This Report serves as the Annual Report and Accounts in accordance with UK requirements and as the Annual Report on Form 20-F as filed with the SEC for the year ended December 31, 2012, for Royal Dutch Shell plc (the Company) and its subsidiaries (collectively known as Shell). It presents the Consolidated Financial Statements of Shell (pages 99-137), the Parent Company Financial Statements of Shell (pages 159-167) and the Financial Statements of the Royal Dutch Shell Dividend Access Trust (pages 171-174). Cross references to Form 20-F are set out on pages 175-176 of this Report.

In this Report “Shell” is sometimes used for convenience where references are made to the Company and its subsidiaries in general. Likewise, the words “we”, “us” and “our” are also used to refer to subsidiaries in general or to those who work for them. These expressions are also used where no useful purpose is served by identifying the particular company or companies. “Subsidiaries” 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, jointly controlled entities and associates are also referred to as “equity-accounted investments”. The term “Shell interest” is used for convenience to indicate the direct and/or indirect 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 or in the Shell Sustainability Report.

Documents on display

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 at 1-800-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 001-32575). 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.

In 2012, we continued to deliver on our strategy in the face of an uncertain economic environment. At Shell, we naturally pay close attention to short-term economic conditions, but we take a long-term, strategic view of the Company’s development. We continue to invest in, and maintain, a diverse portfolio of assets, despite economic headwinds.

This gives us a resilience that enables us to build for the future: we can continue to develop major projects to help meet rising energy demand, while operating a global network of refineries and chemical plants that help us derive maximum value from the resources we produce. We balance growth opportunities and investment returns, while continuously seeking to improve operational safety standards, competitiveness and innovation.

The global economic growth rate for the year fell slightly, to an estimated 3.2% from 3.9% for 2011. The average Brent crude oil price for the year was $112 per barrel, very close to the figure for 2011.

Our dividends in 2012 increased to approximately $11 billion, making them the largest in our sector. We expect to increase dividends for the first quarter of 2013 by 4.7%, compared with the same quarter of 2012.

Energy and climate

Our solid foundations and strategy will enable us to continue to grow in a volatile world facing many difficult challenges. One of the greatest of these challenges is how to meet rising energy demand, while significantly reducing carbon dioxide (CO₂) emissions.

Shell estimates that by 2050, global energy demand could increase by up to 80%, as living standards rise and the world’s population grows from seven to nine billion.

Renewable energy, including biofuels, will play a role. Our Raízen joint venture in Brazil turns sugar cane into ethanol, which could reduce overall CO₂ emissions significantly compared with the gasoline it replaces. By 2050, renewable sources could provide about 30% of the world’s energy. However, fossil fuels are still likely to meet about two-thirds of energy demand.

Natural gas, the cleanest burning fossil fuel, is central to our long-term business strategy. Shell is a major supplier of natural gas that powers homes and businesses. In North America, we are unlocking gas trapped in tight and shale rock formations. The dramatic increase in

gas supplies there, as a result of the shale gas revolution, has lowered prices and brought other advantages. When used to displace coal in electricity generation, it could reduce CO₂ emissions by about half. Now the benefits of tight and shale gas are spreading to other parts of the world, such as China, and we are at the forefront of this development.

The world will also need to address tensions between supplies of the linked essentials of water, energy and food, which could become critical as the population grows. Energy is needed to produce food, and water is needed to produce energy. Shell is leading efforts to understand these stresses, and we are finding ways to recycle and use water more efficiently.

Innovation has a vital role to play in the challenges we face. Since 2007, we have spent more than $1 billion a year on research and development, and continue to deploy new technology. For example, we have formed Sirius Well Manufacturing Services, an international well services company, in partnership with China National Petroleum Corporation. The 50:50 joint venture was incorporated in 2012, and will use advanced techniques to drill multiple wells for tight, shale and coalbed gas extraction in an efficient, repeatable way. It has potential across the world.

We continue to invest in the quality of our people. Our graduate and experienced recruitment programmes, supported by structured learning and development, are focused on providing the capability we need for success in the future.

Learning lessons

As more accessible resources are depleted, those in challenging environments will be essential in meeting global energy demand in the decades ahead. In 2012, we took the first steps in exploring for new resources off the coast of Alaska. Later events involving our drilling ships were most regrettable. We have since decided to pause exploration drilling in 2013, to prepare plans and equipment for activity at a later stage. Alaska remains an area of high potential for Shell in the long term. We will learn lessons from our experience, and continue to explore for resources there in a careful and measured way.

We will also continue to invest in developing capabilities that help us explore for energy resources in the right way: safely and responsibly, with respect for the environment and the communities we operate alongside.

Jorma Ollila

Chairman

We made good progress in 2012 toward improving our performance, even as we dealt with continued volatile economic conditions. We are on target to meet strategic objectives. And we are delivering the projects that form the foundation of our aim to become the world’s most competitive and innovative energy company.

Still, there is work to do. We are focused on further improving our operating performance in key areas, such as oil and gas production and internal processes that influence customer satisfaction.

Let me highlight some of 2012’s milestones and achievements. Our overall safety performance in 2012 matched that of 2011. And we continued our strong focus on ensuring our facilities are safely run and maintained. The Shell Sustainability Report has details on our safety and environmental performance.

For 2012 our earnings on a current cost of supplies basis attributable to shareholders were $27 billion. Cash flow from operating activities was $46 billion and, excluding working capital movements, was $43 billion. Net capital investment was $30 billion, as we build a solid foundation for future growth.

We produced 3.3 million barrels of oil equivalent per day in 2012, up 3% from 2011 excluding the effect of divestments and exits, with important contributions from our Pearl GTL plant in Qatar, which is now ramped up, and the Pluto LNG Project in Australia, through our participation in Woodside Petroleum Ltd. Equity LNG sales volumes of 20.2 million tonnes were up 7% compared with 2011.

In exploration, we continue to expand our portfolio, adding 120,000 square kilometres of new exploration acreage in 2012, including positions in liquids-rich shales. We participated in seven notable conventional exploration discoveries and appraisals, and 10 successful unconventional appraisals.

Harnessing innovation

We are building on our heritage as innovators and gaining public recognition for our accomplishments. Shell was one of 50 innovation leaders worldwide identified by the MIT Technology Review. We also received industry awards for our Perdido deep-water project in the Gulf of Mexico and our Prelude floating LNG project.

We continue to fine-tune our global network of technology centres to support future business opportunities. That includes increasing our capabilities in India and China. In November, we laid the foundation stone for a new technology centre in Bangalore, India, which we aim to build into a world-class technology hub.

Our Downstream business had a good operating performance for the year, with reduced levels of unplanned downtime. We continued to build on the strength of Shell’s brand in markets with growth potential. In Brazil our Raízen biofuels joint venture is making good progress. In its first full year of operation, the venture made a notable contribution to Downstream earnings. Last year we broke ground on Shell’s seventh lubricants blending plant in mainland China, to meet rising demand there. And we also announced plans to build a blending plant in Indonesia, another expanding market in Asia.

Our accomplishments in 2012 helped underpin Shell’s strong track record since 2010. Over the last three years, our earnings on a current cost of supplies basis attributable to shareholders increased by 45% and our cash flow from operating activities increased by 69%. Compared with our major competitors, over the past three years we have delivered the highest rates of growth in earnings per share and cash flow from operating activities.

Building our future

Looking to the future, the projects that will help drive growth are advancing well. We have about 30 projects under construction. We produced the first oil from the Gumusut-Kakap project off the coast of Malaysia and that will ramp up once a floating production facility is in place. We added a new development phase to our Changbei tight-gas operation in China, adding nearly 1,700 square kilometres, as well as agreeing with our partner, China National Petroleum Corporation, to potentially develop the main reservoir.

In October, we cut the first steel for the hull of our ground-breaking Prelude floating LNG project. In November, the hull for the Mars B project was completed in South Korea and shipped to Texas for installation in the Gulf of Mexico. And we took the final investment decision on the Quest carbon capture and storage project associated with our oil sands operations in Canada, which will reduce our environmental footprint. In all, we took final investment decisions on seven projects during the year.

With our progress in 2012, the growth agenda set out at the beginning of the year is on track. It includes $175-200 billion of cash flow from operating activities, excluding working capital movements, for 2012-2015, assuming the Brent oil price remains in the range of $80-100 per barrel and conditions for North American natural gas and downstream margins improve relative to 2012. It also includes net capital investment of $120-130 billion, and a competitive dividend for shareholders.

Looking further ahead, we are considering about 30 additional projects, giving us an attractive set of options for the longer term. We are now more constrained by capital than by opportunities, which allows us to focus resources where the potential for growth is greatest.

Gas leadership

Let me highlight one area where we are already industry leaders and that has great potential for the future: integrated gas projects, which include LNG and gas-to-liquids (GTL), such as our Pearl plant. Integrated gas projects contributed approximately 40% of our total earnings in 2012.

Integrated gas builds on our strengths in exploration and production, our downstream expertise in creating and marketing high-value products, and our know-how in managing huge projects. Growth will come from Australia, where we have an additional 7 million tonnes per year under construction. Longer term, we are studying projects with capacity of another 20 million tonnes per year, so there is significant growth potential.

North America is one region of opportunity. The shale gas revolution there has unlocked vast resources that provide an attractively priced feedstock. We will soon supply LNG for long-haul trucks in Canada. And we have other LNG, GTL and chemicals options on the drawing board.

In February 2013, we agreed to acquire part of Repsol S.A.’s LNG portfolio, subject to regulatory approval and other conditions precedent. This acquisition will extend our international LNG portfolio.

I expect our strength in integrated gas projects will be one of the drivers of our earnings and cash flow in the coming decades.

Strategic priorities

As we push ahead with our strategy, we have taken a fresh look at how we manage our portfolio. Going forward we are using a clear set of strategic themes to drive our choices about investment, people and innovation.

First we have our upstream and downstream ”engines”, which are mature businesses. They generate much of our cash flow. We will continue to invest to keep them running smoothly and to extract additional value.

Next we have our growth priorities, which are three areas of great opportunity for us in the years ahead, thanks to our superior technology and innovation. They are integrated gas, deep water and resources plays, such as shale oil and gas.

Finally we have future opportunities for the longer term, including the Arctic, Iraq, Kazakhstan, Nigeria, and heavy oil. We also continue to ramp up our conventional exploration activities, which we think is a cost-effective way of identifying new resources.

To conclude, we are making good progress toward our objectives. We continue to work hard to improve our operating performance. And we have clear strategic priorities to drive growth and value for our shareholders.

Peter Voser

Chief Executive Officer

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 by Shell subsidiaries and the Shell share of equity-accounted investments. 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.

Equity 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 adjusted for cash and non-current liabilities. It excludes downtime due to uncontrollable factors, such as hurricanes. This indicator is a measure of operational excellence of Shell’s Downstream manufacturing facilities.

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

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 defined as capital expenditure, adjusted for: proceeds from disposals; exploration expense excluding exploration wells written off; investments in equity-accounted investments; and leases and other items. 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 45.

Gearing is defined as net debt (total debt less 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 from Shell subsidiaries (excluding reserves attributable to non-controlling interest) and the Shell share of equity-accounted investments 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 conditions, operating methods and government regulations. 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 “Risk factors”.

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 2011 was updated from 207 to reflect completion of investigations into 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.

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

History

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.

Activities

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, China, Denmark, Germany, Malaysia, the Netherlands, Nigeria, Norway, Oman, Qatar, Russia, the UK and the USA.

We are bringing new oil and gas supplies on-stream from major field developments. We are also investing in growing our integrated gas activities. For example, our Pearl GTL plant completed its ramp-up at the end of 2012. In Downstream we seek innovative ways to market LNG, for example through the use of LNG in the transport sector.

At the same time, we are exploring for oil and gas in prolific conventional geological formations, 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 reservoirs in the USA, Australia, Canada and China, which can be developed by fracturing techniques.

We also have a focused portfolio of refineries and chemical plants. Furthermore, we are a leading biofuel producer and fuel retailer in Brazil, through our Raízen joint venture. We have a strong retail 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. A strong patent portfolio underlies the technology that we

employ in our various businesses. In total, Shell currently has more than 14,000 granted patents and pending patent applications.

Businesses

Upstream International manages the Upstream businesses outside the Americas. It explores for and recovers crude oil, natural gas and natural gas liquids, 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. Since January 2013, it manages its operations primarily by line of business, with this structure overlaying individual country organisations. This organisation is supported by activities such as Exploration and New Business Development. Previously activities were organised primarily by geographical location.

Upstream Americas manages the Upstream businesses in North and South America. It explores for and recovers crude oil, natural gas and natural gas liquids, 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 manages its operations by line of business, supported by activities such as Exploration and New Business Development.

Downstream manages Shell’s refining 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. Refining includes manufacturing, 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 CO₂ management.

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

Segmental reporting

Upstream combines the operating segments Upstream International and Upstream Americas, which have similar economic characteristics, products and services, production processes, types and classes 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.

The risks discussed below could have a material adverse effect separately, or in combination, on our operational performance, earnings, cash flows and financial condition. Accordingly, investors should carefully consider these risks.

We are exposed to fluctuating prices of crude oil, natural gas, oil products and chemicals.

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 could have a material effect. 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 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 could experience sharp increases in cost and under some production-sharing contracts our entitlement to proved reserves would be reduced. Higher prices could also reduce demand for our products. Lower demand for our products might result in lower profitability, particularly in our Downstream business.

Our ability to achieve strategic objectives depends on how we react to competitive forces.

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 could deteriorate and our unit costs may increase. This in turn could 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 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.

As our business model involves trading and treasury risks, we are affected by the global macroeconomic environment as well as financial and commodity market conditions.

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 83). As a global company doing business in more than 70 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. See Notes 6 and 21 to the “Consolidated Financial

Statements”. Shell has significant financial exposure to the euro and could be materially affected by a significant change in its value or any structural changes to the European Union (EU) or the European Economic and Monetary Union affecting the euro. 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 Shell.

Our future hydrocarbon production depends on the delivery of large and complex projects, as well as on our ability to replace proved oil and gas reserves.

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, expiration of licences 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, and in frontier areas, such as the Arctic. Such potential obstacles may impair our delivery of these projects, as well as our ability to fulfil related contractual commitments. 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, as well as developing and applying new technologies and recovery processes to existing fields and mines. Failure to replace proved reserves could result in lower future production.

An erosion of our business reputation would have a negative impact on our brand, our ability to secure new resources and our licence to operate.

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 employees and contractors, well above 100,000 in total, 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 and limit our ability to access the capital market.

Our future performance depends on the successful development and deployment of new technologies.

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 and our licence to operate may be adversely 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 that could harm our reputation, licence to operate or expose us to litigation or sanctions.

Rising climate change concerns could lead to additional regulatory measures that may result in project delays and higher costs.

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 CO₂ intensity of our production, as well as our absolute Upstream CO₂ emissions, 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 CO₂ emissions 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 CO₂ emissions 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 CO₂ emissions for new and existing projects or products, we may incur additional costs, delayed projects or reduced production in certain projects.

Moreover, continued public and political attention to climate change concerns, including existing and future regulatory frameworks to reduce greenhouse gas emissions, could result in increasing production costs, lengthening project implementation times and reducing demand for hydrocarbons.

The nature of our operations exposes us to a wide range of health, safety, security and environment risks.

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. These and other operations expose us to the risk, among others, of major process safety incidents, effects of natural disasters, social unrest, personal health and safety lapses, 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. In certain circumstances, liability could be imposed without regard to Shell’s fault in the matter. Requirements governing HSSE

matters often change and are likely to become more stringent over time. We could incur significant additional costs in the future complying with such requirements or as a result of violations of, or liabilities under, HSSE laws and regulations, such as fines, penalties, clean-up costs and third-party claims.

Shell mainly self-insures its risk exposures.

Shell insurance subsidiaries provide insurance coverage to Shell entities, generally up to $1.15 billion per event and usually 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 like 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.

An erosion of the business and operating environment in Nigeria would adversely impact Shell.

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 adverse impact on Shell’s existing and future activities in that country.

We operate in more than 70 countries, with differing degrees of political, legal and fiscal stability. This exposes us to a wide range of political developments that could result in changes to laws and regulations. In addition, Shell subsidiaries and equity-accounted investments face the risk of litigation and disputes worldwide.

Developments in politics, laws and regulations can – and do – affect our operations. Potential developments include: forced divestment of assets; expropriation of property; cancellation or forced renegotiation 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, US regulators have adopted regulations that require disclosure of information on payments to governments that we believe is immaterial to investors, but that could compromise confidential commercial arrangements and create conflicting legal requirements. EU regulators have also proposed similar regulations. 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 activities 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 that could adversely affect Shell. If we do not comply with policies and regulations, it may result in regulatory investigations, litigation and ultimately sanctions.

Our operations expose us to social instability, terrorism, acts of war, piracy and government sanctions that could have an adverse impact on our business.

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 Shell. 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. For example, EU sanctions have prohibited us from producing oil and gas in Syria, and the USA and the EU have imposed sanctions relating to transactions involving Iran and Sudan, among other countries. If such risks materialise, they could result in injuries and disruption to business activities.

We rely heavily on information technology systems for our operations.

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, aiming to prevent their recurrence. Disruption of critical IT services, or breaches of information security, could have adverse consequences for Shell.

We have substantial pension commitments, whose funding is subject to capital market risks.

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 local regulations.

The estimation of proved oil and gas reserves involves subjective judgements based on available information and the application of complex rules, so subsequent downward adjustments are possible.

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 oil and gas 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.

Many of our major projects and operations are conducted in joint ventures or associates. This may reduce our degree of control, as well as our ability to identify and manage risks.

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. Despite not having control, we could still be exposed to the risks associated with these operations. For example, 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.

Violations of antitrust and competition law carry fines and expose us or our employees to criminal sanctions and civil suits.

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.

Shell is currently subject to a Deferred Prosecution Agreement with the U.S. Department of Justice for violations of the Foreign Corrupt Practices Act.

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.

The Company’s Articles of Association determine the jurisdiction for shareholder disputes. This might limit shareholder remedies.

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.

Earnings 2012-2010

On average, 2012 realised liquids and gas prices remained stable compared with 2011. The increase in Asia-Pacific realised gas prices approximately offset the decrease in Americas realised gas prices. Average realised synthetic crude oil prices for 2012 decreased compared with 2011. Oil and gas production available for sale in 2012 was 3,262 thousand barrels of oil equivalent per day (boe/d), compared with 3,215 thousand boe/d in 2011. Excluding the impact of divestments and exits, production volumes were 3% higher than in 2011. Refining margins were generally higher in 2012 than in 2011 in key refining hubs, except Asia. This increase was driven by the closure of some refining capacity and then refinery outages later in the year, partly offset by an unfavourable economic environment and geopolitical tensions.

Earnings on a current cost of supplies basis attributable to shareholders in 2012 were $27,044 million, 6% lower than in 2011, which, in turn, were 54% higher than in 2010.

In 2012, Upstream earnings were $22,162 million, compared with $24,455 million in 2011 and $15,935 million in 2010. The 9% decrease from 2011 to 2012 reflected higher depreciation charges, increased operating and exploration expenses, lower gains associated with the fair-value accounting of certain gas and derivative contracts and additional tax charges, partly offset by higher contributions from our integrated gas activities (LNG and GTL). In 2011, earnings increased by 53% compared with 2010, reflecting higher realised oil and gas prices, together with higher equity LNG sales volumes, increased trading contributions and a reduced level of impairment, partly offset by higher operating expenses, lower production volumes and increased taxes.

Downstream earnings are presented on a current cost of supplies basis (CCS earnings). On this basis, the purchase price of the volumes sold during a period is based on the current cost of supplies during the same period, after making allowance for the tax effect. CCS earnings therefore exclude the effect of changes in the oil price on inventory valuation. Downstream earnings in 2012 were $5,350 million,

compared with $4,289 million in 2011 and $2,950 million in 2010. The 25% increase from 2011 to 2012 reflected higher realised refining margins, lower operating expenses and a reduced level of impairment. These items were partly offset by lower trading contributions, lower Chemicals earnings, lower divestment gains and lower gains associated with the fair-value accounting of commodity derivatives. Earnings increased between 2010 and 2011 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.

Balance sheet and net capital investment

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 2012. Property, plant and equipment increased by $20 billion. Net capital investment was $30 billion, 27% higher than in 2011; 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 $15 billion.

Of the 2012 net capital investment, approximately 85% related to Upstream projects, providing growth over the long term. They include multibillion dollar, integrated facilities that are expected to provide significant cash flows in the coming decades. In 2012, equity attributable to Royal Dutch Shell plc shareholders increased by $19 billion, to $188 billion, principally as a result of increased retained earnings.

Gearing was 9.2% at the end of 2012, compared with 13.1% at the end of 2011. The change reflects the increase in total equity and in cash and cash equivalents.

Market overview

We estimate that global economic growth weakened to 3.2% in 2012, down from 3.9% the previous year, largely as a result of the recession in the eurozone and a slowdown in most emerging markets. In our view, global economic growth in 2013 is estimated to be 3.4%, below the annual average of 3.8% of the last 10 years.

Within the eurozone, uncertainty and austerity measures weighed heavily on economic sentiment and consumer and business spending. In January 2013, the International Monetary Fund (IMF) projected the eurozone economy to have contracted by 0.4% in 2012. According to the same projections, growth of gross domestic product (GDP) in China slowed to 7.8% in 2012, down from 9.3% in 2011, mainly due to lower export growth and slower domestic demand growth. Other emerging economies including Brazil, Russia and India also had lower GDP growth rates. Brazil decelerated most to a rate of 1.0% in 2012, down from 2.7% in 2011. The USA was a notable exception in this environment; its GDP growth rate accelerated in 2012 to 2.3%, compared with 1.8% in 2011.

Reflecting the state of the global economy, global oil demand rose by 0.9% (0.8 million b/d) in 2012 according to the International Energy Agency December 2012 Oil Market Report. A 1.2 million b/d demand increase in emerging economies offset a decline of 0.4 million b/d in developed economies. We estimate that global gas demand grew by about 3% in 2012 with approximately two-thirds of that growth coming from countries outside the Organisation for Economic Co-operation and Development (OECD). Demand grew strongest in Asia-Pacific, the Middle East and North America, while demand in Europe contracted by an estimated 1% overall, and particularly in electricity generation.

OIL AND NATURAL GAS PRICES

The following table provides an overview of the main oil and gas price markers that Shell is exposed to:

The Brent crude oil price, the international crude-oil benchmark, traded in a range of $88-128 per barrel during 2012, ending the year at $110 per barrel. Both the Brent and the West Texas Intermediate (WTI) average crude oil prices for 2012 were little changed compared with 2011. WTI continued to trade at a significant discount to Brent due to production in the US mid-continent exceeding pipeline capacity to clear the growing volumes. This resulted in crude oil being transported to the Gulf coast by less efficient modes of transport, such as rail, depressing prices in landlocked areas, such as Cushing, Oklahoma, where WTI is delivered.

Unlike crude-oil pricing, which is global in nature, gas prices vary significantly from region to region.

In the USA, the average natural gas price at Henry Hub was 31% lower in 2012 compared with 2011, and traded in a range of $1.91-3.90 per million British thermal units (MMBtu). Domestic production increased strongly, particularly from onshore gas, which more than offset increased demand, and led to lower prices. The daily Henry Hub spot price briefly dropped below $2 per MMBtu in April following an unusually warm winter, meaning that inventories were high and production had to be discouraged. The daily price recovered to a monthly average of $2.50 per MMBtu in May, and continued to recover due to warmer than normal summer temperatures stimulating gas-fired power generation demand due to its price advantage over coal.

In Europe, prices rose. In the UK, the average price at the UK National Balancing Point was 6% higher compared with 2011. In continental Europe, price increases at the main gas trading hubs in Belgium, Germany and the Netherlands were similar to those at the UK National Balancing Point. These prices reflect a tightening of LNG markets and higher prices in Asia-Pacific. The use of oil-indexed gas pricing is decreasing in continental Europe, with many natural gas contracts now including spot market pricing as a major component.

We also produce and sell natural gas in regions whose supply, demand and regulatory circumstances differ markedly from those in the USA or Europe. Long-term contracted LNG prices in Asia-Pacific are predominantly indexed to the price of Japan Customs-cleared Crude (JCC). In Japan, LNG import contracts have historically been indexed to the JCC benchmark, as burning crude and fuel oil is the alternative option for Japanese power utilities.

OIL AND NATURAL GAS PRICES FOR INVESTMENT EVALUATION

The range of possible future crude oil and natural gas prices used in project and portfolio evaluations within Shell is determined after an assessment of short-, medium- and long-term price drivers under different sets of assumptions. Historical analysis, trends and statistical volatility are considered in this assessment, as are analyses of possible future economic conditions, geopolitics, actions by the Organization of the Petroleum Exporting Countries (OPEC), 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 affecting demand, and supply disruptions due to weather or politics, contribute to price volatility.

We expect oil and gas prices to remain volatile. For the purposes of making investment decisions, generally we test the economic performance of long-term projects against price ranges of $70-110 per barrel for Brent oil and $3-5 per MMBtu for gas at Henry Hub. As part of our normal business practice, the range of prices used for this purpose is subject to review and change, and was last updated in the fourth quarter of 2012.

REFINING AND PETROCHEMICAL MARKET TRENDS

Industry refining margins were generally higher in 2012 than in 2011 in key refining hubs, except Asia. Support for margins in 2012 came from refinery closures in North America and Europe at the beginning of the year, and from unplanned refinery outages later in the year. Some demand growth, especially around the summer holiday driving season in the USA, also contributed, although the economic environment and geopolitical tensions dampened further gains. In the USA a surge of light sweet crude supply and infrastructure bottlenecks also acted to support margins.

A key driver of refining margins in 2013 is expected to be middle distillate demand growth with some support from gasoline during the middle of the year. The overall outlook remains uncertain, with the economic environment remaining fragile, a structural overcapacity in global refining, and geopolitical tensions in some regions that could lead to supply disruptions.

Industry chemical margins in Europe and Asia during 2012 were lower than in 2011 due to declining demand in Europe and lower demand growth in Asia. US ethane cracker margins rose significantly due to increased supply of natural gas liquids, and the wide price differential between crude oil and natural gas. The outlook for petrochemicals in 2013 remains uncertain as demand is strongly correlated to economic growth.

Strategy and outlook

STRATEGY

Our strategy seeks to reinforce our position as a leader in the oil and gas industry, while helping to meet global energy demand in a responsible way. We aim to create competitive returns for shareholders. Safety and 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 that our technology, project delivery capability and operational excellence will remain key differentiators for our businesses. We expect about 80% of our capital investment in 2013 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 resources holders.

We focus on a series of strategic themes, each requiring distinctive technologies and risk management:

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, support customers in managing their energy demands, and continue 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.

OUTLOOK

We continuously seek to improve our 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 our investment on the most attractive growth opportunities. Sale of non-core assets in 2010-2012 generated $21 billion in divestment proceeds. Exits from further positions in 2013 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 profitability of our portfolio and growth potential.

In early 2012, Shell set out a new growth agenda, to deliver $175-200 billion of cash flow from operations excluding working capital movements for 2012-2015 in aggregate, some 30-50% higher than in 2008-2011. This assumes that the Brent oil price is in the range of $80-100 per barrel and conditions for North American natural gas and downstream margins improve relative to 2012. This cash flow is to finance a 2012-2015 expected net capital investment programme of $120-130 billion, an increase of some 10-20% compared with the 2008-2011 level, and fund a competitive dividend for shareholders. Shell is on track to deliver these targets.

In Upstream we have the potential to reach an average production of some 4.0 million boe/d in 2017-2018, compared with 3.3 million boe/d in 2012. Shell’s strategy in Upstream is designed to drive financial growth, with production growth regarded as a proxy for this over the long term. Our 2017-2018 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 from 2011 to 2017-2018. In Downstream we evaluate selective growth opportunities in chemicals, biofuels and growth markets.

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 these opportunities are in global exploration and established resources 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.

The statements in this Strategy and outlook section do not take into account the impact of the recently announced agreement to acquire part of Repsol S.A.’s LNG portfolio. See page 137.

The statements in this Strategy and outlook section, including those related to our growth strategies and our expected or potential future cash flow from operations, net capital investment and production, are based on management’s current expectations and certain material assumptions and, accordingly, involve risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied herein. See page 3 and “Risk factors”.

Proved reserves and production

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)”.

In 2012, Shell added 542 million boe of proved reserves before taking into account production, of which 408 million boe came from Shell subsidiaries and 134 million boe from the Shell share of equity-accounted investments. These additions were negatively impacted by lower commodity prices (431 million boe) and divestments (74 million boe).

In 2012, total oil and gas production available for sale was 1,194 million boe. An additional 40 million boe were produced and consumed in operations. Production available for sale from subsidiaries was 825 million boe with an additional 30 million boe consumed in operations. The Shell share of the production available for sale of equity-accounted investments was 369 million boe with an additional 10 million boe consumed in operations.

Accordingly, after taking into account total production, there was a decrease of 692 million boe in proved reserves, comprising 447 million boe from subsidiaries and 245 million boe from the Shell share of equity-accounted investments.

Research and development

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. We have been spending more than any other international oil and gas company to research and develop innovative technology – more than $1 billion annually since 2007. In 2012, research and development (R&D) expenses were $1,314 million, compared with $1,125 million in 2011 and $1,019 million in 2010.

Sustained investment in our key technologies continues to deliver results. In 2012, we launched new fuels and lubricant formulations

meeting specific customer needs for improved efficiency and better performance. We also began construction of what is likely to be the world’s first floating LNG facility, more than 480 metres long and six times heavier than a fully loaded aircraft carrier. The facility is designed to produce natural gas from the Prelude field offshore Australia, cool it into a liquid and pump it onto LNG tankers – all done at sea. The idea was born and developed entirely within Shell as part of an innovation-stimulating programme called GameChanger. Also in 2012, Shell committed itself to design, build and operate the world’s first commercial-scale facility to capture and store safely underground CO₂ emissions of an oil-sands project. The facility, based near Edmonton, Canada, will help develop Shell’s CO₂ capture technology.

The development of Shell technology is based on the needs of our customers and partners, and is intrinsically linked to our strategic objectives. In 2013, the key objectives of our R&D programme will remain unchanged. We will continue to focus strongly on technologies supporting our various businesses. For example: novel seismic acquisition systems that help reveal previously unnoticed geological details; methods based on the application of chemicals, heat or solvent gases to increase the amount of oil ultimately recovered from fields; and biofuels derived from non-edible plants or crop waste. We also continue to work on technologies to reduce the environmental footprint of our operations and products.

We remain committed to further shortening the time taken for technology to move from the laboratory to deployment in the field. Our technology portfolio will maintain a healthy balance of new and mature developments. That will mean an increase in the number of proposed concepts, more rapid termination of less promising projects and increasing focus on larger-scale field tests and demonstrations. Our single, integrated R&D organisation will continue to bring together in-house technology development with external scientific, engineering and commercial partnerships. Such partnering helps to ensure a healthy influx of new ideas and to speed up their realisation.

Key accounting estimates and judgements

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

Legal proceedings

Refer to Note 25 to the “Consolidated Financial Statements” for a discussion of legal proceedings.

Overview

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 high quality fuels and other products, and we market and trade natural gas (including LNG) in support of our Upstream businesses.

Business conditions

According to the International Energy Agency, oil demand in 2012 increased by 0.9% (0.8 million b/d). Demand was impacted by further weakened global economic growth in 2012, largely as a result of a recession in the eurozone and a slowdown in most emerging markets. Increased production, particularly in North America, Libya and Iraq, helped meet this demand, partly offset by a fall in supply from some Middle Eastern countries, especially Iran and Syria. The average Brent crude oil price in 2012 was $112 per barrel, slightly higher than in 2011.

Demand for gas, especially LNG, was robust in markets east of Suez. This was driven by economic growth across Asia-Pacific and nuclear power generation capacity still being offline following Japan’s natural disaster in March 2011. In Europe, gas demand was lower as a result of the ongoing recession and competition from cheap coal imports from the USA. Continued high levels of supply and warmer than normal weather at the beginning of 2012 weakened gas prices in North America by approximately 30% compared with 2011.

Earnings 2012-2011

Segment earnings of $22,162 million included a net gain of $2,137 million, mainly related to gains on divestments, partly offset by impairments for natural gas assets in the USA, net tax charges and decommissioning provisions. Segment earnings in 2011 of $24,455 million included a net gain of $3,855 million, mainly related to gains on divestments, the fair-value accounting of certain gas and derivative 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.

Compared with 2011, segment earnings, excluding the items identified above, benefited from the increased contribution of integrated gas activities (LNG and GTL), reflecting the ramp-up of the Pearl GTL plant in Qatar, higher realised LNG prices as well as increased LNG trading contributions and equity LNG sales volumes. Earnings also reflected higher realised gas prices outside the Americas. These items were more than offset by reduced contributions from the Americas, mainly as a result of higher depreciation, increased operating expenses, higher exploration expenses and lower realised gas prices.

During 2012, our earnings in the Americas were $512 million, excluding the related items identified at the beginning of the earnings section. However, our Americas onshore gas business reported a loss, mainly due to low North American gas prices, and higher depreciation and exploration costs. This was more than offset by earnings from our deep-water and heavy oil production.

Realised global liquids prices were 1% higher than in 2011. In Canada, realised synthetic crude oil prices were 11% lower than in 2011. Realised global natural gas prices were 1% higher than in 2011, with a 31% decrease in the Americas and a 9% increase outside the Americas.

In 2012, production was 3,262 thousand boe/d compared with 3,215 thousand boe/d in 2011. Liquids production was down 2% and natural gas production increased by 5% compared with 2011. Natural gas represented 50% of total production in 2012. Approximately 18% of our natural gas production in 2012 was in the Americas. Excluding the impact of divestments and exits, production volumes in 2012 were 3% higher than in 2011.

New field start-ups and the continuing ramp-up of new projects, in particular the ramp-up of the Pearl GTL plant in Qatar and the Pluto LNG plant in Australia (Shell indirect interest 20.8%), contributed some 225 thousand boe/d to production in 2012, which more than offset the impact of field declines.

Equity LNG sales volumes in 2012 were a record of 20.2 million tonnes, 7% higher than in 2011. The increase mainly came from the first full year of operations for Qatargas 4, the start-up of the Pluto LNG plant in the second quarter of 2012, and the continued strong operational performance of the Sakhalin-2 LNG plant.

Earnings 2011-2010

Segment earnings in 2011 of $24,455 million included a net gain of $3,855 million as described above. 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, the

fair-value accounting 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 continuing portfolio optimisation, higher realised oil, natural gas and LNG prices, higher equity LNG sales volumes and higher trading contributions, partly offset by higher operating expenses, mainly reflecting the start-up of new projects, lower production volumes and increased taxes.

Net capital investment

Net capital investment was $25 billion in 2012, compared with $19 billion in 2011 and $21 billion in 2010. Capital investment in 2012 was $31 billion (of which $14 billion was exploration expenditure, including acquisitions of unproved properties). Divestment proceeds were $6 billion in 2012.

Portfolio actions and business development

In Australia we increased our interest in the West Browse joint venture to 35% and in the East Browse joint venture to 25% in an exchange with Chevron for our 33.3% interest in Clio-Acme plus cash of approximately $0.5 billion.

Also in Australia we formed a joint venture (Shell interest 82%) with Nexus Energy and Osaka Gas to operate the Crux gas and condensate field.

In Norway we acquired BP’s 18.4% interest in the offshore Draugen field for a consideration of $0.2 billion. Shell is already the operator of the field and this transaction brought Shell’s interest to 44.6%.

In the UK we acquired 75% of Hess Corporation’s interests in the Beryl area fields and Scottish Area Gas Evacuation system. This transaction was completed in January 2013, increasing Shell’s production in the Beryl area fields from 9 thousand boe/d to 20 thousand boe/d.

Also in the UK we acquired Hess Corporation’s 15.7% interest in the Schiehallion field and its 12.9% interest in the Schiehallion floating production, storage and offloading (FPSO) facility for $0.5 billion. In February 2013, we also acquired an additional 5.9% interest in the offshore Schiehallion field from Murphy Schiehallion Ltd. bringing our interest in the field to 55%.

Low North American gas prices led to an accelerated shift in exploration and appraisal activities, along with production, from existing dry gas fields to those rich in liquids.

In the USA Shell acquired acreage in the Delaware Permian Basin, West Texas, from Chesapeake Energy Corporation for an announced consideration of $1.9 billion. The acreage of approximately 2,200 square kilometres, with an additional 300 square kilometres linked to contractual conditions, is expected to be rich in oil and natural gas liquids and currently produces approximately 26 thousand boe/d with growth potential.

We also took the following final investment decisions during 2012.

In Nigeria we took the final investment decision on the Forcados Yokri Integrated Project (Shell interest 30%) and the Southern Swamp Associated Gas Gathering Project (Shell interest 30%). These projects are expected to produce at peak production approximately 90 thousand boe/d and 85 thousand boe/d respectively, and reduce flaring intensity.

In Italy we took the final investment decision on the onshore Tempa Rossa field (Shell interest 25%) in the Basilicata region. This project is expected to produce approximately 45 thousand boe/d at peak production.

In Malaysia we took the final investment decision for the development of the Malikai deep-water oil field, part of the Block G PSC (Shell interest 35%), offshore Sabah. The Shell-operated project is expected to produce approximately 60 thousand boe/d at peak production.

In Canada we took the final investment decision on the Quest carbon capture and storage project (Shell interest 60%) near Edmonton, Alberta. The Quest project is expected to capture and store deep underground more than 1 mtpa of CO₂ produced in bitumen processing, and reduce direct emissions from the Scotford Upgrader by up to 35%.

We continued to divest selected Upstream assets during 2012, including our 40% participating interest in the BS-4 oil and gas exploration block in the Santos Basin offshore Brazil; our interest in the Gassled natural gas transport infrastructure joint venture in Norway; our 30% interest in oil mining leases 30, 34 and 40 in the Niger Delta, Nigeria; our 50% interest in the Holstein field in the Gulf of Mexico; and our interest in the Seal area within the Peace River oil sands of Alberta, Canada. Also in Canada, we sold a 20% interest in our Groundbirch tight-gas project. In Australia we completed the sale of a 17.5% interest in the Prelude FLNG project to INPEX, and a 10% interest to KOGAS. We also completed the sale of a further 5% interest to CPC Corporation in the first quarter of 2013.

Available-for-sale production

In 2012, hydrocarbon production from new start-ups and the continuing ramp-up of new projects more than offset the impact of field declines, and the impact of divestments and exits. There was also further upside from new wells and improved reliability compared with 2011, partly offset by changes in contractual entitlements and other non-operational factors.

Production growth was mainly driven by the continued ramp-up of new projects, notably our Pearl GTL plant in Qatar, the start-up of the Pluto LNG Project in Australia, and the first full year of production from Qatargas 4. Further additions also came from new start-ups such as Harweel in Oman, and the early first production from Gumusut-Kakap in Malaysia.

In Qatar we achieved full GTL production at our Pearl GTL plant at the end of the fourth quarter of 2012, with both trains reaching 90% of capacity. This completed the ramp-up period for this project. The plant is designed to run at sustained operating rates of 90% or higher.

In Malaysia the Gumusut-Kakap field, located about 120 kilometres offshore Sabah, began a phase of early production via the Murphy Sabah Oil operated Kikeh production facility. A dedicated floating production system is currently under construction for the Gumusut-Kakap field (Shell interest 33%), which is Shell’s first deep-water opportunity in the country, and is expected to produce approximately 135 thousand boe/d at peak production.

In the USA first production was achieved at the Caesar/Tonga deep-water project (Shell interest 22.5%) in the Gulf of Mexico. At peak production, the project is expected to produce approximately 40 thousand boe/d.

In Oman production began at the Harweel Enhanced Oil Recovery project, which is expected to produce approximately 30 thousand boe/d at peak production.

Proved reserves

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)”.

In 2012, Shell added 542 million boe of proved reserves before taking into account production, of which 408 million boe came from Shell subsidiaries and 134 million boe from the Shell share of equity-accounted investments.

The change in the yearly average commodity prices between 2011 and 2012 resulted in a net negative impact on the proved reserves of 431 million boe.

Shell subsidiaries

Before taking into account production, Shell subsidiaries added 408 million boe of proved reserves in 2012. This comprised 655 million barrels of oil and natural gas liquids and a reduction of 247 million boe (1,431 thousand million scf) of natural gas. Of the 408 million boe: 268 million boe were from the net effects of revisions and reclassifications; a net decrease of 69 million boe related to acquisitions and divestments; 196 million boe came from extensions and discoveries; and 13 million boe were from improved recovery.

After taking into account production of 855 million boe (of which 30 million boe were consumed in operations), Shell subsidiaries’ proved reserves decreased by 447 million boe in 2012.

Shell subsidiaries’ proved developed reserves increased by 19 million boe to 6,502 million boe, while proved undeveloped reserves decreased by 466 million boe to 3,371 million boe.

The total addition of 408 million boe before taking into account production included a net negative impact from commodity price changes of 438 million boe of proved reserves.

SYNTHETIC CRUDE OIL

As part of the total proved reserves’ addition of 542 million boe, we added 131 million barrels to our synthetic crude oil proved reserves. In 2012, we had synthetic crude oil production of 48 million barrels of which 2 million barrels were consumed in operations. At December 31, 2012, we had total synthetic crude oil proved reserves of 1,763 million barrels, of which 1,271 million barrels were proved developed reserves and 492 million barrels were proved undeveloped reserves.

BITUMEN

As part of the total proved reserves’ addition of 542 million boe, we added 1 million barrels of bitumen proved reserves. After taking into account production of 7 million barrels, bitumen proved reserves were 49 million barrels at December 31, 2012.

Shell share of equity-accounted investments

Before taking into account production, there was an increase of 134 million boe in the Shell share of equity-accounted investments’ proved reserves in 2012. This comprised 91 million barrels of oil and natural gas liquids and 43 million boe (248 thousand million scf) of natural gas. Of the 134 million boe: 129 million boe were from the net effects of revisions and reclassifications; a net decrease of 5 million boe related to acquisitions and divestments; 7 million boe came from extensions and discoveries; and 3 million boe were from improved recovery.

After taking into account production of 379 million boe (of which 10 million boe were consumed in operations), the Shell share of equity-accounted investments’ proved reserves decreased by 245 million boe in 2012.

The Shell share of equity-accounted investments’ proved developed reserves decreased by 5 million boe to 3,002 million boe, and proved undeveloped reserves decreased by 240 million boe to 699 million boe.

The total addition of 134 million boe before taking into account production included a net positive impact from commodity price changes of 7 million boe of proved reserves.

Proved undeveloped reserves

In 2012, Shell subsidiaries’ and the Shell share of equity-accounted investments’ proved undeveloped reserves (PUD) decreased by 706 million boe to 4,070 million boe. This is the result of additions of 122 million boe of new PUD offset by the maturation of 828 million boe of PUD to proved developed reserves through project execution. During 2012, Shell spent $9.3 billion on development activities related to PUD maturation.

Proved undeveloped reserves held for five years or more (PUD5+) at December 31, 2012, were 1,012 million boe. These 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, the Netherlands, Nigeria, Norway, the Philippines 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 in 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.

Delivery commitments

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 period 2013 to 2015, Shell is contractually committed to deliver to third parties and equity-accounted investments a total of approximately 4,600 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.

The shortfall between Shell’s delivery commitments and its proved developed reserves is estimated at 24% 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.

Exploration

During 2012, Shell participated in seven notable conventional exploration discoveries and appraisals in Australia, Brazil, Malaysia, Nigeria and the USA, and 10 notable successful unconventional appraisals in Australia, Canada, China, and the USA.

In 2012, Shell participated in 230 productive exploratory wells with proved reserves allocated (Shell share: 168 wells). See page 155 for further information.

In 2012, Shell participated in a further 314 wells (Shell share: 214 wells) that remained pending determination at December 31, 2012.

In 2012, Shell added acreage to its exploration portfolio mainly from new licences in Albania, Australia, Benin, Canada, China, Malaysia, New Zealand, Russia, South Africa, Tanzania, the UK and the USA.

In total, Shell secured rights to 120,000 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, China, Egypt, Germany, Italy, New Zealand, Norway and Tanzania).

Business and property

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:

EUROPE

Denmark

We hold a non-operating 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 reduced to 36.8% from 46% in July 2012, when the government entered the partnership with a 20% interest and the government profit share of 20% was abolished.

Ireland

We are the operator of the Corrib Gas project (Shell interest 45%), which is currently at an advanced stage of construction. At peak production, Corrib is expected to supply a significant proportion of the country’s natural gas needs.

The Netherlands

Shell and ExxonMobil are 50:50 shareholders in Nederlandse Aardolie Maatschappij B.V. (NAM), the largest hydrocarbon producer in the Netherlands. An important part of NAM’s gas production comes from the onshore Groningen gas field, in which the Dutch government has a 40% interest, with NAM holding the remaining 60%. NAM also has a 60% interest in the Schoonebeek oil field, which has been redeveloped using enhanced oil recovery technology. NAM also operates a significant number of other onshore gas fields and offshore gas fields in the North Sea.

Norway

We are a partner in more than 20 production licences on the Norwegian continental shelf and are the operator in six of these, including the Ormen Lange gas field (Shell interest 17%) and the Draugen oil field, where we increased our interest to 44.6%. We have interests in the Troll, Gjøa, and Kvitebjørn fields, and have further interests in the Valemon field development and various other potential development assets.

United Kingdom

We operate a significant number of our interests on 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. We hold various non-operated interests in the Atlantic Margin area, principally in the West of Shetlands area. We have increased our interest in the non-operated Schiehallion field to 55%, and in the Beryl area fields, with interests ranging from 25% to 66%.

Rest of Europe

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

ASIA (INCLUDING THE MIDDLE EAST AND RUSSIA)

Brunei

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 Asia-Pacific, and sells most of its LNG on long-term contracts to customers in Asia.

We are the operator for the Block A concession (Shell interest 53.9%), which is under exploration and development. We have a 35% interest in the Block B concession, where gas and condensate are produced

from the Maharaja Lela Field. In addition, we have a 12.5% interest in exploration Block CA-2 under a PSC.

China

We operate the onshore Changbei tight-gas field under a PSC with PetroChina. The PSC was amended in July 2012 for developing tight gas in different geological layers of the same block.

Shell and PetroChina have also agreed to appraise, develop and produce tight gas in the Jinqiu block under a PSC that expires in 2040 (Shell interest 49%) and signed a PSC in March 2012 for shale-gas exploration, development and production in the Fushun Yongchuan block (Shell interest 49%), both in Sichuan. Shell and PetroChina are also assessing opportunities in coalbed methane in the Ordos Basin.

In 2012, Shell became a party to the Zitong PSC for tight gas exploration, development and production in Sichuan (Shell interest 44.1%).

Shell has agreed with Chinese National Offshore Oil Corporation to appraise and potentially develop two offshore oil and gas blocks in the Yinggehai Basin under a PSC signed in July 2012 (Shell interest 49%).

Indonesia

We have a 30% participating interest in the offshore Masela block where INPEX Masela is the operator. The Masela block contains the Abadi gas field. The operator has currently selected a floating LNG (FLNG) concept for the field’s first development phase.

Iran

Shell transactions in Iran are disclosed in accordance with Section 13(r) of the US Securities Exchange Act of 1934. See page 51.

Iraq

We have a 45% interest in the Majnoon oil field that we operate under a technical service contract that expires in 2030. The other Majnoon shareholders are PETRONAS (30%) and the Iraqi government (25%), which is represented by the Missan Oil Company. Majnoon is located in southern Iraq and is one of the world’s largest oil fields. The first phase of the development is planned to bring production to approximately 175 thousand b/d from the level of 45 thousand b/d when the contract entered into effect in March 2010. We also have a 15% interest in the West Qurna 1 field. At the end of 2012, production was approximately 460 thousand b/d. According to the provisions of both contracts, Shell’s equity entitlement volumes will be lower than the Shell interest implies.

In 2012, Shell continued to work in establishing Basrah Gas Company, a joint venture between Shell (44%), South Gas Company (51%) and Mitsubishi Corporation (5%). The Basrah Gas Company 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 liquefied petroleum gas (LPG), will be sold primarily to the domestic market with the potential to export any surplus.

Kazakhstan

We have a 16.8% interest in the offshore Kashagan field, where the North Caspian Operating Company is the operator. 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 approximately 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. First production is expected in 2013.

We have an interest of 55% in the Pearls PSC, covering an area of approximately 900 square kilometres located in the Kazakh sector of the Caspian Sea that includes two oil discoveries (Auezov and Khazar) and several exploration prospects.

Malaysia

We produce oil and gas located offshore Sabah and Sarawak under 19 PSCs, in which our interests range from 30% to 85%.

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 SB1 PSC (the latter expired at the end of December 2012). We also have additional interests ranging from 30% to 50% in PSCs for the exploration and development of five deep-water blocks. These include the Gumusut-Kakap deep-water field (Shell interest 33%) and the Malikai field (Shell interest 35%). Both these fields are currently being developed with Shell as the operator. We started production from Gumusut-Kakap in November 2012, ahead of completion of a floating production system. We did this by connecting two wells to the Kikeh production facility, which is operated by Murphy Sabah Oil. We also have a 21% interest in the Siakap North-Petai field and a 30% interest in the Kebabangan field.

In Sarawak we are the operator of 20 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 2012, we signed five new exploration PSCs: Deepwater Block 2B, SK318, SK319 and SK408, all offshore Sarawak, and SB311, offshore Sabah.

We also operate a GTL plant (Shell interest 72%), which is adjacent to the Malaysia LNG facilities in Bintulu. Using Shell technology, the plant converts natural gas into high-quality middle distillates, drilling fluids, waxes and other speciality products.

Oman

We have a 34% interest in Petroleum Development Oman (PDO), the operator of an oil concession expiring in 2044. In 2012, production began at its Harweel Enhanced Oil Recovery project, which is expected to produce approximately 30 thousand boe/d at peak production.

We are also participating 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 facility.

Qatar

Pearl in Qatar is the world’s largest GTL plant. Shell operates the plant under a development and production-sharing contract with the government of Qatar. The fully integrated facility includes production, transport and processing of approximately 1.6 billion scf/d of well-head gas from Qatar’s North Field with installed capacity of about 140 thousand boe/d of high-quality liquid hydrocarbon products and 120 thousand boe/d of NGL and ethane. Ramp-up of the project was completed in the fourth quarter of 2012. The plant

delivered its 100th cargo in mid-December and produced GTL Jet fuel, with its first commercial market introduction in January 2013.

We have a 30% interest in Qatargas 4, which comprises integrated facilities to produce approximately 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 NGL. The train delivered its first LNG in 2011 and has been operating at full capacity in 2012. The LNG is shipped mainly to markets in North America, China, Europe and the United Arab Emirates.

We are the operator of Block D under the terms of an exploration and production-sharing contract with Qatar Petroleum, representing the national government. We have a 75% interest, with PetroChina holding the remaining 25% interest.

Russia

We have a 27.5% interest in Sakhalin-2, one of the world’s largest integrated oil and gas projects. Located in a subarctic environment, the project produced approximately 335 thousand boe/d in 2012. Following optimisation of the LNG plant, production from its two trains exceeded 10 million tonnes in 2012.

We have a 50% interest in the Salym fields in western Siberia, where production was approximately 155 thousand boe/d during 2012.

We also have a 100% interest in four exploration and production licences. They are for the East Talotinskiy area in the Nenets Autonomous District, the Barun-Yustinsky block in Kalmykia and the Arkatoitsky and the Lenzitsky blocks in the Yamalo Nenets Autonomous District. We also have an exploration licence in the North-Vorkutinsky area in the Komi Republic.

United Arab Emirates

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.

Rest of Asia (including the Middle East and Russia)

Shell also has interests in India, Japan, Jordan, Kuwait, the Philippines, Saudi Arabia, Singapore, South Korea and Turkey. We suspended all exploration and production activities in Syria in December 2011.

OCEANIA

Australia

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 23% in Woodside Petroleum Ltd (Woodside). All interests in Australian assets quoted below are direct interests.

Woodside is the operator of the Pluto LNG Project which produced its first LNG in 2012. Woodside is also the operator on behalf of six joint-venture participants of the NWS gas, condensate and oil fields, which produced more than 470 thousand boe/d in 2012. Shell provides technical support for the NWS development.

We 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 January 2012, Arrow completed the acquisition of coalbed methane company Bow Energy Ltd (Shell-share consideration $0.3 billion).

We have a 25% interest in the Gorgon LNG project, which involves the development of some of the largest gas discoveries to date in Australia, beginning with the offshore Gorgon (Shell interest 25%) and Jansz-lo (Shell interest approximately 20%) fields. It includes the construction of a 15.3 mtpa LNG plant on Barrow Island.

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. We are developing these fields on the basis of our innovative

FLNG technology. The Prelude FLNG project is expected to produce about 110 thousand boe/d of natural gas and NGL, delivering approximately 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG. During 2012, we commenced construction of the Prelude FLNG project and completed the sale of a 17.5% interest to INPEX and a 10% interest to KOGAS. We also completed the sale of a 5% interest to CPC Corporation in the first quarter of 2013, reducing our interest to 67.5%.

We formed a joint venture to operate the Crux gas and condensate field (Shell interest 82%). We also operate the AC/P41 block (Shell interest 75%).

We are also a partner in the Browse joint ventures covering the Brecknock, Calliance and Torosa gas fields. During 2012, we increased our interest in the West Browse joint venture to 35% and in the East Browse joint venture to 25%. The Browse resources are being assessed for development on the basis of an LNG export project.

In the Timor Sea we have a 26.6% interest in the Sunrise gas field. 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 is a partner in both Shell-operated and non-operated exploration joint ventures in multiple basins including the Bonaparte, Exmouth Plateau, Greater Gorgon, Outer Canning and South Exmouth.

We also have a 6.4% interest in the Wheatstone LNG project, which includes the construction of two LNG trains with a combined capacity of 8.9 mtpa.

Rest of Oceania

Shell also has interests in New Zealand.

AFRICA

Nigeria

Shell-share production in Nigeria was approximately 365 thousand boe/d in 2012 compared with approximately 385 thousand boe/d in 2011. Security, crude oil theft and flooding in the Niger Delta were significant challenges in 2012.

Onshore The Shell Petroleum Development Company of Nigeria Ltd (SPDC) is the operator of a joint venture (Shell interest 30%) that holds more than 25 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 Modified Carry Agreements are being reimbursed, and in

December 2012 NNPC repaid the bridge loan with interest. New financing agreements with NNPC are under discussion and are expected to be put in place during 2013.

We have a 30% interest in the Gbaran-Ubie integrated oil and gas project in Bayelsa State, which delivered 0.9 billion scf/d of gas in 2012. Gas from Gbaran-Ubie is delivered to Nigeria LNG Ltd (NLNG) for export. In October 2012, SPDC declared force majeure on gas supplies, as a result of a security incident on the Bomu-Bonny trunkline and rain flooding. This force majeure was lifted the following month and the impact on SPDC gas production was very limited.

In 2012, we sold our 30% interests in OMLs 30, 34 and 40 for a consideration of $1.1 billion.

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

SPDC also 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 the EA field, in one of the disputed leases, continued throughout 2012.

LNG Shell has a 25.6% interest in NLNG, which operates six LNG trains with a total capacity of 22.0 mtpa. NLNG continued production near full capacity during 2012.

Rest of Africa

Shell also has interests in Benin, Egypt, Gabon, Ghana, Libya, South Africa, Tanzania and Tunisia.

NORTH AMERICA

Canada

We hold more than 2,200 mineral leases in Canada, mainly in Alberta and British Columbia. We produce and market natural gas, NGL, synthetic crude oil and bitumen. In addition, we hold significant exploration acreage offshore. Bitumen is a very heavy crude oil produced through conventional methods as well as through enhanced oil-recovery methods. 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 feedstocks for refineries.

Gas and liquids-rich shale We hold rights to more than 10,000 square kilometres of conventional gas, tight gas and liquids-rich shale acreage. We own and operate four natural gas processing and sulphur-extraction plants in southern and south-central Alberta. We continued to develop conventional gas, tight gas and liquids-rich shale fields in west-central Alberta and east-central British Columbia during 2012, through drilling programmes and investment in infrastructure facilitating new production.

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 AOSP’s bitumen production capacity is 255 thousand boe/d. The bitumen is transported by pipeline for processing at the Scotford Upgrader, which is operated by Shell and located in the Edmonton area, Alberta. The first phase of the AOSP debottlenecking

project comes online in 2013, and is expected to add an additional 10 thousand boe/d at peak production. We also took the final investment decision on the Quest carbon capture and storage project (Shell interest 60%), which is expected to capture and permanently store more than 1 mtpa of CO₂ from the Scotford Upgrader.

Shell also holds a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2018 to 2025. 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 approximately 1,200 square kilometres in the Grosmont oil sands area, also in northern Alberta.

Offshore We have a 31.3% interest in the Sable Offshore Energy project, a natural-gas complex offshore eastern Canada. We also have a 100% operating interest in frontier deep-water acreage offshore Nova Scotia, a 20% non-operating interest in an exploration asset off the east coast of Newfoundland, and a number of exploration licences in the Mackenzie Delta in the Northwest Territories.

United States of America

We produce oil and gas in the Gulf of Mexico, heavy oil in California and primarily tight gas and associated liquid hydrocarbons 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 in the USA, accounting for almost 50% of Shell’s oil and gas production in the country. We have approximately 420 federal offshore leases in the Gulf of Mexico, about one-fifth of which are producing. Our share of production in the Gulf of Mexico averaged almost 190 thousand boe/d in 2012. Key producing assets are Auger, Brutus, Enchilada, Mars, NaKika, Perdido, Ram-Powell and Ursa.

Deferments resulting from the 2010 drilling moratorium, delivery of new-build drilling rigs and new regulatory requirements continued to affect the operational flexibility and delivery timing of our Gulf of Mexico activities in 2012. While the new regulatory regime has resulted in a longer and more complex permitting process, Shell continues to meet all deep-water regulatory permitting and environmental assessment requirements. Despite these challenges, we continued to grow our presence in the Gulf of Mexico, with the addition of two drilling rigs to our contracted offshore fleet in 2012. We also secured 24 blocks in the 2012 central lease sale for a sum of $400 million.

Onshore We hold more than 15,000 square kilometres of tight-gas and liquids-rich shale acreage. This includes significant holdings in the Marcellus shale, centred on Pennsylvania in north-east USA, the Eagle Ford shale formation in south Texas, the Sand Wash and Niobrara Shale in north-west Colorado, as well as the Mississippi Line in south-central Kansas. In 2012, we also acquired approximately 2,200 square kilometres of mineral rights, with an additional

300 square kilometres linked to contractual conditions, in the Delaware Permian Basin in west Texas.

California We have a 51.8% interest in Aera Energy LLC (Aera), which holds assets in the San Joaquin Valley and Los Angeles Basin areas of southern California. Aera operates more than 15,000 wells, producing approximately 130 thousand boe/d of heavy oil and gas.

Alaska We hold more than 410 federal leases for exploration in the Beaufort and Chukchi seas in Alaska. During the 2012 drilling season, we drilled two exploratory wells, one each in the Beaufort and Chukchi seas. These wells are known as top holes as they do not go deep enough to reach hydrocarbon reservoirs. After drilling they were safely capped in accordance with regulatory requirements.

Rest of North America

Shell also has interests in Greenland and Mexico.

SOUTH AMERICA

Brazil

We are the operator of several producing fields offshore Brazil. They include the Bijupirá and Salema fields (Shell interest 80%) and the BC-10 field (Shell interest 50%). We also operate one offshore exploration block in the Santos Basin, BMS-54 (Shell interest 80%). We have interests in two offshore exploration blocks in the Espirito Santo basins, BMES-23 and BMES-27, with a 20% and 17.5% interest respectively. Shell also operates five blocks in the São Francisco onshore basin area. In 2012, we divested our 40% interest in the offshore Block BS-4 in the Santos Basin.

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

French Guiana

We are the operator of an exploration block in the 24,000 square kilometres deep-water Guyane Maritime Permit (Shell interest 45%).

Rest of South America

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

TRADING

We market a portion of our share of equity production of LNG and also trade LNG volumes around the world through our hubs in Dubai, the Netherlands and Singapore. We also market and trade natural gas, power and emission rights in the Americas and Europe.