Shell - 20-F annual report

This Report serves as the Annual Report and Accounts in accordance with UK requirements and as the Annual Report onForm 20-Fas filed with the US Securities and Exchange Commission (SEC) for the year ended December 31, 2009, for Royal Dutch Shell plc (the Company) and its subsidiaries (collectively known as Shell). It presents the Consolidated Financial Statements of Shell (pages 97-139) and the Parent Company Financial Statements of Shell (pages 159-167). Cross references toForm 20-Fare set out on pages 175-176 of this Report.

In this Report “Shell” is sometimes used for convenience where references are made to the Company and its subsidiaries in general. Likewise, the words “we”, “us” and “our” are also used to refer to subsidiaries 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. “Subsidiaries”, “Shell subsidiaries” and “Shell companies” as used in this Report refer to companies over which the Company, either directly or indirectly, has control through a majority of the voting rights or the right to exercise control or to obtain the majority of the benefits and be exposed to the majority of the risks. The Consolidated Financial Statements consolidate the financial statements of the Parent Company and all subsidiaries. The companies in which Shell has significant influence but not control are referred to as “associated companies” or “associates” and companies in which Shell has joint control are referred to as “jointly controlled entities”. Joint ventures are comprised of jointly controlled entities and jointly controlled assets. In this Report, associates and jointly controlled entities are also referred to as “equity-accounted investments”.

The term “Shell interest” is used for convenience to indicate the directand/orindirect (for example, through our 34% shareholding in Woodside Petroleum Ltd.) ownership interest held by Shell in a venture, partnership or company, 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 subsidiaries only, without deduction of minority interest. However, the term “Shell share” is used for convenience to refer to the volumes of hydrocarbons that are produced, processed or sold through both subsidiaries and equity-accounted investments. All of a subsidiary’s production, processing or sales volumes are included in the Shell share, even if Shell owns less than 100% of the subsidiary. In the case of equity-accounted investments, however, Shell-share figures are limited only to Shell’s entitlement. In all cases, royalty payments in kind are deducted from the Shell share.

The Financial Statements contained in this Report have been prepared in accordance with the provisions of the Companies Act 2006, Article 4 of the International Accounting Standards (IAS) Regulation and with both International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and IFRS as adopted by the European Union. IFRS as defined above includes International Financial Reporting Interpretations Committee (IFRIC) interpretations.

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 Business Review (BR) and other sections of this Report contain forward-looking statements (within the meaning of the United States

Private Securities Litigation Reform Act of 1995) concerning the financial condition, results of operations and businesses of 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 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”, “goals”, “intend”, “may”, “objectives”, “outlook”, “plan”, “probably”, “project”, “risks”, “scheduled”, “seek”, “should”, “target”, “will” and similar terms and phrases. There are a number of factors that could affect the future operations of 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 Shell’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserve estimates; (f) loss of market share 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 regulatory measures as a result of climate changes; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. Also see “Risk factors” for additional risks and further discussion. 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 the Company 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 concerning the Company, 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 Shell 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 Shell in The Hague, the Netherlands and London, UK. You may also obtain copies of this Report, free of charge, by mail.

In 2009 the world felt the acute effects of the global recession. Oil demand experienced its steepest drop since 1982. Consumption of natural gas in the European Union fell more than it ever has before. Refining margins were put under great pressure, as were the margins in the petrochemicals business. Financing of projects tightened as banks rebuilt their balance sheets. And the treasuries of many countries came under severe strain.

By the end of 2009, unprecedented economic-stimulus packages and the irrepressible growth of key Asian nations appeared to turn around the global economy. But weak consumer demand and lingering unemployment in the USA and Europe are likely to weigh down the recovery for some time.

We responded swiftly to the downturn, restructuring Shell to make it more competitive. And we did so without diluting the talents that make our company strong. At the same time, we retained our long-term view. We stuck to our capital-spending plans throughout 2009 and continued working on the energy projects that form the foundations of our future.

With economic recovery, global demand for energy will resume its growth, in step with increasing population and rising wealth in developing countries. Supplies of all kinds of energy – not just oil and gas but also renewables – will struggle to keep pace. And even while energy use grows, carbon dioxide (CO₂) emissions must be kept in check.

As the world evolves toward a low-carbon energy system in the years and decades ahead, our unrivalled tradition of technical innovation positions us well.

Our technology enables us to find and produce crude oil and natural gas inhard-to-reachplaces, from the deep ocean to the frozen Arctic. It will one day enable us to produce transport fuels from unusual sources, such as agricultural waste.

We are already applying our technology to capitalise on our supplies of natural gas, the cleanest-burning fossil fuel. When used to generate electricity, it emits half the CO₂of coal. New production techniques help us coax it out of impermeable rock. We aim to maintain our leading position in liquefied natural gas, allowing us to extract gas in far-flung locations and transport it to markets in sea-going tankers. We are also turning natural gas into high-performance lubricants and liquid transport fuels. All of this means that by 2012 more than half of our production will be natural gas.

Shell excels at applying technology to complex projects on a massive scale. The offshore fields that we recently brought on-stream in Brazil and Russia attest to that. We are following a similar project-engineering approach in several demonstration projects to capture CO₂and store it safely underground.

We are also working to squeeze more value out of every unit of energy we use in our operations. And we are introducing new products and services that help our customers become more efficient energy-users themselves.

Making the world’s energy supply secure, affordable and sustainable is not just a worthy goal; it is a global imperative. It will take time, and it will take a lot of effort. But with our far-sightedness and technical prowess, we can contribute to the endeavour even as we deliver the results that our shareholders expect in the long term.

It is a privilege for me to give my first review of Shell’s performance as its Chief Executive Officer. I am proud to report how these trying times have brought out some of our best qualities.

Our new field developments andramp-upsproduced enough oil and gas in 2009 to offset the natural decline of our older fields. The reliability of our refineries also improved. We reduced underlying operating costs by more than $2 billion. And our cash inflows and outflows were broadly balanced in both Upstream and Downstream.

But despite our best efforts, 2009 earnings amounted to $12.7 billion, down from $26.5 billion the year before. The reasons for the drop span all our businesses. Our production decreased because of lower demand for natural gas, although divestments and OPEC quotas were partly responsible as well. Lower oil and gas prices also contributed to lower Upstream revenues. Global demand for oil products weakened and refining margins declined to historical lows, reducing our Downstream earnings. Lower sales volumes and margins affected our chemicals performance.

Those tough economic realities highlight the need for us to do better in containing our costs and improving our competitiveness.

Our performance improved in 2009 in many of the areas we monitor related to sustainable development. Our occupational injury rate was the lowest we have ever recorded. However, tragically we did incur 20 work related fatalities during 2009. To help bring down such fatalities – ideally to zero – we launched a set of safety rules to address specifically the work-time practices with the greatest risk to life.

We had a good year in 2009 in exploration. We discovered gas in shale formations of North America and off shore western Australia. There were 11 notable discoveries. Additions to our proved reserves were more than double our production volumes for the year.

We will continue to apply our exploration capabilities wherever they are appropriate, including our new leases in Egypt, South Africa and French Guiana. Resources found will be matured into the project funnel that drives our growth.

Several major projects already matured in our Upstream portfolio in 2009 – with several more set to reach first production within a few years. Together with our partners, we completed Russia’s first liquefied natural gas (LNG) plant, Sakhalin II, one of the world’s largest integrated projects.

In 2009, the Parque das Conchas project offshore Brazil began delivering heavy oil from fields in waters two kilometres deep. In 2010 our Perdido platform in the Gulf of Mexico will tap fields lying under more than three kilometres of water – a world record. At such depths sophisticatedsub-seaequipment is needed, and it has to be built on site by remote-controlled machines in near-freezing darkness.

Our Pearl gas to liquids project in Qatar will apply Shell technology to convert some 1.6 billion cubic feet of gas per day into liquid transport fuel and other high-quality oil products and petrochemical feedstocks. The Qatargas 4 project will take about the same amount of gas and turn it into LNG. Both projects are progressing well; construction is expected to be completed by the end of 2010 with productionramp-up in 2011.

We have agreed with our partners to begin construction on one of the world’s largest natural gas developments: the Gorgon offshore gas field of Australia. The project will nearly double Australia’s LNG output. It is also expected to pioneer the large scale capture and storage of carbon dioxide.

In late 2009, we secured an important position in Iraq with the government contract for developing the Majnoon field – a huge field in a country with great potential.

Our Downstream portfolio will need to be carefully reassessed in view of the overcapacity in the refining industry and the growth potential for petrochemicals in Asia. But some new business opportunities were already opened up by 2009 developments.

Our new lubricants complex in Zhuhai – our sixth such facility in China – will help us to supply the world’s fastest-growing lubricants market. With the potential for expansion, the complex could become one of Shell’s top three lubricants blending plants.

We also started up the first of several new advanced processing units at the Shell Eastern Petrochemicals Complex in Singapore. All the new units are expected to be up and running in 2010, reinforcing our ambition to maintain a leading position in the regional market.

We have expanded our association with Iogen and Codexis to develop better enzymes and processes for the production of biofuels from straw. In early 2010 we announced our intention to form a $12 billion joint venture with Cosan in Brazil for the production, supply, distribution and retailing of ethanol-based transport fuels.

Our successful projects, our new business opportunities and our continued financial flexibility give me confidence to face the economic uncertainties of 2010. Thereafter, a period of production and cash-flow growth awaits us. To reach it, we will have to rely even more on technical ingenuity, project management and operational excellence – the very things that distinguish us from our competitors.

To channel our skills more quickly, more effectively and more economically, last year I reorganised our business units. One of the main aims was to concentrate in one unit the accountabilities for delivering major new projects and developing new technologies. That will better position us to execute Upstream operations and secure access to resources. It will also help us better manage the many environmental and societal issues associated with developing oil and gas fields.

These changes, which were implemented shortly after I took on the position of CEO, were not a reaction to transient tough times. In the short term they did accelerate our plans to reduce complexity, overheads and – ultimately – costs. But in the long term they will improve our performance by sharpening our external focus and giving added impetus to our technology and innovation.

I look forward to seeing our revitalised organisation succeed in 2010 and beyond.

Total shareholder return (TSR) is the difference between the share price at the start of the year and the share price at the end of the year, plus gross dividends paid during the calendar year (reinvested quarterly), expressed as a percentage of the year-start share price. The TSRs of major publicly-traded oil and gas companies can be directly compared, providing a way to determine how Shell is performing against its industry peers.

Net cash from operating activities is the total of all cash receipts and payments associated with our sales of oil, gas, chemicals and other products. The components that provide a reconciliation from income for the period are listed in the Consolidated Statement of Cash Flows on page 100. This indicator reflects Shell’s ability to generate cash for investment and distributions to shareholders. For scorecard purposes only, it is adjusted to exclude taxes paid on divestments.

Production is the sum of all average daily volumes of unrefined oil and natural gas produced for sale. The unrefined oil comprises crude oil, natural gas liquids and synthetic crude oil. The gas volume is converted into energy-equivalent barrels of oil to make the summation possible. Changes in production have a significant impact on Shell’s cash flow.

Sales of liquefied natural gas (LNG) is a measure of the operational excellence of Shell’s Upstream business and the LNG market demand.

Refinery and chemical plant availability is the weighted average of the actual uptime of plants as a percentage of their maximum possible uptime. The weighting is based on the capital employed. It excludes downtime due to uncontrollable factors, such as hurricanes. This indicator is a measure of operational excellence of Shell’s Downstream manufacturing facilities.

Total reportable case frequency (TRCF) is the number of staff or contractor injuries requiring medical treatment or time off for every million hours worked. It is a standard measure of occupational safety.

Operational spills are the total number of spills of oil and oil products over 100 kilograms per spill that resulted from our operations.

Employees is the number of notional full-time employees whose work hours would be equivalent to those of all staff actually holding full-time and part-time employment contracts with Shell subsidiaries, averaged throughout the year.

Income for the period is the total of all the earnings from every business segment. It is of fundamental importance for a sustainable commercial enterprise.

Return on average capital employed (ROACE) is defined as annual income, adjusted for after-tax interest expense, as a percentage of average capital employed during the year. Capital employed is the sum of total equity and total debt. ROACE measures the efficiency of Shell’s utilisation of the capital that it employs and is a common measure of business performance; see page 48.

Gearing is defined as net debt (total debt minus cash and cash equivalents) as a percentage of total capital (net debt plus total equity), at December 31. It is a measure of the degree to which Shell’s operations are financed by debt. (For further information see Note 16 to the Consolidated Financial Statements.)

Proved oil and gas reserves (excluding minority interest) are the total estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs, as at December 31, under existing economic and operating conditions. Gas volumes are converted into barrels of oil equivalent (boe). Reserves are crucial to an oil and gas company, since they constitute the source of future production. Reserves estimates are subject to change based on a wide variety of factors, some of which are unpredictable; see pages 13 to 15. The proved reserves volumes reported for 2009 have been established using the new SEC rules on oil and gas reporting.

From 1907 until 2005, Royal Dutch Petroleum Company (Royal Dutch) and The “Shell” Transport and Trading Company, p.l.c. (Shell Transport) were the two public parent companies of a group of companies known collectively as the “Royal Dutch/Shell Group” (Group). Operating activities were conducted through the subsidiaries of Royal Dutch and Shell Transport. In 2005, Royal Dutch Shell plc (Royal Dutch Shell) became the single parent company of Royal Dutch and Shell Transport, the two former public parent companies of the Group (the Unification).

Royal Dutch Shell plc (the Company) is a public limited company registered in England and Wales and headquartered in The Hague, the Netherlands.

Shell is one of the world’s largest independent oil and gas companies in terms of market capitalisation, operating cash flow and oil and gas production. Our oil and gas producing heartlands are the core countries that have the available infrastructure, expertise and remaining growth potential for Shell to sustain strong operational performance and support continued investment. They are Australia, Brunei, Canada, Denmark, Malaysia, the Netherlands, Nigeria, Norway, Oman, the UK and the USA. Russia represents a new heartland with Sakhalin II on-stream in 2009, and we expect Qatar to become a heartland in the coming years.

We are bringing new oil and gas supplies on stream from major field developments. We are also investing in growing our gas-based business through liquefied natural gas (LNG) and gas to liquids (GTL) projects. For example, we are building one of the world’s largest GTL projects in Qatar, and we are participating in the Gorgon LNG project in Australia.

At the same time, we are exploring for oil and gas in prolific geological formations that can be conventionally developed, such as those found in the Gulf of Mexico, Brazil and Australia. But we also are exploring for hydrocarbons in formations, such as low-permeability gas reservoirs in the USA, Canada and China, which can be economically developed only by unconventional means.

We also have a diversified and balanced portfolio of refineries and chemicals plants and are a major distributor of biofuels. We have the largest retail portfolio of our peers, and delivered strong growth in differentiated fuels. We 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.

On July 1, 2009, Peter Voser succeeded Jeroen van der Veer as Chief Executive Officer (CEO). On the same date, a series of changes in the organisation and responsibilities of senior management became effective.

The changes were part of the reorganisation programme, called “Transition 2009”. The aim of the programme was to enhance accountability for operating performance and technology development within Shell’s organisation, thereby quickening decision-making and execution as well as reducing costs.

Upstream International manages the upstream business outside the Americas. It searches for and recovers crude oil and natural gas, liquefies and transports gas and operates the upstream and midstream infrastructure necessary to deliver oil and gas to market. Upstream International also manages the global LNG business and the wind business in Europe. The activities are organised within geographical units, some business-wide managed activities and supporting activities.

Upstream Americas manages the upstream business in North and South America. It searches for and recovers crude oil and natural gas, liquefies and transports gas and operates the upstream and midstream infrastructure necessary to deliver oil and gas to market. Upstream Americas also extracts bitumen from oil sands that is converted into synthetic crude oil. Additionally, it manages the US based wind business. It comprises operations organised into business-wide managed activities and supporting activities.

Downstream manages Shell’s manufacturing, distribution and marketing activities for oil products and chemicals. These activities are organised into globally managed classes of business, including chemicals, some regionally and globally managed activities and supporting activities. Manufacturing and supply includes refining, supply and shipping of crude oil. Marketing sells a range of products including fuels, lubricants, bitumen and liquefied petroleum gas (LPG) for home, transport and industrial use. Chemicals produces and markets petrochemicals for industrial customers, including the raw materials for plastics, coatings and detergents used in the manufacture of textiles, medical supplies and computers. Downstream also trades Shell’s flow of hydrocarbons and other energy related products, supplies the Downstream businesses, markets gas and power and provides shipping services. Downstream also oversees Shell’s interests in alternative energy (excluding wind) and CO₂management.

Projects & Technology manages the delivery of Shell’s major projects and drives the research and innovation to create technology solutions. It provides technical services and technology capability covering both Upstream and Downstream activities. It is also responsible for providing functional leadership across Shell in the areas of safety and environment and contracting and procurement.

With effect from July 1, 2009, Upstream consists of the activities previously reported in the Exploration & Production, Gas & Power (excluding solar) and Oil Sands segments. It combines the operating segments Upstream International and Upstream Americas, which have similar economic characteristics and these operating segments are similar in respect of the nature of products and services, the nature of production processes, type and class of customers and the methods of distribution. Downstream consists of the activities previously reported in the Oil Products and Chemicals segments and solar. Upstream and Downstream earnings include their respective elements of Projects & Technology and of trading activities. Corporate represents the key support functions comprising holdings and treasury, headquarters, central functions and Shell’s insurance activities. Comparative information in this Report has been reclassified.

Shell’s operations and earnings are subject to risks from changing conditions in competitive, economic, political, legal, regulatory, social, industry, business and financial fields. These risks could have a material adverse effect separately or in combination on Shell’s operational performance, earnings or financial condition. Investors should carefully consider the risks below and the limitation of shareholder remedies associated with our Articles of Association as discussed below.

Prices of oil, natural gas, oil products and chemicals are affected by supply and demand. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, conflicts, economic conditions and actions by major oil-exporting countries. Price fluctuations have a material effect on our earnings and our financial condition. For example, in a low oil and gas price environment Shell would generate less revenue from its Upstream production, and as a result certain long-term projects might become less profitable or even incur losses. Additionally, low oil and gas prices could result in the debooking of oil or natural gas reserves, if they become uneconomic in this type of environment. Prolonged periods of low oil and gas prices, or rising costs, could also result in projects being delayed or cancelled, as well as in the impairment of certain assets. In a high oil and gas price environment, we can experience sharp increases in cost and under some production-sharing contracts our entitlement to reserves would be reduced. Higher prices can also reduce demand for our products. Lower demand for our products might result in lower profitability, particularly in our Downstream business. Oil and gas prices can move independently from each other.

We face numerous challenges in developing capital projects, especially large ones. Challenges include uncertain geology, frontier conditions, the existence and availability of necessary technology and engineering resources, availability of skilled labour, project delays and potential cost overruns, as well as technical, fiscal, regulatory, political and other conditions. Such potential obstacles may impair our delivery of these projects, as well as our ability to fulfil related contractual commitments, and, in turn, adversely affect our operational performance and financial position. Future oil and gas production will depend on our access to new proved reserves through exploration, negotiations with governments and other owners of known reserves, and acquisitions. Failure to replace proved reserves could result in lower future production.

We face significant competition in each of our businesses. While we try to differentiate our products, many of them are competing in commodity-type markets. If we do not manage our expenses adequately, our cost efficiency might deteriorate and our unit costs might increase. This in turn might erode our competitive position. Increasingly, we compete with state-run oil and gas companies, particularly in seeking access to oil and gas resources. Today, these state-run oil and gas companies control vastly greater quantities of oil and gas resources than the major publicly held oil and gas companies. State-run entities have access to significant resources and may be motivated by political or other factors in their business decisions which may harm our competitive position or access to desirable projects.

Shell is one of the world’s leading energy brands, and our brand and reputation are important assets. The Shell General Business Principles and Code of Conduct govern how Shell and our individual companies conduct our affairs. While we seek to ensure compliance with these requirements by all of our 101 thousand employees, it is a significant challenge. Failure – real or perceived – to follow these principles, or other real or perceived failures of governance or regulatory compliance could harm our reputation. This could impact our licence to operate, damage our brand, harm our ability to secure new resources and affect our operational performance and financial condition.

Emissions of greenhouse gases and associated climate change are real risks to Shell. In the future, in order to help meet the world’s energy demand, we expect more of our production to come from unconventional sources than at present. Energy intensity of production of oil and gas from unconventional sources can be higher than that of production from conventional sources. Therefore, in the long term, it is expected that both the CO₂intensity of our production as well as our absolute CO₂emissions might increase, for example from the expansion of oil sands activities in Canada. Also our Pearl GTL project in Qatar is expected to increase our CO₂emissions when production begins. Over time, we expect that a growing share of our CO₂

emissions will be subject to regulation and carry a cost. If we are unable to find economically viable as well as publicly accepted solutions that reduce our CO₂emissions for new and existing projects or products, regulatoryand/orpolitical and societal pressures could lead to project delays, additional costs as well as compliance and operational risks.

The HSSE risks, to which we are potentially exposed, cover a wide spectrum, given the geographic range, operational diversity and technical complexity of Shell’s daily operations. Shell has significant operations in difficult geographies or climate zones, as well as environmentally sensitive regions which exposes us to the risk, amongst others, of major process safety incidents, effects of natural disasters, social unrest, personal health and safety and crime. If a major HSSE risk, such as an explosion or hydrocarbon spill due to a process safety incident, materialises, this could result in injuries, loss of life, environmental harm, disruption to business activities and, depending on their cause and severity, material damage to Shell’s reputation.

Developments in politics, laws and regulations can and do affect our operations and earnings. Potential developments include forced divestment of assets; expropriation of property; cancellation of contract rights; additional windfall taxes and other retroactive tax claims; import and export restrictions; foreign exchange controls; and changing environmental regulations. In our Upstream activities these developments could additionally affect land tenure, re-writing of leases, entitlement to produced hydrocarbons, production rates, royalties and pricing. Parts of our Downstream business are subject to price controls in some countries. When such risks materialise they can affect the employees, reputation, operational performance and financial position of Shell as well as of the Shell companies located in the country concerned. If we do not comply with policies and regulations, it may result in regulatory investigations, lawsuits and ultimately sanctions.

Social and civil unrest, both within the countries in which we operate and internationally, can and does affect operations and earnings. Potential developments that could impact our business include international conflicts, including war, acts of political or economic terrorism and acts of piracy on the high seas, as well as civil unrest and local security concerns that threaten the safe operation of our facilities and transport of our products. If such risks materialise, they can result in injuries and disruption to business activities, which could have a material adverse effect on our operational performance and financial condition, as well as our reputation.

Many of our major projects and operations are conducted in joint ventures or associated companies. In certain cases, we may have less influence over and control of the behaviour, performance and cost of operations in which a Shell company holds an interest. Additionally, our partners or members of a joint venture or associated company (particularly local partners in developing countries) may not be able to

meet their financial or other obligations to the projects, threatening the viability of a given project.

Organisational changes and process standardisation, which lead to more reliance on a decreasing number of global systems, outsourcing and relocation of information technology services as well as increased regulations increase the risk that our IT systems may fail to deliver products, services and solutions in a compliant, secure and efficient manner.

Technology and innovation are essential to Shell. If we do not develop the right technology, do not have access to it or do not deploy it effectively, it may affect the delivery of our strategy, our profitability and our financial condition.

Shell companies are subject to differing economic and financial market conditions throughout the world. Political or economic instability affect such markets. For example, if the current worldwide economic downturn deepens or is prolonged, it could contribute to instability in financial markets. Shell uses debt instruments such as bonds and commercial paper to raise significant amounts of capital. Should our access to debt markets become more difficult, we might not be able to maintain a level of liquidity required to fund the implementation of our strategy. Trading and treasury risks include among others exposure to movements in commodity prices, interest rates and foreign exchange rates, counterparty default and various operational risks (see also pages 81-82). As a global company doing business in over 90 countries, we are exposed to changes in currency values and exchange controls. While Shell does undertake some currency hedging, we do not do so for all of our activities. The resulting exposure could affect our earnings and cash flow (see Notes 4 and 23 to the Consolidated Financial Statements).

The estimation of oil and gas reserves involves subjective judgements and determinations based on available geological, technical, contractual and economic information. The estimate may change because of new information from production or drilling activities or changes in economic factors. It may also alter because of acquisitions and disposals, new discoveries and extensions of existing fields and mines, as well as the application of improved recovery techniques. Published reserves estimates may also be subject to correction due to the application of published rules and guidance. Any downward adjustment would indicate lower future production volumes and may adversely affect our earnings as well as our financial condition.

Our Articles of Association generally require that all disputes between our shareholders in such capacity and the Company or our subsidiaries (or our Directors or former Directors) or between the Company 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. Accordingly, the ability of shareholders to obtain monetary or other relief, including in respect of securities law claims, may be determined in accordance with these provisions. Please see “Corporate governance” for further information.

Antitrust and competition laws apply to Shell companies in the vast majority of countries in which we do business. Shell companies have been fined for violations of antitrust and competition law. These include a number of fines by the European Commission Directorate-General for Competition (DG COMP). Due to the DG COMP’s fining guidelines, any future conviction of Shell companies for violation of European Union (EU) competition law could result in significantly enhanced fines. Violation of antitrust laws is a criminal offence in many countries, and individuals can be either imprisoned or fined. Furthermore, it is now common for persons or corporations allegedly injured by antitrust violations to sue for damages.

We face various risks in our Nigerian operations. These risks include security issues surrounding the safety of our people, host communities, and operations, our ability to enforce existing contractual rights, limited infrastructure and potential legislation that could increase our taxes. The Nigerian government is contemplating new legislation to govern the petroleum industry which, if passed into law, would likely have a significant influence on Shell’s existing and future activities in that country and could adversely affect our financial returns from projects in that country.

US laws and regulations identify certain countries, including Iran and Syria, 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 any12-monthperiod 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 EU, which means the statutes conflict with each other in some respects. While Shell did not exceed the limit on investments in Iran in 2009, we have exceeded it in the past and may exceed the US-imposed investment limits in Iran in the future. While we seek to comply with legal requirements in our dealings in these countries, it is possible that Shell or persons employed by Shell could be found to be subject to sanctions or other penalties under this legislation in connection with their activities in these countries.

The risk regarding pensions is the ability to fund defined benefit plans to the extent that the pension assets fail to meet future liabilities. Liabilities associated with and cash funding of pensions can be significant and are dependent on various assumptions. Volatility in capital markets and the resulting consequences for investment performance as well as interest rates, may result in significant changes to the funding level of future liabilities. In case of a shortfall, Shell might be required to make substantial cash contributions, depending on the applicable regulations per country. For example, as a result of the funding shortfall experienced at the end of 2008, employer contributions to defined benefit pension funds in 2009 were $3.6 billion higher than in 2008.

See “Liquidity and capital resources” for further discussion.

From time to time cultural and political factors play a significant role in unprecedented and unanticipated judicial outcomes contrary to local and international law. In addition, certain governments, states and regulatory bodies have, in the opinion of Shell, exceeded their constitutional authority by attempting unilaterally to amend or cancel existing agreements or arrangements; by failing to honour existing contractual commitments; and by seeking to adjudicate disputes between private litigants. Adverse outcomes in these areas could have a material effect on our operations and financial condition.

In July 2007, Shell’s US subsidiary, Shell Oil, was contacted by the US Department of Justice regarding Shell’s use of the freight forwarding firm Panalpina, Inc and potential violations of the US Foreign Corrupt Practices Act (FCPA) as a result of such use. Shell has an ongoing internal investigation and is co-operating with the US Department of Justice and the US Securities and Exchange Commission investigations. As a result of these investigations, Shell may face fines and additional costs.

The most significant factors affectingyear-to-yearcomparisons of earnings and cash flow generated by our operating activities are: changes in realised oil and gas prices; oil and gas production levels; and refining and marketing margins.

During 2009, oil prices increased, but the average price was lower than in 2008. Gas prices and refining margins declined sharply, because of weaker demand and high industry inventory levels. Oil and gas production available for sale in 2009 was 3,142 thousand barrels of oil equivalent per day (boe/d), compared with 3,248 thousand boe/d in 2008 (including mined oil sands production of78 thousand b/d).

Earnings in 2009 were 52% lower than in 2008, when they were 17% lower than in 2007. The decrease reflected lower realised oil and gas prices and lower production in Upstream as well as lower margins and sales volumes in Downstream. These effects more than offset the positive effect on earnings of increasing oil prices on inventory.

In 2009, Upstream earnings were $8,354 million, 68% lower than in 2008 and 54% lower than in 2007. Earnings in 2009 reflected the effect of significantly lower realised prices for both oil and gas in combination with lower production volumes. Moreover, the 2008 earnings included significant gains from the divestment of various assets. In 2008, earnings increased by 46% from 2007, mainly reflecting higher realised oil and gas prices, partly offset by lower production volumes.

Downstream earnings in 2009 were $3,054 million, compared with $39 million in 2008 and $12,445 million in 2007. When earnings are adjusted for the impact of changing oil prices on inventory, then earnings in 2009 decreased significantly with respect to 2008 because lower demand drove down our realised refining margins and most of our realised marketing margins in 2009. The adjusted earnings also decreased between 2007 and 2008 because of lower margins on chemical products, lower refining margins in the USA and higher operating costs.

Shell’s strategy to invest in the development of major growth projects, primarily in Upstream, explains the most significant changes to the balance sheet in 2009. Property, plant and equipment increased by $19.6 billion mainly as a result of capital investment of $31.7 billion, 17% lower than capital investment in 2008. The effect of capital investment on property, plant and equipment was partly offset by depreciation, depletion and amortisation of $14.5 billion in 2009.

Of the 2009 capital investment, $24 billion related to Upstream projects that will primarily deliver organic growth over the long term. These projects include several multi-billion-dollar, integrated facilities that are expected to provide significant cash flows for the coming decades. In 2009, the total debt increased by $11.8 billion. Overall, total equity increased by $9.3 billion in 2009, to $138.1 billion.

The gearing ratio was 15.5% at the end of 2009, compared with 5.9% at the end of 2008. The change reflects the increase of the total debt in combination with a decrease in the cash and cash equivalents position in 2009.

The demand for oil and gas is strongly linked to the strength of the global economy. For that reason, projected economic growth is considered an indicator of the future demand for our products and services.

Following the extreme contraction in the global economy in the fourth quarter of 2008 and first quarter of 2009 that was triggered by the severe financial crisis in the USA and Europe, world output accelerated over the remaining quarters of 2009. The recession ended in most major economies by the third quarter of the year. This turnaround was due in part to the extraordinary macroeconomic stimulus and financial sector supports implemented by governments and central banks to contain the crisis. In this context, the global economy contracted by (0.8%) in 2009, down from growth of 3.2% in 2008 and 5.1% in 2007.

In 2010, global output growth is expected to recover, but the recovery is likely to be slow and uncertain given the depth of contraction in 2009.

Oil prices rose steadily through 2009. Brent crude oil started the year at $40 per barrel and inmid-Novemberreached the $78 mark, which is approximately where it ended the year. On average, however, 2009 prices were considerably lower than they were in 2008. Brent crude oil averaged $61.55 per barrel in 2009, compared with $97.14 in 2008, and West Texas Intermediate averaged $61.75 per barrel in 2009, compared with $99.72 a year earlier.

Natural gas prices also spanned a wide range in 2009. The Henry Hub prices trended downwards between January and September: from a monthly average high of $5.27 per million British thermal units (MMBtu) in January down to a monthly low of $2.88 in September, when inventories were hitting an all-time high and production had to be discouraged. From October until the end of 2009, however, Henry Hub gas prices reversed the trend with the onset of winter weather. Overall, the Henry Hub gas price averaged $3.90 per MMBtu in 2009 compared with $8.85 in 2008. In the UK, prices at the National Balancing Point averaged 30.93 pence/therm in 2009 compared with 58.06 pence/therm in 2008.

Unlike crude oil pricing, which is global in nature, gas prices can vary significantly from region to region. Shell produces and sells natural gas in regions whose supply, demand and regulatory circumstances differ markedly from those of the US’s Henry Hub or the UK’s National Balancing Point. Natural gas prices in continental Europe and in the Asia-Pacific region are predominantly indexed to oil prices. In Europe, contractual time-lag effects resulted in a continued price decline throughout the first half of 2009, while demand was at the same time severely impacted by the recession. Oil-indexed prices started to recover in the fourth quarter, maintaining a very significant premium above the UK’s National Balancing Point.

The range of possible future crude oil and natural gas prices used in project and portfolio evaluations within Shell are determined after assessment of short-, medium- and long-term price drivers under different sets of assumptions. Historical analysis, trends and statistical volatility are all part of this assessment, as are analyses of possible future economic conditions, geopolitics, OPEC actions, supply costs

and the balance of supply and demand. Sensitivity analyses are used to test the impact of low-price drivers, such as economic weakness, and high-price drivers, such as 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, contribute to price volatility.

Shell expects oil prices to typically average $50 to $90 per barrel and screens new upstream opportunities inside this range. Shell uses a grid based on low, medium and high oil and gas prices to test the economic performance of long-term projects. As part of our normal business practice, the range of prices used for this purpose is always subject to review and change.

Refining margins were lacklustre in all key refining centres in 2009. Margins came under downward pressure with the reduced demand due to the global recession. On top of that, there was significant refinery overcapacity following thestart-up of major refining facilities in Asia.

Demand for petrochemicals recovered during the second half of 2009, as GDP growth resumed and restocking took place. Global ethylene demand grew a little under 1% in 2009 after suffering a decline of over 3% in 2008.

Industry refining margins in 2010 are likely to remain fundamentally weak because of the expected ongoing global excess product inventory, particularly for middle distillates.

Our strategy seeks to reinforce our position as a leader in the oil and gas industry in order to provide a competitive shareholder return while helping to meet global energy demand in a responsible way.

Intense competition will remain for access to resources by our Upstream businesses and new markets by our Downstream businesses. We believe our technology, project-delivery capability and operational excellence will remain key differentiators for our businesses.

In Upstream, we focus on exploration for new oil and gas reserves and developing major projects where our technology and know-how adds value to the resource holders. In our Downstream businesses, our emphasis remains on sustained cash generation from our existing assets and selective investments in growth markets.

We will continue to focus on capital and cost discipline. We expect around 80% of our capital investment in 2010 to be in our Upstream projects. In Downstream, we aim to maintain relatively steady capital employed.

Meeting the growing demand for energy worldwide in ways that minimise environmental and social impact is a major challenge for the global energy industry. We are committed to improving energy efficiency in our own operations, supporting customers in managing their energy demands and continuing to research and develop technologies that increase efficiency and reduce emissions in oil and gas production.

Our commitment to technology and innovation continues to be at the core of our strategy. As energy projects become more complex and more technically demanding, we believe our technical expertise will be a deciding factor in the growth of our businesses. Our key strengths include the development and application of technology, the financial

and project-management skills that allow us to deliver large oil and gas projects, and the management of integrated value chains. We leverage our diverse and global business portfolio and customer-focused businesses built around the strength of the Shell brand.

We have defined three distinct layers for Shell’s strategy development: near-term performance focus, medium-term growth delivery and maturing next generation project options.

In the near-term, we will emphasise performance focus. We will work on continuous improvements in operating performance, with an emphasis on health, safety and environment, asset performance and operating costs, including plans for $1 billion of cost savings in 2010. There will be asset sales of up to $3 billion per year as Shell exits from non-core positions across the company.

We have new initiatives that are expected to improve on Shell’s industry-leading Downstream, focusing on the most profitable positions and growth potential. Shell has plans to exit from 15% of its world-wide refining capacity and from selected retail and other marketing positions, and is taking steps to improve the quality of its chemicals assets.

We plan net capital investment of some $29 billion in 2010 (net capital investment represents capital investment, less divestment proceeds). This amount relates largely to investments in projects where the final investment decision has already been taken or is expected to be taken in 2010. This excludes any impact of the indicative offer to acquire Arrow Energy Limited.

Organic capital investment is expected to be $25 to $30 billion per year for 2011 to 2014, as Shell invests for long-term growth. Annual spending will be driven by the timing of investment decisions and the near-term macro outlook.

Cash flow from operations excluding working capital was $24 billion in 2009. Shell expects cash flow to grow by around 50% from 2009 to 2012 assuming a $60 oil price and a more normal environment for natural gas prices and downstream. In an $80 environment, 2012 cash flow should be at least 80% higher than 2009 levels.

In Downstream, Shell is adding new chemicals capacity in Singapore and refining capacity in the USA, and making selective growth investment in marketing.

Oil and gas production is expected to average 3.5 million boe/d in 2012, compared to 3.1 million boe/d in 2009, an increase of 11%, and with confidence of further growth to 2014.

Shell has built up a substantial portfolio of options for the next wave of growth. This portfolio has been designed to capture price upside, and minimise Shell’s exposure to industry challenges from cost inflation and political risk. Key elements of this opportunity set are in the Gulf of Mexico, USA and Canada tight gas, and Australia LNG. These are the projects that have the potential to underpin production growth to the end of the decade. Shell is working to mature these projects, with an emphasis on financial returns.

Shell added 4,417 million boe of proved oil and gas reserves before production, of which 3,632 million boe comes from Shell subsidiaries

and 785 million boe is associated with the Shell share of equity-accounted investments. Included in the 4,417 million boe is 1,630 million boe of synthetic crude oil reserves. Last year, we had reported 997 million boe of proven minable oil sands reserves as of December 31, 2008. As a result of the SEC rule changes these proven minable reserves have been converted to synthetic crude oil proved reserves and are included in the 1,630 million boe. Accordingly we will no longer be reporting proven minable oil sands reserves. The increase of 4,417 million boe of proved oil and gas reserves also includes approximately 270 million boe associated with other SEC changes in proved reserves reporting. Furthermore, for the first time we have included 599 million boe proved reserves associated with future production that will be consumed in operations (for example, as fuel gas). Finally, the total additions reflect a net positive impact from commodity price changes of approximately 260 million boe proved reserves.

In 2009, total oil and gas production available for sale was 1,147 million boe. An additional 40 million boe was produced and consumed in operations. Production available for sale from subsidiaries was 828 million boe with an additional 35 million boe consumed in operations. The Shell share of the production available for sale of equity-accounted investments was 319 million boe with an additional 5 million boe consumed in operations.

Accordingly, after taking into account total production we had a net increase of 3,230 million boe in proved oil and gas reserves of which 2,769 million boe is from subsidiaries and 461 million boe is associated with the Shell share of equity-accounted investments.

Details of Shell subsidiaries’ and the Shell share of equity-accounted investments’ estimated net proved reserves are summarised in the table on page 29 and are set out under the heading “Supplementary information – Oil and gas” on pages 140-149.

In 2009, our research and development (R&D) expenses were $1,125 million, compared with $1,230 million in 2008 and $1,167 million in 2007.

Our R&D programme adapts and applies technologies that reduce the energy requirements, environmental impacts and running costs of our current operations. It also develops technologies that help us capitalise on business-growth opportunities, both in Upstream and in Downstream. And it can create entirely new technologies, such as those needed for alternative fuels or carbon capture and sequestration, which may become part of the world’s energy system in the longer term.

The technologies we created, developed and applied in our businesses during 2009 certainly spanned that wide range of purpose. For example, our current operations were made more efficient by the many Smart Field implementations that optimised production from oil and gas fields and by the catalysts we manufactured for the nearly completed Pearl GTL plant. New exploration prospects were identified in the Middle East and Africa with novel seismic survey technologies. And new markets were opened by ourhigh-mileageFuelSave gasoline formulation, which was launched in various countries. Unprecedented technological achievements were also in the works in 2009, so that we can build a floating LNG plant for the offshore Prelude and Concerto fields of Australia and realise a full-scalecellulose-to-ethanolplant for next-generation biofuels.

With the Transition 2009 reorganisation, we sharpened the accountability for delivery of all aspects of our R&D programme. We also linked the programme’s projects more closely with the business

that stands most to profit from what they deliver. In doing so, we also established useful links between our Upstream and Downstream technologies. The new R&D organisation also enables us to introduce further simplification and standardisation in the way we manage the development of technology.

Our R&D programme for 2010 will remain on the same general course as that for 2009. But it will benefit from the clearer lines of sight now established between a technology’s creation and its ultimate deployment in the field.

Please refer to Note 3 to the Consolidated Financial Statements for a discussion of key accounting estimates and judgements.

Please refer to Note 28 to the Consolidated Financial Statements for a discussion of legal proceedings.

Please refer to Note 29 to the Consolidated Financial Statements for a discussion of auditors’ fees and services.

Our Upstream businesses explore for and extract crude oil and natural gas, often in joint ventures with international and national oil companies. We liquefy natural gas by cooling and transport it to customers across the world. We also convert natural gas to liquids (GTL) to provide cleaner burning fuels. Upstream markets and trades natural gas and power in support of our businesses. We extract bitumen – an especially thick, heavy oil – from mined oil sands and convert it to synthetic crude oil. We are also developers of wind power as a means to generate electricity.

The economic environment in 2009 was a challenge to both Shell and the industry. According to the International Energy Agency, the 2009 oil demand decline of 1.5% is the largest decline since 1982. Similarly, we faced gas demand declines in Europe and the USA of some 7% and 2% respectively. At the same time, global liquefied natural gas (LNG) capacity increased by 20% in 2009, exerting downward pressure on global gas prices. Spot gas prices were significantly lower in 2009 than in 2008. Much of Shell’s natural gas and LNG portfolio has term contracts with price realisations that trailed oil price trends, typically by 4 to 6 months. Gas production represented 47% of total production of 3,142 thousand boe/d. The chart below illustrates the significant difference in direction between Shell’s realised prices for oil and gas in 2009.

Segment earnings in 2009 were $8,354 million, 68% lower than in 2008. The decrease in 2009 from 2008 was mainly due to significantly

lower realised oil and gas prices. Higher costs and lower sales volumes also contributed slightly to the decline. The earnings decline was partly offset by lower royalties, lower taxes and higher trading contributions. Additionally, 2009 earnings included a net charge of $134 million compared with net gains of $3,487 million in 2008. The net charge of $134 million in 2009 mainly relates to impairments and redundancy charges, partly offset by exceptional tax items, and divestment gains. The net gains of $3,487 million in 2008 mainly related to the divestment of assets in Australia, Canada, Germany, the Netherlands, Nigeria, the UK and the USA, which were partly offset by themark-to-marketvaluation of certain UK gas contracts and an exceptional tax charge due to new legislation in Italy.

While natural gas production was flat in 2009, LNG sales volumes of 13.40 million tonnes were 3% higher than in 2008. This increase reflected theramp-up in sales volumes from the Sakhalin II LNG project and Train 5 at the Australian North West Shelf project, which were partly offset by lower volumes from Nigeria LNG and reduced LNG demand due to the recession.

Segment earnings in 2008 were $26,506 million, 46% higher than in 2007, due to the impact of higher realised oil and gas prices. This was partly offset by lower production volumes, particularly in the USA, where hurricanes affected operations. Higher taxes, royalties and exploration costs also reduced 2008 earnings. Net gains of $3,487 million in 2008 compared with net gains of $1,471 million in 2007. The net gains in 2007 mainly related to asset divestments and various taxation credits, which were partly offset by themark-to-marketvaluation of certain UK gas contracts and a charge mainly relating to the onshore assets in Nigeria, including impairments and provisions arising from the funding and security situation there.

Capital investment in 2009 was $24 billion. This represents a 26% decrease from 2008, which included over $8 billion in acquisitions, primarily relating to Duvernay Oil Corp. Capital investment included exploration expenditure of $4.5 billion (2008: $11.0 billion).

In Abu Dhabi, Shell signed an agreement with Abu Dhabi National Oil Company (ADNOC) to extend the GASCO joint venture for a further 20 years.

In Australia, Shell and its partners took the final investment decision (FID) for the Gorgon LNG project (Shell share 25%). Gorgon will supply global gas markets to at least 2050, with a capacity of 15 million tonnes (100% basis) of LNG per year and a major carbon capture and storage scheme.

Shell has announced a front-end engineering and design study for a floating LNG (FLNG) project, with the potential to deploy these facilities at the Prelude offshore gas discovery in Australia (Shell share 100%).

In Australia, Shell confirmed that it has accepted Woodside Petroleum Ltd.’s (Woodside) entitlement offer of new shares at a total cost of $0.8 billion, maintaining its 34.27% share in the company; $0.4 billion was paid in 2009 with the remainder paid in 2010.

In Bolivia and Brazil, Shell sold its share in a gas pipeline and in a thermoelectric power plant and its related assets for a total of around $100 million.

In Canada, the Government of Alberta and the national government jointly announced their intent to contribute $0.8 billion of funding towards the Quest carbon capture and sequestration project. Quest,

which is at the feasibility study stage, could capture CO₂from the Athabasca Oil Sands Project at the Scotford Upgrader, for underground storage.

In Egypt, Shell signed agreements to acquire a 40% holding and become the operator on the Alam El Shawish West Concession, where oil and gas discoveries have been confirmed.

In Iraq, Shell was awarded a contract as lead operator in developing the Majnoon field (Shell interest 45%). Production is expected to reach 1.8 million boe/d, up from a current level of approximately 45 thousand boe/d (100% basis). In addition, Shell was awarded a 15% share in a contract for the development of the West Qurna 1 field. According to the contracts’ provisions, Shell’s equity entitlement volumes will be lower than the Shell interest implies.

In the USA, the FID was taken on the Caesar Tonga project (Shell interest 22.4%), with estimated peak production of 40 thousand boe/d (100% basis).

In Africa and Europe, Shell has agreed to an asset swap with Hess Corporation to acquire assets in Gabon and in the UK North Sea in return for Shell’s interest in a pair of Norwegian offshore fields (subject to government approval and other requisite consents).

In 2009, hydrocarbon production averaged 3,142 thousand boe/d, which was 3% lower than in 2008 and 5% lower than in 2007. Lower production in 2009 when compared with 2008 is attributable to field declines, OPEC restrictions, lower production in Nigeria due to security issues, and higher maintenance downtime, mainly in the UK. A reduction in gas demand due to the global recession was also a key factor. These declines were partly offset byramp-up of new fields, PSC price effects and a comparatively mild 2009 hurricane season in the USA.

Field declines affecting production were predominantly in the UK and the USA, but were also seen in Australia, Brazil, Canada, Denmark, Malaysia and Norway. The effect of declining fields was more than offset by production from new fields.

In Brazil, production started from the multi-field Parque das Conchas (BC-10) project (Shell interest 50%). Production wells, which are some two kilometres deep, are linked to a floating production, storage and offloading vessel with a capacity to process 100 thousand barrels of oil and 50 million cubic feet of natural gas a day (100% basis).

In Brunei, field-development projects at Mampak Block 4 and Bugan came on-stream in 2009.

In Norway, the Ormen Lange gas field (Shell interest 17%) reached peak production in November 2009. The field delivers gas to the UK market.

In Russia, the Sakhalin II project (Shell interest 27.5%) achieved peak production of over 400 thousandboe/d in the third quarter. It also successfully ramped up production from its two LNG trains, ahead of schedule. Production continued to increase from the Salym fields (Shell interest 50%), reaching almost 160 thousand boe/d during the latter half of 2009.

During 2009, Shell participated in 11 notable discoveries in Australia, Malaysia, Norway, Oman and the US Gulf of Mexico. Discoveries will be evaluated in order to establish the extent of the volumes they

contain. Shell also saw particularly strong results from exploration and appraisal drilling in the North American Haynesville and Groundbirch tight gas areas. In appraisal drilling, Shell participated in three notable successes in onshore and offshore Australia and the UK.

In total, Shell participated in 345 successful wells drilled outside proved areas. This comprises 28 conventional oil and gas wells and 148 unconventional gas exploration and appraisal wells, as well as 169 additional appraisal wells intended to extend proved areas near existing assets.

In 2009, Shell added acreage to our exploration portfolio mainly from new licences in Australia, Brazil, Canada, Guyana, Italy, Jordan, Norway and the USA, and successfully bid for new exploration licences in Egypt, South Africa and French Guiana. Shell acquired one licence in the Exmouth area, offshore north-west Australia. In Brazil, Shell was awarded 5 blocks in the onshore frontier Sao Francisco Basin. In Canada, Shell expanded our acreage holdings in British Columbia. In Guyana, the farm-in agreement to the Stabroek licence was finalised. In Italy, Shell farmed into six blocks in the deepwater Sicily Channel area. In Jordan, an oil shale concession agreement was finalised. In Norway, Shell was awarded two licences in the 20th bid round. In the US Gulf of Mexico, Shell was awarded exploration rights on 42 blocks in two lease sales, of which 39 were in lease sale 208.

In total, Shell secured rights to some 97,000 km² of new exploration acreage. Overall, our exploration acreage increased in 2009 relative to 2008, mainly due to the acreage additions in locations noted above, partly offset by a combination of divestments, relinquishments and licence expiry of acreage in various countries (mainly Canada, Malaysia and the UK).

Shell, along with the oil and gas industry as a whole, was impacted by the global recession during 2009. Compared with the previous year, the business environment was characterised by overall weaker oil and gas demand, reduced spending on non-core development and exploration activities and lower average realised prices.

Although oil prices did recover throughout the year, this was driven more by disciplined production controls from OPEC and other oil producing countries than from a recovery in underlying demand. In the short term, uncertainties around the robustness of the global economic recovery continue to present the industry with challenges in terms of investment choices, and require a sharp and sustained increase in emphasis on cost management. Longer term we do believe that global energy demand will again experience strong growth based on the fundamentals of an increasing global population and economic development, with supplies ofeasy-to-accessoil and gas remaining challenged to keep up with demand. This long-term view on global energy demand means that Shell’s strategy, which has been pursued consistently for several years, remains unchanged.

The implementation of our strategy will see us actively manage our portfolio around four themes:

Based on production, our heartlands have traditionally included Australia, Brunei, Canada, Denmark, Malaysia, the Netherlands, Nigeria, Norway, Oman, the UK and the USA. Russia represents a new heartland with Sakhalin II on-stream in 2009, and we expect Qatar to become a heartland in the coming years.

Underpinning these four themes is a foundation of technology; Shell’s ability to develop and deploy technology is a key differentiator, with applications across the value chain, and we continue significant investment in R&D to support this position.

We continue to pursue an aggressive exploration programme and we are adding more acreage in support of our strategy themes. Our emphasis remains on drilling large exploration prospects and plays, in selected basins, and targeting under-explored areas with significant potential. The programme is further complemented by our focused Near Field Exploration programme aiming to leverage existing infrastructure near selected Shell production facilities around the world.

Shell seeks to build on its position as one of the world’s largest natural gas producers and retain our position as industry leader in LNG, with a significant presence in the key markets of North America, Asia-Pacific and Europe. We aim to access and monetise new natural gas resources by offering competitive value propositions to our customers and major resource holders. In doing so, we leverage a diverse natural gas portfolio; global capabilities including technical and commercial skills, financing, marketing, trading, shipping and project management expertise; premium market access (for LNG and GTL); and leading technology. With Sakhalin II in Russia now on-stream, integrated gas focus moves to the completion of the Qatar projects, and to further progress in Australia, notably on the Gorgon LNG project, and on moving towards FID on the Prelude floating LNG development. This latter project is an exciting opportunity, continuing Shell’s tradition of driving technological innovation to unlock new resources. In North America, we continue to progress our onshore unconventional gas developments in Pinedale (Wyoming), Haynesville (Louisiana), Groundbirch (British Columbia) and other assets largely as planned, whilst utilising the inherent flexibility some of these developments provide to manage shorter term activity levels.

With respect to Nigeria, the impact of continued security problems in the Niger Delta, and partner funding limitations within the onshore joint venture, continue to present challenges. While we have achieved some success with both funding and restoring production, the security situation remains fragile. Shell’s operating capability with existing assets and infrastructure remains strong in a country with a plentiful hydrocarbon resource base. However, the future industry outlook is uncertain, with the government contemplating the introduction of a new Petroleum Industry Bill, which could potentially reduce the economic attractiveness of oil and gas projects.

Unconventional oil is a material component of our portfolio and in 2009 Shell and others in the oil sands industry reacted to the recession and low oil prices by deferring projects. This has eased the pressure on the demand for labour, and with energy costs also falling, a lower cost environment is starting to materialise. Looking forward it is anticipated that this trend will reverse, although the extreme labour shortages of recent years are not expected to return. The outlook for energy costs is also higher as the economy moves out of recession. These market factors underpin Shell’s continued focus on operational excellence and cost management to ensure a robust business.

Details of Shell subsidiaries’ and the Shell share of equity-accounted investments’ estimated net proved reserves are summarised in the table on page 29 and are set out under the heading “Supplementary information – Oil and gas” on pages 140-149. It should be noted that totals are further influenced by commodity price effects.

In December 2008, the United States Securities and Exchange Commission (SEC) and subsequently in January 2010 the Financial Accounting Standards Board (FASB) adopted revisions to oil and gas reporting rules in order to modernise and update the oil and gas reserves estimation and disclosure requirements. Our proved reserves volumes reported for the end of 2009 have been determined in accordance with these updated rules.

In 2009, we updated and enhanced our reserves assurance process by creating a central group of reserves experts, whom on average have over 25 years experience in the oil and gas industry. This group of experts are part of the Reserves Assurance and Reporting organisation (RAR). RAR provides primary assurance for all proved reserves bookings. A Vice President with over 35 years’ experience in the oil and gas industry currently heads RAR. He is a member of the Society of Petroleum Engineers and holds a Bachelor of Science in Petroleum Engineering from the University of Tulsa, Oklahoma, USA and Master of Science degrees in both Petroleum Engineering and Operations Research from Stanford University, California, USA. This RAR organisation reports directly to an Executive Vice President of Finance, who is a member of the Upstream Reserves Committee. The Upstream Reserves Committee is a multidisciplinary committee consisting of senior representatives from the Finance, Legal, Projects & Technology and the Upstream organisations. The Upstream Reserves Committee reviews and endorses all proved reserves bookings with final approval remaining with Shell’s Executive Committee. Internal Audit also provides secondary assurance through risk-based audits, focusing on the control framework and large proved reserves bookings.

In 2009, Shell added 4,417 million boe of proved oil and gas reserves before accounting for production, of which 3,632 million boe comes from Shell subsidiaries and 785 million boe is associated with Shell’s share of equity-accounted investments. Included in the 4,417 million boe is 1,630 million boe of synthetic crude oil reserves that, as a result of SEC rule changes, can now be considered proved oil and gas reserves as well as approximately 270 million boe associated with other SEC rule changes pertaining to the use of reliable technologies and the use of analogues. The application of reliable technologies contributed approximately 150 million boe of the 270 million boe. The most significant increases related to the use of wireline pressure gradients and wireline testing.

If the 2009 year-end spot price had been used instead of the new SEC requirement to use the 12 month average commodity price, this would have resulted in a reduction of about 160 million boe. Finally, the 4,417 million boe includes 599 million boe that is expected to be consumed in our operations (for example as fuel gas).

Total production available for sale in 2009 was 1,147 million boe and an additional 40 million boe was consumed in our operations. Production from Shell subsidiaries was 828 million boe with an additional 35 million boe consumed in operations. Production associated with the Shell share of equity-accounted investments was 319 million boe with an additional 5 million boe consumed in operations. Accordingly, after taking into account production and volumes consumed in operations, we had a net increase of 3,230 million boe in proved oil and gas reserves of which

2,769 million boe is from Shell subsidiaries and 461 million boe is associated with the Shell share of equity-accounted investments.

Before taking into account production, Shell subsidiaries added 3,632 million boe of proved oil and gas reserves. This includes 843 million barrels of oil and natural gas liquids, 1,103 million boe (6,397 thousand million scf) of natural gas, 1,630 million barrels of synthetic crude oil and 56 million boe of bitumen. Of those volumes 2,266 million boe came from revisions and reclassifications. The revisions and reclassifications include 1,207 million barrels of synthetic crude oil, of which 997 million boe had been previously booked as proven minable oil sands reserves and 325 million boe for volumes expected to be consumed in operations. Also contributing to the 3,632 million boe was a net 2 million boe relating to acquisitions and divestments; 1,324 million boe from extensions and discoveries of which 96 million boe are related to volumes consumed in operations; and 40 million boe from improved recovery.

After taking into account production of 863 million boe (of which 35 million boe was consumed in operations), Shell subsidiaries added 1,017 million boe of proved developed reserves and 1,752 million boe of proved undeveloped reserves.

Before taking into account production, Shell’s equity-accounted investments added 785 million boe of proved reserves, 331 million barrels from oil and natural gas liquids and 454 million boe (2,634 thousand million scf) of natural gas. The majority of these additions – 745 million boe – were from revisions and reclassifications. Included in the 745 million boe is 177 million boe for volumes expected to be consumed in operations and 568 million boe due to extension of licences, improved well performance, ongoing development and commodity price changes.

After taking into account production of 324 million boe (of which 5 million boe was consumed in operations), Shell’s equity-accounted investments added 158 million boe to proved developed reserves and 303 million boe to proved undeveloped reserves.

As a result of SEC rules changes, we are required to report proved synthetic crude oil reserves from our Canadian oil sands operations. Accordingly, in 2009 we added 1,630 million barrels of synthetic crude oil to our proved oil and gas reserves before accounting for production. Last year, we had reported as proven minable oil sands reserves 997 million barrels. As a result of the SEC rules changes these proven minable oil sands reserves have been converted to synthetic crude oil reserves and are included in the 1,630 million barrels of proved synthetic crude oil reserves. Accordingly, we will no longer be reporting proven minable oil sands reserves. Also included in the 1,630 million barrels are 423 million barrels related to new mine extensions.

In 2009 we had synthetic crude oil production of 31 million barrels of which 2 million barrels were consumed in operations. Therefore, as at December 31, 2009 we had total net proved synthetic crude oil reserves of 1,599 million barrels, of which 691 million barrels were proved developed reserves and 908 million barrels were proved undeveloped reserves.

The bitumen proved reserves are reported under the SEC rules definition as other natural resources. The net increase in these proved reserves, before taking into account production, was 56 million

barrels, of which 54 million barrels is attributed to revisions and reclassifications and 2 million barrels to extensions and discoveries; after taking into account production of 7 million barrels, the bitumen proved reserves were 57 million barrels at December 31, 2009.

The changes resulting from the revised SEC rules to Shell’s estimates of proved developed reserves affect prospectively from 2010 the amounts of depreciation, depletion and amortisation charged. These changes will not have a material impact.

The net addition to proved undeveloped reserves was 2,055 million boe in 2009. During the year we converted approximately 556 million boe of proved undeveloped reserves to proved developed reserves, of which approximately 40% is related to fields with no previously reported proved developed reserves. We spent approximately $7.3 billion in developing proved undeveloped reserves in 2009. As at December 31, 2009 we had 7,602 million boe of proved undeveloped reserves.

As at December 31, 2009, approximately 1,064 million boe have been held as proved undeveloped reserves for five years or longer. A majority of these reserves are in locations where Shell has a proven track record of developing major projects, such as in the Netherlands, Nigeria, Norway, Russia and the USA. These proved undeveloped reserves relate primarily to long-life fields. Approximately 90% of these proved undeveloped reserves are associated with currently producing fields. These reserves are expected to be converted from proved undeveloped to proved developed over time as development activities are undertaken to meet contractual obligations and production facilities are expanded or upgraded. The majority of these undeveloped proved reserves are associated with fields that will produce for decades. Accordingly, over the life of these fields, we will be required to provide gas compression and drill additional wells to support existing gas delivery commitments as well as a number of phased developments that will optimise the use of production facilities.

In the coming years we expect an increase in our proved undeveloped reserves that have been held for five years or longer due to the relatively recent commencement of construction of major, long-lasting production projects in Canada, Kazakhstan and Qatar.

Shell sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit Shell to sell quantities based on production from specified properties, some natural gas sales contracts specify delivery of fixed and determinable quantities, as discussed below.

Shell is contractually committed to deliver to third parties and affiliates a total of approximately 4,500 billion cubic feet of natural gas from 2010 through 2012 from Australia, Brunei, China, Malaysia, Nigeria, Norway, Philippines, Russia and the UK. The sales contracts contain a mixture of fixed and variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. Shell believes it can satisfy these contracts from gas sources in these regions.

Shell has met all contractual delivery commitments.

Shell subsidiaries and equity-accounted investments are involved in all aspects of Upstream 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:

Shell holds a 46% interest in a producing concession until 2042. Shell’s interest will reduce to 36.8% in July 2012, when the government increases its position to a 20% fully participating stake in the concession. Shell also holds an interest in one other non-operated exploration licence.

Shell has interests in various assets through its participation in Nederlandse Aardolie Maatschappij B.V. (NAM), a 50:50 joint venture between Shell and ExxonMobil. Those assets are operated by NAM.

An important part of NAM’s gas production is from its onshore Groningen gas field, in which the Dutch government has a 40% financial interest, with NAM retaining the remaining share. During 2009 a field renovation project was completed.

Shell is a partner in over 20 production licences on the Norwegian continental shelf. Shell is operator in eight of these, including those of the Shell-operated Draugen oil field (Shell interest 26%), which has

been producing for 15 years, and the Ormen Lange gas field (Shell interest 17%), which reached peak production in 2009.

Shell was also the operator of the development phase of the Troll field and is a partner in the Statfjord field, both of which were producing in 2009.

Shell also holds interests in potential development assets and in several Norwegian gas transportation and processing systems, pipelines and terminals.

In terms of production volumes, Shell is one of the largest oil and gas exploration and production companies operating in the UK. It operates a significant number of its interests in the UK Continental Shelf on behalf of a 50:50 joint venture with ExxonMobil.

Most of Shell’s UK oil and gas 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. Crude oil comes from the central and northern fields. In the Atlantic Margin area, Shell has interests as a non-operating participant principally in the West of Shetlands area, which encompasses the Schiehallion, Clair and Loyal fields.

In Ireland, the Corrib Gas Project (Shell interest 45%, operator) is currently under development, and is largely complete (pending final decision from the Irish planning board on an application for a nine kilometres onshore pipeline).

Shell also has interests in Austria, Germany, Greece, Hungary, Italy, Slovakia, Spain, Sweden and Ukraine.

Shell and the Brunei government are 50:50 shareholders in Brunei Shell Petroleum Company Sendirian Berhad (BSP). BSP holds long-term oil and gas concession rights onshore and offshore Brunei and sells most of its natural gas production to Brunei LNG Sendirian Berhad (BLNG, Shell interest 25%). BLNG was the first LNG plant in the Asia Pacific region and sells most of the LNG on long-term contracts to buyers in Japan and South Korea.

Shell has a 35% interest in the Block B concession where gas is produced from the Maharaja Lela Field. Shell also has a 54% operating interest in exploration Block A.

Shell operates the onshore Changbei tight gas field (Shell interest 50% average) under a PSC with PetroChina. Shell also participates in the offshore Xijiang fields (Shell interests ranging from 24.5% to 47.8%).

Iran is a major resource holder. It has the world’s second largest oil and natural gas resources. At current global gas usage rates, Iran’s gas is enough to supply the entire world for about 10 years. Given the size and global importance of Iranian hydrocarbon resources, Shell finds it hard to see a future in which production of these resources would not, at some point, play an important role in the global energy supply and demand balance.

Major new projects to deliver hydrocarbon resources to customers can easily take more than 10 years to prepare, and require the completion

of a number of phases of feasibility work before any final decision can be taken. It is hard to predict how circumstances in any one country will evolve over that period. Some countries that today appear stable may become less stable and vice versa. It therefore makes sense for Shell and other international energy companies to prepare a portfolio of possible new energy projects in a variety of different locations, and to leave a final investment decision on whether to proceed until the last practicable moment.

We recognise that there are export controls and sanctions legislation in various jurisdictions targeting Iran. We have established programmes to manage compliance with such applicable laws, including the US Export Administration Regulations and the Iranian Transaction Regulations. However, as discussed in the Risk factors section (pages 13 to 15) conflicting US and European Union regulations in this area complicate compliance matters for European companies.

Shell Exploration B.V. (Shell interest 100%) has a 70% interest in an agreement with the National Iranian Oil Company (NIOC) concerning the Soroosh/Nowrooz fields. The development phase is completed and all permanent facilities were handed over to NIOC in 2005. Since then, the Soroosh/Nowrooz fields have been producing, with NIOC being responsible for all aspects of the operations. The term of the agreement expires when all petroleum costs and the remuneration fee have been recovered, which is expected to occur in 2010.

A project framework agreement for the Persian LNG project was signed in 2004 with Repsol and the National Iranian Oil Co. to take forward the Persian LNG project to the next stage of design. Under this agreement, it is envisaged that Shell would acquire a 50% interest in a project to develop phases of the South Pars field in the Persian Gulf and a 25% interest in the midstream liquefaction company. In early 2007, Shell and Repsol entered into a service contract with respect to development of the South Pars fields for the Persian LNG project. Negotiations on commercial issues continued to make progress in 2009. During 2009 we have also looked to mature the technical basis of the project, including front-end engineering design work for the offshore facilities and for the liquefaction plant. The parties will not reach a final decision on whether to proceed with the project until the remaining significant commercial and engineering work is complete. As with all projects, decision timing is fundamentally driven by the need to ensure first class decision quality. Our main concern is getting the remaining significant commercial and engineering work right. When we come to make a final investment decision, we will take political considerations into account. Naturally, we are following international developments closely and keeping a wide range of governments and other stakeholders informed.

We are also providing China Petroleum and Chemical Corporation with technical services relating to their development of the Yadavaran field in Iran. At this time, we have not made any decision on whether to take an equity stake in the project.

Shell’s investments and activities in Iran are not material to our revenues, earnings or assets. In general, potential US sanctions could have a material adverse effect on our future earnings (see Risk factors).

The Iraqi Ministry of Oil awarded Shell a20-yearcontract as lead contractor in the development of the Majnoon oilfield. Shell will operate the development and production service contract. The Iraqi state owns 25% of the participating interest and Shell will hold a 45% share with Petronas holding the remaining 30%. Majnoon, located in southern Iraq, is considered one of the world’s largest oil fields. The current level of production is approximately45 thousand boe/d.Shell

was also awarded a 15% interest in the West Qurna 1 field, as part of theExxonMobil-ledconsortium. According to the contracts’ provisions, Shell’s equity entitlement volumes will be lower than the Shell interest implies.

Shell signed a heads of agreement with the Iraqi Ministry of Oil in September 2008 which sets out the commercial principles to establish a joint venture between Shell and the South Gas Company. The South Gas Company would be the 51% majority shareholder in the joint venture, with Shell holding 44% and Mitsubishi Corporation holding 5%. The joint venture would gather, treat and process raw gas produced within Basrah and sell the processed natural gas (and associated products such as condensate and LPG) for use in the domestic and export markets. The government has extended the heads of agreement by six months from its current expiry date in March 2010.

Shell has a 16.81% share in the offshore Kashagan field. This shallow-water field covers an area of approximately 3,400 km². Phased development of the field will lead to an expected plateau production of300 thousand boe/d(100%) from phase 1, increasing further with additional phases of development. Shell is now executing Kashagan Phase 2front-endengineering and design. Shell and KazMunayGas will manage production operations on behalf of the operator.

Shell is also a 55% partner in the Pearls production-sharing agreement (PSA) that covers an area of some 1,000 km²in a water depth of nine metres in the North Caspian Sea. The block contains two oil discoveries, Khazar (2007) and Auezov (2008), which are currently under appraisal. In 2009, a successful appraisal well and production test were completed on the Khazar discovery.

The Caspian Pipeline Consortium (Shell interest 5.1%) exports production from west Kazakhstan to the Black Sea. The pipeline is 1,510 kilometres long and has been operational since October 2001. In December 2009, the Caspian Pipeline Consortium shareholders approved a pipeline expansion implementation plan. The expansion project is expected to be fully completed in early 2015.

Shell, as contractor to Petronas, produces oil and gas located offshore of Sarawak and Sabah under 15 PSCs, where Shell’s interests range from 30% to 80%.

In Sabah, Shell operates four producing offshore oil fields (with a 50% interest in three and 80% in the other). Shell also has interests in offshore PSCs for the exploration and development of three blocks with interests ranging from 35% to 40%. In addition, Shell has a 50% interest in offshore blocks ND-6 and ND-7.

Shell operates the unitised Gumusut field (Shell interest 33%), which is currently being developed, and the Malikai field (Shell interest 35%). Shell has a 30% interest in the Kebabangan field held through the Kebabangan Cluster PSC and the Kebabangan Petroleum Operating Company. Shell took FID to proceed with the F28 field development (Shell interest 50%) project under the SK308 PSC in 2009.

In Sarawak, Shell is the operator of 16 gas fields, in which its interests range from 37.5% to 70%. Shell also has a 40% interest in the PETRONAS Carigali operated Baram Delta PSC and a 50% exploration interest inSK-307.

In 2009, over 92% of the gas produced by Shell in Malaysia was supplied to the LNG complex in Bintulu, Sarawak (see table on page 37).

Shell also operates a GTL plant (see table on page 37), adjacent to the LNG facilities. Using Shell technology, the plant converts natural gas into high-quality middle distillates and other specialty products.

Shell has a 34% interest in Petroleum Development Oman (PDO), which is the operator of an oil concession expiring in 2044. The government of Oman holds a 60% interest in the concession and Private Oil Holdings Oman Ltd. (POHOL) holds the remaining 40%. Shell has an 85% shareholding in POHOL.

PDO has a portfolio of field-development projects that will build on the successful delivery of ongoing enhanced oil recovery projects and other chemical and thermal pilots.

Shell also participates in the development of the Mukhaizna oil field (Shell interest 17%) where horizontal steam flooding will be applied on a large scale.

Additionally, Shell has a 30% interest in Oman LNG which mainly supplies Asian markets under long-term contracts, and an interest of 11% in Qalhat LNG.

Shell has a 45% interest in the deep-water PSC for block SC-38, which includes a production licence for the Malampaya, Camago and San Martin fields. Current production comprises gas and condensate from the Malampaya field via a platform north-west of the island of Palawan. Shell also holds a 55% interest in block SC-60, an area offshore of north-east Palawan.

In 2006, construction started on the integrated Pearl GTL project. Shell provides 100% of project funding under the development and PSA with the government of the State of Qatar. The fully integrated project includes Upstream production of some1.6 bcf/dof well-head gas from two unmanned platforms in Qatar’s North Field, transport and processing of the gas to produce around 120 thousand b/d of natural gas liquids and ethane, and the conversion of the remaining gas into140 thousand b/dof high-quality liquid hydrocarbon products in the world’s largest GTL plant. Construction is scheduled to be completed by the end of 2010 with productionramp-up in 2011.

The Qatargas 4 LNG project (Shell interest 30%) is progressing. The project comprises facilities to produce some1.4 bcf/dof natural gas from Qatar’s North Field, an onshore gas-processing facility and an LNG complex yielding70 thousand b/dof natural gas liquids and 7.8mtpa of LNG, and shipping of the LNG to markets in North America, China and Dubai. Construction of the Qatargas 4 project is expected to be substantially complete by the end of 2010.

Shell’s main asset is the Sakhalin II project (Shell interest 27.5%), an integrated oil and gas export project in asub-arcticenvironment. The construction of the project was completed in 2009, and the first LNG from Russia was exported in March 2009.

Plateau production from the Sakhalin II project will be some400 thousand boe/dof oil and gas, supplying 9.6mtpa of LNG from two production trains.

Shell has a 50% interest in the Salym fields in Western Siberia, where production increased, reaching almost160 thousand boe/dduring the latter half of 2009.

A registered branch of Syria Shell Petroleum Development B.V. (Shell interest 100%) holds interests ranging from 62.5% to 66.67% in three PSCs (Deir Ez Zor, Fourth Annex and Ash Sham). These were extended by 10 years in December 2008 and now expire between 2018 and 2024. In addition, Shell companies are parties to a gas utilisation agreement for the collection, processing and sharing of natural gas from designated fields for use in Syrian power generation and other industrial plants. Al Furat Petroleum Company, a Syrian joint stock company in which Syria Shell Petroleum Development B.V. holds a 31.25% to 33.3% interest, performs operations under these contracts.

Shell South Syria Exploration Limited (Shell interest 100%) entered into two production-sharing contracts, effective from February 2007, for Blocks 13 and 15 in the south of Syria. There is a four-year exploration period for these blocks, expiring in February 2011, and seismic data acquisition was completed in 2008. Prospect maturation and drilling preparation is ongoing. Shell completed a 30% farm-out to Tri Ocean Energy in November 2009. Shell remains operator with 70% interest.

In Abu Dhabi, Shell holds a concessionary share of 9.5% in the onshore crude oil and natural gas liquids operations of the Abu Dhabi Company for Onshore Oil Operations (ADCO). The licence expires in 2014. Shell also has a 15% interest in the licence of Abu Dhabi Gas Industries Limited (GASCO), which extracts and exports propane and butane as well as heavier liquid hydrocarbons from the wet natural gas associated with the oil produced by ADCO. Shell signed an agreement with Abu Dhabi National Oil Company (ADNOC) to extend the GASCO Joint Venture for a further twenty years to 2028.

Shell also has interests in India, Japan, Jordan, Pakistan, Saudi Arabia, Singapore, South Korea and Turkey.

Shell has interests in offshore production and exploration licences in the North West Shelf (NWS) and Greater Gorgon areas of the Carnarvon Basin, as well as in the Browse Basin and Timor Sea area. Some interests in these areas are held directly, and some indirectly through a 34.27% shareholding in Woodside.

Woodside is the operator on behalf of six joint venture participants of the NWS gas, condensate and oil fields, of which Shell has a 22.4% interest. Construction of the North Rankin 2 low-pressure gas platform continued in 2009, which will be linked to the existing North Rankin A platform and is designed to recover remaining low-pressure gas from the North Rankin fields.

Shell has a 25% interest in the Gorgon development project covering the offshore Greater Gorgon fields, with the exception of Io gas field, where Shell has a 12.5% interest. The final investment decision on the project was taken in September 2009, and construction activities on Barrow Island commenced in December 2009. Gorgon is the largest single resource project in Australia and, at 15mtpa, the world’s largest foundation LNG project.

Shell is operator and 100% equity holder of a permit in the Browse Basin, in which 12 exploration wells have been drilled, finding two separate gas fields – Prelude and Concerto. After evaluating development options, Shell is working towards deployment of FLNG technology. FLNG processes gas in situ at the offshore gas field

location, reducing project costs and minimising the environmental footprint. During 2009, Shell entered the front-end engineering and design phase for Prelude FLNG. Environmental approval work is continuing.

Also in the Browse basin, Shell is a participant in the Woodside operated Browse Joint Venture (Shell interest approximately 25%) covering the Torosa, Brecknock and Calliance gas fields. The Browse Joint Venture participants have agreed to enter the Basis of Design phase for development of the Browse gas resources at the Kimberley LNG Precinct.

Utilising our 30% equity interest in the Surat and Bowen basin Coal Seam Gas (CSG) reserves we hold in an alliance with Arrow Energy, Shell has progressed its Shell Australia LNG CSG project in Gladstone, Queensland. The project has been granted ‘significant project’ status by the state government, triggering the environmental permitting process.

Shell holds further interests in the Sunrise and Evans Shoal gas fields in the Timor Sea (Shell interests 38% and 25% respectively). Sunrise joint venture partners are considering two concepts for the development of Greater Sunrise gas, which would be delivered either to an offshore Shell FLNG plant or to the onshore Darwin LNG plant.

Shell has a 33% interest in the WA-16-R permit, where a discovery was made with the Iago-2 well. Development options are being assessed. Shell also has gas rights in the Crux field (AC/P23) and in the Libra-1 gas discovery in the Shell-operated AC/P41 block (Shell interest 80%).

Shell has an 83.75% interest in the offshore Maui gas field, a 50% interest in the onshore Kapuni gas field and a 48% interest in the offshore Pohokura gas field. The produced gas is sold domestically, mainly under long-term contracts. Shell also has interests in other exploration licence areas in the Taranaki Basin.

Onshore Nigeria The Shell Petroleum Development Company of Nigeria Ltd. (SPDC) is the operator of a joint venture (Shell interest 30%) that holds 30 onshore oil mining leases (OML) in the Niger Delta. The leases expire in 2019.

In 2009, SPDC ramped up power output of the 640 MW Afam VI Power Plant and fuel gas production from the Okoloma Gas Plant in the Niger Delta, and continued to deliver production from gas wells associated with the project – collectively known as the Afam Integrated Gas and Power Project. The Afam VI Power Plant is capable of delivering over 400 MW since July 2009, but the lack of upgrades on the Nigeria electricity grid limits full production.

The Gbaran-Ubie integrated oil and gas project (Shell interest 30%) is developing an area of approximately 650 km²in Bayelsa State. When fully operational, it is expected at its peak to produceone bcf/dof gas and70 thousand b/dof oil. SPDC will drill more than 30 new oil and gas wells, and is building a central processing facility with gas delivery to power plants and Nigeria LNG Ltd. (NLNG).

On the financing side, progress has been made towards full implementation of the Modified Carry Agreements (MCAs) and the bridge loan signed in 2008 and 2009. All requirements for the utilisation of the bridge loan and the implementation of the MCAs have been met in the fourth quarter of 2009.

Offshore Nigeria The main offshore activities are carried out by Shell Nigeria Exploration and Production Company (SNEPCo – Shell interest 100%) with interests in three deep-water blocks, of which two are operated by Shell. This includes the Bonga field 120 kilometres offshore with a production capacity of more than 200 thousand barrels of oil and 150 million standard cubic feet of gas per day. Deep-water offshore activities are typically governed through PSCs with the Nigerian National Petroleum Corporation.

SPDC also holds an interest in six shallow water offshore leases, of which five expired on November 30, 2008. However, under the Nigerian Petroleum Act, SPDC is entitled to an extension. Currently, the status quo is maintained following a court order issued on November 26, 2008. The parties involved are pursuing a negotiated resolution. Production from one of the leases – the Sea Eagle FPSO (“EA licence”) restarted on July 2, 2009, following the shut-down as a result of security incidents in 2006.

Other Shell companies in Nigeria have an interest in deep-water block OPL 322 and a disputed interest in OML 122. Furthermore, the ownership of the licence and the rights in the OPL 245 PSC are the subject of ongoing litigation.

Shell also has a 25.6% interest in NLNG, which operates six LNG trains with a total capacity of 21.6mtpa (100%). NLNG currently has operational control of 24 LNG vessels.

In Egypt, Shell has a 50% interest in the Badr El-Din Petroleum Company joint venture with the Egyptian General Petroleum Corporation (the Egyptian national oil company). Shell also participates in the deep-water North East Mediterranean Deepwater concession and the North West Damietta concession. In 2009, Shell acquired a 40% working interest in the Alam El Shawish West concession, located in the Egyptian western desert.

In Gabon, Shell has interests in nine onshore mining concessions and exploitation permits, and operates six of them. The three non-Shell-operated concessions expire between 2010 and 2021. Shell also holds the Igoumou Marin permit in ultra-deep water and two exploration and production-sharing contracts offshore Gabon.

In South Africa, Shell won the exploration rights in the Orange Basin deep-water area off the country’s west coast in November 2009. The exploration area covers approximately 37,000 km². In December 2009, the South African Petroleum Authorities (Petroleum Agency SA) awarded Shell a Technical Cooperation Permit for a one-year study to determine the hydrocarbon potential in parts of the Karoo Basin in central South Africa.

Shell also has interests in Algeria, Cameroon, Ghana, Libya, Morocco and Tunisia.

Shell produces natural gas, NGL, bitumen, synthetic crude oil and sulphur mainly in Alberta and British Columbia where the main leases/assets are held.

In total, Shell holds over 2,100 leases. Canadian exploration rights are generally granted for varying terms, depending upon the provincial jurisdiction and applicable regulations. 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.

The Alberta government implemented a new royalty framework effective January 1, 2009, which increased royalty rates in both the pre-payout and post-payout periods based on a sliding scale linked to WTI price movement. This resulted in a pre-payout royalty rate increase ranging from 1% to 9% of gross revenues, and a post-payout rate increase ranging from the greater of between 25% and 40% of net revenues or between 1% and 9% of gross revenues (depending on WTI price).

Gas The majority of Shell’s Canadian gas production comes from the Foothills region of Alberta. Shell also owns and operates four natural gas processing and sulphur extraction plants in southern and south-central Alberta and is among the world’s largest producers and marketers of sulphur. In addition, it holds a 31.3% interest in the Sable Offshore Energy Project, a natural gas complex offshore eastern Canada, has a non-operating 20% interest in an early stage deep-water exploration asset off the east coast of Newfoundland and is a joint venture participant in the Mackenzie Gas Pipeline proposal in northern Canada.

In 2009, Shell continued unconventional gas development in west-central Alberta and east-central British Columbia through drilling programmes and investment in infrastructure facilitating new production. Shell holds approximately 600 thousand tight gas acres (2,400 km²) in these areas, and the Groundbirch area reached a 100 million scf/d production milestone in November.

Bitumen Shell produces and markets bitumen, a very heavy crude oil, through cold (primary) production and thermal (enhanced) recovery in the Peace River area of Alberta, and established a steam-assisted gravity drainage project (Phase 1) near Cold Lake, Alberta.

Additional heavy oil resources and advanced recovery technologies are under evaluation on about 1,200 km²in the Grosmont oil sands area, also in north Alberta.

Oil sands/synthetic crude oil The Athabasca Oil Sands Project (AOSP) in northeast Alberta mines bitumen-saturated sand from which synthetic crude oil is produced. AOSP, operated by Shell, is a joint venture (Shell share 60%) that holds the Muskeg River Mine lease (Lease 13).

The oil sand is open-pit mined, using a truck and shovel operation, then processed inon-sitebitumen extraction andclean-upfacilities to yield a bitumen product. Power and steam for the operations are provided from anon-siteco-generation facility, which is owned and operated by an independent power company, in combination with boiler facilities owned by the joint venture. The bitumen is transported by pipeline for processing at the Scotford Upgrader, which is operated by Shell and located in the Edmonton area of central Alberta. Scotford’s upgrading process adds hydrogen to the bitumen, breaking up the large hydrocarbon molecules. Using this process we produce a wide range of synthetic crude oils suitable as a feedstock for refineries, which process them into refined products such as gasoline.

AOSP’s current bitumen production capacity is155 thousand boe/d(Shell interest 60%). An expansion of AOSP, expected to be completed in 2010 to 2011, will add about 100 thousand barrels of daily production capacity (Shell interest 60%).

Shell also holds a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2010 to 2020. By

completing a minimum level of development prior to their expiry, leases may be extended.

Shell is a producer of oil and gas in the Gulf of Mexico (GoM), onshore tight gas (south Texas, Wyoming and Louisiana) and heavy oil (California). The majority of Shell’s oil and gas production interests are acquired under leases granted by the owner of the minerals underlying the relevant acreage (including many leases for federal onshore and offshore tracts). Such leases are currently running on an initial fixed term that is automatically extended by the establishment of production for as long as production continues, subject to compliance with the terms of the lease (including, in the case of federal leases, extensive regulations imposed by federal law).

In Alaska, Shell holds over 410 federal leases in the Beaufort and Chukchi seas but did not pursue offshore drilling or seismic programmes on them in 2009. It concentrated on obtaining permits and other preparatory work to advance more limited single-year drilling plans in 2010. The modified plans, developed in consultation with native stakeholders, were approved by the Minerals Management Service. Final Environmental Protection Agency air permits, however, still remain to be granted before drilling can begin. Shell hopes to drill exploratory wells in the north Alaska offshore in 2010.

Gulf of Mexico The Gulf of Mexico is the major production area, accounting for some 60% of Shell’s oil and gas production in the USA. Shell holds more than 460 federal offshore leases in the Gulf, about a quarter of them producing. Shell operates five deep-water tension leg platforms, and a dozen others, with average Shell-share production of over270 thousand boe/din 2009. Key producing fields are Auger, Mars, Ram Powell, Ursa, Princess, Brutus, NaKika and Deimos.

Shell, with partners, are advancing the Perdido project (Shell interest 35.4%) in the far south-west Gulf of Mexico throughout 2009 and will achieve first oil in 2010. Shell will operate this ultra deep water spar facility.

Onshore Shell continues to operate efficient multi-rig onshore gas-well drilling programmes in south Texas and Wyoming, where Shell and partners recorded their first full year under revised federal environmental rules allowing year-round operations. Shell also added to its substantial acreage position in the Haynesville shale tight-gas opportunity of north-west Louisiana. Our Haynesville activities are being executed through joint operations (Shell interest 50%), with approximately 25 drilling rigs in operation as at January 1, 2010 between Shell and partners, and aramp-up of operations is planned for 2010.

Shell holds a 51.8% interest in Aera Energy LLC, a US-based exploration and production company with assets in the San Joaquin Valley and Los Angeles Basin areas of southern California. Aera operates more than 15,000 wells, producing about170 thousand boe/dof heavy oil and gas, and accounting for approximately 30% of the state’s production.

Shell continues research into the development of oil shale resources in the Piceance Basin of north-west Colorado, and holds three federal leases for future oil shale activities.

LNG and wind Shell holds capacity rights in US LNG import terminals, at the Cove Point and Elba Island regasification terminals. In the wind energy business, Shell has interests in eight US wind projects (Shell interest 50%) with a total installed capacity of 899 MW.

Shell has a 50% interest in an LNG regasification terminal at Altamira, on Mexico’s gulf coast, and a 75% interest in a separate marketing company that holds the capacity rights in the terminal. Shell also holds capacity rights at the Costa Azul LNG import terminal in Baja California on Mexico’s west coast.

Shell produces oil and gas from the offshore Parque das Conchas(BC-10)field, which came on-stream in 2009 (Shell operated; interest 50%) and Bijupirá and Salema fields (Shell operated; interest 80%). Shell also has an interest in an operated offshore development block and interests in seven deep-water exploration blocks in the Campos, Santos and Espirito Santo basins. Shell operates two of these blocks with interests ranging from 17.5% to 100%.

Shell operates two heavy oil fields inblock BS-4(Shell interest 40%) in the Santos Basin where potential development concepts are being assessed. Shell formally received exploration rights to five onshore blocks comprising over 11,000 km²in the São Francisco basin.

Shell holds an 18% interest in Brazil Companhia de Gas de São Paulo (Comgás), a natural gas distribution company in the state of São Paulo.

Shell also has interests in Argentina, Colombia, French Guiana, Guyana and Venezuela.

Four operations aim to secure LNG supplies for downstream natural gas markets: Shell Western LNG; Shell Eastern LNG; Shell International Trading Middle East LNG; and Shell North American LNG (all Shell interests 100%). These operations primarily use ships (currently a fleet of eight, of which one is on long-term-charter to a third party) which have been acquired, leased or chartered by Shell Tankers Singapore Ltd., Shell Tankers (UK) Ltd and Shell Bermuda (Overseas) Ltd. All of the five Shell owned LNG vessels in the shipping fleet are managed by Shell International Trading and Shipping Company Ltd.