| Proved developed reserves | thousand million standard cubic feeta | |||||||||||||||||||||||||||
| 2003 | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||
| Middle East, | ||||||||||||||||||||||||||||
| Europe | Africab | Asia Pacificc | Russia, CISd | USA | Other | Total | ||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||
At January 1 | 12,061 | 1,181 | 3,775 | 574 | 2,316 | 1,455 | 21,362 | |||||||||||||||||||||
| At December 31 | 12,350 | 1,094 | 3,523 | 449 | 1,758 | 1,316 | 20,490 | |||||||||||||||||||||
Group share of associated companies | ||||||||||||||||||||||||||||
At January 1 | 38 | – | 1,792 | – | 17 | – | 1,847 | |||||||||||||||||||||
| At December 31 | 34 | – | 1,858 | – | 22 | – | 1,914 | |||||||||||||||||||||
| 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. |
| e | As applicable, amounts relating to prior years have been restated. A summary of the changes is shown in the table on page G48. |
| thousand million standard cubic feeta | thousand million standard cubic feeta | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002e | 2001e | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 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 | |||||||||||||||||||||||||||||||||||||||||||
| 22,527 | 1,921 | 9,456 | 1,777 | 3,694 | 2,684 | 42,059 | 22,722 | 1,925 | 8,339 | 2,054 | 3,403 | 3,010 | 41,453 | |||||||||||||||||||||||||||||||||||||||||||
| 3 | 12 | 152 | (282 | ) | 162 | (110 | ) | (63 | ) | 890 | (45 | ) | 260 | (73 | ) | 141 | (257 | ) | 916 | |||||||||||||||||||||||||||||||||||||
| 75 | – | 150 | – | 20 | – | 245 | 38 | – | 266 | – | – | – | 304 | |||||||||||||||||||||||||||||||||||||||||||
| 29 | – | 1 | – | 411 | 9 | 450 | 214 | 121 | 8 | 95 | 385 | 132 | 955 | |||||||||||||||||||||||||||||||||||||||||||
| 748 | – | – | – | 208 | 27 | 983 | – | – | 1,095 | – | 355 | 9 | 1,459 | |||||||||||||||||||||||||||||||||||||||||||
| (5 | ) | – | (212 | ) | – | (10 | ) | – | (227 | ) | – | – | – | – | (9 | ) | (8 | ) | (17 | ) | ||||||||||||||||||||||||||||||||||||
| (1,331 | ) | (89 | ) | (553 | ) | (377 | ) | (611 | ) | (196 | ) | (3,157 | ) | (1,337 | ) | (80 | ) | (512 | ) | (299 | ) | (581 | ) | (202 | ) | (3,011 | ) | |||||||||||||||||||||||||||||
| 22,046 | 1,844 | 8,994 | 1,118 | 3,874 | 2,414 | 40,290 | 22,527 | 1,921 | 9,456 | 1,777 | 3,694 | 2,684 | 42,059 | |||||||||||||||||||||||||||||||||||||||||||
| 48 | – | 2,756 | – | 15 | – | 2,819 | 56 | – | 3,090 | – | 86 | – | 3,232 | |||||||||||||||||||||||||||||||||||||||||||
| 1 | – | 790 | – | 7 | – | 798 | (4 | ) | – | 57 | – | (29 | ) | – | 24 | |||||||||||||||||||||||||||||||||||||||||
| – | – | 8 | – | – | – | 8 | – | – | 17 | – | – | – | 17 | |||||||||||||||||||||||||||||||||||||||||||
| 3 | – | 15 | – | 1 | – | 19 | 3 | – | 2 | – | – | – | 5 | |||||||||||||||||||||||||||||||||||||||||||
| – | – | – | – | – | – | – | – | – | – | – | – | – | – | |||||||||||||||||||||||||||||||||||||||||||
| – | – | – | – | – | – | – | – | – | (181 | ) | – | (40 | ) | – | (221 | ) | ||||||||||||||||||||||||||||||||||||||||
| (8 | ) | – | (222 | ) | – | (2 | ) | – | (232 | ) | (7 | ) | – | (229 | ) | – | (2 | ) | – | (238 | ) | |||||||||||||||||||||||||||||||||||
| 44 | – | 3,347 | – | 21 | – | 3,412 | 48 | – | 2,756 | – | 15 | – | 2,819 | |||||||||||||||||||||||||||||||||||||||||||
| 22,090 | 1,844 | 12,341 | 1,118 | 3,895 | 2,414 | 43,702 | 22,575 | 1,921 | 12,212 | 1,777 | 3,709 | 2,684 | 44,878 | |||||||||||||||||||||||||||||||||||||||||||
| – | – | 66 | 59 | – | 403 | 528 | – | – | 83 | 153 | – | 458 | 694 | |||||||||||||||||||||||||||||||||||||||||||
| thousand million standard cubic feeta | thousand million standard cubic feeta | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002e | 2001e | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 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 | |||||||||||||||||||||||||||||||||||||||||||
| 12,322 | 1,109 | 3,966 | 1,097 | 2,363 | 1,993 | 22,850 | 12,979 | 1,109 | 2,898 | 1,382 | 2,347 | 2,175 | 22,890 | |||||||||||||||||||||||||||||||||||||||||||
| 12,061 | 1,181 | 3,775 | 574 | 2,316 | 1,455 | 21,362 | 12,322 | 1,109 | 3,966 | 1,097 | 2,363 | 1,993 | 22,850 | |||||||||||||||||||||||||||||||||||||||||||
| 41 | – | 1,741 | – | 11 | – | 1,793 | 53 | – | 1,721 | – | 66 | – | 1,840 | |||||||||||||||||||||||||||||||||||||||||||
| 38 | – | 1,792 | – | 17 | – | 1,847 | 41 | – | 1,741 | – | 11 | – | 1,793 | |||||||||||||||||||||||||||||||||||||||||||
Standardised measure of discounted future cash flows
The standardised measure for the Middle East, Russia, CIS geographical grouping includes a negative contribution of $2,238 million from the Group’s Sakhalin properties (Russia). This also accounts for the negative contribution of minority interests to the standardised measure for that geographical grouping and for Group companies as a whole. The standardised measure for Sakhalin is negative due to the inclusion of the full committed costs of development and operation for the asset under the integrated Production Sharing Agreement. Meanwhile, revenues are registered only in relation to the currently estimated proved reserves. Proved gas reserves are constrained to those volumes that are related to firm sales commitments. Consequently the currently stated proved reserves are only a small fraction of the volume that is expected to be committed to sales over time and upon which the decision to proceed with development was based.
| $ million | ||||||||||||||||||||||||||||
| 2003 | ||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||
| Middle East, | ||||||||||||||||||||||||||||
| Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | ||||||||||||||||||||||
Group companies | ||||||||||||||||||||||||||||
| Future cash inflows | 117,606 | 47,325 | 24,115 | 45,238 | 31,419 | 16,224 | 281,927 | |||||||||||||||||||||
| Future production costs | 21,853 | 7,433 | 4,515 | 7,745 | 4,977 | 4,379 | 50,902 | |||||||||||||||||||||
| Future development costs | 6,543 | 7,337 | 2,505 | 9,772 | 3,085 | 1,328 | 30,570 | |||||||||||||||||||||
| Future tax expenses | 44,361 | 18,764 | 4,785 | 16,391 | 8,542 | 2,900 | 95,743 | |||||||||||||||||||||
| Future net cash flows | 44,849 | 13,791 | 12,310 | 11,330 | 14,815 | 7,617 | 104,712 | |||||||||||||||||||||
| Effect of discounting cash flows at 10% | 22,027 | 5,826 | 5,610 | 9,209 | 5,231 | 2,965 | 50,868 | |||||||||||||||||||||
Standardised measure of discounted future net cash flows | 22,822 | 7,965 | 6,700 | 2,121 | 9,584 | 4,652 | 53,844 | |||||||||||||||||||||
Group share of associated companies | 5,828 | |||||||||||||||||||||||||||
Minority interests | – | 170 | 38 | (976 | ) | – | 547 | (221 | ) | |||||||||||||||||||
| Change in standardised measure of Group companies discounted future net cash flows | ||||||||||||
| relating to proved Oil and Gas Reserves | ||||||||||||
| $ million | ||||||||||||
| 2003 | 2002d | 2001d | ||||||||||
At January 1 | 60,362 | 40,414 | 56,958 | |||||||||
| Net changes in prices and production costs | 13,162 | 36,717 | (28,132 | ) | ||||||||
| Extensions, discoveries and improved recovery | 7,043 | 5,356 | 3,280 | |||||||||
| Purchases and sales of minerals in place | (2,801 | ) | 8,284 | 1,932 | ||||||||
| Revisions of previous reserve estimates | (346 | ) | 419 | 2,984 | ||||||||
| Development cost related to future production | (14,413 | ) | (5,931 | ) | (4,713 | ) | ||||||
| Sales and transfers of oil and gas, net of production costs | (24,891 | ) | (20,387 | ) | (20,173 | ) | ||||||
| Development cost incurred during the year | 8,239 | 6,673 | 5,287 | |||||||||
| Accretion of discount | 9,806 | 6,406 | 8,927 | |||||||||
| Net change in income tax | (2,317 | ) | (17,589 | ) | 14,064 | |||||||
At December 31 | 53,844 | 60,362 | 40,414 | |||||||||
| a | Excludes Egypt. |
| b | Excludes Sakhalin. |
| c | Middle East and Former Soviet Union/Commonwealth of Independent States. Includes Caspian region, Egypt and Sakhalin. |
| d | As applicable, amounts relating to prior years have been restated. A summary of the changes is shown in the table on page G48. |
| 1 | The weighted average year-end oil price in 2003 was $26.66/bbl ($24.74/bbl and $16.58/bbl in 2002 and 2001 respectively). The weighted average year-end gas price in 2003 was $4.19 per million Btu ($3.67 and $2.96 per million Btu in 2002 and 2001, respectively). |
| $ million | $ million | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2002d | 2001d | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Eastern Hemisphere | Western Hemisphere | Eastern Hemisphere | Western Hemisphere | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Middle East, | Middle East, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | Europe | Africaa | Asia Pacificb | Russia, CISc | USA | Other | Total | |||||||||||||||||||||||||||||||||||||||||
| 103,061 | 46,571 | 25,791 | 37,606 | 32,702 | 18,854 | 264,585 | 76,299 | 26,986 | 22,577 | 34,375 | 18,982 | 11,796 | 191,015 | |||||||||||||||||||||||||||||||||||||||||
| 19,388 | 6,523 | 3,946 | 5,286 | 4,858 | 4,117 | 44,118 | 14,059 | 5,087 | 4,737 | 5,143 | 4,021 | 3,990 | 37,037 | |||||||||||||||||||||||||||||||||||||||||
| 4,783 | 6,776 | 2,518 | 2,887 | 3,201 | 1,628 | 21,793 | 3,466 | 6,155 | 2,884 | 4,017 | 2,352 | 1,385 | 20,259 | |||||||||||||||||||||||||||||||||||||||||
| 33,827 | 20,395 | 5,330 | 18,389 | 9,158 | 3,870 | 90,969 | 26,002 | 8,644 | 4,293 | 15,651 | 4,543 | 1,648 | 60,781 | |||||||||||||||||||||||||||||||||||||||||
| 45,063 | 12,877 | 13,997 | 11,044 | 15,485 | 9,239 | 107,705 | 32,772 | 7,100 | 10,663 | 9,564 | 8,066 | 4,773 | 72,938 | |||||||||||||||||||||||||||||||||||||||||
| 20,734 | 5,535 | 7,039 | 4,165 | 5,479 | 4,391 | 47,343 | 16,027 | 3,309 | 5,130 | 3,484 | 2,648 | 1,926 | 32,524 | |||||||||||||||||||||||||||||||||||||||||
| 24,329 | 7,342 | 6,958 | 6,879 | 10,006 | 4,848 | 60,362 | 16,745 | 3,791 | 5,533 | 6,080 | 5,418 | 2,847 | 40,414 | |||||||||||||||||||||||||||||||||||||||||
| 5,762 | 2,883 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| – | 136 | 26 | 753 | – | 466 | 1,381 | – | 94 | 15 | 557 | – | 307 | 973 | |||||||||||||||||||||||||||||||||||||||||
Additional information concerning proved reserves
Proved reserves can be either developed or undeveloped. Group proved reserves at December 31, 2003 were divided into 56% developed and 44% undeveloped on a barrel of oil equivalent basis.
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 1,270 million barrels of crude oil and natural gas liquids and 8,530 thousand million standard cubic feet of gas.
A portion of our oil reserves is located in countries that are part of OPEC. As such, our oil production rates may be subject to limitations imposed by OPEC quotas. Our proved oil reserves in OPEC countries totalled some 2,020 million barrels at December 31, 2003.
Supplementary Information – Derivatives and other Financial Instruments and Derivative Commodity Instruments
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-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
| 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 | ||||||||||||||||||||||
| 2002 | $ million | ||||||||||||||||||||||||||||
| 2008 | |||||||||||||||||||||||||||||
| 2003 | 2004 | 2005 | 2006 | 2007 | and after | Total | |||||||||||||||||||||||
| Fixed rate US dollar debt securities | 4 | 41 | 62 | 8 | 100 | 108 | 323 | ||||||||||||||||||||||
| average interest rate | 0.9% | 7.6% | 5.7% | 7.0% | 7.2% | 6.7% | |||||||||||||||||||||||
| Variable rate US dollar debt securities | 9 | – | – | – | – | – | 9 | ||||||||||||||||||||||
| average interest rate | 1.4% | – | – | – | – | – | |||||||||||||||||||||||
| Fixed rate euro debt securities | – | 21 | – | 66 | 38 | 166 | 291 | ||||||||||||||||||||||
| average interest rate | – | 5.8% | – | 6.5% | 5.3% | 5.5% | |||||||||||||||||||||||
| Fixed rate UK pound debt securities | – | – | 16 | – | 4 | 18 | 38 | ||||||||||||||||||||||
| average interest rate | – | – | 8.5% | – | 8.0% | 6.3% | |||||||||||||||||||||||
| Fixed rate Canadian dollar debt securities | 15 | 4 | – | – | – | 15 | 34 | ||||||||||||||||||||||
| average interest rate | 6.5% | 9.0% | – | – | – | 9.6% | |||||||||||||||||||||||
| Fixed rate Swedish krone debt securities | – | 2 | – | – | – | 5 | 7 | ||||||||||||||||||||||
| average interest rate | – | 5.0% | – | – | – | 6.8% | |||||||||||||||||||||||
| Other fixed rate debt securities | 4 | – | – | – | – | – | 4 | ||||||||||||||||||||||
| average interest rate | 37.1% | – | – | – | – | – | |||||||||||||||||||||||
| Other variable rate debt securities | 28 | – | – | – | – | – | 28 | ||||||||||||||||||||||
| average interest rate | 9.6% | – | – | – | – | – | |||||||||||||||||||||||
| Total | 60 | 68 | 78 | 74 | 142 | 312 | 734 | ||||||||||||||||||||||
Equity securities held for purposes other than trading
Debt
| 2003 | $ million | ||||||||||||||||||||||||||||
| 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | Total | |||||||||||||||||||||||
| and after | |||||||||||||||||||||||||||||
| 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 2004 includes $711 million of UK pound debt (with an average interest rate of 8.6%) and $452 million of Euro debt (with an average interest rate of 2.1%). The fixed rate European currency debt expected to mature in 2006 is UK pound debt (with an average interest rate of 4.3%). The fixed rate European currency debt expected to mature in 2007 and 2008 is Euro debt with an average interest rate of 3.3% and 3.5% respectively.
Variable rate European currency debt expected to mature in 2004 includes $1,042 million of UK pound debt with an average interest rate of 2.1%. Other fixed rate debt expected to mature after 2008 includes $167 million of Malaysian Ringgit at an average interest rate of 8.0%. Other variable rate debt expected to mature in 2004 includes $714 million of Canadian dollar debt with an average interest rate of 3.1%. Other variable rate debt expected to mature in 2005 includes $106 million of Canadian dollar debt at an average interest rate of 2.1%.
| 2002 | $ million | ||||||||||||||||||||||||||||
| 2003 | 2004 | 2005 | 2006 | 2007 | 2008 | Total | |||||||||||||||||||||||
| and after | |||||||||||||||||||||||||||||
| Fixed rate US dollar debt | 7,428 | 2 | 827 | 612 | 1,237 | 256 | 10,362 | ||||||||||||||||||||||
| average interest rate | 2.0% | 4.5% | 4.6% | 3.1% | 4.7% | 9.4% | |||||||||||||||||||||||
| Variable rate US dollar debt | 2,405 | 85 | 24 | 25 | 107 | 429 | 3,075 | ||||||||||||||||||||||
| average interest rate | 2.7% | 1.5% | 2.3% | 2.4% | 2.4% | 4.9% | |||||||||||||||||||||||
| Fixed rate European debt | 1,047 | – | – | 603 | 785 | 9 | 2,444 | ||||||||||||||||||||||
| average interest rate | 3.9% | – | – | 4.3% | 3.5% | 4.1% | |||||||||||||||||||||||
| Variable rate European debt | 701 | 839 | 9 | – | – | – | 1,549 | ||||||||||||||||||||||
| average interest rate | 3.9% | 3.2% | 3.8% | – | – | – | |||||||||||||||||||||||
| Other fixed rate debt | 157 | 69 | 38 | – | – | 55 | 319 | ||||||||||||||||||||||
| average interest rate | 7.9% | 1.6% | 8.9% | – | – | 6.3% | |||||||||||||||||||||||
| Other variable rate debt | 1,071 | 195 | 28 | 28 | 24 | 31 | 1,377 | ||||||||||||||||||||||
| average interest rate | 4.8% | 2.5% | 4.6% | 4.6% | 4.6% | 4.6% | |||||||||||||||||||||||
| Total | 12,809 | 1,190 | 926 | 1,268 | 2,153 | 780 | 19,126 | ||||||||||||||||||||||
Interest rate swaps/forward rate agreements
| 2003 | $ million | |||||||||||||||||||||||||||
| 2004 | 2005 | 2006 | 2007 | 2008 | Total contract/ | Estimated | ||||||||||||||||||||||
| 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 | |||||||||||||||||||||
| 2002 | $ million | |||||||||||||||||||||||||||
| 2003 | 2005 | 2006 | 2007 | 2008 | Total contract/ | Estimated | ||||||||||||||||||||||
| and after | notional amount | fair value | ||||||||||||||||||||||||||
| US dollar | ||||||||||||||||||||||||||||
| Fixed to Variable: contract/notional amount | 500 | 919 | 600 | 1,152 | – | 3,171 | 201 | |||||||||||||||||||||
| average pay rate | 1.7% | 2.8% | 1.5% | 1.7% | – | |||||||||||||||||||||||
| average receive rate | 5.0% | 5.7% | 3.1% | 4.8% | – | |||||||||||||||||||||||
| Variable to Fixed: contract/notional amount | 288 | 100 | – | 72 | 88 | 548 | (38 | ) | ||||||||||||||||||||
| average pay rate | 6.0% | 4.7% | – | 7.2% | 7.8% | |||||||||||||||||||||||
| average receive rate | 2.9% | 2.0% | – | 4.8% | 2.5% | |||||||||||||||||||||||
| UK pound | ||||||||||||||||||||||||||||
| Fixed to Variable: contract/notional amount | 8 | – | 603 | – | – | 611 | – | |||||||||||||||||||||
| average pay rate | 4.7% | – | 3.9% | – | – | |||||||||||||||||||||||
| average receive rate | 8.9% | – | 4.3% | – | – | |||||||||||||||||||||||
| Other currencies | ||||||||||||||||||||||||||||
| Fixed to Variable: contract/notional amount | 16 | – | – | – | – | 16 | – | |||||||||||||||||||||
| average pay rate | 2.7% | – | – | – | – | |||||||||||||||||||||||
| average receive rate | 2.8% | – | – | – | – | |||||||||||||||||||||||
| Variable to Fixed: contract/notional amount | 4 | – | – | – | – | 4 | – | |||||||||||||||||||||
| average pay rate | 12.8% | – | – | – | – | |||||||||||||||||||||||
| average receive rate | 12.3% | – | – | – | – | |||||||||||||||||||||||
| Total | 816 | 1,019 | 1,203 | 1,224 | 88 | 4,350 | 163 | |||||||||||||||||||||
At December 31, 2002, a Group company also held an option to enter into a euro fixed (3.8%) to a variable (2.8%) interest rate swap maturing in 2003 with a face value of $1.2 billion and a fair value of $6 million. This was exercised on January 2, 2003.
Foreign exchange contracts
| 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 krona | 6.67 | 672 | (18 | ) | ||||||||
| Buy Singapore dollar/sell US dollar | 0.58 | 381 | 2 | |||||||||
| Buy US dollar/sell Danish krona | 5.88 | 239 | (3 | ) | ||||||||
| Buy US dollar/sell Swedish krona | 7.14 | 429 | (3 | ) | ||||||||
| Buy Swedish krona/sell US dollar | 0.14 | 217 | 1 | |||||||||
| Buy euro/sell Norwegian krona | 8.33 | 127 | 5 | |||||||||
| Buy US dollar/sell Philippine pesor | 55.87 | 118 | – | |||||||||
| Other contracts | 1,074 | 25 | ||||||||||
| Total | 12,845 | 86 | ||||||||||
| 2002 (all contracts mature in 2003) | $ million | |||||||||||
| Average contractual | Contract/notional | Estimated | ||||||||||
| exchange rate | amount | fair value | ||||||||||
| Buy US dollar/sell UK pound | 0.64 | 7,170 | (138 | ) | ||||||||
| Buy US dollar/sell euro | 1.01 | 2,320 | (118 | ) | ||||||||
| Buy euro/sell US dollar | 1.03 | 677 | 13 | |||||||||
| Buy Canadian dollar/sell US dollar | 0.64 | 450 | (6 | ) | ||||||||
| Buy UK pound/sell US dollar | 1.55 | 427 | 14 | |||||||||
| Buy US dollar/sell Australian dollar | 1.77 | 392 | (1 | ) | ||||||||
| Buy Swiss franc/sell US dollar | 0.68 | 283 | 14 | |||||||||
| Buy US dollar/sell Norwegian krona | 7.06 | 209 | (3 | ) | ||||||||
| Buy Singapore dollar/sell US dollar | 0.57 | 180 | 1 | |||||||||
| Buy US dollar/sell Danish krona | 7.18 | 159 | (2 | ) | ||||||||
| Buy US dollar/sell Swedish krona | 8.84 | 154 | (1 | ) | ||||||||
| Buy US dollar/sell Hong Kong dollar | 7.80 | 131 | – | |||||||||
| Other contracts | 1,005 | (2 | ) | |||||||||
| Total | 13,557 | (229 | ) | |||||||||
Currency swaps/options
| 2003 | $ million | |||||||||||||||||||||||||||||||||||
| Average | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | Total contract/ | Estimated | ||||||||||||||||||||||||||||
| contractual | and after | notional amount | fair value | |||||||||||||||||||||||||||||||||
| exchange rate | ||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||
| 2002 | $ million | |||||||||||||||||||||||||||||||||||
| Average | 2003 | 2004 | 2005 | 2006 | 2007 | 2008 | Total contract/ | Estimated | ||||||||||||||||||||||||||||
| contractual | and after | notional amount | fair value | |||||||||||||||||||||||||||||||||
| exchange rate | ||||||||||||||||||||||||||||||||||||
| Buy UK pound/sell euro | 1.57 | – | 1,085 | – | – | – | – | 1,085 | 1 | |||||||||||||||||||||||||||
| Buy US dollar/sell Canadian dollar | 1.54 | 326 | 117 | 64 | 59 | 26 | 9 | 601 | 13 | |||||||||||||||||||||||||||
| Buy US dollar/sell euro | 1.09 | – | 461 | – | – | – | – | 461 | 63 | |||||||||||||||||||||||||||
| Buy Australian dollar/sell US dollar | 0.62 | – | 289 | – | – | – | – | 289 | 3 | |||||||||||||||||||||||||||
| Buy Canadian dollar/sell US dollar | 0.64 | 210 | 55 | 9 | – | 3 | – | 277 | (2 | ) | ||||||||||||||||||||||||||
| Buy US dollar/sell Brazilian real | 3.53 | 65 | 50 | 42 | 4 | 41 | – | 202 | 25 | |||||||||||||||||||||||||||
| Buy US dollar/sell Swiss franc | 1.50 | 200 | – | – | – | – | – | 200 | 30 | |||||||||||||||||||||||||||
| Other contracts | 123 | – | 27 | – | – | – | 150 | 9 | ||||||||||||||||||||||||||||
| Total | 924 | 2,057 | 142 | 63 | 70 | 9 | 3,265 | 142 | ||||||||||||||||||||||||||||
In conjunction with natural gas marketing activities, Group companies held put and call options to buy Canadian dollars and sell US dollars at December 31, 2002 each with a contract/notional amount of $0.1 billion and a total estimated fair value of $(1) million and expected maturity in 2003.
Commodity derivatives
Commodity swaps held for trading purposes
| 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 | – | – | ||||||||||||||||||||||||
| 2003continued | $ 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, 2003 with a contract/notional amount of $10 million (2002: $166 million) and an estimated fair value of $(1) million (2002: $5 million) and expected maturity in 2004 (2003 – 2004).
Commodity swaps held for purposes other than trading
| 2002 | $ million | ||||||||||||||||||||||||||||||||
| 2003 | 2004 | 2005 | 2006 | 2007 | 2008 | Total contract/ | Estimated | ||||||||||||||||||||||||||
| and after | and after | notional amount | fair value | ||||||||||||||||||||||||||||||
| Crude oil swaps | |||||||||||||||||||||||||||||||||
| (a) Variable price to variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 1,374 | 62 | – | – | – | – | 1,436 | (3 | ) | ||||||||||||||||||||||||
| Volume (million barrels “m bbl”) | 55 | 3 | – | – | – | – | |||||||||||||||||||||||||||
| average pay/receive price ($/bbl) | 28.8/28.7 | 22.8/22.8 | – | – | – | – | |||||||||||||||||||||||||||
| (b) Buy fixed price/sell variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 970 | 148 | 20 | 2 | – | – | 1,140 | 70 | |||||||||||||||||||||||||
| Volume (m bbl) | 49 | 6 | 1 | * | – | – | |||||||||||||||||||||||||||
| average pay/receive price ($/bbl) | 19.9/21.3 | 23.6/23.7 | 22.8/23.6 | 21.8/21.3 | – | – | |||||||||||||||||||||||||||
| (c) Buy variable price/sell fixed price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 886 | 57 | 22 | – | – | – | 965 | (90 | ) | ||||||||||||||||||||||||
| Volume (m bbl) | 57 | 4 | 1 | – | – | – | |||||||||||||||||||||||||||
| average pay/receive ($/bbl) | 17.3/15.6 | 15.5/15.6 | 23.6/23.0 | – | – | – | |||||||||||||||||||||||||||
| Oil products swaps | |||||||||||||||||||||||||||||||||
| (a) Variable price to variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 287 | – | – | – | – | – | 287 | (1 | ) | ||||||||||||||||||||||||
| Volume (m bbl) | 70 | – | – | – | – | – | |||||||||||||||||||||||||||
| average pay/receive ($/bbl) | 23.0/19.8 | – | – | – | – | – | |||||||||||||||||||||||||||
| (b) Buy fixed price/sell variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 613 | – | 1 | – | – | – | 614 | 41 | |||||||||||||||||||||||||
| Volume (m bbl) | 76 | – | * | – | – | – | |||||||||||||||||||||||||||
| average pay/receive ($/bbl) | 8.1/8.6 | – | 19.1/17.6 | – | – | – | |||||||||||||||||||||||||||
| (c) Buy variable price/sell fixed price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 681 | – | – | – | – | – | 681 | (42 | ) | ||||||||||||||||||||||||
| Volume (m bbl) | 88 | – | – | – | – | – | |||||||||||||||||||||||||||
| average pay/receive ($/bbl) | 8.2/7.7 | – | – | – | – | – | |||||||||||||||||||||||||||
| Electricity swaps | |||||||||||||||||||||||||||||||||
| (a) Buy fixed price/sell variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 261 | 66 | 36 | 29 | 18 | – | 410 | 66 | |||||||||||||||||||||||||
| Volume (thousand megawatt hours “MMwh”) | 6 | 2 | 1 | 1 | ** | – | |||||||||||||||||||||||||||
| average pay/receive ($/Mwh) | 47.2/54.4 | 39.4/49.8 | 45.2/52.7 | 50.1/53.5 | 49.8/52.7 | – | |||||||||||||||||||||||||||
| (b) Buy variable price/sell fixed price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 320 | 91 | 70 | 54 | 36 | – | 571 | (54 | ) | ||||||||||||||||||||||||
| Volume (MMwh) | 7 | 2 | 1 | 1 | 1 | – | |||||||||||||||||||||||||||
| average pay/receive ($/Mwh) | 53.5/48.4 | 54.8/50.0 | 53.8/50.7 | 52.9/49.3 | 53.1/48.9 | – | |||||||||||||||||||||||||||
| Natural gas swaps | |||||||||||||||||||||||||||||||||
| (a) Buy fixed price/sell variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 3,803 | 925 | 184 | 87 | 32 | – | 5,031 | 895 | |||||||||||||||||||||||||
| Volume (thousand million cubic feet “bcf”) | 938 | 234 | 48 | 22 | 6 | – | |||||||||||||||||||||||||||
| average pay/receive ($/thousand cf) | 4.1/4.8 | 4.0/4.5 | 3.8/4.3 | 3.9/4.5 | 5.4/5.5 | – | |||||||||||||||||||||||||||
| (b) Buy variable price/sell fixed price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 3,951 | 803 | 121 | 25 | 4 | 11 | 4,915 | (831 | ) | ||||||||||||||||||||||||
| Volume (bcf) | 967 | 205 | 33 | 7 | 1 | 3 | |||||||||||||||||||||||||||
| average pay/receive ($/thousand cf) | 4.8/4.1 | 4.4/3.9 | 4.1/3.7 | 4.0/3.5 | 4.2/4.3 | 4.2/4.3 | |||||||||||||||||||||||||||
| NGL gas basis swaps | |||||||||||||||||||||||||||||||||
| (a) Buy fixed price/sell variable price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 373 | 88 | 46 | 24 | 15 | 4 | 550 | (283 | ) | ||||||||||||||||||||||||
| Volume (m bbl) | 1,033 | 246 | 114 | 63 | 40 | 18 | |||||||||||||||||||||||||||
| average pay/receive ($/bbl) | 0.36/0.16 | 0.36/0.18 | 0.4/0.25 | 0.38/0.27 | 0.38/0.27 | 0.23/0.09 | |||||||||||||||||||||||||||
| (b) Buy variable price/sell fixed price contracts: | |||||||||||||||||||||||||||||||||
| contract/notional amount ($ million) | 344 | 73 | 30 | 15 | 9 | 9 | 480 | 277 | |||||||||||||||||||||||||
| Volume (m bbl) | 994 | 210 | 79 | 40 | 26 | 27 | |||||||||||||||||||||||||||
| average pay/receive ($/bbl) | 0.16/0.35 | 0.12/0.35 | 0.14/0.38 | 0.17/0.38 | 0.19/0.35 | 0.13/0.33 | |||||||||||||||||||||||||||
| Total | 17,080 | 45 | |||||||||||||||||||||||||||||||
| * | less than one million barrels |
| ** | less than one thousand megawatt hours |
Commodity options held for trading purposes
| 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 |
Group companies also held chemical and oil products options/swaptions at December 31, 2003 with a contract/notional amount of $1 million (2002: $51 million) and estimated fair value less than $1 million (2002: less than $1 million) and expected maturity in 2004 (2003 – 2004).
| 2002 | $ million | ||||||||||||||||||||
| 2003 | 2004 | 2005 | Total contract/ | Estimated | |||||||||||||||||
| notional amount | fair value | ||||||||||||||||||||
| Crude oil buy calls | |||||||||||||||||||||
| contract/notional amount ($ million) | 711 | 13 | – | 724 | 57 | ||||||||||||||||
| volume (m bbl) | 26 | * | – | ||||||||||||||||||
| average strike price ($/bbl) | 27.6 | 23.1 | – | ||||||||||||||||||
| Crude oil sell calls | |||||||||||||||||||||
| contract/notional amount ($ million) | 620 | 59 | 1 | 680 | (70 | ) | |||||||||||||||
| volume (m bbl) | 23 | 2 | * | ||||||||||||||||||
| average strike price ($/bbl) | 26.5 | 27.2 | 25.1 | ||||||||||||||||||
| Crude oil buy put | |||||||||||||||||||||
| contract/notional amount ($ million) | 416 | 90 | – | 506 | 19 | ||||||||||||||||
| volume (m bbl) | 21 | 4 | – | ||||||||||||||||||
| average strike price ($/bbl) | 20.2 | 20.4 | – | ||||||||||||||||||
| Crude oil sell put | |||||||||||||||||||||
| contract/notional amount ($ million) | 396 | 49 | – | 445 | (19 | ) | |||||||||||||||
| volume (m bbl) | 19 | 2 | – | ||||||||||||||||||
| average strike price ($/bbl) | 21.3 | 21.0 | – | ||||||||||||||||||
| Natural gas buy call | |||||||||||||||||||||
| contract/notional amount ($ million) | 7,284 | 814 | 51 | 8,149 | 654 | ||||||||||||||||
| volume (bcf) | 1,375 | 150 | 12 | ||||||||||||||||||
| average strike price ($/thousand cf) | 5.3 | 5.4 | 4.3 | ||||||||||||||||||
| Natural gas sell call | |||||||||||||||||||||
| contract/notional amount ($ million) | 5,336 | 654 | 48 | 6,038 | (468 | ) | |||||||||||||||
| volume (bcf) | 971 | 114 | 8 | ||||||||||||||||||
| average strike price ($/thousand cf) | 5.5 | 5.7 | 5.9 | ||||||||||||||||||
| Natural gas buy put | |||||||||||||||||||||
| contract/notional amount ($ million) | 3,975 | 411 | 47 | 4,433 | 132 | ||||||||||||||||
| volume (bcf) | 1,157 | 124 | 13 | ||||||||||||||||||
| average strike price ($/thousand cf) | 3.4 | 3.3 | 3.7 | ||||||||||||||||||
| Natural gas sell put | |||||||||||||||||||||
| contract/notional amount ($ million) | 5,481 | 467 | 71 | 6,019 | (209 | ) | |||||||||||||||
| volume (bcf) | 1,483 | 130 | 21 | ||||||||||||||||||
| average strike price ($/thousand cf) | 3.7 | 3.6 | 3 | ||||||||||||||||||
| Total | 26,994 | 96 | |||||||||||||||||||
Commodity options held for purposes other than trading
Commodity futures held for trading purposes
| 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 | – | ||||||||||||||||||
| 2003 | $ million | ||||||||||||||||||||
| 2004 | 2005 | 2006 | Total contract/ | Estimated | |||||||||||||||||
| notional amount | fair value | ||||||||||||||||||||
| 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 ($/bbl) | 28.9 | 25.2 | – | ||||||||||||||||||
| Nymex oil product futures | |||||||||||||||||||||
| (a) Short contracts: | |||||||||||||||||||||
| contract/notional amount ($ 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. |
| 2002 | $ million | ||||||||||||||||||||
| Total contract/ | Estimated | ||||||||||||||||||||
| 2003 | 2004 | 2005 | notional amount | fair value | |||||||||||||||||
| IPE Brent futures | |||||||||||||||||||||
| (a) Short contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 421 | – | – | 421 | (24 | ) | |||||||||||||||
| volume (m bbl) | 16 | – | – | ||||||||||||||||||
| weighted average price ($/bbl) | 26 | – | – | ||||||||||||||||||
| (b) Long contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 184 | – | – | 184 | 20 | ||||||||||||||||
| volume (m bbl) | 7 | – | – | ||||||||||||||||||
| weighted average price ($/bbl) | 26 | – | – | ||||||||||||||||||
| IPE Gasoil futures | |||||||||||||||||||||
| (a) Short contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 417 | – | – | 417 | (31 | ) | |||||||||||||||
| volume (m bbl) | 13 | – | – | ||||||||||||||||||
| weighted average price ($/bbl) | 32 | – | – | ||||||||||||||||||
| (b) Long contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 137 | – | – | 137 | 6 | ||||||||||||||||
| volume (m bbl) | 5 | – | – | ||||||||||||||||||
| weighted average price ($/bbl) | 29 | – | – | ||||||||||||||||||
| Nymex crude oil futures | |||||||||||||||||||||
| (a) Short contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 1,836 | 50 | – | 1,886 | (100 | ) | |||||||||||||||
| volume (m bbl) | 65 | 2 | – | ||||||||||||||||||
| weighted average price ($/bbl) | 28 | 23 | – | ||||||||||||||||||
| (b) Long contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 2,003 | 20 | – | 2,023 | 140 | ||||||||||||||||
| volume (m bbl) | 73 | * | – | ||||||||||||||||||
| weighted average price ($/bbl) | 28 | 23 | – | ||||||||||||||||||
| Nymex oil product futures | |||||||||||||||||||||
| (a) Short contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 1,312 | – | – | 1,312 | (78 | ) | |||||||||||||||
| volume (m bbl) | 51 | – | – | ||||||||||||||||||
| weighted average price ($/bbl) | 26 | – | – | ||||||||||||||||||
| (b) Long contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 1,129 | – | – | 1,129 | 41 | ||||||||||||||||
| volume (m bbl) | 45 | – | – | ||||||||||||||||||
| weighted average price ($/bbl) | 25 | – | – | ||||||||||||||||||
| Nymex natural gas futures | |||||||||||||||||||||
| (a) Short contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 1,452 | 278 | – | 1,730 | (293 | ) | |||||||||||||||
| volume (bcf) | 358 | 71 | – | ||||||||||||||||||
| weighted average price ($/thousand cf) | 4 | 4 | – | ||||||||||||||||||
| (b) Long contracts: | |||||||||||||||||||||
| contract/notional amount ($ million) | 1,411 | 309 | 24 | 1,744 | 284 | ||||||||||||||||
| volume (bcf) | 348 | 78 | 6 | ||||||||||||||||||
| weighted average price ($/thousand cf) | 4 | 4 | 4 | ||||||||||||||||||
| Total | 10,983 | (35 | ) | ||||||||||||||||||
| * | less than one million barrels |
Group companies also held electricity futures contracts at December 31, 2002 with a contract/notional amount of $4 million and an estimated fair value of $1 million with expected maturity in 2003.
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, 2003 and 2002 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, 2003 and 2002 respectively, purchase contracts exceed the sales contracts with the same maturity date.
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, 2003 | 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 | ||||
