Shell - 20-F annual report

 

 

 

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

 

3,480,868,822 Class A ordinary shares of the nominal value of €0.07 each.

2,673,333,694 Class B ordinary shares of the nominal value of €0.07 each.

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  þ Yes        o No

 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.       o Yes        þ No

 

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.

 

See definition of “accelerated filer and large accelerated filer” inRule 12b-2of the Exchange Act. (Check one):

 

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP o  International Financial Reporting Standards as issued by the International Accounting Standards Board þ  Other o      

 

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.       Item 17 o    Item 18 o      

 

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2of the Exchange Act).       o Yes        þ No

 

 

 

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, 2010, for Royal Dutch Shell plc (the Company) and its subsidiaries (collectively known as Shell). It presents the Consolidated Financial Statements of Shell(pages 98–138)and the Parent Company Financial Statements of Shell(pages 158–167).Cross references toForm 20-Fare set out onpages 175–176of 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 ownership interest held by Shell in a venture, partnership or company, after exclusion of all third-party interests. (For example, Shell interest in Woodside Petroleum Ltd is 24%.)

Except as otherwise specified, the figures shown in the tables in this Report represent those in respect of subsidiaries only, without deduction of the non-controlling 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 share of 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 interpretations issued by the IFRS Interpretations Committee.

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 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 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, USA. For further information on the operation of the public reference room and the copy charges, please call the SEC at 1-800-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 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. Copies of this Report also may be obtained, free of charge, by mail.

Macroeconomic conditions in 2010 were considerably better than they were in 2009. The price of crude oil rose. So too did the price of traded natural gas, despite being weighed down by the abundant supplies from North America. Oil-product and chemical margins also strengthened. Conditions remained challenging for refining, though.

The resumption of economic growth – particularly in Asia – has set energy demand on its upward course again. The increasing populations of developing countries will impart further momentum to the trend. To meet that surging demand, energy of all sorts will be needed – not just oil and gas but also nuclear and renewables.

The sheer scale of the energy demandbuild-up,however, limits the speed with which alternative sources can capture market share. Even if renewable energy sources develop faster than any energy source ever did, we believe that they could provide no more than 30% of global energy by 2050. Fossil fuels and uranium will continue to supply the bulk of the world’s energy for the foreseeable future, and the energy industry has to do what it can to ameliorate their known environmental impacts.

More recently, events in north Africa showed how quickly momentum for political change can develop. It is still too early to tell whether they have lasting implications for the global supply of energy. We continue to monitor developments in the region closely.

Fortunately, human creativity has proved to be remarkably adept at reconciling the often conflicting constraints that economic growth, political authority, individual well-being and environmental protection impose. Still, those who ultimately balance the pull and push of these constraints occasionally get it wrong – sometimes tragically so, as happened with the Deepwater Horizon.

The incident provided the basis for a thorough review of our global safety standards and procedures. Our review confirmed that they are among the most stringent in the world.

With this important lesson in mind, we will continue to apply our creativity to develop technologies for discovering new energy resources and making previously uneconomic ones viable. We think it makes a lot of sense to focus our innovation on natural gas, the cleanest-burning fossil fuel.

We are also directing part of our R&D effort to produce transport fuels from biomass. By taking inedible plant matter as feedstock, we can ensure that these advanced biofuels do not compete for resources with food crops. Until they are ready for commercialisation, we will continue working with industrial bodies, governments and other organisations to establish sustainability standards for conventional biofuels.

We are participating in projects to demonstrate techniques for capturing carbon dioxide at its source and storing it permanently underground. Such carbon capture and storage will be a necessary adjunct to fossil-fuel power plants and other large CO₂-emitting installations by 2050, according to the International Energy Agency.

And we are constantly thinking of ways to improve the efficiency with which we – and our customers – use energy and raw materials.

We laid out a strategy in 2010 that helps us manage the way we allocate R&D resources. It distinguishes between “core”, “first” and “emerging” technologies on the basis of whether they can be immediately applied in our existing activities, whether they open new business opportunities in the medium term or whether they have the potential to change the very nature of the energy industry in the long term.

But our innovations go beyond the purely technological.

To supply energy to Asia’s fast-growing markets, we have teamed up with Chinese national oil companies to develop energy resources not only inside but also outside China – in Australia, Qatar and Syria. We also intend to move into the sugar industry through a joint venture with Cosan in Brazil. The proposed joint venture will produce and sell ethanol biofuel, sugar and power from sugar cane.

Our technological and commercial innovations are helping create a low-carbon energy system that is not only secure and affordable but also sustainable – in the widest sense of the word. For the sake of our industry, we will keep working with regulators and international organisations to improve its safety and environmental regimes. Both resource holders and resource consumers stand to gain from these efforts. And so too will our shareholders.

2010 was a good year for Shell. In the wake of a global economic crisis we improved our operating performance and competitive position thanks to the dedication and creativity of our employees around the world. We made progress in focusing our portfolio of assets on our strengths in both Upstream and Downstream. And we were busy generating new opportunities for further growth over the period2014–2020.

We are delivering on our strategy, which is based on performance now, growth from new projects and creating options for the future.

Our earnings for the year were $20.5 billion, up 61% from 2009. On the basis of estimated current cost of supplies, our earnings per share increased by 90%. And cash flow from operating activities, excluding net working capital movements, was 40% higher.

Oil and gas production volumes increased by 5%, and sales volumes of liquefied natural gas (LNG) rose by 25%. Sales volumes of oil products and chemical products also grew – by 5% and 13% respectively.

Our declared dividends for the year underscored our commitment to shareholder returns. They totalled $10.2 billion – the largest in our sector.

We drove down our occupational injury rate again for the sixth straight year. Regrettably, we still had 12 work-related fatalities in 2010. Seven of them were related to road accidents, and two were related to security incidents. So we must continue to implement rigorous safety practices, particularly those related to driving. As we develop new projects in countries where there are security risks, we need to continue to carefully assess the threat and implement controls to safeguard people. And, as events in north Africa have made clear, we have to keep our contingency plans ready for activation on short notice.

Since April 2010, public discussions about safety in the oil industry have been dominated by the Deepwater Horizonincident in the Gulf of Mexico. This tragic incident reflects poorly on our industry. It will take a lot of effort to re-establish trust in our industry.

We agree with the majority of the findings of the US National Commission report on the incident. In fact, our safety procedures already conform to many of the recommendations in the report. Drilling responsibilities at our rigs are clear, and we assure both ourselves and regulators that all necessary safety measures have been put in place.

Our good safety record shows that we have the capability to access oil and gas safely and responsibly inhard-to-reachplaces, such as under deep or Arctic waters, and in remote or geologically challenging onshore locations.

Continued efforts to improve our environmental performance met with some success in 2010. The number of operational oil spills was down significantly from 2009. And we made progress in our ongoing emission-reduction plans in Nigeria, where we began working on further projects worth more than $2 billion to capture more of the gas associated with oil production.

In 2010, we reduced our costs by $2 billion, or around 5%, and both acquired and divested assets of $7 billion. These actions helped improve returns and capital efficiencies. They also reflect the priority we give to continual improvement along all fronts within our organisation. I am indebted to the more than 93,000 Shell employees who bring about these improvements, sometimes under trying circumstances.

We brought six key projects on-stream in 2010, and several more are nearly there. Thanks largely to them, we are on track to reach the 2012 performance targets we set back in 2009: 11% more production and at least 80% more cash flow at an oil price greater than $80 per barrel. In Nigeria the Gbaran-Ubie project is now producing both oil and gas from a collection of fields. Production also started at our Perdido offshore platform, which taps fields in the Gulf of Mexico in record-setting water depths. We also saw the first output increases from the expansion of the Athabasca Oil Sands project in Canada. And in Qatar we completed major construction at our Pearlgas-to-liquids(GTL) plant and began producing LNG at the Qatargas 4 plant in January 2011.

In Downstream in 2010, our Shell Eastern Petrochemicals Complex (SEPC) in Singapore began to operate as a fully integrated refinery and petrochemical hub. The SEPC is the largest petrochemical project ever undertaken by Shell. It enables us to maintain a leading position in the expanding Asian market.

We also made good progress in the restructuring of our Downstream businesses in 2010. We sold refining and marketing assets in several countries – Finland, Sweden, Greece and New Zealand, to name a few. In certain cases, service stations will remain Shell-branded through licensing agreements with the new owners. Such divestments allow us to concentrate our commercial strengths in large markets or markets with growth potential.

In 2010, we assembled ample opportunities for growth beyond 2012.

We took the Final Investment Decision on two new oil and gas projects in deep water – one in the Gulf of Mexico and the other offshore Brazil. In Australia the Gorgon joint venture is constructing facilities for one of the world’s largest natural gas projects, and we are nearing a Final Investment Decision on whether to develop the Prelude and Concerto offshore gas fields on the basis of a floating LNG plant.

We signed contracts with our partners to develop the Majnoon and West Qurna fields in Iraq. And we agreed to join Qatar Petroleum in a study of the feasibility of building a major petrochemical complex at the same industrial site where the Qatargas 4 and Pearl GTL plants are located.

We added to our shale-gas holdings in 2010. These consist of gas-bearing shale formations that must be fractured in order for the gas to flow freely to the wells. We acquired acreage in the Eagle Ford formation of south Texas and the Marcellus formation of north-eastern USA. These acquisitions bring our total North American holdings in such formations to some 3.6 million acres.

We also signed a contract in 2010 to explore, appraise and develop more gas resources in the Sichuan and Ordos Basins in China. The area over which we are now conducting onshore gas operations in China totals some 12,000 square kilometres (about 3 million acres) – roughly one-third the size of the Netherlands. We additionally

partnered with PetroChina to buy Arrow Energy, which has coalbed methane resources in Australia.

Our exploration programme made nine notable discoveries in 2010. Additions to our proved reserves exceeded our production volumes for the year. We plan to spend some $3 billion in 2011 in our continuing search for more resources.

In Downstream, we continued our investments to increase refining capability in the US Gulf Coast. We also signed binding agreements with Cosan to form a marketing and biofuels joint venture in Brazil. Through it, we will for the first time become a wholesale producer of ethanol derived from sugar cane. We think such biofuels provide the most commercially feasible way for us to reduce carbon dioxide emissions from road transport over the next two decades. And for the longer term we will bring to the venture the results of our advanced-biofuels R&D programme.

To make our R&D programme an intrinsic part of Shell’s strategic objectives, we adopted a new technology strategy in 2010. It emphasises continued strong investment in research, speeding up the commercialisation of ideas, and working more closely with strategic external partners, such as customers and universities.

Our successful projects and future growth opportunities help us increase our potential value to partners, customers and shareholders alike. But there is still more to come.

I know I speak for my colleagues at Shell when I say that we are eager to get on with the job.

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 delivered 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”. This indicator reflects Shell’s ability to generate cash for investment and distributions to shareholders.

Project delivery is a new key performance indicator. It reflects Shell’s capability to complete a defined set of projects on time and within budget, compared with targets set in the annual Business Plan. The set of projects consists of at least 20 major capital projects that are in the execution phase (post Final Investment Decision) and are operated by Shell.

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 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 performance 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 recordable 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.

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.

Net capital investment is capital investment (capital expenditure, exploration expense, new equity and loans in equity-accounted investments and leases and other adjustments), less divestment proceeds. See Notes 2 and 7 to the “Consolidated Financial Statements” for further information.

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 47.

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”.

Earnings per share on an estimated current cost of supplies (CCS) basis are calculated in this way: the income attributable to shareholders is first adjusted to take into account the after-tax effect of oil-price changes on inventory before it is divided by the average number of shares outstanding. Without the adjustment, earnings per share are affected by changes in inventory caused simply by movements in the oil price.

CCS earnings have become the dominant measure used by the Chief Executive Officer for the purpose of making decisions about allocating resources to Downstream and assessing its performance. See Notes 2 and 7 to the “Consolidated Financial Statements”.

Proved oil and gas reserves (excluding reserves attributable to non-controlling interest in Shell subsidiaries held by third parties) 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; seepages 13–15.

Operational spills reflects the total number of incidents in which 100 kilograms or more of oil or oil products were spilled as a result of our operations. The number for 2009 was updated from 264 to reflect completion of investigations into operational spills.

Employees is calculated as the annual average full-time equivalent number of employees who are employed by Shell subsidiaries through full-time and part-time employment contracts.

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. We aim to sustain our strong operational performance and continue our investments primarily in countries that have the necessary infrastructure, expertise and remaining growth potential. Such countries include: Australia; Brunei; Canada; Denmark; Malaysia; the Netherlands; Nigeria; Norway; Oman; Qatar; Russia; the UK; the USA; and, in the coming years, China.

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) andgas-to-liquids(GTL) projects. For example, in January 2011, together with our partner, we brought the Qatargas 4 LNG project on-stream and later in the year we will start up the world’s largest GTL project also in Qatar. We are also 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 are also exploring for hydrocarbons in formations, such as low-permeability gas reservoirs in the USA, Australia, 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.

Upstream International manages the Upstream businesses 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 Shell’s entire LNG business, GTL and the wind business in Europe. Its activities are organised primarily within geographical units, although there are some activities that are managed across the businesses or provided through support units.

Upstream Americas manages the Upstream businesses in North and South America. It searches for and recovers crude oil and natural gas, 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, although some are managed regionally or provided through support units. 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. 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 additionally oversees Shell’s interests in alternative energy (including biofuels, and excluding wind) and CO₂ management.

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 health, safety and environment, and contracting and procurement.

Upstream combines the operating segments Upstream International and Upstream Americas, which have similar economic characteristics, products and services, production processes, type and class of customers and methods of distribution. 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 self-insurance activities.

Shell’s operations and earnings are subject to competitive, economic, political, legal, regulatory, social, industry, business and financial risks, as discussed below. These could have a material adverse effect separately, or in combination, on our operational performance, earnings or financial condition. Investors should carefully consider the risks discussed below. They should also be aware that our Articles of Association limit the jurisdictions under which shareholder disputes are settled (see also below).

Prices of oil, natural gas, oil products and chemicals are affected by supply and demand, both globally and regionally. Moreover, prices for oil and gas can move independently from each other. 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.

We face competition in each of our businesses. While we seek 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 companies are subject to differing economic and financial market conditions throughout the world. Political or economic instability affects such 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, the potential impact on our liquidity could have an adverse effect on our operations. For example, our net debt increased by $5.6 billion in 2010. 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 82–83).As a global company doing business in over 90 countries, we are exposed to changes in currency values and exchange controls. While we 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”).

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. These challenges are particularly relevant in certain developing and emerging market countries, such as Kazakhstan, Iraq, etc. Such potential obstacles may impair our delivery of these projects, as well as our ability to fulfil related contractual commitments, and, in turn, negatively 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.

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 97 thousand employees, it is a 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, limit our ability to access the capital market and affect our operational performance and financial condition.

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, the delivery of our strategy, our profitability and our earnings may be affected. We operate in environments where the most advanced technologies are needed. While these technologies are regarded as safe for the environment with today’s knowledge, there is always the possibility of unknown or unforeseeable environmental impacts. If these materialise, they might affect our earnings and financial condition and expose us to sanctions or litigation.

In the future, in order to help meet the world’s energy demand, we expect our production to rise and 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, it is expected that both the CO₂intensity of our production, as well as our absolute Upstream CO₂emissions, will increase as our business grows, 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 CO₂emissions will be subject to regulation and carry a cost. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our CO₂emissions for new and existing projects or products, we may incur additional costs in delayed projects or reduced production in certain projects.

The health, safety, security and environment (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. We have operations, including oil and gas production, transport and shipping of hydrocarbons, and refining, in difficult geographies or climate zones, as well as environmentally sensitive regions, such as the Arctic or maritime environments, especially in deep water. This 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 materialises, such as an explosion or hydrocarbon spill, this could result in injuries, loss of life, environmental harm, disruption to business activities and, depending on their cause and severity, material damage to our reputation and eventually loss of licence to operate. Ultimately, any serious incident could harm our competitive position and materially impact our earnings and financial condition. In certain circumstances, liability could be imposed without regard to Shell’s fault in the matter.

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 impact on Shell’s existing and future activities in that country and could adversely affect our financial returns from projects in that country.

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. 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. In our Upstream activities these developments could affect land tenure, re-writing of leases, entitlement to produced hydrocarbons, production rates, royalties and pricing. Parts of our Downstream businesses are subject to price controls in some countries. From time to time, cultural and political factors play a role in unprecedented and unanticipated judicial outcomes contrary to local and international law. 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.

As seen recently in north Africa and the Middle East, 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 negative effect on our operational performance and financial condition, as well as on our reputation.

The operation of many of our business processes depends on the availability of information technology (IT) systems. Our IT systems are increasingly concentrated in terms of geography, number of systems, and key contractors supporting the delivery of IT services. Shell, like many other multinational companies, has been the target of attempts by others to gain unauthorised access through the Internet to our IT systems, including more sophisticated attempts often referred to as advanced persistent threat. For all security incidents Shell seeks to

detect and investigate them with an aim to prevent their recurrence. Disruption of critical IT services, or breaches of information security, could have a negative effect on our operational performance and earnings, as well as on our reputation.

Liabilities associated with defined benefit plans can be significant, as can the cash funding of such plans; both depend 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. See “Liquidity and capital resources” for further discussion.

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, including changes in the price of oil or gas and changes in the taxation or regulatory policies of host governments. It may also alter because of acquisitions and divestments, 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 errors in the application of published rules and changes in guidance. Any downward adjustment would indicate lower future production volumes and may adversely affect our earnings as well as our financial condition.

A significant share of our capital is invested in joint ventures or associated companies. In cases where we are not the operator we have limited influence over, and control of, the behaviour, performance and cost of operations of joint ventures or associated companies. 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.

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 larger 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.

In 2010, a Shell company agreed to a Deferred Prosecution Agreement (DPA) with the US Department of Justice (DOJ) for violations of the US Foreign Corrupt Practices Act (FCPA), which arose in connection with its use of the freight forwarding firm Panalpina. Also the Company has consented to a Cease and Desist Order from the US Securities and Exchange Commission (SEC) for violations of the record keeping and internal control provisions of the FCPA as a result of another Shell company’s violation of the FCPA, which also arose in connection with the use of the freight forwarding firm Panalpina in Nigeria. The DPA requires Shell to continue to implement a compliance and ethics programme designed to prevent and detect violations of the FCPA and other applicable anti-corruption laws throughout Shell’s operations. The DPA also requires the Company to report to the DOJ, promptly, any credible evidence of questionable or corrupt payments. Additionally, Shell paid a $30 million penalty to the DOJ and approximately $18.1 million in disgorgement and prejudgement interest to the SEC. Any violations of the DPA, or the SEC’s Cease and Desist Order, could have a material adverse effect on the Company.

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.

The most significant factors affectingyear-on-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.

On average, 2010 realised oil and gas prices increased significantly compared with 2009. Refining margins in 2010 showed some improvements over those in 2009, supported by the growing demand for oil products. The continuing high inventories, particularly for middle distillates, and industrial overcapacity following thestart-up of major refining facilities in Asia, however, had a downward effect on refining margins. Oil and gas production available for sale in 2010 was 3,314 thousand barrels of oil equivalent per day (boe/d), compared with 3,142 thousand boe/d in 2009.

Earnings on a current cost of supplies basis in 2010 were 91% higher than in 2009, when they were 69% lower than in 2008. The increase reflected higher realised oil and gas prices and production in Upstream as well as higher margins in Downstream.

In 2010, Upstream earnings were $15,935 million, 91% higher than in 2009 and 40% lower than in 2008. The difference between the 2010 and 2009 earnings reflected the effect of significantly higher realised prices for both oil and gas in combination with higher production volumes. In 2009, earnings decreased by 68% from 2008, mainly reflecting lower realised oil and gas prices and lower production volumes. Moreover, the 2010 and 2008 earnings included significant gains from the divestment of various assets.

Downstream earnings in 2010 were $2,950 million, compared with $258 million in 2009 and $5,309 million in 2008. Earnings in 2010 increased significantly with respect to 2009 because of higher realised refining margins and increased volumes. Earnings decreased between 2008 and 2009 because lower demand drove down our realised refining margins and most of our realised marketing margins in 2009.

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 2010. Property, plant and equipment increased by $11.1 billion. Capital investment was $30.6 billion, 4% lower than in 2009. The effect of capital investment on property, plant and equipment was partly offset by depreciation, depletion and amortisation of some $15 billion in 2010.

Of the 2010 capital investment, $25.7 billion related to Upstream projects that will 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 2010, the total debt increased by $9.3 billion. Total equity increased by $11.6 billion in 2010, to $149.8 billion.

The gearing ratio was 17.1% at the end of 2010, compared with 15.5% at the end of 2009. The change reflects the increase of the total debt, partly offset by an increase in the cash and cash equivalents position in 2010.

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.

The global economy continued to recover in 2010 from the recession of late 2008 and early 2009 that was triggered by the severe financial crisis in the USA and Europe. The contours of the global recovery, however, have differed significantly across countries. Most emerging markets weathered well the global downturn and grew robustly in 2010, with output in China and India growing by 10.3% and 9.7% respectively. In contrast, the USA and the euro area saw output grow by 2.8% and 1.8%, respectively, which was not sufficiently rapid to bring down high unemployment rates.

In 2011, global output growth is set to continue, led by the emerging markets. Key uncertainties to the outlook are associated with high sovereign debt burdens in some European countries, fragile US and European consumer confidence with high unemployment and indebtedness, and global frictions over imbalances and exchange rates.

Oil prices traded in a range of $70–85 per barrel throughout most of 2010 but ended the year at a high of $94 per barrel. On average, 2010 prices were considerably higher than they were in 2009. Brent crude oil averaged $79.50 per barrel in 2010, compared with $61.55 in 2009; West Texas Intermediate averaged $79.45 per barrel in 2010, compared with $61.75 a year earlier.

Natural gas prices saw a more pronounced downward trend in 2010 compared with 2009. The Henry Hub prices fell from a monthly average high of $5.80 per million British thermal units (MMBtu) in January to a monthly low of $3.48 per MMBtu in October, when inventories were high and production had to be discouraged. From November until the end of 2010, Henry Hub prices reversed their trend with the onset of winter weather. Averaged over the year, the Henry Hubper-MMBtuprice was higher in 2010 than in 2009 – $4.40 compared with $3.90. In the UK prices at the National Balancing Point averaged 42.12 pence/therm in 2010, compared with 30.93 pence/therm in 2009.

Unlike crude-oil pricing, which is global in nature, gas prices vary significantly from region to region. We produce and sell 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 the Asia-Pacific region and in some parts of continental Europe are predominantly indexed to oil prices. However, natural gas prices are increasingly moving to spot market pricing in continental Europe. In Europe contractual time-lag effects resulted in flat prices throughout the first quarter of 2010, while demand was still feeling the impact of the recession. Oil-indexed prices

started to rise in the second 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 and supply disruptions due to weather or politics, contribute to price volatility.

We expect oil prices to average in the range of$50–90 perbarrel and US gas prices to average in the range of$4–8 perMMBtu. We make our investment decisions inside these ranges. We use 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 subject to review and change.

Refining margins in 2010 showed some improvement over those of 2009 in all key refining centres. Margins were supported by the growing demand for oil products in 2010 as the world moved out of recession. But they were also subjected to downward pressure from the continuing high inventories, particularly for middle distillates, and industrial overcapacity following thestart-up of major refining facilities in Asia.

Chemicals margins in 2010 were higher than expected because of unanticipated demand growth, high unplanned plant downtime, feedstock constraints in the Middle East and a large price differential between crude oil and US natural gas.

Industry refining margins in 2011 will be supported if global oil demand continues to grow with economic recovery, but their growth may be tempered by the continuing industrial overcapacity. Chemicals margins in 2011 will depend on continued economic growth and the level of feedstock constraints in the Middle East. The large US natural gas–crude differential will help chemicals margins.

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. Safety and corporate responsibility are at the heart of our activities.

Intense competition exists for access to upstream resources and to new downstream markets. But we believe our technology, project-delivery capability and operational excellence will remain key differentiators for our businesses. We expect around 75% of our capital investment in 2011 to be in our Upstream projects.

In Upstream we focus on exploration for new oil and gas reserves and developing major projects where our technology and know-how add

value to the resource holders. The implementation of our strategy will see us actively manage our portfolio around three themes in Upstream:

In our Downstream businesses, our emphasis remains on sustained cash generation from our existing assets and selective investments in growth markets. The implementation of our strategy will see us actively manage around three themes in Downstream:

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 engineering 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 for the longer term.

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. Shell’s underlying costs declined by some $2 billion in 2010, and by over $4 billion since 2008. Asset sales are a core element of the strategy – improving our capital efficiency by focusing investment on the most attractive growth opportunities. There are expected to be asset sales of up to $5 billion in 2011 as Shell exits from non-core positions.

We have initiatives underway that are expected to improve Shell’s industry-leading Downstream businesses, focusing on the most profitable positions and growth potential. Shell has plans to exit from non-core refining capacity and from selected retail and other marketing

positions and is taking steps to improve the quality of its Chemicals assets.

We are planning a net capital investment of some $25–27 billion in 2011. This amount relates largely to investments in projects where the Final Investment Decision has already been taken or is expected to be taken in 2011.

Organic capital investment is expected to be $25–30 billion per year between 2012 and 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.

In early 2010, Shell defined a set of ambitious financial and operating targets to rebalance the financial framework to a cash flow surplus, and to grow Shell. These targets are driven by Shell’s performance in maturing new projects for investment and by projectstart-ups.

Cash flow from operations, excluding changes in working capital, was $24 billion in 2009. We expect cash flow to grow by around 50% from 2009 to 2012 assuming a $60-per-barrel oil price and an improved environment for natural gas prices and downstream margins. In an $80-per-barrel environment, 2012 cash flow should be at least 80% higher than 2009 levels.

In Downstream we are adding new refining capacity in the USA and making selective growth investments in marketing.

Oil and gas production is expected to average 3.5 million boe/d in 2012, compared with 3.3 million boe/d in 2010. We are confident of further growth by 2014 to as much as 3.7 million boe/d (subject to licence extensions and asset sales).

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, North American tight gas and Australian LNG. These projects are part of a portfolio that has 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.

In 2010, Shell added 1,653 million boe proved reserves before taking into account a net negative impact from commodity price changes of 198 million boe proved reserves and a net negative impact from acquisition and divestment activity of 85 million boe proved reserves. Of the total net additions of proved oil and gas reserves before production of 1,370 million boe, 1,197 million boe came from Shell subsidiaries and 173 million boe were associated with the Shell share of equity-accounted investments.

In 2010, total oil and gas production available for sale was 1,210 million boe. An additional 32 million boe were produced and consumed in operations. Production available for sale from subsidiaries was 855 million boe with an additional 25 million boe consumed in operations. The Shell share of the production available for sale of equity-accounted investments was 355 million boe with an additional 7 million boe consumed in operations.

Accordingly, after taking into account total production, we had a net increase of 128 million boe in proved oil and gas reserves, of which 317 million boe came from subsidiaries and a net decrease of

189 million boe was associated with the Shell share of equity-accounted investments.

Shell subsidiaries’ and the Shell share of equity-accounted investments’ estimated net proved reserves are summarised in the table on page 27 and are set out in more detail under the heading “Supplementary information – Oil and gas” onpages 139–147.

In 2010, our research and development (R&D) expenses remained above $1 billion ($1,019 million, compared with $1,125 million in 2009 and $1,230 million in 2008).

Following the creation of a single R&D organisation in 2009, we adopted in 2010 an integrated company-wide technology strategy that is intrinsically linked to Shell’s strategic objectives. The needs of our customers and partners are the critical drivers behind the development of our technologies. The speed of deployment of the right technology for a particular job is also of importance. The strategy encourages further leverage of external science and technology developments through active partnering with other research institutions – sometimes even through open innovation schemes – to identify the most suitable ways to meet the growing global demand for energy. Of course, we will continue to foster our proprietary technology and drive in-house development of differentiating technologies wherever it makes business sense to do so.

Our new technology strategy enables us to support current business activities with “core technologies” while developing “technological firsts” for the medium term and “emerging technologies” for the long term. Our key “core” technology developments are intended: to improve oil and gas recovery from existing fields; to further enhance our exploration success; to provide better ways to conduct operations in deep water; to grow our GTL and LNG businesses; and to deliver advanced fuels and lubricants that give customers increased fuel efficiency and engine performance. Delivering technological “firsts” will allow us to move into more challenging operational environments, such as the Arctic, and pursue next-generation biofuels. They are also designed to allow us to unlockdifficult-to-produceoil and gas resources, and provide ways to abate carbon dioxide emissions or to capture and store them.

In 2011, our R&D programme will continue to pursue the same key targets as those we had in 2010, although we foresee a further shift in focus to upstream-related and gas-related technologies. We aim to continue reducing the time for a technology to progress from initial idea to field trials and then on to large-scale deployment. We will also continue to keep a healthy balance between new and more mature projects in our R&D portfolio, increasing the number of early-stage concepts while terminating less-promising projects more quickly.

Our new integrated R&D organisation and our focused technology strategy, in combination with our industry-leading talent, make us confident that our technology will keep differentiating us from the competition.

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

Please refer to Note 27 to the “Consolidated Financial Statements” for a discussion of legal proceedings.

Our Upstream businesses explore for and extract crude oil and natural gas, often in joint ventures with international and national oil companies. This includes the extraction of bitumen from mined oil sands which we convert into synthetic crude oil. We liquefy natural gas by cooling and transport it to customers across the world. We convert natural gas to liquids (GTL) to provide cleaner-burning fuels. We also market and trade natural gas (including LNG) in support of our Upstream businesses.

According to the International Energy Agency, oil demand in 2010 increased by 2.7 million b/d, or 3%, compared with a 1% demand decline in 2009. The oil demand turnaround was driven by non-OECD countries, especially China and India. This growth rate has only been seen twice in the last 30 years, and the world is now using more oil than before the 2008 recession. Global gas demand also increased in 2010 led by Asia and Europe, offsetting a 2% drop in 2009.

Our Upstream results have rebounded from last year, driven by improved industry conditions and delivery of Shell’s strategy. We have brought some large growth projects on-stream, and production from these projects has been ramping up well. These new fields, along with an improved security environment in Nigeria, have driven a 5% production increase from last year, mostly through increases in natural gas production. Record LNG sales mainly reflect the ramp-up in sales volumes from the Sakhalin 2 LNG project and improved feed gas supplies to Nigeria LNG helped by the start-up of the Gbaran-Ubie field.

Segment earnings in 2010 were $15,935 million, 91% higher than in 2009. The increase in 2010 from 2009 was mainly due to higher realised oil, natural gas and LNG prices, higher production volumes, lower exploration expenses and lower underlying depreciation (when excluding impacts of asset impairments), partly offset by higher production taxes. Additionally, 2010 earnings included a net gain of $1,493 million related to identified items compared with a net charge of $134 million in 2009. The net gain in 2010 mainly related to gains on divestments, partly offset by asset impairments and write-offs,mark-to-marketvaluation of certain gas contracts and the cost impacts from the US offshore drilling moratorium ($185 million). The net charge

in 2009 mainly related to impairments and redundancy charges, partly offset by exceptional tax items and divestment gains.

As the chart below illustrates, the spread between our global average oil and natural gas realisations remained wide. Natural gas production represented 48% of total production of 3,314 thousand boe/d in 2010. Gas realisations were influenced by many factors, primarily a continued deterioration since the first quarter of 2010 of the North American market linked to Henry Hub, and low price realisations in the European gas market during the first half of the year as a result of price renegotiations and increased exposure to the spot market. Approximately 20% of Shell’s natural gas production in 2010 was in the Americas.

Segment earnings in 2009 were $8,354 million, 68% lower than in 2008, due to the impact of significantly lower realised oil and gas prices, higher costs and lower production volumes, partly offset by lower production taxes and improved trading contributions. 2009 included a net charge of $134 million for identified items compared with net gains of $3,487 million in 2008. The net gains in 2008 mainly related to asset divestments across the Shell portfolio, which were partly offset by themark-to-marketvaluation of certain UK gas contracts and an exceptional tax charge due to new legislation in Italy.

Net capital investment was some $21 billion in 2010, compared with some $22 billion in 2009 and some $28 billion in 2008. Capital investment in 2010 was $26 billion (including $11 billion in exploration expenditure). This represents an 8% increase from 2009 capital investment of $24 billion. 2010 capital investment included $7 billion in acquisitions, primarily relating to East Resources.

In Africa and Europe we completed an asset swap with Hess to acquire assets in Gabon and in the UK North Sea in return for Shell’s interest in a pair of Norwegian offshore fields.

In Australia Shell and PetroChina completed the acquisition of all of the shares in Arrow Energy Limited; the total cash consideration was some $3.1 billion (Shell interest in Arrow 50%).

Also in Australia we sold 29.18% of our interest in Woodside, or 10.0% of Woodside’s issued capital, for a total price of $3.2 billion, reducing Shell’s interest in the company to 24.27%.

In Brazil we announced the Final Investment Decision to support phase 2 of the Parque das Conchas(BC-10)project (Shell interest 50%).

In China Shell and PetroChina announced plans to appraise, develop and produce tight gas under a30-yearproduction-sharing contract in

an area of approximately 4,000 square kilometres in the Jinqiu block of central Sichuan Province. In addition, shale gas assessment work commenced in January 2010 in the Fushun block that covers another area of also approximately 4,000 square kilometres.

In Nigeria we sold our 30% interest in three production leases (oil mining leases 4, 38 and 41) and related equipment in the Niger Delta to a consortium led by two Nigerian companies.

In Qatar we signed a new exploration and production-sharing agreement for Qatar block D. Under the agreement, the partners will jointly explore for natural gas in an area of 8,089 square kilometres onshore and offshore Qatar. The total term of this agreement is 30 years and will start with a five-year First Exploration Period.

In Syria we sold a 35% interest in Syria Shell Petroleum Development (SSPD), previously 100% owned, to China National Petroleum Corporation. SSPD has interests in three production licences covering some 40 oil fields, with production in 2010 of approximately 20 thousand boe/d (Shell share).

In the USA we acquired the majority of assets held by East Resources for a cash consideration of $4.5 billion. The assets acquired cover an area of some 2,800 square kilometres (700 thousand net acres) of highly contiguous acreage, with the primary focus on the Marcellus shale, centred in Pennsylvania in the north-east USA. Additionally, we acquired and began exploration drilling on some 1,000 square kilometres (250 thousand net acres) of mineral rights in the Eagle Ford shale play in south Texas.

Also in the USA we announced the Final Investment Decision for the Mars B project (Shell interest 71.5%), a tension leg platform in the Gulf of Mexico with a 100 thousand boe/d capacity.

Furthermore, also in the USA, in 2011 we divested our Rio Grande Valley south Texas portfolio for $1.8 billion as part of ongoing asset optimisation.

In 2010, hydrocarbon production available for sale averaged 3,314 thousand boe/d, which was 5% higher than in 2009 and 2% higher than in 2008. It represents the first year-on-year increase since 2002. Higher production in 2010 was mainly driven by new fields coming on-stream (notably Gbaran-Ubie in Nigeria in 2010), the continued ramp-up of certain fields brought on-stream before 2010 (notably Parque das Conchas(BC-10) in Brazil and Sakhalin 2 in Russia), improved security conditions in Nigeria and increased demand, mainly in Europe. This increase was partly offset by natural field declines, divestments and PSC price effects.

LNG sales volumes in 2010 of 16.76 million tonnes were 25% higher than in 2009. This increase mainly reflected theramp-up in sales volumes from the Sakhalin 2 LNG project and improved feed gas supplies to Nigeria LNG helped by thestart-up of the Gbaran-Ubie field.

In Canada we started production from expanded mining facilities at our oil sands operations. Production from the new Jackpine Mine, combined with existing production from the Muskeg River Mine, will feed the Scotford Upgrader, which processes the oil sands bitumen into synthetic crude. Construction for the expansion of the Scotford Upgrader has been underway, and will come on-stream in 2011, allowing synthetic crude production capacity to rise to 255 thousand boe/d (Shell share 60%). 2010 synthetic crude production declined

from 2009 mainly due to the scheduled maintenance of all equipment. The last time a full turnaround of the asset occurred was in 2006.

In Nigeria oil and gas production started from the Gbaran-Ubie project in the Niger Delta (Shell interest 30%). In early 2011, Gbaran-Ubie achieved peak gas production of 1 billion standard cubic feet of gas per day (scf/d); oil production has reached some 50 thousand barrels per day (b/d) and is expected to peak at some 70 thousand b/d.

Major construction of the Qatargas 4 project has been completed and first LNG was produced in January 2011, with production expected to reach full capacity in 2011.

During 2010, Shell participated in nine notable exploration discoveries and six notable successful appraisals, in Australia, Brazil, Brunei, Oman, the US Gulf of Mexico and North America onshore. Discoveries will be evaluated in order to establish the extent of the volumes they contain.

In total, Shell participated in 403 successful wells drilled outside proved areas. These comprised 45 conventional oil and gas exploration wells and 94 unconventional gas exploration and appraisal wells, as well as 264 additional appraisal wells intended to extend proved areas near existing assets.

In 2010, Shell added acreage to its exploration portfolio from new licences in Canada, China, Egypt, Greenland, Iraq, Qatar, Russia, Tunisia and the USA. In Canada Shell expanded the acreage holdings in British Columbia and Alberta. In China the joint exploration and development of the Jinqiu block in the Sichuan Basin was announced. In Egypt the offshore North Damietta block was awarded. In Greenland two offshore exploration blocks in Baffin Bay were awarded. In Iraq Shell acquired an interest in the Majnoon field with additional exploration potential. In Qatar a new exploration and production-sharing agreement for block D was signed. In Russia the Barun-Yustinsky exploration and production licence in the Republic of Kalmykia was awarded. In Tunisia two offshore prospecting licences were awarded. In the USA additional leases were acquired in the Rocky Mountains, south Texas and Pennsylvania. In Colombia, Shell successfully bid for one contract and one Technical Evaluation Agreement.

In total, Shell secured rights to some 53,000 square kilometres of new exploration acreage. This was more than offset by divestments, relinquishments and licence expiry of acreage, which took place in various countries (mainly Malaysia, Norway, Saudi Arabia and the UK).

Shell subsidiaries’ and the Shell share of equity-accounted investments’ estimated net proved reserves are summarised in the table on page 27 and are set out in more detail under the heading “Supplementary information – Oil and gas” onpages 139–147.

In December 2008, the US 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 and 2010 have been determined in accordance with these updated rules.

In 2010, Shell added 1,370 million boe of proved oil and gas reserves before accounting for production, of which 1,197 million boe came from Shell subsidiaries and 173 million boe were from the Shell share of equity-accounted investments.

The increase in the average yearly commodity prices between 2009 and 2010 resulted in a net negative impact on the proved reserves of 198 million boe. This was mainly due to production-sharing contracts where a higher price resulted in lower entitlements.

Before taking into account production, Shell subsidiaries added 1,197 million boe of proved oil and gas reserves in 2010. This comprised 949 million barrels of oil and natural gas liquids and 248 million boe (1,438 thousand million scf) of natural gas. Of the 1,197 million boe: 780 million boe were from the net effects of revisions and reclassifications; 11 million boe related to acquisitions and divestments; 337 million boe came from extensions and discoveries; and 69 million boe were from improved recovery.

After taking into account production of 880 million boe (of which 25 million boe were consumed in operations), 887 million boe of proved developed reserves were added and proved undeveloped reserves decreased by 570 million boe.

The total addition of 1,197 million boe reflected a net negative impact from commodity price changes of approximately 208 million boe of proved reserves.

Before taking into account production, there was an increase of 173 million boe in the Shell share of equity-accounted investments’ proved oil and gas reserves in 2010. This comprised 136 million barrels of oil and natural gas liquids and 37 million boe (215 thousand million scf) of natural gas. Of the 173 million boe: 219 million boe were from the net effects of revisions and reclassifications; a decrease of 96 million boe related to acquisitions and divestments; 46 million boe came from extensions and discoveries; and 4 million boe were from improved recovery.

After taking into account production of 362 million boe (of which 7 million boe were consumed in operations), proved developed reserves decreased by 44 million boe and proved undeveloped reserves decreased by 145 million boe.

The total addition of 173 million boe reflected a net positive impact from commodity price changes of approximately 10 million boe of proved reserves.

In 2010, we did not add to our synthetic crude oil proved reserves.

In 2010, we had synthetic crude oil production of 28 million barrels of which 2 million barrels were consumed in operations. At December 31, 2010, we had total synthetic crude oil proved reserves of 1,567 million barrels, of which 1,214 million barrels were proved developed reserves and 353 million barrels were proved undeveloped reserves.

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 1 million barrels. After taking into account production of 7 million barrels, bitumen proved reserves were 51 million barrels at December 31, 2010.

The net decrease to proved undeveloped reserves was 715 million boe in 2010. The decrease comprised a transfer of 1,207 million boe from proved undeveloped to proved developed reserves and additions of 492 million boe of new proved undeveloped reserves. The total volume of proved undeveloped reserves was 6,887 million boe at December 31, 2010. During 2010, we spent $7.1 billion on activities related to the maturation of proved undeveloped reserves to proved developed.

In 2010, the proved undeveloped reserves held for more than five years increased from 1,064 million boe to 1,666 million boe. This net increase reflected an increase of 756 million boe in proved undeveloped reserves that were held for more than five years as of December 31, 2010, partially offset by a transfer of 154 million boe to proved developed reserves.

The proved undeveloped reserves held for more than five years are generally in locations where Shell has a proven track record of developing major projects, such as in the Netherlands, Norway, Nigeria, Australia, Malaysia, Russia and the USA and in new major, complex projects such as Kashagan. These proved undeveloped reserves relate primarily to long-life fields.

Approximately 78% of these proved undeveloped reserves are associated with currently producing fields expected to produce for decades. These reserves are expected to be converted from proved undeveloped to proved developed over time as development activities such as gas compression and additional wells are executed to support existing gas delivery commitments, as well as a number of phased developments.

In the coming years we expect an increase in our proved undeveloped reserves that have been held for more than five years in major, long-lasting production projects in Canada and Kazakhstan.

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, although 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 5,400 thousand million scf of natural gas from 2011–2013. The sales contracts contain a mixture of fixed and variable pricing formulae that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery.

Shell’s LNG operations constitute some 38% of the total contractual commitment. Shell believes it can satisfy these commitments from quantities available from production of its proved developed reserves in the period 2011–2013 in Australia, Russia, Brunei, Malaysia, Nigeria and Qatar or from planned development activities to transfer undeveloped reserves to developed reserves. Mitigation measures are in place to meet any shortfalls, if needed, and include in-field activities, debottlenecking and purchase on the spot market.

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 are generally granted by or entered into with a government, government entity or state oil company, and the exploration risk usually rests with the independent oil company. In North America these agreements may also be with private parties who own mineral rights. Of these agreements, the following are most relevant to Shell’s interests:

Shell holds a non-operating 46% interest in a producing concession, covering the majority of Shell’s activities in Denmark. The concession was granted in 1962 and will expire in 2042. Shell’s interest will reduce to 36.8% in July 2012, when the government takes a working interest in the concession compensated by a favourable change in tax regime. Additionally, Shell holds exploration interests in offshore Greenland.

Shell is the operator of the Corrib Gas project (Shell interest 45%), which is currently under development. In 2011, Shell received approval for the statutory permit for the onshore pipeline to the processing plant. Decisions are still pending on two other statutory permits. Corrib will not come on-stream before 2013. At peak production, Corrib will produce just under 60 thousand boe/d and is expected to supply up to 60% of Ireland’s natural gas needs.

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 formed in 1947. NAM is the

largest hydrocarbon producer in the Netherlands. An important part of NAM’s gas production comes from its onshore Groningen gas field (Shell interest 30%), in which the Dutch government has a 40% financial interest, with NAM holding the remaining share. Shell also has a 30% interest in the Schoonebeek oil field, which had been shut down since 1996. Production restarted at Schoonebeek in 2011 following completion of a field redevelopment using enhanced oil recovery technology.

Shell is a partner in over 20 production licences on the Norwegian continental shelf. Shell is operator in eight of these, including the Draugen oil field (Shell interest 26%) and the Ormen Lange gas field (Shell interest 17%). Shell also holds an 8.1% interest in the Troll field, and a 12% interest in the Gjøa field which began production in 2010. In 2010, Shell transferred its interest in the Valhall and Hod fields to Hess in exchange for Hess’ interests in certain assets in Gabon and the UK. Shell also sold its interest in the Statfjord field, along with associated satellite fields, in the Norwegian sector of the North Sea.

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

Shell 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. The northern sector and central sectors of the North Sea contain a mixture of oil and gas fields, and the southern sector contains mainly gas fields. Shell holds various non-operating interests in the Atlantic Margin area, principally in the West of Shetlands area, which encompasses the Schiehallion, Clair and Loyal fields. In 2010, Shell increased its interest in the Clair field as a result of an asset swap with Hess.

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 also has a 35% interest in the block B concession, where gas and condensate are produced from the Maharaja Lela Field, as well as a 53.9% operating interest in exploration block A.

Shell operates the onshore Changbei tight gas field under a PSC with PetroChina. The two parties also plan to appraise, develop and produce tight gas in the Jinqiu block of the central Sichuan Province under a30-year PSC, which expires in 2040. Also in Sichuan, Shell and PetroChina are assessing shale gas opportunities in the Fushun block. In coalbed methane, Shell has a 55% interest in a PSC in North Shilou and is assessing another opportunity with PetroChina in Daning,

both in the Ordos basin. The PSC for the offshore Xijiang fields expired in 2010 after 15 years of licensed production.

As of October 31, 2010, Shell has ceased all upstream activities in Iran in compliance with the US Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010.

Shell holds a20-yeartechnical service contract, which expires in 2029, for the development of the Majnoon oil field. Shell operates the field with a 45% interest. The other Majnoon Venture shareholders are Petronas (30%) and the Iraqi State partner (25%), represented by the Missan Oil Company.

Located in southern Iraq, Majnoon is one of the world’s largest oil fields, estimated by the Iraqi government to have about 38 billion barrels of oil in place. The first phase of the development is planned to bring production to some 175 thousand b/d from a 2010 level of 66 thousand b/d. Shell also holds a 15% interest in the West Qurna 1 field, as part of the ExxonMobil-led consortium. At the end of 2010, production was some 250 thousand b/d. According to both 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 that 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 from three fields within Basra and sell the processed natural gas (and associated products, such as condensate and LPG) for use in the domestic and export markets. Contract terms are still subject to ongoing discussions with the Iraqi government.

Shell has a 16.8% interest in the offshore Kashagan field, where the North Caspian Operating Company is the operator on behalf of the shareholders. This shallow-water field covers an area of approximately 3,400 square kilometres. Phased development of the field will lead to an expected plateau production of some 300 thousandb/d from phase 1, increasing further with additional phases of development. 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 square kilometres in the North Caspian Sea. The block contains two oil discoveries, which are currently under appraisal.

The Caspian Pipeline Consortium (Shell interest 5.4%) exports production from west Kazakhstan to the Black Sea. The pipeline is 1,510 kilometres long and has been operational since October 2001. A pipeline expansion project is underway and is expected to be completed in 2015.

Shell has been operating in Malaysia for 100 years. As contractor to Petronas, Shell produces oil and gas located offshore Sarawak and Sabah under 15 PSCs, in which Shell’s interests range from 30% to 80%.

In Sabah Shell operates four producing offshore oil fields with Shell interests ranging from 50% to 80%. Shell also has additional interests

ranging from 35% to 50% in offshore PSCs for the exploration and development of five blocks, where Shell is the operator of the unitised Gumusut-Kakap field (Shell interest 33%), and the Malikai field (Shell interest 35%), both of which are currently being developed. Shell has a 30% interest in the Kebabangan field for which Kebabangan Petroleum Operating Company is the operator.

In Sarawak Shell is the operator of 17 gas fields with interests ranging from 37.5% to 70%. Nearly all of the gas produced is supplied to the Malaysia LNG (MLNG) Satu, Dua and Tiga plants (Shell interest 15% in MLNG Dua and Tiga plants) in Bintulu, Sarawak. Shell also has a 40% interest in the Baram Delta PSC, a 50% interest in SK-307 and a 60% interest in deep-water block SK-E.

Shell also operates a GTL plant (Shell interest 72%), which is adjacent to the LNG facilities in Bintulu. 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). PDO is the operator of an oil concession expiring in 2044. PDO currently produces about 550 thousand b/d and plans to maintain that rate by delivering a steady stream of new field developments and enhanced oil recovery projects that will utilise a wide range of thermal and chemical hydrocarbon recovery techniques.

Shell also participates in the development and production of the Mukhaizna oil field (Shell interest 17%) where steam flooding, an enhanced oil recovery method, is being applied on a large scale.

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

Shell has a 45% interest in the deep-water PSC for blockSC-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 exploration blockSC-60, an area offshore of north-east Palawan. Additionally, a farm-in agreement was signed in October 2010, for a 45% interest inblock SC-54B,situated south ofSC-38.

Pearl GTL is the world’s largestgas-to-liquidsproject. Shell provides 100% of the project funding under a development and production-sharing agreement with the government of Qatar. The fully integrated project includes production, transport and processing of some 1.6 billion scf/d of well-head gas from Qatar’s North Field to produce around 120 thousand b/d of natural gas liquids and ethane, and the conversion of the remaining gas into 140 thousand b/d of high-quality liquid hydrocarbon products. Major construction was substantially complete by the end of 2010. Pearl GTL will go into thestart-upphase in 2011, with aramp-up of production during 2011 until reaching full capacity in 2012.

Shell has a 30% interest in the Qatargas 4 LNG project, which comprises integrated facilities to produce some 1.4 billion scf/d of natural gas from Qatar’s North Field, an onshore gas-processing facility and a LNG train collectively yielding 70 thousand b/d of natural gas liquids and 7.8 mtpa of LNG. The LNG will be shipped to markets mainly in North America, China and the United Arab Emirates. Major construction of the Qatargas 4 project has been completed and

first LNG was produced in January 2011, with production expected to reach full capacity in 2011.

In May 2010, Shell and PetroChina signed an exploration and production-sharing agreement with Qatar Petroleum on behalf of the government of Qatar for block D. Shell, as operator, holds a 75% equity interest with PetroChina holding a 25% interest.

In December 2010, Shell and Qatar Petroleum signed a Memorandum of Understanding to jointly study the development of a major petrochemical complex in Ras Laffan Industrial City, Qatar.

Shell has a 27.5% interest in Sakhalin 2, which is one of the world’s largest integrated oil and gas projects. Located in a subarctic environment, the project started LNG production in 2009 and has been ramping up throughout 2010. Plateau production from Sakhalin 2 is some 360 thousand boe/d, supplying around 9.6 mtpa of LNG from two trains.

Shell has a 50% interest in the Salym fields in western Siberia, where production was some 160 thousand boe/d during 2010.

Shell’s principal operations in Syria are conducted by a registered branch of Syria Shell Petroleum Development B.V. (SSPD). SSPD holds interests ranging from 62.5% to 66.67% in three PSCs (Deir Ez Zor, Fourth Annex and Ash Sham), which expire between 2018 and 2024. SSPD is also party 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 SSPD holds a 31.25% interest, performs operations under these contracts.

In 2010, Shell transferred 35% of its interest in SSPD to China National Petroleum Corporation. Shell maintains a 65% interest in SSPD.

Shell South Syria Exploration Limited (Shell interest 100%) has exploration interests in two production-sharing contracts, for blocks 13 and 15 in the south of Syria, expiring in 2011 and 2014 respectively. A one-year extension for block 13 has been requested and is pending government approval. Seismic data acquisition was completed in 2008 and exploration drilling commenced in 2010. Shell is the operator with a 70% interest.

In Abu Dhabi Shell holds a concessionary share of 9.5% in the oil and gas operations run by 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 expires in 2028. GASCO exports propane and butane, as well as heavier liquid hydrocarbons that it extracts from the wet natural gas associated with the oil produced by ADCO.

Shell also has interests in Azerbaijan, India, Japan, Jordan, Kuwait, 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 areas. Some of these interests are held directly and some indirectly, through a

shareholding in Woodside Petroleum Ltd (Woodside). In 2010, Shell sold a portion of its shareholding in Woodside for a cash consideration of $3.2 billion, and now holds a 24.27% interest in the company (from 34.27%). Woodside is the operator of the Pluto LNG project currently under construction. Woodside is also the operator on behalf of six joint venture participants of the NWS gas, condensate and oil fields. Shell provides technical support for the NWS development. Gas and condensate are currently produced from the North Rankin, Goodwyn, Perseus and Angel fields, which are piped to the expanded NWS onshore gas processing facility and LNG plant on the Burrup Peninsula.

In 2010, Shell and PetroChina jointly purchased Arrow Energy Limited (Arrow); the total cash consideration was $3.1 billion (Shell interest in Arrow 50%). The joint venture owns Arrow’s Queensland coalbed methane assets and a domestic power business as well as the site for a proposed LNG plant on Curtis Island, near Gladstone, Queensland.

The Gorgon LNG project (Shell interest 25%) involves the development of the largest gas discoveries to date in Australia, beginning with the offshore Gorgon (Shell interest 25%) and Jansz/Io fields (Shell interest approximately 20%). It is the single largest resource development project in Australia. Construction activities on Barrow Island continued in 2010 with completion expected in 2015. It is expected to be a world leader in capturing the carbon dioxide by-product from the fields and storing it safely underground, more than 2 kilometres beneath Barrow Island.

Shell is the operator and 100% equity holder of a permit in the Browse Basin in which two separate gas fields were found – Prelude in 2007 and Concerto in 2009. In 2009, Shell announced plans to develop these fields on the basis of our innovative floating liquefied natural gas (FLNG) technology. This technology enables gas to be processed offshore, reducing the development’s costs and minimising its environmental impact. The front-end engineering and design has been progressed and environmental approvals have been conditionally granted. Shell also has rights to the gas of the nearby Crux field (AC/P23) and operates the AC/P41 block (Shell interest 75%), where the Libra-1 gas discovery was made in 2008.

Shell is also a partner in the Browse joint venture (Shell interest approximately 20%) covering the Torosa, Brecknock and Calliance gas fields. In 2010, the joint venture participants agreed to begin designing the development of the Browse resources for an LNG plant at James Price Point on the Dampier Peninsula of Western Australia.

In the Timor Sea Shell holds interests in the large Sunrise and Evans Shoal gas fields (Shell interest 33% and 25%, respectively). The partners have selected a FLNG development concept for Greater Sunrise gas.

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 gas produced is sold domestically, mainly under long-term contracts. Shell also has interests in other exploration licence areas in the Taranaki Basin.

Shell has a 50% interest in the Badr El-Din Petroleum Company (Bapetco), a joint venture with the Egyptian General Petroleum Corporation. Bapetco carries out field operations in West Desert concessions in which Shell has an interest in BED, NEAG, NEAG

Extension, West Sitra, Sitra, Obaiyed and the recently acquired Alam El Shawish West Concession area.

In addition, Shell is carrying out offshore exploration in the North West Damietta Extension and has an interest in two BP-operated offshore concessions: North Damietta and North Tineh.

Shell has interests in eight onshore mining concessions and three offshore exploration concessions. Two of the non-operated concessions (Coucal and Avocette) have been converted into PSCs as of January 1, 2011. An offshore exploration concession – the Shell-operated Igoumou Marin ultra-deep concession – expired in 2010 and is yet to be renewed due to a geographical boundary dispute. The other concessions expire between 2011–2042, and requests for extensions are in progress for the near-term expirations. In 2010, Shell increased its interests in two Shell-operated assets and one non-operated asset as a result of an asset swap with Hess.

While security in Nigeria remains fragile, the situation has improved in 2010, allowing the restart of certain facilities that were previously inaccessible. Overall 2010 production in Nigeria was some 400 thousand boe/d compared with some 280 thousand boe/d in 2009 (Shell share).

Onshore The Shell Petroleum Development Company of Nigeria Ltd (SPDC) is the operator of a joint venture (Shell interest 30%) that holds 27 Niger Delta onshore oil mining leases (OMLs), which expire in 2019.

On the funding side, Modified Carry Agreements (MCAs) are in place for certain key projects and a bridge loan was drawn down by the Nigerian National Petroleum Company (NNPC) in 2010. Additionally, the Gbaran-Ubie integrated oil and gas project (Shell interest 30%) came on-stream in 2010 in Bayelsa State. In early 2011, Gbaran-Ubie achieved peak gas production of 1 billionscf/d; oil production has reached some 50 thousandb/d and is expected to peak at some 70 thousand b/d. Gas from Gbaran-Ubie is delivered to power plants for domestic use and to Nigeria LNG Ltd (NLNG) for export.

In 2010, Shell sold its interests in OMLs 4, 38 and 41 in the Niger Delta and related equipment to a consortium led by two Nigerian companies. In October 2010, Shell reached agreement to transfer its rights in OML 26 in the Niger Delta to FHN26 Ltd, a subsidiary of First Hydrocarbon Nigeria Limited. This transaction is expected to be completed in 2011, subject to approval by NNPC and the Federal Government of Nigeria.

Offshore The main offshore deep-water activities are carried out by Shell Nigeria Exploration and Production Company (SNEPCo – Shell interest 100%) with interests in three deep-water blocks. Shell operates two of the blocks including the Bonga field 120 kilometres offshore with a production capacity of more than 200 thousand b/d of oil and 150 million scf/d of gas. Deep-water offshore activities are typically governed through PSCs with NNPC.

Additionally, 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. SPDC is pursuing a negotiated solution with the Federal Government of Nigeria. However, this process has been protracted and is expected to be further delayed. Production from one of the leases – the EA licence – continued from the Sea Eagle Floating

Production, Storage and Offloading vessel throughout the year following thestart-up of production in 2009 after being shut-in following security incidents in 2006.

Shell also has 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.

LNG Shell has a 25.6% interest in Nigeria LNG (NLNG), which operates six LNG trains with a total capacity of 21.6 mtpa. NLNG achieved near full capacity during 2010, helped by better gas supply due to improved security and thestart-up of Gbaran-Ubie.

Shell also has interests in Algeria, Benin, Cameroon, Ghana, Libya, South Africa, Tanzania, Togo and Tunisia.

In total, Shell holds over 2,000 mineral leases in Canada (mainly in Alberta and British Columbia). Shell produces and markets natural gas, NGL, sulphur, synthetic crude oil and bitumen. Bitumen is a very heavy crude oil produced through conventional methods as well as through enhanced oil-recovery methods, such as heating the reservoirs for example. Synthetic crude oil is produced by mining bitumen-saturated sands, extracting the bitumen from the sands, and transporting it to a processing facility where hydrogen is added to produce a wide range of feedstock for refineries.

Gas The majority of Shell’s Canadian gas production comes from the Foothills region of Alberta, where Shell holds approximately 2,000 square kilometres (500 thousand acres). Shell 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. Additionally, Shell holds a 31.3% interest in the Sable Offshore Energy project, a natural gas complex offshore eastern Canada, and has a 20% non-operating interest in an early stage deep-water exploration asset off the east coast of Newfoundland. Shell also holds a number of exploration licences in the Mackenzie Delta. Shell continued unconventional gas development in west-central Alberta and east-central British Columbia during 2010, through drilling programmes and investment in infrastructure facilitating new production. Shell holds approximately 2,800 square kilometres (700 thousand acres) in these tight gas areas.

Synthetic crude oil Shell operates the Athabasca Oil Sands project (AOSP) in north-east Alberta as part of a joint venture (Shell interest 60%). Power and steam for the operations are provided from anon-siteco-generation facility, which is owned and operated by an independent 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. In 2010, Shell completed an expansion project to increase AOSP’s bitumen production capacity by 100 thousand boe/d. Construction for the expansion of the Scotford Upgrader is underway, and will come on-stream in 2011 allowing total upgrading capacity of 255 thousand boe/d.

Shell also holds a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2011 to 2020. By completing a certain minimum level of development prior to their expiry, leases may be extended.

Bitumen Shell produces and markets bitumen in the Peace River area of Alberta, and has a steam-assisted gravity drainage project in operation near Cold Lake, Alberta. Additional heavy oil resources and advanced recovery technologies are under evaluation on about 1,200 square kilometres (300 thousand acres) in the Grosmont oil sands area, also in northern Alberta.

Shell produces oil and gas in the Gulf of Mexico, heavy oil in California and primarily onshore tight gas in Louisiana, Pennsylvania, Texas and Wyoming. 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).

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, with about a quarter of them producing. Shell’s share of production in the Gulf of Mexico averaged over 220 thousand boe/d in 2010. Key producing assets are Auger, Brutus, Enchilada, Holstein, Mars, Mensa, NaKika, Perdido, Ram Powell and Ursa.

Shell, with partners, brought the Perdido deep-water spar development (Shell interest 35%) on-stream in March 2010. Following a shutdown in mid-2010, Perdido continued ramp up in the second half of 2010, and is expected to reach its peak production in 2012.

The drilling moratorium in the Gulf of Mexico, and new regulatory requirements following the Deepwater Horizonincident, have resulted in deferment of various Shell exploration and development programmes. Shell is fully prepared to resume normal operations in compliance with new regulations and pending final regulatory approval of required exploration, development, oil spill response plans and operation-specific drilling permits.

As part of an ongoing portfolio optimisation programme, Shell divested its interests in a package of various non-strategic assets in the Gulf of Mexico in late 2010 – early 2011.

Onshore Following the acquisition of East Resources, Shell holds some 2,800 square kilometres (700 thousand net acres) of highly contiguous acreage with a focus on the Marcellus shale, centred on Pennsylvania in the north-east USA. Additionally, Shell has acquired and began exploration drilling on some 1,000 square kilometres (250 thousand net acres) of mineral rights in the Eagle Ford shale play in south Texas.

In addition to the Pennsylvania Marcellus and south Texas Eagle Ford operations, Shell also has multi-rig onshore gas drilling programmes on the Pinedale Anticline in Wyoming and in the Haynesville shale tight-gas opportunity of north-west Louisiana.

California Shell holds a 51.8% interest in Aera Energy LLC, an 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 about 160 thousand boe/d of heavy oil and gas, and accounting for approximately 30% of the state’s production.

Alaska Shell also holds over 410 federal leases for exploration in the Beaufort and Chukchi seas in Alaska. Due to, among other things, the Federal government’s suspension of Shell’s drilling plans imposed after the Deepwater Horizon incident in the Gulf of Mexico, Shell was prevented from pursuing offshore drilling in 2010. An adverse Environmental Appeals Board ruling on Environmental Protection Agency air permits at the end of 2010 increased regulatory uncertainty for 2011 drilling, therefore, in 2011, Shell will focus on obtaining the permits required for drilling in 2012.

Wind In the wind energy business, Shell has interests in eight US wind projects (Shell interest 50%) with a total installed capacity of 899 MW.

In Mexico Shell has interests in a gulf coast LNG regasification terminal and a related gas marketing business, as well as capacity rights in a west coast LNG import terminal.

Shell is the operator of several producing fields offshore Brazil. They include the Bijupirá and Salema fields (Shell interest 80%) and the Parque das Conchas (BC-10) field (Shell interest 50%), which came on-stream in 2009 and continuedramp-up in 2010. Shell has taken a Final Investment Decision for phase 2 of theBC-10project. Shell also has interests in offshore development and exploration blocks in the Campos, Santos and Espirito Santo basins as well as in the São Francisco onshore area. Shell operates two of these blocks with interests ranging from 17.5% to 100%. In 2010, Shell divested its interest in the Merluza property.

Additionally, 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.