Shell - 20-F annual report

This Report serves as the Annual Report and Accounts in accordance with UK requirements and as the Annual Report onForm 20-Fas filed with the SEC for the year ended December 31, 2011, for Royal Dutch Shell plc (the Company) and its subsidiaries (collectively known as Shell). It presents the Consolidated Financial Statements of Shell (pages 101-140), the Parent Company Financial Statements of Shell (pages 160-168) and the Financial Statements of the Royal Dutch Shell Dividend Access Trust (pages 172-175). Cross references toForm 20-Fare set out on pages 176-177 of this Report.

In this Report “Shell” is sometimes used for convenience where references are made to the Company and its subsidiaries in general. Likewise, the words “we”, “us” and “our” are also used to refer to subsidiaries in general or to those who work for them. These expressions are also used where no useful purpose is served by identifying the particular company or companies. “Subsidiaries” and “Shell subsidiaries” 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 Company and all subsidiaries. The companies in which Shell has significant influence but not control are referred to as “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.

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 and with International Financial Reporting Standards (IFRS) as adopted by the European Union. As applied to the financial statements, there are no material differences from IFRS as issued by the International Accounting Standards Board (IASB); therefore, the financial statements have been prepared in accordance with IFRS as issued by the IASB. IFRS as defined above includes IFRIC.

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 US 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) proved reserves 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 government 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 and to the Shell Sustainability Report. These references are for the readers’ convenience only. Shell is not incorporating by reference any information posted on www.shell.com and in the Shell Sustainability Report.

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, call the SEC at1-800-SEC-0330.All of the SEC filings made electronically by Shell are available to the public on 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.

Global economic recovery progressed in 2011. But it has been put under threat by the eurozone’s financial turbulence. And that turmoil may extend into the medium term if the public debt continues to grow in the USA and Japan. Growth in the developing economies is also expected to slow because of a weakening global demand for their exports and a general loss of investor confidence.

Nevertheless, population growth and rising prosperity in developing countries continue to drive upwards the long-term demand for all forms of energy – both renewable and nonrenewable.

Meeting that demand will require the development of oil and gas resources that, so far, have been passed over because of their geological complexity or geographic remoteness. Such developments have implications for higher costs – and higher energy prices.

With such fundamental market forces increasing the tension between energy supply and demand, the world will be vulnerable to economic and political volatility. Unpredictable events almost anywhere in the world – a rash regulatory decision, a populist revolt or a natural disaster – could trigger swings in cost and prices.

We are living in a very interdependent world. Energy issues cut across geographic and industrial boundaries.

As a bigger, more diverse energy system is built, the economic, political and environmental impacts of extraction, processing, distribution and disposal of all raw materials need to be taken into account. From such a perspective, managing the emission of greenhouse gases is but one facet of a multifaceted problem. Even basic commodities such as water and food have to be managed in the context of the evolving world energy system.

These developments are already influencing our own industry, and they will do so more strongly in the decades ahead. We at Shell seek to gain a better understanding of the inter-relationship between water, food and energy systems. We believe it is critical that these systems not be looked at in isolation.

At Shell, we are applying our creativity to discover new energy resources and make previously uneconomic ones viable. And we are

willing to invest substantial sums of money to secure tomorrow’s energy production.

Our technical and financial means enable us to develop oil and gas resources in very deep water, in very “tight” rock and in the very cold climate of the Arctic. We aim to be an industry leader in these kinds of developments, demonstrating high standards of environmental stewardship and social responsibility.

We are focusing on natural gas. About half of the energy we produce comes out of wells in that form already, and we plan to increase that proportion in the coming years. It is, after all, the cleanest fossil fuel. Replacing coal-fired power plants with gas-fired ones is the fastest and cheapest way for the world to reduce CO₂emissions in the power sector. And gas-fired power additionally has the big advantage of24/7 on-call reliability, complementing the intermittency of solar and wind power.

Natural gas can also be cooled into a liquid that can be shipped across oceans. We expect the global market for liquefied natural gas to continue to grow, and we intend to retain our leading position within it.

We are also big believers in biofuels. With our Raízen joint venture, we have now become a leading producer of ethanol from Brazilian sugar cane, which can cut CO₂emissions by about 70% compared with standard transport fuels. The joint venture works with its suppliers, contractors and landowners to make sure that they follow sustainable practices with their land, water and labour.

But today’s volatile world requires more than Shell alone can deliver. So we are forging strong ties with partners whose know-how, strategic aims or geographic reach fill gaps in our own capabilities. These partners can be governmental or non-governmental bodies, commercial or non-commercial institutions. The task is clear: create a low-carbon energy system that is secure, affordable and sustainable.

Our collaborative efforts will enable us to continue pushing the limits of technology as we execute more complex energy projects. And they will spur us to think in new ways about the earth’s natural resources.

Our partners, our customers and our shareholders would expect no less from us.

In 2011, production began at three major projects that reflect some of Shell’s key strengths: innovation and technology; creating value through the integration of upstream and downstream operations; and long-lived returns. I am referring to Pearl GTL, Qatargas 4 and the expansion of the Athabasca Oil Sands Project. Together with a host of smaller projects, they provide the springboard for growth in production, cash flow and sales of liquefied natural gas (LNG). I thank our employees and project partners for the hard work and dedication that brought all these projects on-stream.

Growth is a key part of our strategy, but so too are operational excellence and the cultivation of future opportunities. I am happy to report that we also made major strides in those aspects of our strategy in 2011, bringing us closer to being the world’s most competitive and innovative energy company.

Our earnings on a current cost of supplies basis attributable to shareholders were approximately $29 billion, up 54% from 2010. Assisted by higher oil prices and asset sales, both the Upstream and Downstream segments generated a cash surplus. This accomplishment came despite low North American natural gas prices and thin refining margins. Excluding working capital movements, cash flow from operational activities amounted to $43 billion – 30% more than in 2010 and 82% more than in 2009.

We announced dividends for the year totalling more than $10 billion, and we are in a position to increase them for the first quarter of 2012. Over the past three years, our shareholders have enjoyed a total return of about 70%.

In 2011, we also made good progress in reshaping our portfolio to support further growth. We received some $7.5 billion in proceeds from the sale of non-core businesses.

Our goal is to have zero fatalities and no incidents that harm our employees, contractors or neighbours – or put our facilities at risk. We continue to make progress on the safety of our people, and the number of work-related fatalities has fallen significantly in recent years. But we still have a way to go to reach our goal. I regret that six people died working for Shell in 2011.

Several incidents at our facilities in 2011 reinforced the need for us to stay vigilant and to maintain our focus on the safety of our operations. Shell Nigeria Exploration and Production Company experienced a leak offshore during the loading of an oil tanker. There was also a fire at our Singapore refinery and a pipeline leak in the UK North Sea. In each case, the rapid and effective response of staff, working with local authorities, prevented injury and limited environmental impact.

We continue to be open about our operational performance. Such transparency is necessary for the industry to work together with local, national and international bodies to minimise negative environmental and social impacts throughout the world.

That kind of open, multilateral approach may also help to ease concerns about hydraulic fracturing – the technique that enables oil and natural gas to be economically produced from shale or other “tight” rock. We introduced in 2011 a set of aspirational principles that

lay out how we intend to pursue tight-oil and tight-gas developments around the globe. These provide a framework for protecting water, air, wildlife and the communities in which we operate. By sticking to them, we uphold our reputation as a responsible operator and set an example for others in the industry.

The year 2011 allowed us to lay the solid foundation on which to build our future.

Our exploration activities, which increased in 2011, resulted in five notable discoveries. We also secured the rights to explore in more than 140,000 square kilometres of new acreage in several countries in Africa, the Americas and Asia-Pacific.

Plans are in place to begin drilling in Alaskan waters. We are also executing drilling campaigns onshore China, offshore French Guiana and both on- and offshore Australia, having already obtained encouraging results in all those places.

In 2011, we took 12 final investment decisions, four of which involve North American tight gas and two of which involve LNG projects. One of the LNG projects – Prelude – is unprecedented: it entails building the world’s first floating production and liquefaction facility.

We also made the financial commitment to carry out the Cardamom project in the Gulf of Mexico. That investment decision, plus another for a project offshore Malaysia, underscores our world-class capability in deep water. All in all, we now have seven deep-water projects under construction.

Together with our partners, we began building the early production facilities for Iraq’s Majnoon field – one of the world’s super-giant oil fields. The agreement setting up the Basrah Gas Company was also endorsed by the Iraqi government in 2011.

In 2011, we agreed to develop a gas-based petrochemical complex with Qatar Petroleum at the same site where our Pearl GTL and Qatargas 4 plants are located. And this year – 2012 – we expect to see the joint-venture refinery at Port Arthur, Texas, become one of the biggest in the USA when the expansion project there more than doubles the refinery’s capacity.

We launched in 2011 the Downstream marketing and biofuel joint venture Raízen in Brazil, one of the world’s fastest-growing economies. Already a leading ethanol producer in Brazil, it could open new international markets for us. In the longer term, it also gives us an opportunity to draw on our advanced biofuel R&D programme.

Our strengthened financial position and re-focused portfolio now enable us to drive forward a new agenda for the medium term. We are planning to raise net capital investment to about $30 billion in 2012, up from some $24 billion in 2011. Maintaining a robust investment programme – even through the dips of business cycles – is the best way to create growth and shareholder returns. The actual spending level in any given year, of course, will depend on project timings, industry costs, asset sales and the flexibility to scale up or down our drilling programmes.

We expect the cumulative cash flow from operations, excluding working capital movements, to be approximately 50% higher over the next four years than it was over the past four years – if the Brent price is around $100 per barrel, the North American natural gas price returns to $5 per MMBtu in the medium term and the environment improves for

refining. We have the potential to see a 25% increase in our production from the 2011 level by2017-2018.Some of this new production is expected to come from liquids-rich shales.

We see further growth potential in our differentiated fuels, our lubricants and our chemicals. So we will continue to make selective investments related to those markets and products. But we will also focus on improving Downstream operations.

Our successful projects, our good performance and our growth opportunities clearly show that we are on the right track. But I believe we can get more value out of our assets. The uptime of our processing facilities, for example, could be greater. And there are significant savings to be realised in our supply chains.

So we will continue our efforts to improve our operating performance and competitive position. We will also continue focusing on customer satisfaction and capitalising on our integrated operations. And, of course, we must never, ever lose sight of safety and environmental performance.

If we get those aspects of our businesses right, then Shell will surely be the number-one choice of both resource holders and resource consumers.

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 both investment and distribution to shareholders.

 

Project delivery reflects Shell’s capability to complete major projects on time and within budget on the basis of targets set in the annual Business Plan. The set of projects consists of at least 20 Shell-operated capital projects that are in the execution phase (post final investment decision).

 

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, synthetic crude oil and bitumen. 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.

2011 chemical plant availability has been measured based on an updated methodology, without resulting in a material change. See page 37.

 

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.

Earnings on a current cost of supplies (CCS) basis attributable to Royal Dutch Shell plc shareholders is the income for the period, adjusted for the after-tax effect of oil-price changes on inventory and non-controlling interest. CCS earnings per share is calculated by dividing CCS earnings attributable to shareholders by the average number of shares outstanding. See page 16 and Note 2 to the “Consolidated Financial Statements”.

 

Net capital investment is capital investment (capital expenditure, exploration expense, new equity and loans in equity-accounted investments and leases and other adjustments), less proceeds from disposals. See Notes 2 and 4 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 48.

 

Gearing is defined as net debt (total debt minus cash and cash equivalents) as a percentage of total capital (net debt plus total equity), at December 31. It is a measure of the degree to which Shell’s operations are financed by debt. For further information see Note 15 to the “Consolidated Financial Statements”.

Proved oil and gas reserves attributable to Royal Dutch Shell plc shareholders are the total estimated quantities of oil and gas (excluding reserves attributable to non-controlling interest in Shell subsidiaries) that geoscience and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs, as at December 31, under existing economic and operating conditions. Gas volumes are converted into barrels of oil equivalent (boe). Reserves are crucial to an oil and gas company, since they constitute the source of future production. Reserves estimates are subject to change based on a wide variety of factors, some of which are unpredictable. See pages 13-15.

 

The operational spills indicator reflects the total number of incidents in which 100 kilograms or more of oil or oil products were spilled by a Shell-operated entity as a result of its operations. The number for 2010 was updated from 193 to reflect completion of investigations into operational spills.

 

The employees indicator consists of the annual average full-time employee equivalent of the total number of people on full-time or part-time employment contracts with Shell subsidiaries.

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

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, Brazil, Brunei, Canada, Denmark, Germany, 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 2011, we brought on-stream both types of projects with our partner in Qatar: Qatargas 4 LNG and Pearl, the world’s largest GTL plant. We also took the final investment decision on the Prelude project, initiating the first-ever construction of a floating LNG facility.

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 Australia, Brazil and the Gulf of Mexico. 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 chemical plants. In 2011, we further expanded our biofuel business with the creation of the Raízen joint venture, which is a leading biofuel producer and fuel retailer in Brazil. 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 LNG and GTL businesses. 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, governs the marketing and trading of gas and power and provides shipping services. Additionally, Downstream oversees Shell’s interests in alternative energy (including biofuels but excluding wind) and CO₂management.

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

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.

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 proved 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 proved 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 government-run oil and gas companies, particularly in seeking access to oil and gas resources. Today, these government-run oil and gas companies control vastly greater quantities of oil and gas resources than the major, publicly held oil and gas companies. Government-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 hinder our access to desirable projects.

Shell subsidiaries and equity-accounted investments 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. Commodity trading is an important component of our supply and distribution function. 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 page 85). As a global company doing business in more than 80 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 6 and 21 to the “Consolidated Financial Statements”). Shell has significant financial exposure to the euro and any significant change in its value would have a material effect on our earnings. Similarly, any structural changes to the European and Monetary Union affecting the euro could also have a material effect on our earnings or financial condition. While we do not have significant direct exposure to sovereign debt, it is possible that our partners and customers may have exposure which could impair their ability to meet their obligations to us. Therefore, a sovereign debt downgrade or default could have a material adverse effect on our earnings or financial condition.

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 Iraq and Kazakhstan. 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 proved 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 its brand and reputation are important assets. The Shell General Business Principles

and Code of Conduct govern how Shell and its individual companies conduct their affairs. It is a challenge for us to ensure that all our thousands of employees comply with the principles. 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. Examples of such developments are our expansion of oil sands activities in Canada and our gas-to-liquids project in Qatar. Additionally, as production from Iraq increases, we expect that CO₂emissions from flaring will rise. We are working with our partners on finding ways to capture the gas that is flared. 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, among 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.

Shell insurance subsidiaries provide insurance coverage to Shell entities, up to $1.15 billion per event generally limited to Shell’s percentage interest in the relevant entity. The type and extent of the coverage provided is equal to that which is otherwise commercially available in the third-party insurance market. While from time to time the insurance subsidiaries may seek reinsurance for some of their risk exposures, such reinsurance would not provide any material coverage in the event of an incident such as BP Deepwater Horizon. Similarly, in the event of a material environmental incident, there would be no material proceeds available from third-party insurance companies to meet Shell’s obligations.

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 or costs of operation. 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 taxes including windfall taxes, restrictions on deductions and retroactive tax claims; import and export restrictions; foreign exchange controls; and changing environmental regulations and disclosure requirements. 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. As a result of the financial crisis, regulators have proposed regulations that would require disclosure of information that is immaterial to investors, but that could compromise confidential commercial arrangements and create conflicting legal requirements. Additional regulations targeted at the financial sector could have unintended consequences for our trading, treasury and pension operations. In our Upstream activities these developments can and do 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 subsidiaries and equity-accounted investments located in the country concerned. If we do not comply with policies and regulations, it may result in regulatory investigations, litigation 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. For example, European Union (EU) sanctions have prohibited us from producing oil and gas in Syria. Potential developments that could impact our business include international sanctions, 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 to gain unauthorised access through the internet to our IT systems, including more sophisticated attempts often referred to as advanced persistent threat. Shell seeks to detect and investigate all such security incidents with the 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 and 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 proved 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 proved 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 associates. In cases where we are not the operator we have limited influence over, and control of, the behaviour, performance and costs of operation of joint ventures or associates. Additionally, our partners or members of a joint venture or an associate (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 subsidiaries and equity-accounted investments in the vast majority of countries in which we do business. Shell subsidiaries and equity-accounted investments 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 subsidiaries or equity-accounted investments for violation of 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 subsidiary agreed to a Deferred Prosecution Agreement (DPA) with the U.S. Department of Justice (DOJ) for violations of the 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 U.S. Securities and Exchange Commission (SEC) for violations of the record keeping and internal control provisions of the FCPA as a result of another Shell subsidiary’s violation of the FCPA, which also arose in connection with the use of 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. Any violations of the DPA, or of 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 to 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. See “Corporate governance” for further information.

On average, 2011 realised oil and gas prices were significantly higher than in 2010 in all regions, except for realised gas prices in the Americas. Oil and gas production available for sale in 2011 was 3,215 thousand barrels of oil equivalent per day (boe/d), compared with 3,314 thousand boe/d in 2010. Excluding the impact of divestments of some 100 thousand boe/d, full year 2011 production was in line with 2010. Refining margins suffered in the tough 2011 environment, being generally lower than those of 2010 in key refining hubs. Weakening demand and industrial overcapacity following the start-up of major refining facilities, especially in Asia, continued to weigh on the sector.

Earnings on a current cost of supplies basis attributable to shareholders in 2011 were $28,625 million, 54% higher than in 2010, which, in turn, were 90% higher than in 2009.

In 2011, Upstream earnings were $24,455 million, compared with $15,935 million in 2010 and $8,354 million in 2009. The 53% increase between the 2011 and 2010 earnings reflected higher realised oil and gas prices, together with higher LNG sales volumes, increased trading contributions and a reduced level of impairment. These items were partly offset by higher operating expenses mainly reflecting the start-up of new projects, lower production volumes and increased taxes. In 2010, earnings increased by 91% compared with 2009, reflecting higher realised oil and gas prices, higher production volumes and gains from divestments, partly offset by an increased level of impairment.

Downstream earnings in 2011 were $4,289 million, compared with $2,950 million in 2010 and $258 million in 2009. Earnings in 2011 increased compared with 2010 as a result of higher chemical margins, increased trading contributions and lower operating expenses, partly offset by a larger loss in refining and lower sales volumes. Earnings increased between 2009 and 2010 because of higher refining margins and sales volumes.

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 2011. Property, plant and equipment and equity-accounted investments increased by approximately $14 billion. Net capital investment was some $24 billion, 1% lower than in 2010; see Note 4 to the “Consolidated Financial Statements”. The effect of net capital investment on property, plant and equipment was partly offset by depreciation, depletion and amortisation of some $13 billion.

Of the 2011 net capital investment, more than 80% related to Upstream projects, some of which were completed in 2011 and started delivering cash inflows. Other projects should deliver organic growth over the long term and include multibillion-dollar integrated facilities that are expected to provide significant cash flows for the coming decades. In 2011, total debt decreased by $7.2 billion. Total equity increased by $21.2 billion in 2011, to $171 billion, as a result of increased retained earnings.

The gearing was 13.1% at the end of 2011, compared with 17.1% at the end of 2010. The change reflects the decrease in total debt and the increase in total equity, partly offset by a decrease in cash and cash equivalents.

Reflecting the state of the global economy, world oil demand rose modestly by 0.7 million b/d in 2011, with a strong 1.3 million b/d demand increase in the emerging economies more than offsetting the decline of 0.6 millionb/d in the developed economies.

Economic growth, which had been strong in 2010, weakened in 2011. Several serious shocks were partly responsible: the devastating earthquake and tsunami in Japan; unrest in some oil-producing countries in north Africa and the Middle East; and major financial turbulence in the eurozone due to high budget deficits and rising debt burdens.

Most emerging economies weathered the turmoil well and grew robustly in 2011, with output in China and India growing by 9% and 7% respectively. In contrast, the USA and the eurozone saw output grow by 1.8% and 1.6% respectively, which was not sufficiently rapid to bring down high unemployment rates.

For 2012, there are concerns about a global economic slowdown. Most analysts expect a recession in the eurozone and slower economic growth in the USA. Economic activity is expected to be more robust in the emerging economies, but their performance remains closely linked to the developed world. So these projections assume that policymakers in the developed economies keep their monetary and fiscal policy commitments and manage to control the financial turmoil, allowing conditions to stabilise.

Brent crude oil prices traded in a range of $95-125 per barrel throughout most of 2011, ending the year at $106.51 per barrel. On average, 2011 prices were some 40% higher than they were in 2010. Brent crude oil averaged $111.26 per barrel in 2011, compared with $79.50 in 2010; West Texas Intermediate (WTI) averaged $95.04 per barrel in 2011, compared with $79.45 a year earlier. WTI traded at a discount to international crude-oil benchmarks like Brent as a consequence of the infrastructure bottlenecks at the landlocked storage and distribution area of Cushing, Oklahoma, in the USA. TheBrent/WTIprice differential averaged $16.22 per barrel over the year.

Natural gas prices in North America were on average 9% lower in 2011 than in 2010. The Henry Hub prices fell from a monthly average range of $4.00-4.55 per million British thermal units (MMBtu) in the first eight months to a monthly average range of $3.15-3.90 per

MMBtu in the last four months of the year, when inventories were high and production had to be discouraged. Averaged over the year, the Henry Hub price was $4.01 per MMBtu compared with $4.40 per MMBtu in 2010. In the UK, prices at the National Balancing Point (NBP) averaged 56.35 pence per therm in 2011, compared with 42.12 pence per therm in 2010. Price developments at the main gas trading hubs in Belgium, Germany and the Netherlands were very similar to those at the NBP. The price increase reflects a tightening of LNG markets and hence the influence of continental oil-indexed prices. Asia-Pacific LNG is predominantly sold under long-term oil indexation contracts. In the Asia-Pacific spot market, the average monthly settlements of the Platts Japan Korea Marker was $13.98 per MMBtu for 2011 compared with $7.71 per MMBtu for 2010.

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 in the USA or the UK. Long-term contracted LNG prices in the Asia-Pacific region are predominantly indexed to oil prices and this is reflected in our LNG portfolio. Oil-indexed gas pricing is still prevalent in some parts of continental Europe, although natural gas contracts have recently included a greater element of spot market pricing.

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 capacity. 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 remain volatile. For the purposes of making investment decisions, we assume a price range of$50-90 per barrel for Brent oil and of$4-6 per MMBtu for US Henry Hub gas. 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 suffered in the tough 2011 environment, being generally lower than those of 2010 in key refining hubs. The year saw a succession of downward revisions to demand forecasts. Industrial overcapacity continued to weigh on the sector following thestart-up of major refining facilities, especially in Asia. Key drivers of refining margins in 2012 are expected to be demand growth in an uncertain economic environment, structural global refining overcapacity and geopolitical tensions leading to possible supply disruptions.

Chemical margins during 2011 were under pressure in Asia from Middle East exports and increasing economic uncertainty. European cracker margins were strong, supported by higher regional prices and lower costs. US ethane cracker margins benefited from the wide price differential between crude oil and natural gas in the country. Chemical margins in 2012 are expected to be demand-led and dependent on the state of the global economy. US ethane cracker margins should be supported by the ongoing feedstock price differential between oil and gas.

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, corporate environmental and social 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 80% of our capital investment in 2012 to be in our Upstream businesses.

In Upstream we focus on exploration for new liquids and natural gas reserves and on developing major new 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 our assets 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 aim to improve 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 liquids and natural 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 field-development projects, and the management of integrated value chains. We aim to 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: performance focus and continuous improvement; growth delivery; and maturing next-generation project options for the longer term.

We will work on continuous improvements in operating performance, with an emphasis on health, safety and environment, asset performance and operating costs. Asset sales are a key element of our strategy – improving our capital efficiency by focusing investment on the most attractive growth opportunities. Sale of non-core assets in 2009-2011 generated some $17 billion in divestment proceeds. Exits from further non-core positions in 2012 are expected to generate up to $3 billion in divestment proceeds.

We have initiatives underway that are expected to improve Shell’s integrated Downstream business, focusing on the most profitable positions and growth potential. Shell announced exits from 800 thousand b/d of non-core refining capacity and from selected retail and other marketing positions in2009-2011,and has taken steps to improve the quality of its Chemicals assets.

We are planning a net capital investment of some $30 billion in 2012 – an increase from 2011 levels – as Shell invests for long-term growth. This amount relates largely to investments in some 17 new projects for which final investment decisions were taken in2010-2011.They are part of a portfolio of more than 60 new growth projects that are under construction or being assessed for future investment. Going forward, annual spending will be driven by the timing of investment decisions and the near-term macroeconomic outlook.

In early 2012, Shell defined a set of ambitious financial and operating targets for profitable growth. These targets are driven by Shell’s performance in maturing new projects for final investment decision and by projectstart-ups.

Cash flow from operations, excluding working capital movements, was $136 billion for2008-2011.We expect aggregate cash flow from operations, excluding working capital movements, for 2012-2015 to be 30-50% higher, assuming that the Brent oil price is in the range of $80-100 per barrel and that conditions improve for North American natural gas prices and downstream margins relative to 2011.

In Upstream we have the potential to reach an average production of some 4.0 million boe/d in 2017-2018, compared with 3.2 million boe/d in 2011. This production potential will be driven by the timing of investment decisions and the near-term macroeconomic outlook, and assumes some 250 thousand boe/d of expected asset sales and licence expiries. In Downstream we are adding new refining capacity in the USA and making selective growth investments in marketing.

Shell has built up a substantial portfolio of options for a next wave of growth. This portfolio has been designed to capture energy price upside and manage Shell’s exposure to industry challenges from cost inflation and political risk. Key elements of this opportunity set are in global exploration and established resource positions in the Gulf of Mexico, North American tight gas, liquids-rich shales and Australian LNG. These projects are part of a portfolio that has the potential to underpin production growth to the end of this decade. Shell is working to mature these projects, with an emphasis on financial returns.

Shell subsidiaries’ and the Shell share of equity-accounted investments’ estimated net proved oil and gas reserves are summarised in the table on page 28 and are set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 141-149.

In 2011, Shell added 1,545 million boe of proved reserves before taking into account a net negative impact from commodity price changes of 235 million boe of proved reserves and a net negative impact from acquisition and divestment activity of 105 million boe of proved reserves. Of the total net additions of 1,205 million boe of proved reserves before taking into account production, 984 million boe came from Shell subsidiaries and 221 million boe were from the Shell share of equity-accounted investments.

In 2011, total oil and gas production available for sale was 1,173 million boe. An additional 39 million boe were produced and consumed in operations. Production available for sale from subsidiaries was 811 million boe with an additional 29 million boe consumed in operations. The Shell share of the production available for sale of equity-accounted investments was 362 million boe with an additional 10 million boe consumed in operations.

Accordingly, after taking into account total production, we had a net decrease of 7 million boe in proved reserves, comprising an increase of 144 million boe from subsidiaries and a decrease of 151 million boe from the Shell share of equity-accounted investments.

Technology and innovation provide ways for Shell to stand apart from its competitors. They help our current businesses perform, and they make our future businesses possible. Over the last five years our spend on research and development (R&D) averaged more than $1 billion annually, more than any other international oil and gas company. In 2011, R&D expenses were $1,125 million, compared with $1,019 million in 2010 and $1,125 million in 2009.

The development of Shell technology is intrinsically linked to our strategic objectives and based on the needs of our customers and partners. It is executed by a single integrated R&D organisation where in-house development of proprietary technologies is complemented with external scientific and technological partnerships. This partnering helps to ensure a healthy influx of new ideas and to speed up technology developments.

We pursue technological breakthroughs across the full spectrum of our businesses and their needs; from novel seismic acquisition technology employing multimillion sensors that help find previously invisible subsurface hydrocarbon accumulations to oil-recovery methods that increase the amount of oil ultimately extracted from existing fields; from advanced biofuels that are derived from non-edible plants or crop waste – such as wheat and barley straw – to a concept engine lubricant which helps increase the overall fuel efficiency. We also work on technologies to reduce the environmental footprint of our operations and products. These are applied, for example, in carbon capture and storage schemes to reduce CO₂and other emissions or in energy-efficiency programmes for our refineries or for our customers.

Sustained investment in our key technologies is paying off. For example, back in the 1980s we initiated the development of the gas-to-liquids (GTL) process and catalysts that in 2011 enabled the start-upof the world’s largest GTL plant in Qatar. Some 30 years ago we started working on chemicals for enhanced oil recovery that include polymer solutions like the one that has been injected since early 2010 into the Marmul field in Oman, where it is expected to boost oil recovery by

some 10% or more. Shell has pioneered deep-water oil production since the 1970s, culminating in world-class projects such as Perdido in the Gulf of Mexico and Parque das Conchas, offshore Brazil.

The floating LNG (FLNG) concept is another example of where we are trying to take extraordinary leaps through technological innovation. The Shell FLNG concept entails a massive floating facility — more than 480 metres long and six times heavier than a fully-loaded aircraft carrier — that can be used to produce natural gas, turn it into a liquid and pump it onto LNG tankers for delivery to customers across the globe. The idea was born and developed entirely within Shell as part of an innovation-stimulating scheme we call GameChanger and it is now applied in Prelude, the world’s first FLNG project, offshore Australia.

In 2012, the key objectives of our R&D programme will remain unchanged. We will continue to focus strongly on technologies supporting our various businesses. Equally, we remain committed to shorten further the time for technology to move from the laboratory to its deployment in the field. This will mean increasing the number of early-stage concepts while terminating less promising projects quickly. As a result, our technology portfolio will maintain a healthy balance between new and mature projects.

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

Refer to Note 25 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 and gas 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 the liquefied natural gas (LNG) to customers across the world. We also convert natural gas to liquids (GTL) to provide cleaner-burning fuels and we market and trade natural gas (including LNG) in support of our Upstream businesses.

2011 was a year of volatility in the global economy and energy markets with unprecedented geopolitical events. According to the International Energy Agency, oil demand in 2011 increased by 0.7 million b/d, or 1%, compared with a 3% demand increase in 2010. The slowing of oil demand growth was largely due to the eurozone and US debt crises. Warmer than normal weather in the fourth quarter of 2011 weakened gas demand in Europe and North America. Demand for gas, and specifically LNG, was robust in markets east of Suez, driven by economic growth across the region and substantial nuclear power generation capacity taken off-line for inspections following Japan’s natural disaster in March 2011.

Average Brent crude oil prices in 2011 increased to $111 per barrel, 40% higher than in 2010, driven by geopolitical unrest in the Middle East and north Africa and the resulting fall in supply from some countries, particularly Libya. In contrast, the average Henry Hub natural gas price fell 9% due to an increase in supply from onshore gas in North America.

Segment earnings in 2011 of $24,455 million included a net gain of $3,855 million mainly related to gains on divestments, mark-to-market valuation of certain gas and derivative contracts, and exceptional tax items. These were partly offset by asset impairments and the cost impact of the US offshore drilling moratorium. Segment earnings in 2010 of $15,935 million included a net gain of $1,493 million, mainly related to gains on divestments, partly offset by asset impairments, mark-to-market valuation of certain gas contracts and the cost impact of the US offshore drilling moratorium. All gains and losses identified above relate to items that individually exceed $50 million.

Excluding these gains and losses, segment earnings in 2011 were 43% higher than in 2010, driven by the delivery of Shell’s growth strategy, continuing portfolio optimisation and higher market prices. Higher realised oil, natural gas and LNG prices, higher LNG sales volumes and higher trading contributions were partly offset by higher operating expenses, mainly reflecting the start-up of new projects, lower production volumes and increased taxes.

We brought several large growth projects on-stream including Qatargas 4 and Pearl GTL in Qatar and the Athabasca Oil Sands Project (AOSP) expansion in Canada. Production from these projects has been ramping up well and, excluding the impact of divestments, our production was in line with 2010. LNG sales volumes grew 12% in 2011 to a new record, reflecting the ramp-up of Qatargas 4 to full capacity and the continued good performance of Nigeria LNG and Sakhalin-2 LNG.

Natural gas production represented 48% of total production of 3,215 thousand boe/d in 2011. Global natural gas realisations improved by 18% in 2011, primarily due to an increase in realisations in the European gas market, which was influenced by higher spot prices. This was partly offset by continued low prices in the North American market linked to Henry Hub and AECO, the main pricing point in Canada. Approximately 18% of Shell’s natural gas production in 2011 was in the Americas. As the chart below illustrates, the spread between energy-equivalent oil and gas prices widened significantly in 2011, with global liquids realisations 39% higher than in 2010, mainly driven by higher oil prices.

Segment earnings in 2010 of $15,935 million included a net gain of $1,493 million as described above. In 2009, earnings of $8,354 million included a net charge of $134 million mainly related to impairments and redundancy charges, partly offset by exceptional tax items and divestment gains. These identified items individually exceed $50 million.

Excluding the gains and charges identified above, segment earnings in 2010 were 70% higher than in 2009. The increase was mainly due to higher realised oil, natural gas and LNG prices, higher production volumes, lower exploration expenses and lower underlying depreciation, partly offset by higher taxes.

Net capital investment was some $19 billion in 2011, compared with some $21 billion in 2010 and some $22 billion in 2009. Capital investment in 2011 was $23 billion (of which $9 billion was exploration expenditure, including acquisitions of unproved properties). This represents a decrease from the 2010 capital

investment of $26 billion, which included $7 billion in acquisitions, primarily relating to East Resources.

In Australia we announced in 2011 the final investment decision on the Prelude floating LNG project. The project is expected to produce up to 110 thousand boe/d of natural gas and natural gas liquids, for sale as some 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of liquefied petroleum gas (LPG).

In Australia Arrow Energy Holdings Pty Ltd (Shell interest 50%) acquired all of the shares in Bow Energy Ltd, a coalbed methane company, for a Shell-share consideration of some $0.3 billion. The transaction was completed in January 2012.

In China Shell and China National Petroleum Corporation (CNPC) signed a global alliance agreement to pursue cooperative opportunities internationally as well as in China. The two parties also signed a shareholders’ agreement to establish a well-manufacturing joint venture (50% Shell and 50% CNPC) subject to further corporate and government approvals.

In Indonesia we entered into the Masela PSC by purchasing a 30% stake for a consideration of some $0.9 billion. The Masela PSC contains the Abadi gas discovery, which is planned to be developed on the basis of a floating LNG project, initially for 2.5 mtpa capacity, with the potential for significant project expansions at a later stage. Front-end engineering and design is expected to begin in 2012.

In Iraq final government approvals were received to form the Basrah Gas Company, a joint venture between Iraq’s South Gas Company (51%), Shell (44%) and Mitsubishi Corporation (5%). The joint venture will gather, treat and process raw gas from the Rumaila, West Qurna 1 and Zubair fields.

In Malaysia Shell extended two PSCs by 30 years with the intention of executing enhanced oil recovery projects offshore Sarawak and Sabah. The improvement in recovery efficiency of the Baram Delta (Shell interest 40%) and North Sabah (Shell interest 50%) oil fields is expected to result in additional oil production and may extend field life to beyond 2040.

In the USA Shell announced a multi-billion dollar investment to develop its major Cardamom oil and gas field in the deep waters of the Gulf of Mexico. The Cardamom project (Shell interest 100%) is expected to produce 50 thousand boe/d at peak production.

In the USA we divested our Rio Grande Valley assets as part of our ongoing portfolio upgrading for some $1.8 billion.

We also completed the divestment of other selected upstream assets including: our 80% interest in Pecten Cameroon Company LLC; our 30% interest in oil mining leases 26 and 42 and related facilities in Nigeria; and our interests in the natural gas transport infrastructure joint venture Gassled in Norway for a total combined consideration of approximately $1.7 billion. In addition, we sold various other non-core assets in Brazil, Canada, Germany, Mexico, Pakistan, the UK and the USA.

During 2011, total LNG sales contracts were signed for some 6 mtpa. These long-term contracts of up to 25 years are linked to oil prices and will be fulfilled by Shell’s global LNG portfolio.

In 2011, hydrocarbon production available for sale averaged 3,215 thousand boe/d, which was 3% lower than in 2010, but 2% higher than in 2009. Excluding production lost from divestments, production was approximately the same as in 2010. Production in 2011 was mainly driven by new projects coming on-stream, notably Qatargas 4 LNG and Pearl GTL in Qatar, the AOSP expansion in Canada and the continuedramp-up of the Gbaran-Ubie project in Nigeria. Newstart-upsand the continuingramp-up of fields more than offset the impact of field declines and the effect of higher prices on PSC entitlements, but lower demand due to warmer weather in Europe and increased maintenance activities compared with 2010 had an additional impact.

LNG sales volumes in 2011 of 18.83 million tonnes were 12% higher than in 2010. This increase mainly reflected the increase in sales volumes from Qatargas 4 (Shell interest 30%), which delivered first LNG in January 2011 and ramped up to full production during the year. Sales volumes were also higher from Nigeria LNG, helped by a stable gas supply, and from the Sakhalin-2 LNG project, where production reached 10 mtpa. These increases were partly offset by the reduction in the Shell share of LNG production from Woodside Petroleum Ltd – the result of Shell’s sale of part of its shareholding in the company in November 2010.

In Qatar both trains of the Pearl GTL project have started production. The first gas from the wells flowed into Train 1 in March 2011 and we achieved the first commercial gasoil shipment in June 2011. Train 2 produced first GTL wax in December 2011. We are continuing to ramp up this substantial project, aiming to reach plateau production capacity by mid-2012.

In Canada production began from the Scotford Upgrader Expansion project (Shell interest 60%). The 100 thousand boe/d expansion brings the upgrader’s capacity to 255 thousand boe/d of heavy oil from the Athabasca oil sands.

In Nigeria the Gbaran-Ubie project achieved peak gas production of 1 billion scf/d in early 2011.

During 2011, Shell participated in five notable exploration discoveries in Australia, French Guiana and Nigeria and six notable successful appraisals. Discoveries will be evaluated in order to establish the extent of the volumes they contain.

In total, Shell participated in 417 successful wells drilled outside proved areas, of which 197 had proved oil and gas reserves allocated in 2011.

In 2011, Shell added acreage to its exploration portfolio mainly from new licences in Australia, Brunei, Canada, Colombia, French Guiana, New Zealand, Russia, Tanzania, Turkey and the USA. Shell also successfully bid for new exploration and production rights in Russia.

In total, Shell secured rights to more than 140,000 square kilometres of new exploration acreage, including positions in liquids-rich shales. This was offset by divestments and relinquishments of acreage, which took place in various countries (mainly Australia, Brazil, Canada, Colombia, Egypt, Norway and the USA).

Shell subsidiaries’ and the Shell share of equity-accounted investments’ estimated net proved oil and gas reserves are summarised in the table

on page 28 and are set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 141-149.

In 2011, Shell added 1,205 million boe of proved reserves before taking into account production, of which 984 million boe came from Shell subsidiaries and 221 million boe were from the Shell share of equity-accounted investments.

The increase in the average yearly commodity prices between 2010 and 2011 resulted in a net negative impact on the proved reserves of 235 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 984 million boe of proved reserves in 2011. This comprised 363 million barrels of oil and natural gas liquids and 621 million boe (3,602 thousand million scf) of natural gas. Of the 984 million boe: 194 million boe were from the net effects of revisions and reclassifications; a decrease of 96 million boe related to acquisitions and divestments; 884 million boe came from extensions and discoveries; and 2 million boe were from improved recovery.

After taking into account production of 840 million boe (of which 29 million boe were consumed in operations), Shell subsidiaries added proved reserves of 144 million boe in 2011. Shell subsidiaries’ proved developed reserves increased by 1,672 million boe to 6,483 million boe while proved undeveloped reserves decreased by 1,528 million boe to 3,837 million boe.

The total addition of 984 million boe reflected a net negative impact from commodity price changes of approximately 261 million boe of proved reserves.

As part of the total proved reserves’ addition of 984 million boe, we added 158 million barrels to our synthetic crude oil proved reserves. In 2011, we had synthetic crude oil production of 45 million barrels of which 3 million barrels were consumed in operations. At December 31, 2011, we had total synthetic crude oil proved reserves of 1,680 million barrels, of which 1,249 million barrels were proved developed reserves and 431 million barrels were proved undeveloped reserves.

As part of the total proved reserves’ addition of 984 million boe, we added 9 million barrels of bitumen proved reserves. After taking into account production of 5 million barrels, bitumen proved reserves were 55 million barrels at December 31, 2011.

Before taking into account production, there was an increase of 221 million boe in the Shell share of equity-accounted investments’ proved reserves in 2011. This comprised 150 million barrels of oil and natural gas liquids and 71 million boe (410 thousand million scf) of natural gas. Of the 221 million boe: 151 million boe were from the net effects of revisions and reclassifications; a decrease of 9 million boe related to acquisitions and divestments; 46 million boe came from extensions and discoveries; and 33 million boe were from improved recovery.

After taking into account production of 372 million boe (of which 10 million boe were consumed in operations), the Shell share of equity-accounted investments’ proved reserves decreased by 151 million boe in 2011. The Shell share of equity-accounted investments’ proved developed reserves increased by 432 million boe to 3,007 million boe,

while proved undeveloped reserves decreased by 583 million boe to 939 million boe.

The total addition of 221 million boe reflected a net positive impact from commodity price changes of approximately 26 million boe of proved reserves.

In 2011, Shell subsidiaries’ and the Shell share of equity-accounted investments’ proved undeveloped reserves (PUD) decreased by 2,111 million boe to 4,776 million boe. This is the result of additions of 775 million boe of new PUD offset by the maturation of 2,886 million boe of PUD to proved developed reserves through project execution. We estimate that more than 90% of the maturation PUD to proved developed reserves came from projects with PUD at the start of the year. During 2011, Shell spent $7.4 billion on development activities related to PUD maturation.

Proved undeveloped reserves held for five years or more (PUD5+) at end-2011 were 1,201 million boe. After a global review during 2011, the end-2009 and end-2010 PUD5+ have been revised from previous estimates, resulting in PUD5+ of 1,193 million boe at end-2009 and 1,312 million boe at end-2010.

PUD5+ at end-2011 relate to installation of gas compression and drilling of additional gas wells which will be executed when required to support existing gas delivery commitments (Australia, Malaysia, the Netherlands, Nigeria and Russia), gas cap blow down awaiting end of oil production (Nigeria), ongoing onshore oil and gas development (USA), Gulf of Mexico water-injection project execution in progress (USA) and major complex projects taking longer than five years to develop (such as Kazakhstan). Most of the PUD5+ are held in locations where Shell has a proven track record of developing similar major projects or where project execution is ongoing but is taking longer than expected.

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.

In the past three years, Shell met all contractual delivery commitments.

In the period2012-2014,Shell is contractually committed to deliver to third parties and equity-accounted investments a total of approximately 4,800 thousand million scf of natural gas from Shell subsidiaries and equity-accounted investments. 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.

A shortfall between Shell’s delivery commitments and its proved developed reserves has been identified, estimated at 23% of Shell’s total gas delivery commitments. This shortfall is expected to be met through the development of proved undeveloped reserves as well as new projects and purchases on the spot market.

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 government-run oil and gas company, and the exploration risk usually rests with the independent oil and gas 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:

We hold a non-operating 46% interest in a producing concession covering the majority of our activities in Denmark. The concession was granted in 1962 and will expire in 2042. Our interest will reduce to 36.8% in July 2012, when the government enters the partnership with a 20% interest and the government profit share of 20% is abolished.

We are the operator of the Corrib Gas project (Shell interest 45%), which is currently under development. In 2011, we received all permits for the planning and construction of an onshore pipeline. The legal challenges to the onshore consents have been withdrawn. The construction of the onshore pipeline is expected to commence in 2012 and will take at least two years to complete. At peak production, Corrib is expected to supply a significant proportion of the country’s natural gas demand.

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, 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, where production restarted in 2011 after a15-yearhiatus. The field’s redevelopment was made possible by enhanced oil recovery technology.

We are a partner in more than 20 production licences on the Norwegian continental shelf and are the operator in eight of these, including the Draugen oil field (Shell interest 26.2%) and the Ormen Lange gas field (Shell interest 17.1%). We hold interests in the Troll field (Shell interest 8.1%), the Gjøa field (Shell interest 12%), the Kvitebjørn field (Shell interest 6.5%), and have further interests in the Valemon field development and various other potential development assets. In 2011, we divested our interests in the Gassled natural gas transport infrastructure joint venture for a consideration of $0.7 billion.

We operate a significant number of our interests in the UK Continental Shelf on behalf of a 50:50 joint venture with ExxonMobil. Most of our 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. We hold various non-Shell operated interests in the Atlantic Margin area, principally in the West of Shetlands area. In 2011, we took final investment decision for the Clair development (Shell interest 28%) and the Schiehallion redevelopment (Shell interest 36.3%) projects.

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

We also have a 35% interest in the Block B concession, where gas and condensate are produced from the Maharaja Lela Field, a 12.5% interest in exploration Block CA-2 and 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 have also agreed to appraise, develop and produce tight gas in the Jinqiu block of the central Sichuan Province under a30-year PSC (Shell interest 49%), which expires in 2040. The Jinqiu project achieved first gas production in September 2011. Also in Sichuan, Shell and PetroChina are assessing shale-gas opportunities in the Fushun block. The two parties are also assessing opportunities in coalbed methane in the Ordos Basin, where Shell has an agreement to evaluate resources in Daning.

Shell is also a partner in the Hangzhou city ring joint venture that develops, operates and manages a high-pressure natural gas pipeline system.

In 2011, Shell agreed to acquire a 30% participating interest in the offshore Masela block from Inpex Masela, the operator. The Masela block contains the Abadi gas field. The operator has selected an FLNG concept for the field’s first development phase. The transaction was formally approved by the Indonesian government on December 1, 2011.

Shell ceased its upstream activities in Iran in 2010 as a direct consequence of the international sanctions imposed on Iran, including the US Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010.

We hold a20-yeartechnical service contract, which expires in 2030, for the development of the Majnoon oil field and operate the field with a 45% interest. The other Majnoon shareholders are PETRONAS (30%) and the Iraqi government 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 the level of 45 thousand b/d when the contract entered into effect in March 2010. We also hold a 15% interest in the West Qurna 1 field, as part of the ExxonMobil-led consortium. At the end of 2011, production was some 370 thousand b/d. According to both contracts’ provisions, Shell’s equity entitlement volumes will be lower than the Shell interest implies.

In November 2011, Shell signed an agreement with the government of Iraq to establish a joint venture between Shell (44%), the South Gas Company (51%) and Mitsubishi Corporation (5%). The joint venture will be called Basrah Gas Company, and will gather, treat and process raw gas produced from the Rumaila, West Qurna 1 and Zubair fields. Currently, an estimated 700 million scf/d of gas is flared because of a lack of infrastructure to collect and process it. The processed natural gas and associated products, such as condensate and LPG, will be sold primarily to the domestic market with the potential to export any surplus.

We have 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. Phase 1 development of the field is expected to lead to plateau production of some 300 thousand boe/d, increasing further with additional phases of development. NC Production Operations Company, a joint venture between Shell and KazMunayGas, will manage production operations.

We are also a 55% partner in the Pearls PSC, which covers an area of some 900 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.

We have been operating in Malaysia since 1910. As contractor to PETRONAS, we produce oil and gas located offshore Sarawak and Sabah under 14 PSCs, in which our interests range from 30% to 80%.

In Sabah we operate four producing offshore oil fields with interests ranging from 50% to 80% as part of the 2011 North Sabah EOR PSC and the SB1 PSC. We also have additional interests ranging from 35% to 50% in PSCs for the exploration and development of five deep-water blocks, which include the unitised Gumusut-Kakap field (Shell interest 33%) and the Malikai field (Shell interest 35%). Both fields are currently being developed with Shell as the operator. We have a 21% interest in the SiakapNorth-Petaifield operated by Murphy and a 30% interest in the Kebabangan field operated by the Kebabangan Petroleum Operating Company.

In Sarawak we are the operator of 18 gas fields with interests ranging from 37.5% to 70%. Nearly all of the gas produced is supplied to Malaysia LNG in Bintulu where we have a 15% interest in each of the Dua and Tiga LNG plants. We also have a 40% interest in the 2011 Baram Delta EOR PSC and a 50% interest in Block SK-307.

In 2011, we signed a heads of agreement (HOA) with PETRONAS for two 30-yearPSCs for enhanced oil recovery projects offshore Sarawak and Sabah. These PSCs replace the existing 2003 Baram Delta and 1996 North Sabah PSCs. The HOA specifies work activities and new investment from Shell and its joint-venture partner to increase the average recovery factor of the fields in the PSC and extend their productive life beyond 2040.

We also operate 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.

We have a 34% interest in Petroleum Development Oman (PDO). PDO is the operator of an oil concession expiring in 2044. Current production is about 550 thousand b/d.

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

We have a 30% interest in Oman LNG, which mainly supplies Asian markets under long-term contracts. We also have an 11% indirect interest in Qalhat LNG, another Oman-based LNG supplier.

Pearl GTL in Qatar is the world’s largestgas-to-liquidsproject. Shell provides 100% of the funding under a development and production-sharing contract 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 with installed capacity of around 140 thousand boe/d of high-quality liquid hydrocarbon products and 120 thousand boe/d of natural gas liquids and ethane. By the end of 2011, Train 1 was ramping up production and Train 2 had started up.

Shell has a 30% interest in Qatargas 4, 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 an LNG train with a collective production capacity of 7.8 mtpa of LNG and 70 thousand boe/d of natural gas liquids. The train delivered first LNG in January 2011 and has ramped up to full production during the year with the LNG shipped mainly to markets in North America, China, Europe and the United Arab Emirates.

Shell also holds a 75% equity interest in Block D under the terms of an exploration and production-sharing contract with Qatar Petroleum,

representing the national government. Shell is the operator, with PetroChina holding a 25% interest.

We have 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 reached planned plateau production of some 360 thousand boe/d in 2010, supplying around 9.6 mtpa of LNG from two trains. After optimisation of the LNG plant, production from the two trains reached 10 mtpa.

We have a 50% interest in the Salym fields in western Siberia, where production was some 165 thousand boe/d during 2011.

We also hold interest in two exploration and production licences in Russia for the East Talotinskiy area in the Nenets Autonomous District and for Barun-Yustinsky licence block in Kalmykia.

Shell holds a 65% interest in Shell Petroleum Development B.V. (SSPD), a venture between Shell and CNPC. SSPD holds a 31.3% interest in Furat Petroleum Company (AFPC), a Syrian joint-stock company, which performs operations under SSPD contracts. In compliance with international sanctions on Syria, including European Council Decision 2011/782/CFSP, in December 2011 Shell suspended all exploration and production activities in Syria.

In Abu Dhabi we hold a concessionary interest of 9.5% in the oil and gas operations run by Abu Dhabi Company for Onshore Oil Operations (ADCO). The licence expires in 2014. We also have a 15% interest in the licence of Abu Dhabi Gas Industries Limited (GASCO), which expires in 2028. GASCO exports propane, butane and 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, the Philippines, Saudi Arabia, Singapore, South Korea and Turkey.

We have 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. Some of these interests are held directly and others indirectly through a shareholding of approximately 24% in Woodside Petroleum Ltd (Woodside). 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, which produced 512 thousand boe/d in 2011. Shell provides technical support for the NWS development. In December 2011, the NWS joint venture announced the final investment decision on the Greater Western Flank Phase 1 project.

We also have a 50% interest in Arrow Energy Holdings Pty Limited (Arrow), a Queensland-based joint venture with PetroChina. Arrow owns coalbed methane assets, a domestic power business and the site for a proposed LNG plant on Curtis Island, near Gladstone. In 2011, Arrow entered into an agreement to acquire all the shares of coalbed methane company Bow Energy Ltd (Bow) for a Shell-share consideration of some $0.3 billion. The acquisition of Bow contributes to Arrow’s opportunity to

expand the proposed LNG project on Curtis Island from the currently planned 8.0 mtpa. In December 2011, the transaction received final government and shareholder approval, and was completed in January 2012.

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%) andJansz-lofields (Shell interest approximately 20%). It includes the construction of a 15.3 mtpa LNG plant on Barrow Island. Construction activities continued in 2011.

We are the operator of a permit in the Browse Basin in which two separate gas fields were found – Prelude in 2007 and Concerto in 2009. In 2011, we announced the final investment decision 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 Prelude FLNG project is expected to produce some 110 thousand boe/d of natural gas and natural gas liquids, delivering some 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG. 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.

We are also a partner in the Browse joint venture (Shell interest approximately 20%) covering the Brecknock, Calliance and Torosa gas fields. In 2010, as required by the Retention Lease, the joint-venture participants began planning the development of the Browse resources on the basis of 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 approximately 34% and 32.5%, respectively). The joint-venture partners have selected FLNG as the preferred development concept for Sunrise. The development is subject to approval from both the Australian and Timor-Leste governments.

Shell also holds a 6.4% interest in the Wheatstone LNG project, which includes construction of two LNG trains with a combined capacity of 8.9 mtpa. The final investment decision for the Wheatstone LNG project was announced in 2011.

We have an 83.8% 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 has interests in other exploration licence areas in the Taranaki Basin. In 2011, we acquired a 50% interest in two exploration licences in the Great South Basin.

We have 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 the West Desert, where we have interests in the Alam El Shawish West, BED, NEAG, NEAG Extension, Obaiyed, Sitra and West Sitra concession areas.

In addition, we have interests in the offshore North West Demiatta concession and in two BP-operated offshore concessions: North Damietta Offshore and North Tineh Offshore.

We have interests in eight onshore mining concessions and three offshore exploration concessions. Two of the non-operated concessions (Avocette and Coucal) have been converted into PSCs as of January 1, 2011. A Shell-operated exploration concession – in the deep-water Igoumou Marin block – has entered the second exploration period, but is currently suspended pending the resolution of a geographical boundary dispute.

Security in Nigeria remained relatively stable during 2011. Shell-share production in Nigeria was some 385 thousand boe/d in 2011 compared with some 400 thousand boe/d in 2010.

Onshore The Shell Petroleum Development Company of Nigeria Ltd (SPDC) is the operator of a joint venture (Shell interest 30%) that holds more than 30 Niger Delta onshore oil mining leases (OMLs), which expire in 2019. To provide funding, Modified Carry Agreements are in place for certain key projects and a bridge loan was drawn down by the Nigerian National Petroleum Company (NNPC) in 2010.

The Gbaran-Ubie integrated oil and gas project (Shell interest 30%) came on-stream in 2010 in Bayelsa State and achieved peak gas production of 1 billion scf/d in early 2011. Gas from Gbaran-Ubie is delivered to power plants for domestic use and to Nigeria LNG Ltd (NLNG) for export.

In Nigeria Shell sold its 30% interest in OMLs 26 and 42 and related facilities in the Niger Delta for a consideration of approximately $0.5 billion. The assignment of its interests in respect of OMLs 34 and 40 is still awaiting requisite consents for completion.

Offshore The main offshore deep-water activities are carried out by Shell Nigeria Exploration and Production Company (Shell interest 100%) with interests in three deep-water blocks. Shell operates two of the blocks including the Bonga field 120 kilometres offshore. Deep-water offshore activities are typically governed through PSCs with NNPC.

Additionally, SPDC holds an interest in six shallow-water offshore leases, of which five expired on November 30, 2008. However, SPDC satisfied all the requirements of the Nigerian Petroleum Act to be 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. Production from a field (the EA field) in one of the disputed leases, OML 79, continued from the Sea Eagle floating production, storage and offloading vessel throughout 2011. The dispute regarding the ownership of the licence and the rights in the OPL 245 PSC was resolved during 2011, with Shell being awarded a 50% equity interest.

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 continued production at near full capacity during 2011, mainly as a consequence of improved gas supply due to stable security and the ramp up of the Gbaran-Ubie project.

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

In total, we hold more than 2,000 mineral leases in Canada (mainly in Alberta and British Columbia). We produce and market 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 those based on heating the reservoirs. 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 In Alberta we hold rights to more than 2,400 square kilometres (600 thousand acres). Half of our Canadian gas production comes from the Foothills region of Alberta. We own and operate four natural gas processing and sulphur-extraction plants in southern and south-central Alberta and are among the world’s largest producers and marketers of sulphur. Additionally, we hold a 31.3% interest in the Sable Offshore Energy project, a natural gas complex offshore eastern Canada, and have a 20% non-operating interest in an early stage deep-water exploration asset off the east coast of Newfoundland. We also hold a number of exploration licences in the Mackenzie Delta. Shell continued to develop tight and shale gas fields in west-central Alberta and east-central British Columbia during 2011, through drilling programmes and investment in infrastructure facilitating new production. Shell holds rights to approximately 3,200 square kilometres (800 thousand acres) in these tight-gas areas.

Synthetic crude oil We operate the Athabasca Oil Sands Project (AOSP) in north-east Alberta as part of a joint venture (Shell interest 60%). 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. The AOSP’s bitumen production capacity is 255 thousand boe/d, following an expansion project completed in 2010. In 2011, the expansion of the Scotford Upgrader was completed, delivering first commercial production in May and allowing it to process 255 thousand boe/d. In addition, we took the final investment decision on a debottlenecking project for the AOSP, which is expected to add an additional 10 thousand boe/d at peak production. This project is the first of several debottlenecking opportunities for the AOSP. We also signed agreements with the governments of Alberta and Canada to secure some $0.9 billion in funding for the Quest Carbon Capture and Storage project (Shell interest 60%), which is expected to capture and permanently store more than one mtpa of CO₂from the Scotford Upgrader.

Shell also holds a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2012 to 2020. By completing a certain minimum level of development prior to their expiry, leases may be extended.

Bitumen We produce and market bitumen in the Peace River area of Alberta, and have 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.

LNG In 2011, Shell announced investment in the Green CorridorLNG-for-transportproject (Shell interest 100%). Pending regulatory approval, the Green Corridor project includes a 0.3 mtpa LNG production facility in Alberta.

We produce 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 our 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 usually run 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 a little over 50% of Shell’s oil and gas production in the USA. We hold approximately 600 federal offshore leases in the Gulf of Mexico, about one-third of which are producing. Our share of production in the Gulf of Mexico averaged more than 180 thousand boe/d in 2011. Key producing assets are Auger, Brutus, Enchilada, Holstein, Mars, NaKika, Perdido, Ram-Powell and Ursa.

The 2010 drilling moratorium in the Gulf of Mexico, and new regulatory requirements following the BP Deepwater Horizon incident, resulted in deferment of various Shell exploration and development programmes. Those deferments continued to affect the operational flexibility and delivery timing of our Gulf of Mexico business in 2011. Since the lifting of the moratorium, Shell has met all deep-water regulatory permitting and environmental assessment requirements for key projects. Although the new regulatory regime has resulted in a longer permitting process, the number of permits we secured in 2011 is approximately the same as in 2009 and is aligned with 2011 activity plans. Additionally, all Shell rigs are compliant with new regulatory mandates.

Onshore We hold some 3,400 square kilometres (850 thousand acres) of highly contiguous acreage with a focus on the Marcellus shale, centred on Pennsylvania in the north-east USA. We also have some 1,100 square kilometres (270 thousand acres) of mineral rights in the Eagle Ford shale formation in south Texas.

Additionally, we have multi-rig onshore gas drilling programmes on the Pinedale Anticline in Wyoming (35 thousand acres) and in the Haynesville tight-gas formation of north-west Louisiana (200 thousand acres).

California We hold a 51.8% interest in Aera Energy LLC (Aera), 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 140 thousand boe/d of heavy oil and gas, accounting for approximately 30% of the state’s production.

Alaska We hold more than 410 federal leases for exploration in the Beaufort and Chukchi seas in Alaska. Following an adverse Environmental Appeals Board ruling on Environmental Protection Agency air permits at the end of 2010, we cancelled our 2011 Alaska exploratory drilling programme. We focused therefore on obtaining the permits required for drilling in 2012, receiving conditional approvals from the Bureau of Ocean Energy Management, Regulation and Enforcement for the Beaufort and Chukchi Seas Exploration Plans. We also received an air permit for the Discoverer drillship to work in both the Beaufort and Chukchi Seas.

Wind We have interests in eight US wind projects (Shell interest 50%) with a total installed capacity of 899 megawatts.

Shell also has exploration interests offshore Greenland and interests in Mexico.

We are 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%). We also have interests in offshore development and exploration blocks in the Campos, Espirito Santo and Santos basins with interests ranging from 17.5% to 80%. We operate one of these blocks (BM-S-54), as well as five blocks in the São Francisco area. In 2011, as part of a portfolio review, we divested our 20% participating interest in Block BM-S-8 and entered into an agreement to divest, subject to regulatory approvals, our 40% interest in Block BS-4, both in the Santos basin, offshore Brazil.

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

Shell has a 45% interest in the offshore Zaedyus field.

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