Royal Dutch Shell

Our purpose

The objectives of the Shell Group are to engage safely, responsibly, efficiently and profitably in oil, gas, oil products, chemicals and other selected businesses and to participate in the search for and development of other sources of energy to meet evolving customer needs and the world’s growing demand for energy.

We believe that oil and gas will be integral to the global energy needs for economic development for many decades to come. Our role is to ensure that we extract and deliver them in environmentally and socially responsible ways, safely and profitably.

We seek a high standard of performance, maintaining a strong long-term and growing position in the competitive environments in which we choose to operate.

We aim to work closely with our stakeholders to advance more efficient and sustainable use of energy and natural resources.

This Report combines the Annual Report and Accounts and the Annual Report on Form 20-F (“Report”) for the year ended December 31, 2006, for Royal Dutch Shell plc (“Royal Dutch Shell”) and its subsidiaries. It presents the Consolidated Financial Statements of Royal Dutch Shell (pages 103–160) and the parent company-only Financial Statements of Royal Dutch Shell (pages 191–207). This Report complies with all applicable UK regulations. This Report also includes the disclosure included in the Annual Report on Form 20-F for the year ended December 31, 2006 as filed with the U.S. Securities and Exchange Commission (“SEC”). Cross references to Form 20-F are set out on the previous page of this Report.

In this Report “Group” is defined as Royal Dutch Shell together with all of its consolidated subsidiaries. The expressions “Shell”, “Group”, “Shell Group” and “Royal Dutch Shell” are sometimes used for convenience where references are made to the Group or Group companies in general. Likewise, the words “we”, “us” and “our” are also used to refer to Group companies in general or to those who work for them. 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 Shell either directly or indirectly has control, by having either a majority of the voting rights or the right to exercise a controlling influence. The companies in which the Group has significant influence but not control are referred to as “associated companies” or “associates” and companies in which the Group has joint control are referred to as “jointly controlled entities”. In this Report, associates and jointly controlled entities are also referred to as “equity accounted investments”.

The expression “operating companies” as used in the Report refers to those Group and equity accounted investments that are engaged in the exploration for and extraction of oil and natural gas and delivery of these hydrocarbons to market, the marketing and trading of natural gas and electricity, the conversion of natural gas to liquids and the refining of crude oil into products including fuels, lubricants, petrochemicals, and other industry segments such as Hydrogen and Renewables. The term “Group interest” is used for convenience to indicate the direct and/or indirect equity interest held by the Group in a venture, partnership or company (i.e., after exclusion of all third-party interests).

Except as otherwise specified, the figures shown in 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, 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 equity accounted investments to which Group companies are entitled or which is proportionate to the Group interest in those companies.

Except as otherwise stated, the Financial Statements contained in this Report have been prepared in accordance with the provisions of the Companies Act 1985, Article 4 of the International Accounting Standards (IAS) Regulation and with International Financial Reporting Standards (“IFRS”) as adopted by the European Union. As applied to Royal Dutch Shell, there are no material differences with IFRS as issued by the International Accounting Standards Board. Prior to the Shell Group’s date of transition to IFRS of January 1, 2004 it prepared Consolidated Financial Statements in accordance with US Generally Accepted Accounting Principles (“US GAAP”). Tables and disclosure that provide data over a five year period show 2006, 2005 and 2004 on an IFRS basis and 2003 and 2002 on a US GAAP basis.

The Consolidated Financial Statements of Royal Dutch Shell and its subsidiaries have been prepared using the carry-over basis to account for the

Unification (see page 4) and on the basis that the resulting structure was in place throughout the periods presented.

Except as otherwise noted, the figures shown in this Report are stated in US dollars. As used herein all references to ‘‘dollars’’ or ‘‘$’’ are to the US currency.

The Operating and Financial Review (“OFR”) and other sections of this Report contain forward-looking statements concerning the financial condition, results of operations and businesses of Royal Dutch Shell. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Royal Dutch Shell to market risks and statements expressing management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as ‘‘anticipate’’, ‘‘believe’’, ‘‘could’’, ‘‘estimate’’, ‘‘expect’’, ‘‘intend’’, ‘‘may’’, ‘‘plan’’, ‘‘objectives’’, ‘‘outlook’’, ‘‘probably’’, ‘‘project’’, ‘‘will’’, ‘‘seek’’, ‘‘target’’, ‘‘risks’’, ‘‘goals’’, ‘‘should’’ and similar terms and phrases. There are a number of factors that could affect the future operations of Royal Dutch Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this Report, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for the Group’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserve estimates; (f) loss of market and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including potential litigation and regulatory effects arising from recategorisation of reserves; (k) economic and financial market conditions in various countries and regions; (l) political risks, project delay or advancement, approvals and cost estimates; and (m) changes in trading conditions. All forward-looking statements contained in this Report are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of this Report. Neither Royal Dutch Shell nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this Report.

This Report contains references to Shell’s website. These references are for the readers’ convenience only. Shell is not incorporating by reference any information posted on www.shell.com.

DOCUMENTS ON DISPLAY

Documents concerning Royal Dutch Shell, or its predecessors for reporting purposes, which are referred to in this Report have been filed with the SEC and may be examined and copied at the public reference facility maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. For further information on the operation of the public reference room and the copy charges, please call the SEC at (800) SEC-0330. All of the SEC filings made electronically by the Group are available to the public at the SEC website at www.sec.gov (commission file number 1-32575). This Report, as well as the Annual Review, is also available, free of charge, at www.shell.com/annualreport or at the offices of Royal Dutch Shell in The Hague, The Netherlands and London, UK. You may also obtain copies of this Report, free of charge, by mail.

Chairman’s message

“

As Shell marks its centenary year, I hope shareholders share my excitement at being part of a business that is successfully playing its part in meeting the world’s energy needs.

”

 

 

In this, my first message to shareholders, I would like to share with you some of the impressions I have gained since I became Chairman of Royal Dutch Shell plc in 2006.

The energy business, as I am seeing first-hand, is at the heart of some of the most important economic, environmental and social issues facing the world. Reliable and affordable supplies of energy are essential for economic growth and for raising living standards amongst the world’s poorest people. Equally, as the growing concern over climate change shows, providing those energy supplies in a way that minimises the impact on the environment is one of the greatest challenges we all face.

Shell is playing its part in addressing those challenges. Our business strategy is focused on finding and producing the resources to help meet the world’s growing demand for energy, and doing so in a responsible way. This includes researching and developing projects to reduce carbon dioxide emissions and ensuring that the operations at individual Shell facilities meet the highest environmental standards. The Board’s Social Responsibility Committee has a very direct role in overseeing the company’s approach to these issues and makes regular visits to Shell locations to see how environmental and social challenges are being met.

I see the Board’s role as providing both support and challenge to the Chief Executive and his team in their work; and ensuring that Shell continues to provide shareholders with the returns they expect. I believe that the structures put in place since our 2005 unification provide an effective framework for the Board to fulfil that role. I would like to pay a particular tribute to my predecessor as Chairman, Aad Jacobs, for his role in seeing the company through a challenging period.

Across Shell I have met dedicated and committed people working in a productive corporate culture with very strong values. I have been particularly impressed with the way they are responding to the pace of change in the energy industry; how they are delivering strong results; and how they are putting in place plans to secure the future growth of Shell’s business.

As Shell marks its centenary year, I hope shareholders share my excitement at being part of a business that is successfully playing its part in meeting the world’s energy needs.

Jorma Ollila
Chairman

Chief Executive’s review

Shell performed well in 2006. Our financial position is strong and we posted record income of $26.3 billion, returning $16.3 billion to shareholders. We built on our achievements of 2005 by focusing on delivery and growth, laying solid foundations for our future.

Our strategy of more upstream, profitable downstream is on track. We made good progress in rejuvenating our diverse portfolio. Our upstream exploration efforts are paying off. We invested large stakes in major integrated long-life projects that will generate cash for decades to come. Downstream, we added to our growth portfolio, especially in China.

The security situation in Nigeria – which has shut significant production in the Delta region – remains a serious concern and we do not know when production will resume. Our deep water projects in Nigeria really delivered in 2006, partially offsetting lost production onshore. In Sakhalin, we cleared the way forward by agreeing to partner with Gazprom on what is the world’s largest integrated oil and gas project under construction.

Our Exploration & Production business performed well. Earnings were up 7% from 2005 at $15.2 billion. We added approximately 2 billion barrels of oil equivalent to our proved oil and gas reserves and proven mining reserves. The bid for the minority shares in Shell Canada and expansion of the Athabasca Oil Sands Project reaffirm our commitment to maintaining a leading position in unconventional oil.

Our Gas & Power division delivered particularly strong earnings growth of 68% at $2.7 billion. We are proceeding with construction of the Pearl Gas to Liquids (GTL) plant in Qatar, the largest such plant in the world. Sales of liquefied natural gas (LNG) grew 14%, strengthening our leading position in the LNG markets of North America, Asia Pacific and Europe.

Downstream we are investing in major manufacturing projects, particularly in Asia. The expansion of our petrochemicals complex in Singapore and a successful start-up of the Nanhai complex in China strengthen our position in Asia’s dynamic markets. We acquired a 75% interest in China’s leading lubricants manufacturer and marketer, making Shell the leading lubricants company in China. Plans to expand our Port Arthur facilities would create the largest refinery in the USA.

As we operate in ever more demanding environments, safety becomes a bigger challenge. We continue to place great emphasis on training to support safety’s role as a key component of operational excellence. Our safety performance in 2006 was mixed, however, with an increase in fatalities. We have responded by reinforcing our safety focus through a dedicated global safety function that will improve compliance with standards and procedures worldwide.

We remain committed to developing one substantial business in alternative energy. We launched our first offshore wind farm in the North Sea off the Netherlands. We continue to make progress on projects in hydrogen, advanced solar technology and second-generation biofuels.

I am convinced that technology is key to delivering our business strategy and the complex projects of the future. In 2006 we appointed a Chief Technology Officer to head our technology drive with seven Chief Scientists and thousands of technical staff at our worldwide technology centres, including our new one in Bangalore, India. We also published Shell’s first Technology Report.

Technology is central to managing carbon dioxide (CO ₂ ) emissions. Within Shell we are pursuing a range of activities to address the challenge of CO ₂ , including improving efficiency, reducing flaring and exploring opportunities for CO ₂ capture and storage.

None of this would be possible without the efforts of our people, who I would like to thank. Our strong performance in 2006 prepares us well for the increasingly fierce competition in the energy industry and confirms our ability to deliver results to both shareholders and our partners. In 2007 we will strive to maintain our momentum by continuing to focus on delivery and growth.

Jeroen van der Veer
Chief Executive

“

Our strong performance in 2006 confirms
our ability to deliver results. This is the basis
for our growth.

”

 

Unification of Royal Dutch and Shell Transport

In 2005, Royal Dutch Shell plc (Royal Dutch Shell) became the single parent company of Royal Dutch Petroleum Company (“Royal Dutch”) and of The “Shell” Transport and Trading Company, p.l.c. (“Shell Transport”) the two former public parent companies of the Group (the “Unification”).

Immediately after the Unification each former Royal Dutch and Shell Transport shareholder who participated in the Unification held the same economic interest in Royal Dutch Shell as the shareholder held in the Group immediately prior to implementation of the Unification. Accordingly, the Unification has been accounted for using a carry-over basis of the historical costs of the assets and liabilities of Royal Dutch, Shell Transport and the other companies comprising the Group.

4   Royal Dutch Shell plc

 

Selected financial data

The selected financial data set out below is derived, in part, from the Consolidated Financial Statements. The selected data should be read in conjunction with the Consolidated Financial Statements and related Notes, as well as the Operating and Financial Review in this Report.

The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS), which differ in certain respects from US GAAP. For a summary of the material differences between IFRS and US GAAP, see Note 38 to the Consolidated Financial Statements.

Except as otherwise stated, all selected financial data are prepared in accordance with IFRS.

[A]		Prior to 2004, financial statements prepared in accordance with IFRS are not available. Going forward, additional years will be presented until the usual five years of data is provided.

[A]

The difference between capital expenditure in this table and capital expenditure in the adjacent table (other consolidated data) relates to non-cash effects from new finance leases, the acquisition of assets with non-cash consideration and the pre-funding of working capital within jointly controlled assets.

[A]		See Note 19D to Consolidated Financial Statements on page 130.
[B]		See Note 13 to the Parent Company Financial Statements on page 202.
[C]		Comprises Royal Dutch interim dividend of € 0.75 made payable in September 2004 and a second interim dividend of € 1.04 made payable in March 2005 as well as a Shell Transport interim dividend of 6.25 pence and a second interim dividend of 10.7 pence that are used to calculate the equivalent dividend on a Royal Dutch Shell basis.

The following table sets forth the consolidated unaudited Ratio of Earnings to Fixed Charges of Royal Dutch Shell on an IFRS basis for the years ended December 31, 2004, 2005 and 2006 and on a US GAAP basis for the years ended December 31, 2002, 2003, 2004, 2005 and 2006.

RATIO OF EARNINGS TO FIXED CHARGES (IFRS and US GAAP)																		%
		2006				2005				2004				2003				2002
Ratio of Earnings to Fixed Charges (IFRS)			19.99				23.33				19.17
Ratio of Earnings to Fixed Charges (US GAAP)			23.31				26.84				17.13				15.67				11.69

For the purposes of this table, earnings consists of pre-tax income from continuing operations before adjustment for minority interest and Group share of profit of equity accounted investments plus fixed charges (excluding capitalised interest) less undistributed earnings of equity accounted investments, plus distributed income from equity accounted investments. Fixed charges consists of expensed and capitalised interest plus interest within rental expenses (for operating leases) plus preference security dividend requirements of consolidated subsidiaries.

Please refer to Exhibit 7.1 for details concerning the calculation of the Ratio of Earnings to Fixed Charges.

Royal Dutch Shell plc 7

Operating and Financial Review

 

 

 

 

 

 

 

 

The Operating and Financial Review (OFR) provides a business, market and strategic overview of the operations and financial situation of the Group, as seen by management. It describes the activities, properties and performance and also discusses the risks and environmental and social challenges facing the Group.

The OFR set out on pages 9 to 69 fulfils the requirements of the Business Review, which forms part of the Report of the Directors set out on pages 71 to 77 of this Report.

The Nanhai petrochemicals complex
in southern China

Royal Dutch Shell plc 9

OPERATING AND FINANCIAL REVIEW

Business and market overview

Royal Dutch Shell consists of the upstream businesses of Exploration & Production and Gas & Power and the downstream businesses of Oil Products and Chemicals. We also have interests in alternative energy sources including Renewables and Hydrogen.

We are active in more than 130 countries and territories worldwide. We are exploring for oil and gas in well-established regions such as the Gulf of Mexico and in frontier territories such as the Beaufort Sea. Key producing areas today are the USA, Europe and our operations in Africa and the Middle East. New supplies are being brought onstream from major projects in challenging frontier environments such as Sakhalin and Athabasca. We are a world leader in liquefied natural gas (LNG) and are pioneering new uses of gas including Gas to Liquids (GTL). We have a diverse and well balanced downstream portfolio and are one of the world’s largest distributors of biofuels.

10 Royal Dutch Shell plc

 

 

ROYAL DUTCH SHELL STRATEGY

A key challenge facing the global oil and gas industry is to find and develop sufficient resources to help meet growing world demand for energy. Over time and across the commodity cycle the Group has achieved higher earnings and returns on investment in the upstream compared with its other businesses and sees significant growth potential for oil and natural gas. Our upstream business will therefore be the focus for future growth. In the downstream the emphasis will be on sustained cash generation and on continuing to reshape our portfolio with a focus on the growing markets of Asia Pacific.

Our strategy of more upstream and profitable downstream will reinforce our position as a leader in the industry and provide investors with a competitive and sustained total shareholder return. We plan net capital spending ^[A] of $22 to $23 billion in 2007, of which around 80% will be invested in upstream projects. This investment will help create an upstream portfolio of assets that will have long, productive lives. These investments will be in both conventional and unconventional hydrocarbon projects. Our capital programme will also maintain and enhance our competitive position in the downstream by improving the quality, integrity and competitiveness of our refinery portfolio and by developing our presence in growth markets.

Meeting growing world demand for energy in ways that minimise the impact on the environment is a major challenge for the global energy industry. We are pursuing a range of potential opportunities to develop businesses based on alternative energies. We also recognise the importance of CO ₂ management to our business and the opportunities it represents. We are playing a key role in developing responsible ways to manage carbon dioxide. These include CO ₂ sequestration projects, energy efficiency and investment in CO ₂ mitigation technology.

A commitment to technology and innovation continues to be at the heart of our business strategy. We believe our technological expertise will be a key factor in the growth of our business as energy projects become more complex and more technically demanding. The Group’s core strengths include the development and application of technology, and the financial and project management skills that allow us to undertake large oil and gas projects. We also benefit from having a diverse international business portfolio and customer-focused businesses built around the strength of the Shell brand. Our ability to manage large and challenging projects in conventional and unconventional oil and gas; to find ways of managing CO ₂ emissions; and to provide alternative energy solutions means we are well placed to be preferred partners for governments and other resource holders, now and in the future.

MARKET OVERVIEW

The global economy expanded by a robust 5.4% in 2006, up from 4.8% in 2005, supported by strong activity in China, India and Russia. While growth in the USA also entered the year on a firm note, the economy slowed in the course of the year. In contrast, growth in key developing countries strengthened and surpassed expectations by the year’s end.

In the USA, the key development was the sharp slowdown in the housing sector in the second half of the year. However, consumer spending and business investment remained firm and underpinned growth. Employment and consumer confidence was relatively immune to the downturn in housing, while business investment was supported by high corporate profit. For 2007, the housing downturn is likely to continue to weigh on the economy, but growth is expected to pick up as the drag from housing diminishes, according to the Federal Reserve Bank.

[A]		Net capital spending represents the expected capital expenditure after including cash received from divestments as well as cash utilised in relation to acquisitions.

The European economy strengthened significantly in 2006: what was initially an export led recovery became increasingly driven by domestic demand. Business investment was particularly robust, buoyed by high corporate profits and looking ahead, the European economy is set to grow solidly according to the European Central Bank.

In contrast to the European economy, the Japanese economy hit an unexpected soft patch in 2006 as consumer spending waned. Nevertheless, exports and business investment remained strong and this points to a stronger 2007, particularly if employment and wages remain firm.

China and India saw particularly robust growth in 2006. In China, business investments and exports were the drivers of growth while in India it was domestic demand and the services sector. For 2007, growth in these two countries is expected to ease back from their recent heights, but to continue apace.

While global growth is likely to slow towards its longer-term trend rate in 2007, risks to the outlook are evenly balanced on the upside and downside, in contrast to 2006 when risks were slanted towards downside by the impending turn in the US cycle. The main downside risk remains the potential for a wider slowdown in the US domestic demand. The main upside potential is in Europe and in the major developing countries. Both have scope for above trend growth, as they showed in 2006.

OIL AND NATURAL GAS PRICES

Brent crude oil prices averaged $65.10 per barrel in 2006 compared with $54.55 in 2005, while West Texas Intermediate (WTI) averaged $66.04 per barrel compared with $56.60 a year earlier. Oil prices increased in 2006 due to a combination of strong world economic growth, supply disruptions in countries including Nigeria and Alaska, geopolitical tensions in the Middle East, and limited OPEC spare production capacity. Prices started the year with Brent and WTI at $58 and $61 a barrel respectively, reaching highs of just under $79 per barrel for Brent and $77 per barrel WTI in early August before declining to around $56 per barrel for Brent and $57 per barrel WTI in October due to rising oil stocks in the USA. Prices recovered marginally in late fourth quarter on OPEC’s decision to curtail supply, but were tempered again by a mild winter in the northern hemisphere. Brent and WTI crude oil prices ended 2006 at $59 and $61 per barrel respectively.

We expect oil prices, on balance, to remain robust in 2007 with ongoing geopolitical tensions, but – in the absence of major supply disruptions – may trend lower than in 2006 against the prospect of potentially slower economic growth, stronger non-OPEC supply growth and higher OPEC spare capacity levels. In the medium to longer term, the Group anticipates prices to moderate from present levels, as both supply and demand are expected to respond to a higher price environment and OPEC spare capacity is being rebuilt.

Henry Hub gas prices in the USA averaged $6.76 per million British thermal units (Btu) in 2006 compared with $8.80 in 2005. Prices moderated as far down as $4.00 per million Btu in early October, due to high inventory levels caused by a relatively warm winter and the absence of weather related supply disruptions during the hurricane season, before recovering to $8.3 per million Btu by the end of November with the onset of the winter season. Henry Hub closed at $5.48 per million Btu at year-end.

Henry Hub prices are expected to remain at present levels in 2007, supported by anticipated modest demand growth, mainly in the electricity generation sector, and balanced by modest growth in domestic supply and LNG imports.

The drivers of natural gas prices are more regionalised than the relatively global nature of crude oil pricing. While the Henry Hub price is a recognised price benchmark in North America, the Group also produces and sells natural gas in other areas that have significantly different supply, demand, and regulatory circumstances and therefore pricing structures. Natural gas prices in continental Europe and Asia Pacific are predominantly indexed to oil prices. In Europe prices have risen reflecting higher oil prices and strong demand. In the UK prices at the National Balancing Point averaged $41.93 pence/therm compared with $40.61 pence/therm in 2005.

OIL AND NATURAL GAS PRICES FOR INVESTMENT EVALUATION

The range of possible future crude oil and natural gas prices to be used in project and portfolio evaluations within the Group are determined after assessment of short, medium and long-term price drivers under different sets of assumptions. Historical analysis, trends and statistical volatility are part of this assessment, as well as analysis of global and regional economic conditions, geopolitics, OPEC actions, cost of future supply and the balance of supply and demand. Sensitivity analyses are used to test the impact of low price drivers like economic weakness and high investment levels in new production, and high price drivers like strong economic growth and low investment levels in new production. Short-term events, such as relatively warm winters or cool summers, weather and (geo)political related supply disruptions and the resulting effects on demand and inventory levels, contribute to price volatility.

During 2006, the Group used a grid based on low, medium and high oil and gas prices to test the economic performance of long-term projects at different prices or margin levels. The prices utilised were significantly lower than the average market industry prices for 2006. As part of normal business practice, the range of prices used for this purpose continues to be under review and may change.

DOWNSTREAM MARKET TRENDS

Refining margins remained well supported in 2006, with robust product demand and constraints on supply due to unusually intense industry refinery turnaround activity on the US Gulf Coast following the extensive hurricane-related damages in 2005. In the absence of any major disruptions, refining margins are expected to trend lower in 2007 than 2006 with new conversion capacities coming on-stream and the prospect for potentially slower global economic growth. However, the eventual levels are uncertain and will be strongly influenced by the pace of global economic growth, the effect of persistently high oil prices on product demand and start-up timing of expected refinery expansions.

The demand for petrochemicals in 2007 is expected to increase in line with the growth in the global economy, mainly in Asia Pacific. Globally, new expected industry capacity additions coupled with the prospect of continued high feedstock and energy costs may limit the opportunities for improving margins.

ACTIVITIES, INTERESTS AND PROPERTY

Our various activities are conducted in more than 130 countries and territories. The Group constitutes one of the largest independent oil and gas enterprises in the world (by a number of measures, including market capitalisation, operating cash flow and oil and gas production). Oil and gas, by far the largest of our business activities (including the Group’s Exploration & Production, Gas & Power, and Oil Products segments), accounted for nearly 90% of revenue in 2006. We market 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

Royal Dutch Shell plc 11

Risk factors

Royal Dutch Shell has a single risk based control framework – the Shell Control Framework – to identify and manage risks (see page 82).

The Group’s operations and earnings are subject to various key risks, described below, involving changing competitive, economic, political, legal, social, industry, business and financial conditions. Investors should carefully consider these risks. These risks could have a material adverse effect on the Group’s results from operations and/or financial condition.

FLUCTUATING PRICES FOR OIL, NATURAL GAS, OIL
PRODUCTS AND CHEMICALS

Oil, natural gas, oil products and chemical prices rise and fall for various reasons involving supply and demand. These include natural disasters, weather, political instability or conflicts, economic conditions or actions by major oil-exporting countries. Price fluctuations can test our business assumptions, and can affect the Group’s investment decisions, operational performance and financial position.

PROJECT DELIVERY AND THE ABILITY TO REPLACE OIL AND GAS RESERVES

The Group’s future oil and gas production depends on the success of very large projects. In developing these projects we are faced with numerous challenges such as uncertain geology, frontier conditions, availability of new technology and engineering capacity, availability of skilled resources, project delays and potential cost overruns, as well as technical, fiscal, regulatory and other conditions. Such potential obstacles may impair our delivery of these projects and, in turn, our operational performance and financial position. Future oil and gas production will depend on our access to new reserves through exploration, negotiation with countries and other owners of known reserves, and acquisitions. Failures in exploration or in identifying and finalising transactions to access potential reserves could slow the Group’s oil and gas production and replacement of reserves. This could weaken the Group’s future operational performance and financial position.

COMPETITION

The Group faces competition within the energy industry and from other industries for land and reserves, developing innovative products and solutions, and developing and applying new technology. Failure to clearly understand or effectively respond to competition could affect our financial position. Furthermore, Shell is increasingly in competition with state run oil companies with access to significant resources.

LOSS OF BUSINESS REPUTATION

The Shell brand is one of the world’s leading energy brands. We have a strong corporate reputation, which is important to maintaining our licence to operate. The Shell General Business Principles govern how the Group and our individual companies conduct our affairs. The Shell Code of Conduct describes how the Business Principles apply to individual employees of Shell. Failure – real or perceived – to follow these principles could harm our reputation, which could reduce our licence to operate, damage our brand and affect our operational performance and financial position.

IMPACT OF CLIMATE CHANGE

Concerns over climate change and any resulting challenges from society and governments could lead to project delays and compliance risks for existing assets. As such, delivery of future projects may be at risk. There is also a compliance risk if existing facilities cannot show that they are managing emissions in line with changing laws and regulations. These risks, if realised, could affect the Group’s operational performance and financial position.

HEALTH, SAFETY, SECURITY AND ENVIRONMENT

Given the range and complexity of the daily operations undertaken by the Group, the potential HSSE risks faced cover a wide spectrum. These risks include major process safety incidents, failure to comply with approved policies, effects of natural disasters and pandemics, social unrest, civil war and terrorism, exposure to general operational hazards, personal health and safety and crime. The consequences of such risk events can be injuries, loss of life, environmental harm and disruption to business activities and can affect the Group’s reputation, operational performance and financial position.

POLITICALLY SENSITIVE OR UNSTABLE COUNTRIES

Developments in politics, laws and regulations can affect the Group’s operations and earnings. These include forced divestment of assets, limits on production, imports and exports, international conflicts, including war, civil unrest and local security concerns that threaten the safe operation of company facilities, price controls, tax increases and other retroactive tax claims, expropriation of property, cancellation of contract rights, and environmental regulations. It is difficult to predict the timing or severity of these occurrences or their effect upon the Group and when such risks materialise they could affect our employees, reputation, operational performance and financial positions of the Group and Group companies located in the country concerned.

PARTNERS AND VENTURES

Many of our major projects and operations are conducted with partners or in joint ventures. Our investment with partners and in joint ventures decreases our ability to manage risks and costs. As a result, the Group could have limited influence over and control of the operations, behaviours and performance of these operations with whom the Group is engaged in business. This could affect the Group’s operational performance and financial position.

INFORMATION TECHNOLOGY (IT)

Growing standardisation, more reliance on global systems, relocation of information technology services and increased regulations lead to a risk that the Group’s IT systems may fail to deliver products, services and solutions in a compliant, secure and efficient manner. This could affect the Group’s operational performance and financial position.

TECHNOLOGY AND INNOVATION

Technology and innovation are essential to the delivery of the Group’s strategy. If the Group does not develop or does not have access to the right technology, it may affect delivery of the strategy and affect the Group’s operational performance and financial position.

RESOURCING CHALLENGES

Skilled employees are essential to the successful delivery of the Group strategy. Top quality talent is a scarce resource and we sometimes experience recruitment shortfalls. Such shortfalls could affect the Group’s operational performance and financial position.

CHANGES IN LEGISLATION AND FISCAL AND REGULATORY POLICIES

Changes in legislation, taxation (tax rate or policy), regulation and to policies on renationalisation and the seizure of property all pose a risk to our operations and can affect the operational performance and financial position of the Group or Group companies concerned. In the upstream these matters affect land tenure, entitlement to produced hydrocarbons, production rates, royalties, pricing, environmental protection, social impact, exports, taxes and foreign exchange.

CURRENCY FLUCTUATIONS AND EXCHANGE CONTROLS

As a global group, changes in currency values and exchange controls could affect our operational performance and financial position.

Royal Dutch Shell plc 13

ECONOMIC AND FINANCIAL MARKET CONDITIONS

Group companies are subject to differing economic and financial market conditions throughout the world. Political or economic instability pose a risk to such markets. If such a risk materialises it could affect the operational performance and financial position of the Group companies operating in the country or region concerned.

ESTIMATION OF RESERVES

The estimation of oil and gas reserves involves subjective judgements and determinations based on available geological, technical, contractual and economic information. It is not an exact calculation. It may change because of new information from production or drilling activities or changes in economic factors. It may also alter because of acquisitions and dispositions, new discoveries and extensions of existing fields, as well as the application of improved recovery techniques. Published reserves estimates may also be subject to correction in the application of published rules and guidance.

LIMITATIONS ON SHAREHOLDER REMEDIES

Our Articles of Association generally require that all disputes between our shareholders in such capacity and us or our subsidiaries (or our directors or former Directors) or between us and our directors or former directors be exclusively resolved by arbitration in The Hague, the Netherlands under the Rules of Arbitration of the International Chamber of Commerce. Our Articles of Association also provide that if this provision is for any reason determined to be invalid or unenforceable, the dispute may only be brought in the courts of England and Wales. This provision may affect the ability of shareholders to obtain monetary or other relief, including in respect of securities law claims. See “Supplementary information – Control of registrant (unaudited)”.

ANTITRUST AND COMPETITION LAW

Antitrust and competition law apply to Group companies in the vast majority of countries in which we do business. In 2006 the Group was fined over $200 million by the European Commission Directorate-General for Competition. Due to the European Commission Directorate-General for Competition’s 2006 fining guidelines any future conviction by Group companies could result in significant fines. In addition, it is becoming increasingly more common for plaintiffs to seek payment of damages for anti-trust violations. Both these factors could have a material adverse effect on the Group’s results.

US GOVERNMENT SANCTIONS

The Group has investments in Iran and Syria and certain operations in Sudan. US laws and regulations identify certain countries, including Iran, Syria and Sudan, as state sponsors of terrorism and currently impose economic sanctions against these countries. Certain activities and transactions in these countries are banned. Breaking these bans can trigger penalties including criminal and civil fines and imprisonment. For Iran, US law sets a limit of $20 million in any 12-month period on certain investments knowingly made in that country, prohibits the transfer of goods or services made with the knowledge that they will contribute materially to that country’s weapons capabilities and authorises sanctions against any company violating these rules (including denial of financings by the US export/import bank, denial of certain export licences, denial of certain government contracts and limits of loans or credits from US financial institutions). However, compliance with this investment limit by European companies is prohibited by Council Regulation No. 2271/96 adopted by the Council of the European Union, which means the statutes conflict with each other in some respects. The Group has exceeded and expects to exceed in the future the US imposed investment limits in Iran. While we seek to comply with legal requirements in its dealings in these countries, it is possible that the Group or persons employed by the Group

could be found to be subject to sanctions or other penalties under this legislation in connection with their activities in these countries.

PROPERTY AND LIABILITY

The Group’s operating companies are exposed to property and liability risks that could affect its operational performance and financial position. The Group insures itself against most of these risks through its captive insurance companies. These companies reinsure part of their major catastrophe risks with a variety of international insurers. The effect of these arrangements is that uninsured losses for any one incident are unlikely to exceed $550 million.

TRADING AND TREASURY

In the course of normal business activities the Group is subject to trading and treasury risks. These include inter alia exposure to movements in commodity prices, interest rates, and foreign exchange rates, counter party default and various operational risks.

PENSION FUNDS

The risk with respect to pensions is the ability of the pension assets to meet future liabilities and fund defined benefit plans going forward. Note 21 to the Consolidated Financial Statements provides further disclosure on retirement benefits.

Liabilities associated with and cash funding of pensions can be significant. Should the Group inappropriately value, provide for and/or fund these obligations, there could be a significant impact on its financial performance.

Local trustees manage the pension funds and set the required contributions from Group companies based on independent actuarial valuation rather than the IFRS measures. These valuations are sensitive to changes in the assumptions made regarding future outcomes, the principal ones being in respect of increases in remuneration and pension benefits, demography (including mortality), the discount rate used to convert future cash flows to current values and the long-term return on plan assets. Substantial judgement is required in determining the assumptions.

For further information regarding the judgement applied in these assumptions and the relation to the financial position and performance of the company, see Note 21 to the Consolidated Financial Statements.

The Group’s pension risk response has been developed based on a comprehensive risk review. The following framework reflects the key responses to the identified sponsor risks:

•		A Joint HR/Finance Pensions Forum is responsible for the retirement benefit strategy and risk responses.
•		Controls are established over retirement benefit and plan (re)–design.
•		Controls are established over pension plan investments, liabilities and funding.
•		Centres of excellence have been established to deliver support services to Sponsor Companies and Pension Funds.
•		Controls are established over pension reporting.

EARNINGS		$ million
		2006				2005				2004
Income from continuing operations			26,311				26,568				19,491
Income/(loss) from discontinued operations			–				(307	)			(234	)
Income for the period			26,311				26,261				19,257

 

[A]		Segment earnings as disclosed in the table above differ from the segment results disclosed in Note 10 beginning on page 117. Segment earnings include share of profit of equity accounted investments, other income/expense and taxation attributable to the segment.

2006 COMPARED TO 2005 AND 2004

EARNINGS

The Group’s businesses delivered strong operational and financial performance in 2006, resulting in earnings of $26.3 billion. The Group’s healthy financial position allowed it to return $16.3 billion to shareholders, through dividends and share repurchases, while capital investment reached $24.9 billion.

The 2006 earnings were in line with 2005 which were up 36% from 2004. The increase in 2005 reflected higher realised oil and gas prices as well as higher LNG volumes and prices.

Exploration & Production earnings were $15,195 million in 2006 compared with $14,238 million in 2005, up 7%. Earnings reflected higher oil prices, partly offset by lower production volumes, higher operating costs reflecting industry conditions, increased pre-development activity levels and lower US gas prices. In 2005, earnings increased by 45% compared with 2004 as hydrocarbon prices increased by nearly the same amount (e.g. Brent increased by 42%) over the same period. Production in 2006 was 2% higher than 2005, excluding the impact of security concerns in Nigeria, price effects and hurricanes in the Gulf of Mexico and one-off contractual settlements. This represented an improvement over 2005 where volumes had declined by 1% compared with 2004 volumes, when calculated on a similar basis.

Hydrocarbon prices were higher in 2006 compared with 2005 and 2004, Brent crude prices averaged $65.10 per barrel in 2006 compared with $54.55 in 2005 and $38.30 in 2004. West Texas Intermediate prices averaged $66.04 per barrel in 2006 compared with $56.60 in 2005 and $41.50 in 2004.

Gas & Power earnings were up 68% in 2006 reaching $2,650 million, compared with $1,573 million in 2005 and $1,815 million in 2004. The earnings decline in 2005 compared with 2004 was driven by non-operational gains and losses related to divestments. Excluding these non-recurring items, earnings were 21% higher in 2005.

LNG sales volumes in 2006 of 12.1 million tonnes showed an increase of 14% compared to 2005 due to the capacity growth in Nigeria and Oman. Income from LNG cargo optimisation in 2006 increased reflecting market conditions and success in accessing high value markets. Marketing and trading earnings reflected gas storage optimisation in the USA and overall strong marketing performance across North America and Europe.

Oil Products earnings in 2006 were $7,125 million, 29% lower than 2005. Refining earnings in 2006 were lower than 2005 reflecting reduced refining margins. Marketing earnings in 2006 were higher than 2005, mainly due to higher earnings in Lubricants offsetting lower earnings in Retail and Business to Business (B2B). Trading earnings increased from 2005 to 2006 as a result of capitalising on the global downstream portfolio and the attractive trading conditions, which stemmed from high price volatility and market structure. The impact of price volatility on inventory had favourable effects on 2006 earnings of approximately $0.1 billion compared with approximately $2.5 billion in 2005. Earnings in 2005 grew 31% compared with 2004 reflecting high refining margins, improved operational performance and increased trading results and higher inventory gains.

Chemicals earnings were $1,064 million compared with $991 million in 2005 and $1,148 million in 2004. Earnings in 2006 included $113 million of net charges, including legal costs and pension costs partly offset by tax effects. Earnings in 2005 included charges of $565 million mainly from the divestment of the polyolefins joint venture, Basell, and legal provisions. Excluding these effects, 2006 earnings were 24% lower than a year ago reflecting lower margins partly offset by higher earnings from equity accounted investments, including Nanhai petrochemicals complex in China. Earnings in 2005 were 14% lower than 2004 due to the impact of discontinued operations as well as lower volumes and higher costs.

BALANCE SHEET AND CAPITAL INVESTMENT

The most significant changes to the balance sheet in 2006 reflect the Group’s strategy to invest in the development of long-term growth projects, primarily in the upstream businesses. Property, plant and equipment and equity accounted investments increased by over $17 billion in 2006 as capital investment increased by over 40% in 2006 compared with 2005 reaching $24.9 billion. This was partly offset by depreciation, depletion and amortisation of nearly $13 billion. Over $20 billion of the capital investment was dedicated to projects in upstream that will primarily deliver organic growth over the long term. These projects include several multi-billion, integrated facilities that should provide significant cash flow for the coming decades.

The capital investment programme in 2006 was primarily funded internally, either from cash from operations of $31.7 billion or with proceeds from divestments of $1.7 billion, with net debt (defined as total debt, including tolling arrangements, minus cash) increasing by $5.6 billion to a year-end balance of $6.8 billion. Total equity increased by $17 billion in 2006 resulting in a year-end balance of $115 billion.

Gearing increased from 13.6% at year-end 2005 to 14.8% at year-end 2006. See Note 19D to the Consolidated Financial Statements for a further discussion on gearing.

PORTFOLIO ACTIONS

In January 2007 the Group made an offer to the shareholders of Shell Canada Limited to acquire all of the outstanding common shares not owned by the Group at a cash price of C$45 per share. The offer would value Shell Canada’s fully diluted minority share capital at approximately C$8.7 billion (approximately $7.5 billion).

In December 2006 the Group, Gazprom, Mitsui & Co., and Mitsubishi Corporation signed a protocol to bring Gazprom into the Sakhalin Energy Investment Company Ltd. (SEIC) as the leading shareholder. Under the terms of the protocol, Gazprom will acquire a 50% interest plus one share in SEIC for a total cash purchase price of $7.45 billion of which Shell is expected to receive approximately $4.1 billion. The current SEIC partners will each dilute their interests by 50% to accommodate this transaction, with a proportionate share of the purchase price. Shell will retain a 27.5% interest, with Mitsui and Mitsubishi holding 12.5% and 10% interests, respectively.

PERFORMANCE AND CAPITAL

Please refer to page 54 and 56 for a discussion of key performance indicators and liquidity and capital resources.

Royal Dutch Shell plc 17

•		Achieved record segment earnings which increased 7% from 2005.
•		Production in line with 2005 production of 3.5 million barrels of oil equivalent (boe) per day, despite security issues in Nigeria.
•		Added approximately 2 billion boe of proved oil and gas reserves and proven oil sands mining reserves.
•		Added some 45 thousand square kilometres of exploration acreage.
•		Commenced execution of several major long-life projects, including Athabasca oil sands expansion, Pearl Gas to Liquids (GTL) in Qatar and two major ultra-deep water developments in the USA and Brazil.

“

 

 

[A]		Segment earnings as disclosed in the table above differ from the segment results disclosed in Note 10 beginning on page 117. Segment earnings include share of profit of equity accounted investments, other income/expense and taxation attributable to the segment.

2006 COMPARED TO 2005 AND 2004

EARNINGS

Segment earnings in 2006 were $15,195 million, 7% higher than in 2005 and 55% higher than in 2004. The increase in 2006 from 2005 reflected higher realised oil prices, partly offset by the impact of lower US gas prices, marginally lower production volumes and higher operating costs reflecting industry conditions, increased pre-development activity levels and higher maintenance costs (including increased technical integrity spend). Segment earnings in 2005 were $14,238 million, 45% higher than in 2004 due to the benefits of higher oil and gas prices, which were partly offset by lower hydrocarbon production and higher costs.

Earnings in 2006 included net gains of $641 million compared with net gains of $1,727 million in 2005 and net charges of $4 million in 2004. The net gains in 2006 mainly related to the mark-to-market valuation of certain UK gas contracts and divestment gains. The net gains in 2005 were almost entirely related to the divestment of pipeline assets in the Netherlands, as various taxation credits and other divestments were almost offset by a net charge relating to mark-to-market gas contracts in the UK. The net charges in 2004 comprised mainly divestment gains of $699 million and impairment reversals of $469 million, offset by mark-to-market losses and impairments.

OUTLOOK AND STRATEGY

The environment for the exploration and production industry has continued to be characterised by higher oil prices, high activity levels, tightness in the supply of oilfield goods and services, cost escalation and strong competition for new opportunities. We anticipate that the environment in 2007 will be similar. We believe that crude oil prices in the near future will continue to be influenced by OPEC supply policy and the industry’s limited ability to generate significant additional near-term production capacity, the rate of global economic expansion, particularly in the USA, India and the Asia Pacific region and, to a lesser extent, the severity of the northern hemisphere winter.

The Exploration & Production strategy pursued consistently for the last three years is unchanged and delivery remains on track. Our strategy has four portfolio themes: sustaining our heartlands, focusing on new oil and gas plays where technology is a differentiator, integrated gas opportunities and unlocking unconventional resources. We will continue to pursue an aggressive exploration programme to add more acreage in support of these themes. We will also invest in organic growth, open up new positions and make selective acquisitions, divestments and asset swaps as a means to expand and high-grade

our asset portfolio. In terms of our existing portfolio, we will focus on production and project delivery, cost performance and operational excellence.

The Group will seek to sustain long-term production from our existing heartlands, i.e. our core countries that have the available infrastructure, expertise and remaining growth potential for the Group to sustain top quartile operations and support continued investment. We will look for further and stronger integrated gas positions such as onshore USA and through projects like Ormen Lange in Norway. We will extend our leadership position in LNG, leveraging our presence across the natural gas value chain from exploration to production and markets to maximise the value from our integrated gas projects. Examples of key project activity in this area include Sakhalin in Russia, Nigeria, the North West Shelf in Australia and Qatar. We intend to build on our existing strengths in unconventional oil and gas technologies. We have taken investment decisions on the Pearl GTL project in Qatar and are building on the success of the Athabasca Oil Sands Project in Canada where we have already started to expand. We intend to maintain our emphasis on developing and applying technology as a key differentiator in securing access to good upstream opportunities and then delivering more value from them. Such areas of focus include deep water, enhanced oil recovery, tight gas, contaminated gas and heavy oil. Leveraging technology is central to our strategy. We have tripled our R&D budget and shifted our emphasis further to subsurface and unconventionals.

Our focus on the reduction of costs will be sustained through optimised management of the supply chain and standardising processes globally. We will continue to strengthen our capabilities in project delivery. Having people in place with the requisite skills is vital to the successful delivery of our strategy: in 2006 we have increased our establishment of technical professionals by over 1,500 people and we will continue to build our capacity through redeployment and external recruitment.

PRODUCTION

In 2006, total hydrocarbon production (including oil sands) was 3,473 thousand boe per day. This was 1% lower than in 2005 and 8% lower than in 2004. Contractual settlements benefited production by 27 thousand boe per day. The underlying production trend was up 2% (excluding the impacts of security issues in Nigeria, hurricane damage in the Gulf of Mexico, PSC price impacts and one-off contractual settlements).

Field declines affecting oil production were seen in the USA, Oman, UK, Norway and Brunei during 2006. Operational shutdowns in the UK and Canada also impacted production levels. Similarly, natural gas production was impacted by declining fields in the USA and the UK, as well as by lower seasonal demand in Northwest Europe.

The effect of declining fields was more than offset by production from new fields such as Erha in Nigeria, E8 in Malaysia, Champion West Phase III in Brunei and Pohokura in New Zealand, and by increased production from Bonga in Nigeria and West Salym in Russia. Total new production added was 207 thousand boe per day in 2006. Production was boosted by the re-start of operations at the Mars platform in the Gulf of Mexico which achieved daily production levels over 20% above those prior to the shut down due to hurricanes.

The Group’s production for 2007 is expected to be around 3.3-3.5 million boe per day. Community disturbances in the Nigeria Western Delta have significantly increased in 2006 and remain an ongoing risk to our business in Nigeria, not only affecting our current production levels but also our ability to grow production in the future because of damage to existing facilities and lack

of drilling and construction activity. This situation will be closely monitored throughout 2007. We expect production growth for the Group to be modest over the coming years, around 1-2% per annum from 2007 to the end of the decade, as a result of the impact of the Nigeria security issues and the portfolio management actions we intend to take. Following this, the Group has a strong resource base with the potential to support 2-3% per annum average growth. Actual growth each year will depend on project start-ups, portfolio management action and the tightness of the market. Our investment decision making will focus on value generation rather than specific reserves or volumes targets.

Several new fields came onstream delivering additional production volumes in 2006. In Brunei, oil production started from the first well of Phase III of the Champion West field (Group interest 50%) using Shell’s Smart Fields ^® technology. This makes use of a network of down-hole and surface sensors to create a real-time picture of reservoir dynamics and production which integrates with data from production facilities allowing optimisation of the entire production system. Unique snake wells were drilled which follow complex trajectories allowing them to pass through multiple reservoirs. The additional production helped Brunei Shell Petroleum (BSP) achieve a 25-year production record. Over time almost a quarter of BSP’s production is expected to come from Champion West.

First gas was delivered from the offshore E8 field (Group interest 50%) in Malaysia, which is a key component of the E11 Hub integrated gas project which aims to rejuvenate existing E11 facilities and develop several offshore gas fields over the next years. The E11 hub has a design capacity of 1.6 billion cubic feet (bcf) of gas per day.

First gas was also delivered from the Pohokura field (Group interest 48%) in New Zealand, which is expected to produce around 40 thousand boe a day at its peak.

In Nigeria, the deep water Erha field (Group interest 43.75%) started up in April 2006 and the deep water Bonga field (Group interest 55%) which started production in late 2005 continued to ramp up. Both fields achieved their nameplate capacity in 2006 which on a combined basis is some 220 thousand boe per day (Group interest).

PRICES

Oil prices increased in 2006 with Brent and West Texas Intermediate crude prices 19% and 17% higher than in 2005, respectively. The Group’s overall realised oil and natural gas liquids (NGL) prices were $60.13 a barrel, compared with $50.36 in 2005 and $35.61 in 2004. In the USA, realised oil and NGL prices averaged $58.53 a barrel, compared with $48.94 in 2005 and $36.15 in 2004. Outside the USA, realised oil and NGL prices averaged $60.37 a barrel compared with $50.56 in 2005 and $35.53 in 2004. Realised prices differ from published crude oil prices because the quality, and therefore price, of actual crude oil produced differs from the quoted blends. In general, the Group produces crude oil of a lower quality than the quoted blends. The Group’s overall realised gas prices (excluding equity accounted investments) in

Royal Dutch Shell plc 19

Exploration & Production averaged $5.08 per thousand standard cubic feet (scf) in 2006 compared with $4.77 in 2005 and $3.59 in 2004. In the USA, realised gas prices averaged $7.74 per thousand standard cubic feet (scf), compared with $8.43 in 2005 and $6.33 in 2004. Outside the USA, realised gas prices averaged $4.41 compared with $3.84 in 2005 and $2.81 in 2004.

CAPITAL INVESTMENT AND PORTFOLIO ACTIONS

Capital investment in 2006 increased 53% to $16.5 billion (excluding the contribution of our minority partners in Sakhalin of $1.4 billion). This included exploration expenditure of $5.1 billion of which $2.4 billion was related to acquisitions. Overall, the costs of the acquisitions totalled $2.9 billion. In 2005, capital investment was $10.8 billion and was $8.8 billion in 2004 (excluding the contribution of our minority partners in Sakhalin of $1.3 billion and $1.1 billion respectively).

Decisions were made to proceed with a number of major projects in 2006. We announced the go ahead of the development of the BC-10 deepwater block offshore Brazil following an earlier declaration of commerciality. The BC-10 development consists of multiple subsea wells and manifolds, tied back to a floating production, storage and offloading vessel with a capacity of 100 thousand barrels per day. First production is expected around the turn of the decade. Earlier in the year, Shell exercised its pre-emption option for an additional 30% participating interest in the BC-10 block and subsequently sold half of the additional stake acquired to the Indian National Oil Company, ONGC Videsh Ltd (OVL) resulting in a 50% interest in this block together with Petrobras (35%) and OVL (15%).

Shell announced the development of the Great White (Group interest 33.34%), Tobago (Group interest 32.5%) and Silvertip fields (Group interest 40%), via the Perdido development host (Group interest 35%), located in Alaminos Canyon, offshore Gulf of Mexico. The facility will be designed to handle 130 thousand boe per day. Also in the USA, major multi-year investment programmes were approved to further develop our onshore gas projects at Pinedale in Wyoming and in South Texas.

In 2006, Shell Canada received the regulatory approvals needed to proceed with Athabasca Oil Sands Project Expansion 1 (Shell Canada interest 60%), a fully integrated 100 thousand barrels per day expansion of oil sands mining and upgrading facilities. Shell Canada acquired 100% of BlackRock Ventures Inc (BlackRock). The integration of the acquired assets and operations into Shell Canada has now been completed.

Also in Canada, the wholly-owned Shell subsidiary, SURE Northern Energy Ltd., acquired 19 parcels of land in Northern Alberta to evaluate and potentially develop heavy oil resources.

Royal Dutch Shell plc announced in January 2007 that it has reached agreement with and obtained the recommendation of the Board of Directors of Shell Canada on a revised offer to acquire all of the outstanding common shares of Shell Canada not owned by Royal Dutch Shell at a cash price of C$45 per share. This offer would value Shell Canada’s fully diluted minority share capital at around C$8.7 billion. Royal Dutch Shell currently owns 78% of the common shares of Shell Canada.

Shell acquired acreage in the Carnarvon Basin in Australia through the offshore block WA-374-P in the Greater Gorgon Area (Group interest 25%) and in the Browse Basin through the permit area WA-371-P in the Caswell Sub-basin.

In Russia, Shell, Gazprom, Mitsui and Mitsubishi signed a protocol to bring Gazprom into the Sakhalin Energy Investment Company Ltd. (SEIC) as the

leading shareholder. Under the terms of the protocol, Gazprom will acquire a 50% interest plus one share in SEIC for a total cash purchase price of $7.45 billion. The current SEIC partners will each dilute their interest by 50% to accommodate this transaction, with a proportionate share of the purchase price. Shell will retain a 27.5% interest, with Mitsui and Mitsubishi holding 12.5% and 10% interest, respectively. Gazprom and existing SEIC shareholders will enter into an Area of Mutual Interest arrangement, which will cover both future Sakhalin oil and gas exploration and production opportunities, and building of Sakhalin II into a regional oil and LNG hub. Furthermore, agreement has been reached with the Ministry of Industry and Energy, regarding the amended budget of Sakhalin II and cost recovery. The Production Sharing Agreement for the project will continue and the amended project budget for phase 2 is expected to be approved by the Supervisory Board of SEIC.

A number of divestments were completed in 2006. In the UK, Shell completed the sale of its 50% holding in the Auk and 43% holding in the Fulmar fields and associated infrastructure, while in Norway, the divestment of the Jotun field (Group interest 45%) was also completed. In the Netherlands, Energie Beheer Nederland B.V. has agreed to take a 40% financial interest from NAM (Group interest 50%) in the possible redevelopment of a part of the Schoonebeek oilfield.

In Norway, Shell and Statoil signed an agreement to work towards developing the world’s largest project using carbon dioxide (CO ₂ ) for enhanced oil recovery offshore. If technical and economic challenges can be overcome, the Halten project would involve capturing CO ₂ from power generation and using it to enhance oil recovery initially at the Shell-operated Draugen field and later at the Statoil-operated Heidrun field.

A Joint Activity Agreement was signed in Ukraine, with Ukrgazvydobuvannya, a subsidiary of Naftogaz Ukrainy. Shell has farmed into eight licences in the Dniepr Donets Basin and exploration work commenced in 2006.

EXPLORATION

During 2006, we participated in 198 successful exploratory wells (wells drilled outside proved area). These included exploration discoveries in Australia, Brunei, Cameroon, Egypt, Malaysia, Netherlands, Nigeria, Oman, Syria and the USA. Discoveries will be evaluated in order to establish the extent of the volumes they contain.

The Group made significant additions to its overall acreage position with new exploration licences in Australia, Canada, Denmark, Ireland, Norway, Philippines, Tunisia, Ukraine and the USA (Gulf of Mexico and Onshore). In 2006, some 45 thousand square kilometres of additional exploration acreage was added in the above-mentioned countries. Globally, we maintained our acreage position to the same level in comparison to last year.

RESEARCH AND DEVELOPMENT

The Shell Exploration & Production Technology organisation is responsible for the research, development and application of integrated technology solutions for Group operating businesses and assets around the world. The primary objectives are to select, develop and implement technologies that enable the Group operating businesses and assets to successfully discover and produce greater levels of hydrocarbons; to achieve continuous improvement in cost-efficiency and performance; to increase operational safety and to reduce environmental impact.

Exploration & Production R&D is carried out in two main laboratory locations: Rijswijk (the Netherlands) and Houston (Texas, USA). Additional technology facilities are in Oman, Qatar, Stavanger (Norway) and Calgary (Canada). In-house teams and facilities are used in the research and

development of proprietary exploration and production technologies along with service industry and/or academic capabilities where applicable.

The primary focus of the research and development work is in the following areas: enhanced subsurface imaging; reservoir surveillance and characterisation; smart reservoir management; improving hydrocarbon recovery efficiency; reducing the cost of wells and facilities; enabling the development of ultra-deep water fields; separation and utilisation of contaminated gas; recovery of unconventional hydrocarbons; upgrading recovered unconventional hydrocarbons; and developing solutions for capture and sequestration of CO ₂ .

BUSINESS AND PROPERTY

The Group and its equity accounted investments are involved in the exploration for and production of crude oil and natural gas and operate under a broad range of laws and regulations that change over time. These cover virtually all aspects of exploration and production activities, including matters such as land tenure, entitlement to produced hydrocarbons, production rates, royalties, pricing, environmental protection, social impact, exports, taxes and foreign exchange. The conditions of the leases, licences and contracts under which oil and gas interests are held vary from country to country. In almost all cases (outside North America), the legal agreements generally are granted by or entered into with a government, government entity or state oil company, and the exploration risk practically always rests with the oil company. In North America, these agreements may also be with private parties who own mineral interests. Of these agreements, the following are most relevant to Shell’s interests:

•		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.
•		PSCs entered into with a state or state oil company oblige the oil company, as contractor, to provide all the financing generally, 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 on a per field basis. Additionally, as the price of oil or gas increases above certain pre-determined levels, the Group’s entitlement share of production would normally decrease.

Group companies’ exploration and production interests, including acreage holdings and statistics on wells drilled and drilling, are shown on pages 22 to 26.

PROVED RESERVES

Details of Group companies’ and the Group share of equity accounted investments’ 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 161 to 167. Oil and gas reserves cannot be measured exactly since estimation of reserves involves subjective judgement. 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 that 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.

During 2006, a total of 1,638 million boe was added to proved developed and undeveloped reserves by Group companies, consisting of 367 million barrels of oil and natural gas liquids and 7,373 thousand million scf of natural gas (in each case before taking account of production). The addition to proved developed and undeveloped reserves consisted of additions of 7 million boe from revisions, 27 million boe from improved recovery and 1,539 million boe from extensions and discoveries, and 65 million boe from acquisitions and divestments. There was a net addition of 463 million boe to proved developed reserves and a net addition of 1,175 million boe to proved undeveloped reserves (before taking account of production).

During the same period, the Group share of proved developed and undeveloped reserves additions by equity accounted investments, that are in addition to the additions to the reserves by Group companies described above, represented a reduction of 59 million boe, consisting of a reduction of 95 million barrels of oil and natural gas liquids and an increase of 208 thousand million scf of natural gas (in each case before taking account of production). The Group share of changes to proved developed and undeveloped reserves by equity accounted investments consisted of a reduction of 89 million boe from revisions and an increase of 30 million boe from extensions and discoveries. There were no changes to reserves as a result of acquisitions and divestments. There was a net addition of 101 million boe to proved developed reserves and a net reduction of 160 million boe to proved undeveloped reserves (before taking account of production).

Details of the main proved reserves changes during 2006 are provided in the section entitled “Supplementary information – Oil and gas (unaudited)”.

At December 31, 2006, after taking account of Group companies’ 2006 net additions to proved developed and undeveloped reserves and production, total proved reserves for Group companies was 9% higher than at December 31, 2005. At the same date, after taking into account the Group’s share of equity accounted investments’ net additions and production, the Group’s share of total proved developed and undeveloped reserves of equity accounted investments was 9% lower than at December 31, 2005.

In December 2006, Shell signed a protocol with Gazprom, which results in a reduction in Shell’s 55% interest in Sakhalin II, in Russia, to a 27.5% interest. At the end of 2006, Sakhalin II was recorded in Shell’s reserves on a fully consolidated basis, with net reserves of 0.8 billion barrel of oil equivalent (boe), consisting of approximately 1.5 billion boe for Group companies, partly offset by 0.7 billion boe attributable to minority interests. On successful completion of this transaction, Shell’s net share of these reserves would be reduced by approximately 0.4 billion boe and the remaining reserves of approximately 0.4 billion boe on a 2006 basis would be reclassified to Group share of equity accounted investments. This transaction is expected to close in 2007 and to reduce Shell’s reserves from 2007.

In addition to proved conventional liquids and natural gas reserves, the Group has significant interests in proven oil sands reserves in Canada associated with the Athabasca Oil Sands Project. The Group views these reserves and their development as an integral part of the company’s total upstream operations. However, since SEC regulations define these reserves as mining-related and not part of conventional oil and gas reserves, these are presented separately to

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