The Royal Dutch Shell plc Annual Report and Form 20-F (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, 2013, for Royal Dutch Shell plc (the Company) and its subsidiaries (collectively referred to as Shell). This Report presents the Consolidated Financial Statements of Shell (pages 101-139), the Parent Company Financial Statements of Shell (pages 162-170) and the Financial Statements of the Royal Dutch Shell Dividend Access Trust (pages 175-178). Cross references to Form 20-F are set out on pages 2-3 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 exposure or rights to their variable returns and the ability to affect those returns through its power over the companies. The Consolidated Financial Statements consolidate the financial statements of the Company and all subsidiaries. Companies over which Shell has joint control are generally referred to as “joint ventures” and companies over which Shell has significant influence but neither control nor joint control are referred to as “associates”. 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 are in respect of subsidiaries only, without deduction of any 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 subsidiaries, joint ventures and associates. 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 joint ventures and associates, 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.

This Report contains 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”, “schedule”, “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) 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 addressing climate change; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. Also see “Risk factors” for additional risks and further discussion. All forward-looking statements contained in this Report are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of this Report. Neither the Company nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this Report.

This Report contains references to Shell’s website 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.

Shell has the ability to take a long-term view in an industry where this is vital, and in a world where energy demand will continue to rise. In 2013, we maintained our strategy amid economic uncertainty. However, our results were disappointing, and we must improve our financial returns and operational effectiveness.

The global economic recovery remains fragile, especially in the eurozone. The global growth rate in 2013 was 3.0%, little changed from 3.1% in 2012, according to estimates by the International Monetary Fund. The Brent crude oil price averaged $109 per barrel in 2013, which was similar to the previous year.

Meanwhile, we faced a difficult operating environment. But there was also room for sharpening Shell’s financial and operational performance, and we have made this a major priority for the year ahead. We will also put particular emphasis on improving our capital discipline and the process through which our capital allocation decisions are taken, implemented and followed up.

Nevertheless, Shell’s underlying strategy is robust. With a stronger emphasis on improving financial returns and cash flow in 2014 and beyond, it aims to deliver competitive returns including a growing dividend.

Our investment programme is underpinned by a sound balance sheet, which is strong enough to withstand volatile energy prices and revenues. It is also flexible enough to underpin billions of dollars of investment in new energy sources. Of course, we must balance this investment with a prudent financial framework, generating the cash to invest in new projects and providing shareholders with an attractive return.

With global energy demand expected to grow strongly in the decades ahead, I am confident that this strategy – of long-term investment in new supplies, and a sharper focus on shareholder returns – is the right one.

Global primary energy demand is set to grow by between 30% and 40% by 2035, according to projections by the International Energy Agency published in its World Energy Outlook 2013. Large numbers of people in emerging economies are expected to benefit from higher incomes, and the world’s population will continue to expand, increasing total energy consumption.

TAKING A LONG-TERM VIEW

That is why Shell has maintained a long-term approach. To help meet the world’s rising energy needs, we have continued to invest in new supplies, in technology and in our people.

When it comes to developing new energy supplies, integrated gas remains a core priority. In particular, global demand for liquefied natural gas (LNG) is set for strong growth, as more governments around the world recognise the environmental advantages of gas-fired power. When used to replace coal, gas can sharply reduce emissions of pollutants such as nitrogen oxides and particulates, as well as CO₂. This can make a real difference, especially in Asia’s rapidly expanding cities.

TECHNOLOGY AND INNOVATION

At Shell, we have also continued to develop our technological capabilities. In an increasingly tough industry landscape, this is critical to our competitiveness. In 2013, we saw many positive developments. In December, together with our partners, including operator Petrobras, we signed a production-sharing contract for the giant Libra oil field off the coast of Brazil. It will be a great opportunity for us to showcase our deep-water expertise in one of the biggest deep-water fields in the world.

Work is under way in South Korea’s shipyards to build a floating LNG (FLNG) facility that uses Shell’s technology. It will allow us to tap the Prelude gas field more than 200 kilometres off Australia’s north-west coast and to process, store and transfer LNG at sea. When built, it will be the world’s largest offshore structure, with a hull measuring nearly half a kilometre in length. The technology will allow us to open up gas fields previously seen as too remote or small.

INVESTING IN OUR PEOPLE

Shell’s projects, of course, are only as effective as the people who build and maintain them. It was another year in which we invested heavily in recruiting and training the right people. For example, we hired around 1,200 graduates in 2013. We also continued to equip our employees with the technical and operational skills to build and manage difficult projects. For instance, we opened a centre in Sarawak, Malaysia, that aims to train well operators to the highest operational and safety standards. The hub is the first of its kind in Asia, and its training programmes are open to professionals from across the region and from other companies. The centre will help Malaysia and other Asian countries tap their oil and gas resources safely, including those trapped in deep waters.

These are just some examples of how, despite an uncertain and challenging environment, continuing to invest in the future will bring rewards for Shell, our customers and partners, and, of course, our investors.

Jorma Ollila

Chairman

For Shell, 2013 proved to be a challenging year, in part due to a complex and difficult operating environment.

We faced a deteriorating security situation in Nigeria. In Downstream, refining margins in Asia and Europe were depressed by an oversupply of global refining capacity and lower demand.

There were also areas where we as a company could have been more competitive, including our day-to-day operational performance and our capital efficiency. Some of our businesses demonstrated outstanding operational and financial performance. The reality, however, is that several operated below their full potential in 2013. Our overall performance was frankly not what I expect from Shell.

Our strategy remains robust, but 2014 will signal a change of emphasis. We will concentrate on improving returns and cash flow performance, with a focus on three main priorities:

2013 MILESTONES

Let me first comment on some of the milestones of 2013. Our overall safety performance improved as we maintained a strict focus on running and maintaining our operations safely. The Shell Sustainability Report details our safety and environmental performance.

For 2013, our earnings on a current cost of supplies basis attributable to shareholders were $17 billion, compared with $27 billion in 2012. Net cash flow from operating activities also fell, to $40 billion from $46 billion in 2012. However, our combined net cash flow from operating activities in 2012 and 2013 marked a 35% increase compared with 2010 and 2011, as new large-scale projects such as Pearl GTL made a significant contribution. Capital investment totalled $46 billion, including $8 billion of acquisitions.

We produced 3.2 million barrels of oil equivalent a day (boe/d) in 2013. Sales of liquefied natural gas (LNG) totalled 19.6 million tonnes. Both were lower than the previous year, mainly due to the difficult operating environment in Nigeria.

Underlining our commitment to shareholder returns, in 2013 we distributed more than $11 billion to shareholders in dividends – including those taken as shares under our Scrip Dividend Programme – and spent $5 billion on share repurchases. This compares with $11 billion of dividends and $1 billion of share repurchases in 2012.

IMPROVING OUR FINANCIAL PERFORMANCE AND CAPITAL EFFICIENCY

Looking ahead, our first goal is to improve our competitive financial performance, increasing the value we obtain from the capital entrusted to us by our shareholders.

In the year to come, we will reduce our capital spending. In 2014, we expect total capital spending of around $37 billion, a reduction of $9 billion compared with 2013, as we moderate our growth ambitions and strive to improve our free cash flow and returns.

We have also embarked on a fresh programme of asset sales, refocusing our capital and technology on the areas that will deliver sustained profits and cash flow. In 2014 and 2015, our total divestments across the company could total some $15 billion.

In 2013, for example, we announced our intention to divest several positions in tight-gas and liquids-rich shale in North America. And in early 2014, we agreed to sell our stake in an Australian gas project, Wheatstone LNG, while staying focused on our bigger investments in the country, which is emerging as a major supplier of energy to the world.

In our Downstream business, we are also streamlining our portfolio. For example, in 2013 we agreed to sell our stake in a refining business in the Czech Republic. In February 2014, we agreed to sell the majority of our downstream activities in Italy and Australia, subject to the deal completing. We are also in the process of divesting a refinery in Germany. Throughout 2014, we will continue to make tough decisions about our portfolio.

Better operational performance is another critical step to shareholder returns. I want to see continuous improvement in our execution, including the day-to-day work of delivering our projects consistently.

THE NEXT PHASE OF GROWTH: PROJECT DELIVERY

Despite disappointing financial results, 2013 was also a year in which we laid firm foundations for the future, bringing projects to fruition that will underpin our ability to deliver increasing cash flow through economic cycles and competitive returns including a growing dividend.

In 2014, we will strive to build on our track record of delivering new projects. And we will continue to use a clear set of strategic themes to guide decisions about investment and technology.

To recap, we have our upstream and downstream “engines”. These are mature businesses that generate the bulk of our cash flow. Then there are our growth priorities, integrated gas and deep water. These play to our strengths in technology, and will afford significant opportunities in the years ahead. Finally, we have opportunities for the longer-term, including gas and oil in tight rock and shale, heavy oil, and in the Arctic, Iraq, Kazakhstan, and Nigeria.

In 2013, we made strong progress against many of these strategic priorities. In total, we took nine final investment decisions on large projects across all areas of our business during the year.

We also delivered several important new projects. In Downstream, for example, we took further steps to meet growing long-term demand for chemical and lubricant products in Asia’s growth markets. In China, we opened a grease manufacturing plant, while in Singapore we decided to expand our Jurong Island petrochemicals plant.

Our portfolio of deep-water oil and gas projects went from strength to strength. In Brazil, we bid successfully with partners for the Libra field, and started production at the second phase of Parque das Conchas (BC-10), which Shell operates and which is one of the world’s most challenging deep-water projects. We also took the final investment decision to develop a third phase at Parque das Conchas (BC-10).

We had exploration success in the deep waters of the Gulf of Mexico, with our Vicksburg exploratory well making a notable oil discovery. Also in the Gulf of Mexico, we worked towards the start of production in early 2014 at our new Mars B development. Peak production is expected to be 100,000 boe/d. It will extend the life of the Mars field, first discovered by Shell in 1989, to around 2050.

We expect to make further advances in our deep-water portfolio. For example, with our partners, we expect to begin production via a dedicated floating production system from the Gumusut-Kakap field offshore Malaysia in 2014.

With demand for LNG set for rapid growth, we moved to strengthen our leadership position within the industry. In January 2014, we completed the purchase from Repsol of new LNG positions in the Atlantic and Pacific regions, increasing Shell’s worldwide equity LNG capacity by around one-fifth.

There were also significant developments in Iraq, including at the Majnoon field, one of the world’s largest oil fields. With our partners, we reached commercial production. We also began operations at the Basrah Gas Company, the biggest natural gas project in the country’s history, as well as the world’s largest flare-reduction project. It captures gas that is being flared from three oil fields in southern Iraq.

In 2014, we will make hard decisions about our next phase of projects. Capital discipline and potential returns will be critical factors in deciding which to take forward to development.

In Alaska, we decided to suspend our exploration programme for 2014 following a court ruling against a government department. The ruling raised obstacles to offshore drilling there.

From 2014, tight-gas and liquids-rich shale will have a different role in our strategy. We now see them as an opportunity for the longer term rather than the immediate future. We are reducing the number of these opportunities in our North American portfolio as we strive to improve our financial performance.

We are responding to our disappointing results for 2013 with a renewed focus on competitive financial performance and capital efficiency, while maintaining our strong record of project delivery. I am satisfied our strategy is sound and we will continue to invest in new projects. These will not only be the foundation of our future competitiveness, but also help to supply the world’s growing energy needs.

Ben van Beurden

Chief Executive Officer

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 for strong operational performance and productive investments in countries around the world including 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, in February 2013 we agreed to buy part of Repsol S.A.’s liquefied natural gas (LNG) portfolio, including supply positions in Peru, and Trinidad and Tobago. This acquisition was completed in January 2014. Our Downstream integrated gas activities include converting gas to high-value petrochemicals and liquid products such as fuels and lubricants.

At the same time, we are exploring for oil and gas from conventional, and from tight rock, shale and coal formations. Areas where we are exploring for conventional resources include offshore Australia and Brazil, and in the Gulf of Mexico. Our exploration for tight oil or gas, which can require hydraulic fracturing, is taking place in countries including Australia, Canada, China and the USA.

We also have a diverse portfolio of refineries and chemical plants that enable us to capture value from the oil and natural gas that we produce. 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 about 15,000 granted patents and pending patent applications.

BUSINESSES

Upstream International

Upstream International manages the Upstream businesses outside the Americas. It explores for and recovers crude oil, natural gas and natural gas liquids, transports oil and gas, and operates the upstream and midstream infrastructure necessary to deliver oil and gas to market. Upstream International also manages Shell’s Upstream LNG and GTL businesses. It manages its operations primarily by line of business, with this structure overlaying country organisations. This organisation is supported by activities such as Exploration and New Business Development. This organisational structure has been in place since January 1, 2013. Previously activities were organised primarily by geographical location.

Upstream Americas

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 oil and 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

Downstream manages Shell’s refining and marketing activities for oil products and chemicals. These activities are organised into globally managed classes of business. 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 our 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).

Projects & Technology

Projects & Technology manages the delivery of Shell’s major projects and drives 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. Since January 2013, it has also been responsible for all wells activities and CO₂ management.

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.

RESEARCH AND DEVELOPMENT

Innovative technology provides ways for Shell to stand apart from its competitors. It helps our current businesses perform, and it makes future businesses possible.

For that reason 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 2013, research and development (R&D) expenses were $1,318 million, compared with $1,307 million in 2012 and $1,123 million in 2011 [A].

Such sustained investment has enabled us to advance technologies that help us access new resources and better meet the needs of our customers and partners. To name a few: seismic processing and visualisation software that reveal previously unnoticed geological details; drilling-rig equipment that delivers wells more quickly and more safely; oil-recovery methods that increase production from fields; processes that refine crude oil and liquefy natural gas more efficiently; as well as fuel and lubricant formulations that perform better.

In 2014, we will continue to focus strongly on technologies that support our various businesses and reduce the environmental footprint of our operations and products.

[A] R&D expenses for 2012 and 2011 have been restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013.

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 crude 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-producing 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 which might result in lower profitability, particularly in our Downstream business.

We have commenced a review of our global refining portfolio, in the context of the growth of light crude oil supply in North America, and excess industry refining capacity worldwide. These factors are affecting the dynamics of the global refining industry environment. The portfolio review could potentially lead to asset sales, closures and/or impairments.

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

Shell subsidiaries, joint ventures and associates 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. Treasury and trading risks include, among others, exposure to movements in interest rates, foreign exchange rates and commodity prices, counterparty default and various operational risks. 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 20 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, cash flow and earnings.

In recent years, we have invested significant amounts in our tight-gas and liquids-rich shale portfolio. There is still a significant amount of drilling that must be conducted in certain properties. If future well results do not meet our expectations, there could be additional asset sales and/or impairments. Additionally, management will continue to review the strategic fit of our tight-gas and liquids-rich shale assets. Depending on the outcome of that review and future capital allocation to these properties, additional asset sales and/or impairments could also occur.

[A] Natural gas volumes are converted to oil equivalent using a factor of 5,800 scf per barrel.

[A] We manage our total proved reserves base without distinguishing between proved reserves from subsidiaries and those from joint ventures and associates.

[B] Includes proved reserves associated with future production that will be consumed in operations.

[C] Natural gas volumes are converted to oil equivalent using a factor of 5,800 scf per barrel.

[D] Proved reserves attributable to non-controlling interest in Shell subsidiaries.

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 govern how Shell and its individual companies conduct their affairs, and the Code of Conduct instructs employees and contractors on how to behave in line with the principles. 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 higher energy-intensive sources than at present. 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 in-situ Peace River project and our oil sands activities in Canada. Additionally, as production from Iraq increases, we expect that CO₂ emissions from flaring will rise. We are working with our partners to find 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 result in increasing our costs. Furthermore, continued attention to climate change, including activities by non-governmental and political organisations, is likely to lead to additional regulations designed to reduce greenhouse gas emissions. 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 experience additional costs, delayed projects, reduced production and reduced 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, earth tremors, 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. The operator could be asked to adjust its future production plan, as we have seen in the Netherlands, impacting production and costs. 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.

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

In our Nigerian operations we face various risks and adverse conditions, some of which have deteriorated during the year. These risks include: security issues surrounding the safety of our people, host communities, and operations; sabotage and theft; 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 that have 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 and its joint ventures and associates 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. 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, this may result in regulatory investigations, litigation and ultimately sanctions. 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. EU regulators have adopted regulations that, subject to UK implementation, 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. The United States Securities and Exchange Commission (SEC) had adopted similar requirements, but these requirements were vacated by the US Federal District Court. Accordingly, the SEC must adopt new rules. Additional regulations targeted at the financial sector could have adverse consequences for our trading, treasury and pension operations.

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

As seen in recent years in Nigeria, north Africa and the Middle East, social and civil unrest, both within the countries in which we operate and elsewhere, 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, including disruptions by non-governmental and political organisations, 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 threats. 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. Estimates 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 or other events. Estimates may also be altered by 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 arrangements 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 arrangements 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 such joint arrangements 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 arrangement 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 and/or our employees to criminal sanctions and civil suits.

Antitrust and competition laws apply to Shell and its joint ventures and associates in the vast majority of countries in which we do business. Shell and its joint ventures and associates 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 and its joint ventures or associates for violation of EU competition law could result in significantly 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.

Violations of anti-bribery and corruption law carry fines and expose us and/or our employees to criminal sanctions and civil suits.

In 2010, Shell 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. In November 2013, the DPA was successfully concluded. Shell’s ethics and compliance programme was enhanced during the DPA and remains in full force and effect. Any violations of the FCPA or other relevant anti-bribery and corruption legislation could have a material adverse effect on the Company.

Violations of data protection laws carry fines and expose us and/or our employees to criminal sanctions and civil suits.

Data protection laws apply to Shell and its joint ventures and associates in the vast majority of countries in which we do business. Over 100 countries globally have data protection laws and regulations. Additionally, impending EU Data Privacy Regulation proposes to increase penalties up to a maximum of 5% of global annual turnover for breach. Non-compliance with data protection laws could expose Shell to regulatory investigations, which may result in fines and penalties. Shell also could be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offence in some countries, and individuals can be either imprisoned or fined.

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 the “Corporate governance” report.

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 grow our cash flow and deliver competitive returns through economic cycles, to finance a competitive dividend and fund investment for future growth. 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 85% of our capital investment in 2014 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. For 2014, we have set out three key priorities: improving our financial performance, enhancing our capital efficiency, including financial discipline when evaluating investment opportunities, and continuing our focus on project delivery.

In 2014, we expect capital investment of around $37 billion, a reduction of $9 billion compared with 2013, as we moderate our growth ambitions and strive to improve our free cash flow and returns. Asset sales are a key element of our strategy – improving our capital efficiency by focusing our investment on the most attractive growth opportunities. Sales of non-core assets in 2011 to 2013 generated $16 billion in divestment proceeds. Exits from further positions in 2014 to 2015 are expected to generate some $15 billion in divestment proceeds. We have initiatives underway that are expected to improve our Upstream Americas and integrated Downstream businesses, focusing on the profitability of our portfolio and growth potential.

Shell has built up a substantial portfolio of project options for future 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, Australian LNG, offshore Europe, and others. Shell is working to mature these projects, with an emphasis on financial returns.

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, capital investment, divestment proceeds, 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 “About this Report” and “Risk factors”.

According to the International Monetary Fund (IMF), global economic growth in 2013 was 3.0%, little changed from 3.1% in 2012, and is forecast to rise to 3.7% for 2014, which would still be below the annual average of 3.9% for the previous 10 years.

In 2013, the recovery in the USA was hampered by factors including the expiration of the payroll tax holiday, while the eurozone suffered from reduced public spending and weak domestic demand. An improved outlook for the US economy brought forward the tapering of quantitative easing, causing turmoil in many emerging markets, due to a reversal of capital flows, tighter financial conditions and a fall in exchange rates.

In January 2014, the IMF estimated that: the eurozone’s gross domestic product (GDP) contracted by 0.4% in 2013 compared with a contraction of 0.7% in 2012; US GDP growth slowed to 1.9% from 2.8% in 2012; China’s GDP growth was 7.7%, the same as in 2012; and the average GDP growth rate for emerging markets and developing economies fell slightly to 4.7% compared with 4.9% in 2012.

Reflecting economic conditions, global oil demand rose by 1.4% (1.4 million barrels per day (b/d)) in 2013, according to the International Energy Agency January 2014 Oil Market Report. This growth was driven by emerging economies while demand in advanced economies remained almost flat.

We estimate that global gas demand grew by about 2% in 2013. This compares with an estimate of 2.5% for 2012 published in 2013 by CEDIGAZ. We believe that the growth in 2013 was driven by power and industry sectors in Asia-Pacific, mainly in China and Japan, the Middle East and the USA. European gas demand continued to contract, and was estimated by Eurostat and Country Transmission System Operators to have fallen by 1% in 2013, largely due to economic recession, imports of cheap US coal and increased use of renewable energy sources.

CRUDE OIL AND NATURAL GAS PRICES

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

[A] Yearly average prices are based on daily spot prices. The 2013 average price for Japan Customs-cleared Crude excludes December data.

The Brent crude oil price, an international crude-oil benchmark, traded in a range of $97-118 per barrel during 2013, ending the year at $109 per barrel. Both the Brent and the West Texas Intermediate (WTI) average crude oil prices for 2013 were little changed compared with 2012. WTI traded overall at a discount to Brent, but the discount was much narrower in the second half of 2013 as an expansion in pipeline capacity increased the ability to move oil from the landlocked area of 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 natural gas price at Henry Hub in 2013 averaged $3.7 per million British thermal units (MMBtu), 34% higher compared with 2012, and traded in a range of

$3.1-4.5 per MMBtu. At the start of 2013, the price was $3.1 per MMBtu due to mild winter weather, before a late cold snap in March increased demand and pushed it up to almost $4.4 per MMBtu. The price then trended downwards until December, when cold weather pushed it up to a peak of $4.5 per MMBtu, before it fell slightly to end the year at $4.4 per MMBtu.

In Europe, gas prices rose despite the fall in demand. In the UK, the average price at the UK National Balancing Point was 14% higher compared with 2012. 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 reflected a tightening of global 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 where 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.

Increasingly, we note growing demand for LNG in China, India, the Middle East, South America and South East Asia. In these markets, LNG supply is offered on term and spot bases in a competitive market. North American projects have been offering future supply linked to Henry Hub gas prices in the USA.

CRUDE 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 crude 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 confirmed in the fourth quarter of 2013.

REFINING AND PETROCHEMICAL MARKET TRENDS

Industry refining margins were lower in 2013 than in 2012 in key refining hubs, except for US Gulf Coast (USGC) margins, where increased domestic crude oil production lowered crude oil acquisition costs relative to international benchmarks. Some demand growth, especially around the summer driving season in the USA, also contributed to higher USGC margins. The global economic environment generally improved from the previous year. Political tensions, especially in the Middle East and north Africa, tended to add volatility to markets.

In 2014, increased demand for middle distillates is expected to be a key driver of refining margins, supported by demand for gasoline in the middle of the year. However, the overall outlook remains uncertain

because of continuing economic uncertainty, geopolitical tensions in some regions that could lead to supply disruptions, and structural overcapacity in global refining.

Industry naphtha cracker margins in Asia and Europe were broadly similar to those in 2012 as growth remained below the historic average. US ethane cracker margins rose because ethane prices fell. The outlook for petrochemicals for 2014 is highly dependent on further economic recovery.

EARNINGS 2013-2011

Global realised liquids prices were 6% lower in 2013 than in 2012. In Canada, realised synthetic crude oil prices were 7% higher than in 2012. Global realised natural gas prices were 6% higher than in 2012, with a 27% increase in the Americas and a 3% increase outside the Americas. Oil and gas production available for sale in 2013 was 3,199 thousand barrels of oil equivalent per day (boe/d), compared with 3,262 thousand boe/d in 2012. Liquids production was down 6% and natural gas production increased by 2% compared with 2012. Excluding the impact of divestments, production-sharing contract price effects and the deteriorated operating environment in Nigeria, production volumes in 2013 were in line with 2012. Realised refining margins were significantly lower in 2013 compared with 2012, mainly as a result of a deterioration in industry conditions in most regions (see “Market overview”).

Earnings on a current cost of supplies basis (CCS earnings) attributable to shareholders in 2013 of $16,745 million were in line with our announcement on January 17, 2014, that they were expected to be approximately $16.8 billion. CCS earnings in 2013 were 38% lower than in 2012, which, in turn, were 5% lower than in 2011.

CCS earnings exclude the effect of changes in the oil price on inventory valuation, as 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. Accordingly, when oil prices increase during the period, CCS earnings are likely to be lower than earnings calculated on a first-in first-out (FIFO) basis. Similarly, in a period with declining oil prices, CCS earnings are likely to be higher than earnings calculated on a FIFO basis. This explains why 2013 CCS earnings were $353 million higher than earnings calculated on a FIFO basis (2012: $463 million higher; 2011: $2,355 million lower).

Upstream earnings in 2013 were $12,638 million, compared with $22,444 million in 2012 and $24,466 million in 2011. The 43% decrease from 2012 to 2013 reflected higher depreciation charges (partly driven by impairments), lower divestment gains, higher exploration expenses (mainly driven by well write-offs), higher operating expenses and lower liquids and LNG realisations. Earnings were also impacted by a deterioration in the operating environment in Nigeria and the impact of the weakening Australian dollar on a deferred tax liability. These effects were partly offset by the contribution of our Pearl GTL plant in Qatar and higher gas price realisations in the Americas, together with net tax gains in 2013 compared with net tax

charges and higher decommissioning provisions in 2012. In 2012, earnings decreased by 9% compared with 2011, reflecting 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).

Downstream earnings in 2013 were $3,869 million compared with $5,382 million in 2012, and $4,170 million in 2011. The 28% decrease from 2012 to 2013 reflected significantly lower realised refining margins and higher charges for impairment, partly offset by higher contributions from Chemicals and Trading. Continued strong contributions from Marketing were broadly similar to 2012. The 29% increase in earnings from 2011 to 2012 reflected higher realised refining margins, lower operating expenses and a reduced level of impairment, partly offset by lower trading contributions, lower Chemicals earnings, lower divestment gains and lower gains associated with the fair-value accounting of commodity derivatives.

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 2013. Property, plant and equipment increased by $20 billion. Net capital investment was $44 billion, 49% higher than in 2012; 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 $22 billion.

Of the net capital investment in 2013, 89% related to Upstream projects, aimed at providing growth over the long term.

Gearing was 16.1% at the end of 2013, compared with 9.8% at the end of 2012 as restated for the retrospective application of revised IAS 19 Employee Benefits, mainly reflecting a decrease in cash and cash equivalents, and an increase in debt.

ADOPTION OF IFRS 11 JOINT ARRANGEMENTS

As noted above and explained in Note 1 to the “Consolidated Financial Statements”, Shell adopted a number of new and revised accounting standards in 2013, including IFRS 11 Joint Arrangements. The adoption of IFRS 11 did not materially affect the “Consolidated Financial Statements”, and comparative information was therefore not restated. However, the impact of the adoption of IFRS 11 on certain information presented in this Report is explained, where appropriate, to aid evaluation of this information.

PROVED RESERVES AND PRODUCTION

Shell subsidiaries’ and the Shell share of joint ventures and associates’ estimated net proved oil and gas reserves are summarised in “Upstream” and set out in more detail in “Supplementary information – oil and gas (unaudited)”. The impact in 2013 of the reclassification of certain entities, consistent with the change in their accounting treatment as a result of the adoption of IFRS 11 Joint Arrangements, is provided separately; this had no impact on proved reserves in total. The changes in proved reserves described below for Shell subsidiaries and for the Shell share of joint ventures and associates respectively exclude the effect of this reclassification.

In 2013, Shell added 1,577 million boe of proved reserves before taking production into account, of which 1,445 million boe came from Shell subsidiaries and 132 million boe from the Shell share of joint ventures and associates. These additions were positively impacted by lower commodity prices (48 million boe) and purchases that more than offset sales (44 million boe).

In 2013, total oil and gas production available for sale was 1,168 million boe. An additional 39 million boe was produced and consumed in operations. Production available for sale from subsidiaries was 850 million boe with an additional 28 million boe consumed in operations. The Shell share of the production available for sale of joint ventures and associates was 318 million boe with an additional 11 million boe consumed in operations.

Accordingly, after taking production into account, there was an increase of 370 million boe in proved reserves, comprising an increase of 567 million boe from subsidiaries and a decrease of 197 million boe from the Shell share of joint ventures and associates.

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.

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 joint ventures and associates. 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 “Summary of results” and Note 2 to the “Consolidated Financial Statements”.

Net capital investment is defined as capital expenditure, adjusted for: proceeds from disposals (excluding other investments (net) in the Corporate segment); exploration expense excluding exploration wells written off; investments in joint ventures and associates; and leases and other items. See Notes 2 and 4 to the “Consolidated Financial Statements”.

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 “Liquidity and capital resources – Return on average capital employed”.

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. See Note 15 to the “Consolidated Financial Statements”.

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 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 joint ventures and associates 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) using a factor of 5,800 standard cubic feet per barrel. 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 is the number of incidents in respect of activities where we are the operator in which 100 kilograms or more of oil or oil products were spilled as a result of those activities. The number for 2012 was updated from 204 to reflect the 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 including, from January 1, 2013, our share of employees of certain additional joint operations, as a result of the adoption of IFRS 11 Joint Arrangements.

The selected financial data set out below are 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 with this Strategic Report.

Revised IAS 19 Employee Benefits has been adopted with effect from January 1, 2013, with retrospective application to the “Consolidated Financial Statements” for 2011 and 2012, reflected in the data below. See Note 28 to the “Consolidated Financial Statements”. For comparison purposes, 2009 and 2010 data below have been adjusted where significant to reflect the estimated effects of applying revised IAS 19.

OVERVIEW

Our Upstream businesses explore for and extract crude oil and natural gas, often in joint arrangements 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 it, 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

Global oil demand rose by 1.4% (1.4 million b/d) in 2013 according to the International Energy Agency January 2014 Oil Market Report. This growth was driven by emerging economies while demand in advanced economies remained almost flat. The Brent crude oil price, an international crude-oil benchmark, traded in a range of $97-118 per barrel during 2013, ending the year at $109 per barrel.

We estimate that global gas demand grew by about 2% in 2013. This compares with an estimate of 2.5% for 2012 published in 2013 by CEDIGAZ. We believe that the growth in 2013 was driven by power and industry sectors in Asia-Pacific, mainly in China and Japan, the Middle East and the USA. European gas demand continued to contract, and was estimated by Eurostat and Country Transmission System Operators to have fallen by 1% in 2013, largely due to the economic recession, imports of cheap US coal and increased use of renewable energy sources.

EARNINGS 2013-2012

Segment earnings of $12,638 million included a net charge of $2,479 million, primarily related to the impairment of liquids-rich shale properties in North America, partly offset by net tax gains and gains on divestments. Segment earnings in 2012 of $22,244 million included a net gain of $2,137 million, mainly related to gains on divestments, partly offset by impairments for onshore gas assets in the USA, net tax charges and decommissioning provisions.

Excluding the net charge and net gain described above, segment earnings in 2013 decreased compared with 2012 because of higher exploration expenses (mainly driven by well write-offs), operating expenses and depreciation, and lower liquids and LNG realisations. Earnings were also impacted by a deterioration in the operating environment in Nigeria and the impact of the weakening Australian

dollar on a deferred tax liability. This was partly offset by an increased contribution from our Pearl GTL plant in Qatar, and higher gas prices in the Americas.

Earnings in the Americas were a loss of $900 million in 2013, excluding the related items identified at the beginning of this earnings section. Compared with 2012 earnings of $670 million, they decreased mainly because of higher exploration and operating expenses, partly offset by higher gas prices. Our deep-water and heavy oil businesses in the Americas reported positive earnings, whereas our onshore business reported a loss.

Global realised liquids prices were 6% lower than in 2012. In Canada, realised synthetic crude oil prices were 7% higher than in 2012. Global realised gas prices were 6% higher than in 2012, with a 27% increase in the Americas and a 3% increase outside the Americas.

Equity LNG sales volumes of 19.6 million tonnes were 3% lower than in 2012, mainly reflecting lower volumes from Nigeria LNG as a result of the deterioration in the operating environment in Nigeria, including reduced feed gas supply and a blockade on shipments. Excluding the impact of the challenging operating environment in Nigeria, equity LNG sales volumes were similar to 2012.

EARNINGS 2012-2011

Segment earnings in 2012 of $22,244 million included a net gain of $2,137 million as described above. Segment earnings in 2011 of $24,466 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, partly offset by the cost impact of the US offshore drilling moratorium.

Excluding the net gains described above, segment earnings in 2012 were 2% lower than in 2011, primarily driven by reduced contributions from the Americas, mainly as a result of higher depreciation, increased operating expenses, higher exploration expenses and lower realised gas prices. These were partly offset by the increased contribution of integrated gas activities (LNG and GTL), reflecting the ramp-up of the Pearl GTL plant, higher realised LNG prices as well as increased LNG trading contributions and equity LNG sales volumes. Earnings in 2012 also reflected higher realised gas prices outside the Americas.

NET CAPITAL INVESTMENT

Net capital investment was $39 billion in 2013, compared with $25 billion in 2012 and $19 billion in 2011. Capital investment in 2013 was $40 billion (of which $11 billion was exploration expenditure, including acquisitions of unproved properties). Capital investment in 2012 was $31 billion. Divestment proceeds were $1 billion in 2013 compared with $6 billion in 2012.

Net capital investment was higher than in 2012 mainly due to lower divestment proceeds and higher expenditure on acquisitions, primarily due to the purchase of LNG assets from Repsol as described below. There was also higher capital investment in growth projects, particularly: deep-water projects in Malaysia, Nigeria and the Americas; integrated gas projects in Australia; and tight-gas projects in China.

PORTFOLIO ACTIONS AND BUSINESS DEVELOPMENT

In Brazil, a consortium of companies in which Shell holds a 20% interest won a 35-year production-sharing contract (PSC) to develop the Libra discovery, a potential multibillion barrel oil field in pre-salt reservoirs located in the Santos Basin.

Also in Brazil, we completed the acquisition of an additional 23% interest in the Shell-operated Parque das Conchas (BC-10) deep-water project. In January 2014, we announced an agreement to sell a 23% interest in the BC-10 project to Qatar Petroleum International which would return Shell to a 50% interest in the field, subject to completion.

In Indonesia, we acquired an additional 5% interest in the Masela block, increasing our interest to 35%. The Masela PSC contains the Abadi gas field, for which a 2.5 million tonnes per annum (mtpa) floating LNG (FLNG) facility is in the front-end engineering and design (FEED) phase.

In Iraq, the Basrah Gas Company, a joint venture between Shell (44%), South Gas Company (51%) and Mitsubishi Corporation (5%) officially started operations. The Basrah Gas Company gathers, treats and processes raw gas produced from the Rumaila, West Qurna 1 and Zubair fields that was previously being flared.

In the UK, we acquired 75% of Hess Corporation’s interests in the Beryl area fields and Scottish Area Gas Evacuation system, 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 an additional 5.9% interest in the offshore Schiehallion field from Murphy Schiehallion Ltd bringing our interest in the field to 55%.

In January 2014, Shell completed the acquisition of Repsol S.A.’s LNG portfolio outside of North America, including supply positions in Peru and Trinidad and Tobago, for a net cash purchase price of $3.8 billion, subject to post-closing adjustments. As part of the transaction, Shell also assumed $1.6 billion of balance sheet liabilities relating to existing leases for LNG ship charters. The acquisition adds 7.2 mtpa of directly managed LNG volumes through long-term off-take agreements, including 4.2 mtpa of equity LNG plant capacity. Capital investment of $3.4 billion was reported in 2013 with the remaining $2.0 billion to be reported in the first quarter of 2014.

We also took several final investment decisions during 2013, including the following.

In Canada, we took the final investment decision for Phase 1 and 2 of the Carmon Creek in-situ project (Shell interest 100%). The project will

include central processing facilities and well pads and is expected to deliver peak production of 80 thousand barrels of bitumen production per day.

In Nigeria, we took the final investment decision for the development of the Erha North Phase 2 deep-water project (Shell interest 44%). The project is expected to produce around 60 thousand boe/d at peak production and improve the utilisation of the existing Erha floating production, storage and offloading (FPSO) vessel.

In the USA, we took the final investment decision for the Stones deep-water project (Shell interest 100%) in the Gulf of Mexico. The first phase of development has an expected peak production of 50 thousand boe/d.

We continued to divest selected Upstream assets during 2013, including a 5% interest in the Prelude FLNG project in Australia to CPC Corporation, reducing Shell’s interest in the project to 67.5%.

In January 2014, we agreed the sale of our 8% interest in the Wheatstone-Iago joint venture and our 6.4% interest in the 8.9 mtpa Wheatstone LNG project, both in Australia, to the Kuwait Foreign Petroleum Exploration Company.

In Upstream Americas’ tight-gas and liquids-rich shale, insights from ongoing exploration and appraisal drilling results and production information, and Shell’s ongoing restructuring of this portfolio, could potentially lead to future asset sales and/or impairments.

We have launched a strategic portfolio review in Nigeria, regarding the potential exit from interests we hold in some onshore leases in the eastern Niger Delta, subject to partner and regulatory approvals.

AVAILABLE-FOR-SALE PRODUCTION

In 2013, production was 3,199 thousand boe/d compared with 3,262 thousand boe/d in 2012. Liquids production was down 6% and gas production increased by 2% compared with 2012.

Production in 2013 was positively impacted by new field start-ups and the continuing ramp-up of existing projects, including the first full year of production from the Pearl GTL plant, the ramp-up of multiple projects in Malaysia, first commercial production in the Majnoon field in Iraq, and start-ups such as the BC-10 Phase 2 project in Brazil and the North Rankin Redevelopment project in Australia.

These factors were more than offset by field declines, the impact of the challenging operating environment in Nigeria, and an increase in maintenance and asset replacement activities.

In February 2014, we started production from the Mars B development through the Olympus platform (Shell interest 71.5%), our seventh, and largest, floating deep-water platform in the Gulf of Mexico.

PROVED RESERVES

Shell subsidiaries’ and the Shell share of joint ventures and associates’ estimated net proved oil and gas reserves are summarised later in this Upstream section and set out in more detail in “Supplementary information – oil and gas (unaudited)”. The impact in 2013 of the reclassification of certain entities, consistent with the change in their accounting treatment as a result of the adoption of IFRS 11 Joint Arrangements (see Note 1 to the “Consolidated Financial Statements”), is provided separately; this had no impact on proved reserves in total. The changes in proved reserves described below for Shell subsidiaries and for the Shell share of joint ventures and associates respectively exclude the effect of this reclassification.

In 2013, Shell added 1,577 million boe of proved reserves before taking production into account, of which 1,445 million boe came from Shell subsidiaries and 132 million boe from the Shell share of joint ventures and associates.

The change in the yearly average commodity prices between 2012 and 2013 resulted in a net positive impact on the proved reserves of 48 million boe.

Shell subsidiaries

Before taking production into account, Shell subsidiaries added 1,445 million boe of proved reserves in 2013. This comprised 932 million barrels of oil and natural gas liquids and 513 million boe (2,973 thousand million scf) of natural gas. Of the 1,445 million boe: 657 million boe were from the net effects of revisions and reclassifications; 440 million boe were from improved recovery; 304 million boe came from extensions and discoveries; and a net increase of 44 million boe related to purchases and sales.

After taking into account production of 878 million boe (of which 28 million boe were consumed in operations), Shell subsidiaries’ proved reserves increased by 567 million boe in 2013.

Shell subsidiaries’ proved developed reserves decreased by 24 million boe to 6,790 million boe, while proved undeveloped reserves increased by 591 million boe to 4,046 million boe.

The total addition of 1,445 million boe before taking production into account included a net positive impact from commodity price changes of 48 million boe of proved reserves.

SYNTHETIC CRUDE OIL

Of the 1,577 million boe added to proved reserves, 16 million barrels were synthetic crude oil. In 2013, we had synthetic crude oil production of 48 million barrels of which 2 million barrels were consumed in operations. At December 31, 2013, we had synthetic crude oil proved reserves of 1,731 million barrels, of which 1,299 million barrels were proved developed reserves and 432 million barrels were proved undeveloped reserves.

BITUMEN

Of the 1,577 million boe added to proved reserves, 380 million barrels were bitumen. The addition of 380 million barrels comprised a decrease of 30 million barrels from net effects of revisions and reclassifications, and an addition of 410 million barrels from improved recovery. After taking into account production of 7 million barrels, bitumen proved reserves were 422 million barrels at December 31, 2013.

Shell share of joint ventures and associates

Before taking production into account, there was an increase of 132 million boe in the Shell share of joint ventures and associates’ proved reserves in 2013. This comprised 57 million barrels of oil and natural gas liquids and 75 million boe (437 thousand million scf) of natural gas. Of the 132 million boe, 130 million boe came from the net effects of revisions and reclassifications, and 2 million boe came from extensions and discoveries.

After taking into account production of 329 million boe (of which 11 million boe were consumed in operations), the Shell share of joint ventures and associates’ proved reserves decreased by 197 million boe in 2013.

The Shell share of joint ventures and associates’ proved developed reserves decreased by 149 million boe to 2,542 million boe, and proved undeveloped reserves decreased by 48 million boe to 567 million boe.

The total addition of 132 million boe before taking production into account was not impacted by commodity price changes.

Proved undeveloped reserves

In 2013, Shell subsidiaries’ and Shell share of joint ventures and associates’ proved undeveloped reserves (PUD) increased by 543 million boe to 4,613 million boe; in addition 107 million boe of new proved undeveloped reserves in 2013 were matured to proved developed reserves. During 2013, Shell spent $17 billion on development activities related to PUD maturation.

Proved undeveloped reserves held for five years or more (PUD5+) at December 31, 2013, were 826 million boe, a decrease of 186 million boe compared with the end of 2012. These proved reserves remain undeveloped because development either: requires the installation of gas compression and the drilling of additional gas wells, which will be executed when required to support existing gas delivery commitments (in the Netherlands, Norway, the Philippines, Russia); requires gas cap blow-down which is awaiting end-of-oil production (in Nigeria); is part of ongoing onshore oil and gas development (in the USA); is part of water-injection project execution that is still in progress (in the Gulf of Mexico); or will take longer than five years because of the complexity and scale of the project (in countries such as Kazakhstan). Most of the PUD5+ are held in locations where Shell has a proven track record of developing similar major projects or where project execution is ongoing but is taking longer than expected.

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 2014 to 2016, Shell is contractually committed to deliver to third parties and joint ventures and associates a total of approximately 4,400 thousand million scf of natural gas from Shell subsidiaries, joint ventures and associates. 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

While 2013 included some disappointing exploration results, Shell did participate in nine notable exploration discoveries and appraisals. An increase in exploration activity has contributed to an increase in dry holes, which more than doubled from 2012 to 2013. Accordingly, exploration expenses increased by 70% over the same period, primarily in North and South America.

In 2013, Shell participated in 263 productive exploratory wells with proved reserves allocated (Shell share: 200 wells). For further information, see “Supplementary information – oil and gas (unaudited) – Acreage and wells”.

In 2013, Shell participated in a further 273 wells (Shell share: 205 wells) that remained pending determination at December 31, 2013.

In total, Shell added net 3,700 square kilometres of acreage to its exploration portfolio, comprising acreage increases of 78,800 square

kilometres with notable (over 10,000 square kilometres) increases in

Australia and Canada, and reductions of 75,100 square kilometres with notable reductions in Brazil and Libya due to relinquishments and exits respectively.

BUSINESS AND PROPERTY

Shell subsidiaries, joint ventures and associates 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 that 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 in Denmark (Shell interest 36.8%), which was granted in 1962 and will expire in 2042. The Danish government is one of our partners with a 20% interest.

IRELAND

We are the operator of the Corrib Gas project (Shell interest 45%), which is currently at an advanced stage of construction. Its

four kilometre onshore gas pipeline has been installed, while construction of a 4.9 kilometre tunnel under Sruwaddacon Bay is progressing. Corrib has the potential to supply a significant proportion of the country’s natural gas requirement.

ITALY

We hold two non-operating interests in Italy: the Val d’Agri producing concession (Shell interest 39.23%) and the Tempa Rossa concession (Shell interest 25%). The Tempa Rossa field is under development by the operator, Total, and first oil is currently expected in late 2016.

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 and NAM a 60% interest. 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. It is expected that, later in 2014, the Minister of Economic Affairs of the Netherlands will formally approve NAM’s production plan for the Groningen field. It would cap production in 2014 at 42.5 billion cubic metres, in an effort to diminish the potential for seismic activity.

NORWAY

We are a partner in more than 20 production licences on the Norwegian continental shelf. We are the operator in six of these, of which two are producing: the Ormen Lange gas field (Shell interest 17.8%) and the Draugen oil field (Shell interest 44.6%). The other producing fields are the Troll, Gjøa and Kvitebjørn fields.

UK

We operate a significant number of our interests on the UK Continental Shelf on behalf of a 50:50 joint arrangement 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 also have interests in the non-operated Schiehallion field (Shell interest 55%), and in the Beryl area fields, with interests ranging from 20% to 49%.

REST OF EUROPE

Shell also has interests in Albania, Austria, Germany, Greece, Greenland, Hungary, 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, and also operator for exploration Block Q (Shell interest 50%). We have a 35% non-operating interest in the Block B concession, where gas and condensate are produced from the Maharaja Lela Field. In addition, we have non-operating interests in deep-water exploration Block CA-2 (Shell interest 12.5%) and in exploration Block N (Shell interest 50%), both under PSCs.

CHINA

We operate the onshore Changbei tight-gas field under a PSC with China National Petroleum Corporation (CNPC). The PSC includes the development of tight gas in different geological layers of the block.

In Sichuan, Shell and CNPC have agreed to appraise, develop and produce tight gas in the Jinqiu block under a PSC (Shell interest 49%) and have a PSC for shale-gas exploration, development and production in the Fushun Yongchuan block (Shell interest 49%). Shell is also a party to the Zitong PSC for tight-gas exploration, development and production (Shell interest 44.1%).

We have also agreed with Chinese National Offshore Oil Corporation to appraise and potentially develop three offshore oil and gas blocks in the Yinggehai Basin, each under a PSC (Shell interest 49%).

INDONESIA

We have a participating interest in the offshore Masela block where INPEX Masela is the operator. During 2013, we increased our interest from 30% to 35%. The Masela block contains the Abadi gas field. The operator has selected a FLNG concept for the field’s first development phase.

IRAN

Shell transactions with Iran are disclosed separately. See “Section 13(r) of the US Securities Exchange Act of 1934 Disclosure”.

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. In 2013, we successfully restarted production and Majnoon has reached the milestone of first commercial production of 175 thousand b/d, which triggers the commencement of cost recovery. We also have a 15% interest in the West Qurna 1 field. According to the provisions of both contracts, Shell’s equity entitlement volumes will be lower than the Shell interest implies.

In 2013, the Basrah Gas Company, a joint venture between Shell (44%), South Gas Company (51%) and Mitsubishi Corporation (5%) officially started operations. The Basrah Gas Company gathers, treats and processes raw gas produced from the Rumaila, West Qurna 1 and Zubair fields that was previously being flared. 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. After the start of production from the Kashagan field in September 2013, operations had to be stopped in October due to gas leaks from the sour gas pipeline. Investigations and repair activities are ongoing.

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

MALAYSIA

We explore for and produce oil and gas located offshore Sabah and Sarawak under 19 PSCs, in which our interests range from 20% to 85%.

Offshore Sabah, we operate four producing oil fields (Shell interest 50%). 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 began early production from Gumusut-Kakap in November 2012, by connecting two wells to the Kikeh production facility, which is operated by Murphy Sabah Oil. Production from Gumusut-Kakap via a dedicated floating production system is expected to commence during 2014. We also have a 21% interest in the Siakap North-Petai field, a 30% interest in the Kebabangan field and a 30% interest in offshore exploration PSC, SB311.

Offshore Sarawak, we are the operator of 17 producing gas fields (Shell 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. Additionally, we have interests in five exploration PSCs: Deepwater Block 2B, SK318, SK319, SK408 and SK320.

We operate a GTL plant (Shell interest 72%) 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 speciality products.

OMAN

We have a 34% interest in Petroleum Development Oman (PDO); the Omani government has a 60% interest. PDO is the operator of more than 160 oil fields, mainly located in central and southern Oman over an area of around 114,000 square kilometres. The concession expires in 2044. During 2013, the Amal Steam enhanced oil recovery project was brought on stream. The project is expected to ramp up over a number of years and produce some 20 thousand b/d of oil at peak production.

We are also participating in 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. 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 LNG is shipped mainly to markets in 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, which represents 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 320 thousand boe/d and more than 10 million tonnes of LNG in 2013.

We have a 50% interest in the Salym fields in western Siberia, where production was approximately 145 thousand boe/d in 2013.

We also have a 100% interest in three exploration and production licences. They are for the Barun-Yustinsky block in Kalmykia, and the Arkatoitsky and Lenzitsky blocks in the Yamalo Nenets Autonomous District. We also have an exploration licence in the North-Vorkutinsky area in the Komi Republic. In 2013, we returned the East Talotinskiy licence in the Nenets Autonomous District to the government.

UNITED ARAB EMIRATES

In Abu Dhabi, we held a concessionary interest of 9.5% in the oil and gas operations run by Abu Dhabi Company for Onshore Oil Operations (ADCO) from 1939 to January 2014, when the licence expired. 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, which it extracts from the wet natural gas associated with the oil produced by ADCO.

In 2013, we were chosen by the Abu Dhabi National Oil Company (ADNOC) to participate in a 30-year joint venture to potentially develop the Bab sour gas reservoirs in Abu Dhabi (Shell interest 40%). Shell and ADNOC are currently in a period of commercial and technical work that may lead to development, subject to the signing of the respective joint-venture agreements. It is intended that the joint venture will be the operator, and that the gas will supply the local market in the United Arab Emirates.

REST OF ASIA

Shell also has interests in India, Japan, Jordan, 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. Woodside is also the operator on behalf of six joint-venture participants in the NWS gas, condensate and oil fields, which produced more than 470 thousand boe/d in 2013. 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 potential LNG plant on Curtis Island, near Gladstone.

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 19.3%) 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 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 2013, construction of the Prelude FLNG

project continued and we completed the sale of a 5% interest to CPC Corporation, reducing our interest to 67.5%.

We are also a partner in the Browse joint ventures (Shell interests ranging from 25% to 35%) covering the Brecknock, Calliance and Torosa gas fields. In 2013, the Browse joint venture selected Shell’s FLNG technology to progress to the basis of design phase of the project.

Our other interests include: a joint venture with Shell as the operator of the Crux gas and condensate field (Shell interest 82%); the Shell operated AC/P41 block (Shell interest 75%); and the Sunrise gas field in the Timor Sea (Shell interest 26.6%). We agreed to sell our interest in the Wheatstone LNG project in January 2014.

We are a partner in both Shell-operated and other, non-operated, exploration joint ventures in multiple basins including the Bonaparte, Exmouth Plateau, Greater Gorgon, Outer Canning and South Exmouth.

REST OF OCEANIA

Shell also has interests in New Zealand.

Africa

NIGERIA

Shell’s share of production, onshore and offshore, in Nigeria was approximately 265 thousand boe/d in 2013, compared with approximately 365 thousand boe/d in 2012. Security issues and crude oil theft in the Niger Delta continued to be significant challenges in 2013.

Onshore

The Shell Petroleum Development Company of Nigeria Ltd (SPDC) is the operator of a joint arrangement (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 are being reimbursed. Further new carry agreements with the Nigerian National Petroleum Corporation were put in place during 2013.

SPDC supplies gas to Nigeria LNG Ltd (NLNG) mainly through its Gbaran-Ubie and Soku projects. During 2013, force majeure was declared on several occasions, mainly related to security issues, sabotage and crude oil theft incidents. This reduced onshore oil and gas production significantly, and impacted gas supplies to NLNG. SPDC is undertaking a strategic review of its interests in the eastern Niger Delta that may lead to the divestment of certain leases.

Offshore

Our main offshore deep-water activities are carried out by Shell Nigeria Exploration and Production Company (SNEPCO, Shell interest 100%) which holds interests in four deep-water blocks. SNEPCO operates OMLs 118 (including the Bonga field) and 135 (Bolia) holding a 55% interest in each, and holds a 43.75% interest in OML 133 (Erha) and a 50% interest in oil production lease (OPL) 245 (Zabazaba). 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 2013.

Liquefied natural gas

Shell has a 25.6% interest in NLNG, which operates six LNG trains with a total capacity of 22.0 mtpa. In 2013, LNG production was

lower than in 2012 because of gas supply constraints and the impact of a blockade of NLNG export facilities by the Nigerian Maritime Administration and Safety Agency (NIMASA).

REST OF AFRICA

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

North America

CANADA

We hold more than 2,100 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 continued to develop fields in Alberta and British Columbia during 2013 through drilling programmes and investment in infrastructure to facilitate new production. We own and operate four natural gas processing and sulphur-extraction plants in Alberta.

Synthetic crude oil

We operate the Athabasca Oil Sands Project (AOSP) in north-east Alberta as part of a joint arrangement (Shell interest 60%). The bitumen is transported by pipeline for processing at the Scotford Upgrader, which is also operated by Shell and located in the Edmonton area. In 2013, the first phase of the AOSP debottlenecking project came online, adding an additional 10 thousand boe/d of capacity at peak production. 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, is currently under construction and is expected to start operation towards the end of 2015.

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. During 2013, we announced our final investment decision to proceed with our Carmon Creek project (Shell interest 100%), an in-situ project that is expected to produce up to 80 thousand boe/d.

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 and Newfoundland, and a number of exploration licences off the west coast of British Columbia and in the Mackenzie Delta in the Northwest Territories.

USA

We produce oil and gas in the Gulf of Mexico, heavy oil in California and primarily tight gas and 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, and accounts for almost 50% of Shell’s oil and gas production in the country. We have an interest in approximately 450 federal offshore leases in the Gulf of Mexico. Our share of production in the Gulf of Mexico averaged almost 180 thousand boe/d in 2013. Key producing assets are Auger, Brutus, Enchilada, Mars, NaKika, Perdido, Ram-Powell and Ursa.

We continued to grow our presence in the Gulf of Mexico in 2013, adding three drilling rigs to our contracted offshore fleet. We also secured 36 blocks in the central and western lease sales in 2013.

Onshore

We have significant holdings of tight-gas and liquids-rich shale acreage including in the Marcellus shale, centred on Pennsylvania in north-east USA, the Eagle Ford shale formation in south Texas, the Delaware Permian Basin in west Texas, the Sand Wash Basin and Niobrara Shale in north-west Colorado, as well as the Mississippi Lime in Kansas.

In recent years, we have invested significant amounts in our tight-gas and liquids-rich shale portfolio. There is still a significant amount of drilling that must be conducted in certain properties. If future well results do not meet our expectations, there could be additional asset sales and/or impairments. Additionally, management will continue to review the strategic fit of our tight-gas and liquids-rich shale assets. Depending on the outcome of that review and future capital allocation to these properties, additional asset sales and/or impairments could also occur.

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. As a result of the grounding of the Kulluk drilling rig at the end of 2012, exploration drilling in 2013 was deferred. We have made the decision to dispose of the Kulluk and contracted a replacement rig. An impairment charge was recognised in 2013. A recent US Ninth Circuit Court decision against the Department of the Interior raises obstacles to our plans for drilling offshore Alaska. As a result, we have decided to suspend our exploration programme for Alaska for 2014, and we will continue to review the situation as we develop our plans for 2015.

REST OF NORTH AMERICA

Shell also has interests in 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 73%). We started production from the BC-10 Phase 2 project in October 2013, which aims to deliver peak production of 35 thousand boe/d. In 2013, we exercised our pre-emptive rights to acquire an additional 23% in the BC-10 project, and

in January 2014 we agreed to sell a 23% interest to Qatar Petroleum International, which would return our interest to 50%, subject to completion. 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 (Shell interest 20%) and BMES-27 (Shell interest 17.5%). We also operate one block in the São Francisco onshore basin area.

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.

In 2013, a consortium of companies in which Shell holds a 20% interest won a 35-year PSC to develop the Libra pre-salt oil discovery located in the Santos Basin.

REST OF SOUTH AMERICA

Shell also has interests in Argentina, Colombia, French Guiana, Guyana, Peru, Trinidad and Tobago, 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.