CONTENTS

Cover images

The cover shows some of the ways that Shell helps to meet the world’s diverse energy needs – from supplying gas for cooking, heating, and generating electricity for homes and businesses, to liquefied natural gas (LNG) to fuel trucks and ships. Pearl, the world’s largest gas-to-liquids (GTL) plant, makes lubricants, fuels and products for plastics. Prelude, the world’s largest floating LNG facility, will produce LNG off the coast of Australia.

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 US Securities and Exchange Commission (SEC) for the year ended December 31, 2015, 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 115-152), the Parent Company Financial Statements of Shell (pages 173-181) and the Financial Statements of the Royal Dutch Shell Dividend Access Trust (pages 173-181). Cross references to Form 20-F are set out on pages 02-03 of this Report.

Information in this Report in respect of Shell’s performance in 2015 and position at December 31, 2015, excludes the activities of BG Group plc, which was acquired on February 15, 2016.

Financial reporting terms used in this Report are in accordance with International Financial Reporting Standards (IFRS). The Consolidated Financial Statements comprise the financial statements of the Company and its subsidiaries. “Subsidiaries” and “Shell subsidiaries” refer to those entities over which the Company has control, either directly or indirectly. Entities and unincorporated arrangements over which Shell has joint control are generally referred to as “joint ventures” and “joint operations” respectively, and entities over which Shell has significant influence but neither control nor joint control are referred to as “associates”. “Joint ventures” and “joint operations” are collectively referred to as “joint arrangements”.

In addition to the term “Shell”, in this Report “we”, “us” and “our” are also used to refer to the Company and its subsidiaries in general or to those who work for them. These terms are also used where no useful purpose is served by identifying the particular entity or entities. The term “Shell interest” is used for convenience to indicate the direct and/or indirect ownership interest held by Shell in an entity or unincorporated joint arrangement, after exclusion of all third-party interests. The companies in which Royal Dutch Shell plc has a direct or indirect interest are separate entities.

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 production, processing or sales volumes (including the share of joint operations) 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 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 interpretations issued by the IFRS Interpretations Committee.

Except as otherwise noted, the figures shown in this Report are stated in US dollars. As used herein all references to “dollars” or “$” are to the US currency.

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” on pages 08-12 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, DC 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, United Kingdom. Copies of this Report also may be obtained, free of charge, by mail.

There is no doubt that 2015 was a turbulent year, with low oil and gas prices having a far-reaching impact on the energy industry.

We have taken the opportunity to strengthen our business by reducing our operating expenses and capital investment, while continuing to divest assets that are not central to our long-term strategy.

Our acquisition of BG Group plc (BG) – one of the largest takeovers in UK corporate history – in February 2016 will help sharpen our focus on liquefied natural gas (LNG) and deep-water exploration and production. Combined, we are stronger, more competitive and better-equipped financially to continue to play an important role in meeting global energy demand for decades to come. It underscores our role as one of the largest independent oil and gas producers. Increased cash flows from our newly acquired assets will also help to support dividend payments and future investment.

A major challenge facing society is how to meet the needs of a growing global population, while limiting the amount of carbon dioxide (CO₂) in our atmosphere. This requires a mix of urgent action, realism and long-term planning by governments and industry alike. It will also require unprecedented co-operation, investment and innovation.

It was encouraging to see governments reach a global climate agreement in Paris in December. The agreement should now encourage countries to develop policies that balance environmental concerns with enabling a decent quality of life for more people.

Delivering the energy essential for economic development and the wellbeing of billions of people will require huge and sustained investment. Limiting the amount of CO₂ in our atmosphere also requires major investments in advanced technologies, such as carbon capture and storage (CCS). Oil and gas, which make up over 50% of global energy supplies today, will need to continue to provide a large part of the world’s energy for decades to come.

The International Energy Agency estimates that over $25 trillion of investment will be needed in oil and gas supply alone from 2015 to 2040. So the long-term investment case for oil and gas remains strong, despite the fall in oil prices over the last 18 months. The concern is that prices seen in late 2015 and early 2016 may be too low to spur investment in projects that are needed to ensure long-term supplies. Without sufficient investment, the risk of demand exceeding supply will increase.

We know that understanding the world’s future energy needs will help us improve our competitiveness.

We have evolved over the last few decades from a company focused almost entirely on oil to one of the world’s leading suppliers of gas, the cleanest-burning hydrocarbon. Gas is already playing a role in tackling carbon emissions. Switching from coal to gas for power generation is one way to reduce emissions of CO₂, while increasing energy supply to a growing global population, including more than 1 billion people who lack access to electricity today.

We are working on multiple fronts to play our part in the energy transition. For example, we are now one of the world’s largest suppliers of low-carbon biofuel through our Raízen joint venture in Brazil, which produces ethanol from sugar cane. We are in the early stages of developing biofuels that could further reduce the environmental impact of the transport sector. Our high-performance lubricants can already contribute to improved energy efficiency for motorists and we are working with vehicle manufacturers to improve them further. We are also increasingly offering LNG as a transport fuel and are exploring the potential of hydrogen.

CCS is an especially important technology for reducing CO₂ emissions from a range of industries. Quest, which we opened in 2015, captures and safely stores around one-third of the annual CO₂ emissions from an oil sands bitumen processing facility in Canada. We are sharing information on its design and processes so that it can serve as a blueprint for others. Strong government support is needed to encourage many more businesses around the world to invest in CCS.

The Paris climate agreement provided a promising platform for society to develop a solution to climate change. Governments now need to implement policies that will stimulate investment in all technologies that can contribute to a lower-carbon future.

Despite some of the toughest operating conditions that our industry has seen, we are in a stronger position to weather current market volatility and play our part in the energy transition.

Let me take this opportunity to thank our shareholders for supporting the BG acquisition at a very challenging time for the industry. Your Board of Directors is committed to delivering the value from this important investment.

Chad Holliday

Chairman

It was a highly challenging year for the industry, but our integrated business and improved operational performance helped soften the impact of lower energy prices.

In these difficult economic times, our acquisition of BG Group plc (BG), which came into effect on February 15, 2016, will make us stronger.

The global portfolio we acquired is a good complement to our own. The combination will help us concentrate on more profitable pillars of our business, particularly deep water and liquefied natural gas (LNG). We are entering an exciting new era for Shell.

We continued our focus on safety. However, sadly seven people working for Shell in 2015 lost their lives. A fire at our Bukom refinery in Singapore also led to six workers being injured. Such tragic events underscore the importance of unwavering vigilance.

RESULTS

Earnings on a current cost of supplies basis attributable to Royal Dutch Shell plc shareholders were $3.8 billion in 2015, compared with $19.0 billion in 2014.

Lower oil prices and charges related to our exit from Alaska and decision to stop work on the Carmon Creek project in Canada contributed to our Upstream business making a loss in 2015. Strong performances by our Integrated Gas and Downstream businesses helped offset some of the impact of low energy prices. This is a reminder of the importance of remaining an integrated energy company.

Responding to the changing industry landscape, we reduced our operating expenses and capital investment by a combined $12.5 billion in 2015 compared with 2014. We distributed $12.0 billion to shareholders in dividends in 2015, including those taken as shares under our Scrip Dividend Programme.

Divestments amounted to $5.5 billion in 2015, and to more than $20 billion for 2014-2015. This exceeded our target of $15 billion for the period. The asset sales are part of our ongoing strategy of reducing costs and concentrating on markets where we can be most competitive.

Our oil and gas production averaged around 3 million barrels of oil equivalent per day in 2015. We started production at a major project off the coast of Nigeria which, combined with increased output from existing projects, helped partially offset the impact on production from naturally declining fields and divestments.

RENEWED FOCUS

We continue to lower our costs and take tough decisions on projects that, in the current oil-price environment, may be uncompetitive or unaffordable. For example, we stopped construction of the Carmon Creek in-situ oil project in 2015 and exited the development of the Bab sour gas project in the United Arab Emirates in early 2016. We are also postponing final investment decisions on the Bonga South West project off the coast of Nigeria and the LNG Canada facility.

Despite the current market uncertainty, it is important that we continue to invest wisely to achieve the most competitive portfolio we can. For example, we have decided to expand capacity at our Pernis refinery in the Netherlands and embark on a major expansion at our Geismar plant in the USA, reflecting the strong growth potential in chemicals for Shell.

In 2015, we announced the final investment decision to go ahead with the Appomattox deep-water project in the Gulf of Mexico.

We are prepared to reduce investments further, if evolving market conditions call for that. But we want to protect our growth prospects in a world where long-term demand for energy will continue to rise.

Greater energy efficiency and cleaner technologies are needed to help keep pace with energy demand growth, while limiting carbon dioxide (CO₂) emissions in the fight against climate change.

Meeting the energy needs of a growing world population means oil and gas are expected to continue to play vital roles in global energy supply into the latter half of the century.

Carbon capture and storage (CCS) systems that safely trap CO₂ deep underground can play an important part in the energy future. Shell started its first major CCS facility, Quest, in Canada in 2015. Government-led carbon pricing mechanisms can provide impartial and long-term incentives to invest in effective lower-carbon technologies, such as CCS.

Natural gas, the cleanest-burning hydrocarbon, can play a role in limiting emissions if more of it is used instead of coal for power generation. Gas is also making a growing contribution as a transport fuel.

As a whole, the oil and gas industry is going through a difficult period. However, our financial fortitude before the downturn and our sound strategy are helping us through the rough weather.

The acquisition of BG reinforces and reinvigorates us, and I am confident that our combined strength greatly improves our ability to thrive in a challenging business environment.

Ben van Beurden

Chief Executive Officer

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.

Measures that we use to manage or mitigate our various risks are set out in the relevant sections of this Report. The Board’s responsibility for identifying, evaluating and managing our significant risks is discussed in “Corporate governance” on page 74.

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

The 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 of each other. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, conflicts, economic conditions and actions by major oil and gas producing countries. Price fluctuations could have a material adverse effect on our business, including on our cash flows and earnings. For example, in a low oil and gas price environment, we would generate less revenue from our Upstream production, and, as a result, some long-term projects would become less profitable, or could incur losses. In this regard, if oil and gas prices remain at the levels observed in early 2016, there is the potential for our Upstream and Integrated Gas segments to incur a loss. Additionally, low oil and gas prices have resulted, and could continue to result, in the debooking of proved oil or gas reserves, if they become uneconomic in this type of price environment. Prolonged periods of low oil and gas prices, or rising costs, have resulted, and could continue to result, in projects being delayed or cancelled. In addition, assets have been impaired in the past, and there could be impairments in the future. Low oil and gas prices could also affect our ability to maintain our long-term capital investment programme and dividend payments. In a high oil and gas price environment, we could experience sharp increases in costs, and, under some production-sharing contracts, our entitlement to proved reserves would be reduced. Higher prices could also reduce demand for our products, which could result in lower profitability, particularly in our Downstream business. See “Market overview” on page 16.

Our ability to deliver competitive returns and pursue commercial opportunities depends in part on the robustness and, ultimately, the accuracy of our price assumptions.

We use oil and gas price assumptions, which we review on a periodic basis, to evaluate project decisions and commercial opportunities. While we believe our current long-term price assumptions are prudent, if our assumptions prove to be incorrect, it could have a material adverse effect on our earnings, cash flows and financial condition. See “Market overview” on page 17.

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

We face competition in each of our businesses. We seek to differentiate our products, however many of them are competing in commodity-type markets. Accordingly, failure to manage our costs as well as our operational performance could result in a material adverse effect on our earnings, cash flows and financial condition.

Increasingly, we compete with state-owned oil and gas entities, particularly in seeking access to oil and gas resources. These entities control vastly greater quantities of oil and gas resources than the major independent oil and gas companies. State-owned entities have access to significant resources and could be motivated by political or other factors in their business decisions, which could harm our competitive position or reduce our access to desirable projects. See “Strategy and outlook” on page 15.

The acquisition of BG Group plc exposes us to integration risks and other challenges.

Our future prospects will, in part, be dependent upon our ability to integrate BG Group plc (BG) successfully and completely, without disruption to our

existing business. Value delivery from a number of key jurisdictions, including BG’s assets in Australia and Brazil, as well as the integration of its LNG shipping and marketing business and trading activities and the successful execution of the substantial disposals that we expect to make following the acquisition are, in particular, critical to overall success. The BG acquisition was premised on a number of factors, including expected benefits from synergies, but also our expectation of future oil and gas prices. If these synergies do not materialise or oil and gas prices remain low for a prolonged period, this could result in future impairments and further pressure on our financial framework. We will face challenges when integrating the businesses, including standardisation of ways of working, policies and procedures, processes and systems. No assurance can be given that the integration process will deliver all the expected benefits within the assumed time frame or that the expected disposals will be made as planned. Unanticipated events, liabilities, tax impacts or unknown pre-existing issues could arise and result in the costs of integration being higher and the realisable benefits being lower than expected, with a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Strategy and outlook” on page 15.

Following the acquisition of BG, we seek to execute divestments in the pursuit of our strategy. We may not be able to successfully divest these assets in line with our strategy.

We may not be able to successfully divest assets at acceptable prices or within the timeline envisaged in view of market conditions or credit risk, resulting in increased pressure on our cash position. We may be held liable for past acts, failures to act or liabilities that are different from those foreseen. We may also face liabilities if a purchaser fails to honour all of its commitments. See “Strategy and outlook” on page 15.

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 those which are large and complex. Challenges include uncertain geology, frontier conditions, the existence and availability of necessary technology and engineering resources, the availability of skilled labour, the existence of transportation infrastructure, project delays, the 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, in frontier areas and in deep-water fields, such as in Brazil. We may fail to assess or manage these and other risks properly. Such potential obstacles could impair our delivery of these projects, our ability to fulfil the value potential at the time of the project investment approval, and our ability to fulfil related contractual commitments. These could lead to impairments and could have a material adverse effect on our operational performance, earnings, cash flows and financial condition.

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 on developing and applying new technologies and recovery processes to existing fields and mines. Failure to replace proved reserves could result in lower future production, earnings and cash flows.

See “Business overview” on page 14.

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

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 could 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 regulatory policies of host governments or other events. Estimates could 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 could also be subject to correction due to errors in the application of published rules and changes in guidance. Downward adjustments could indicate lower future production volumes and could also lead to impairment of some assets. This could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Supplementary information – oil and gas (unaudited)” on page 153.

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 contractual terms, laws and regulations. In addition, we and our joint arrangements 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; trade controls; price controls; local content requirements; foreign exchange controls; changing environmental regulations; and disclosure requirements. A prolonged period of lower oil and gas prices could affect the financial, fiscal, legal, political and social stability of countries that rely significantly on oil and gas revenue. This could, in turn, have a material adverse effect on us.

From time to time, cultural and political factors play a role in unprecedented and unanticipated judicial outcomes that could adversely affect Shell. Non-compliance with policies and regulations could result in regulatory investigations, litigation and ultimately sanctions. Certain governments and regulatory bodies have, in the opinion of Shell, exceeded their constitutional authority by: attempting unilaterally to amend or cancel existing agreements or arrangements; failing to honour existing contractual commitments; and

seeking to adjudicate disputes between private litigants. Additionally, certain governments have adopted laws and regulations that could potentially force us to violate other countries’ laws and regulations, therefore potentially subjecting us to both criminal and civil sanctions. Such developments and outcomes could have a material adverse effect on our operational performance, earnings, cash flows and financial condition.

See “Corporate governance” on page 74.

Our operations expose us to social instability, civil unrest, terrorism, piracy, acts of war and risks of pandemic diseases that could have a material adverse effect on our business.

As seen in recent years in Nigeria, North Africa and the Middle East, social and civil unrest, both in the countries in which we operate and elsewhere, can and do affect us. Such potential developments that could have a material adverse effect on us include: acts of political or economic terrorism; acts of maritime piracy; conflicts including war and 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. Pandemic diseases, such as Ebola, can affect our operations directly and indirectly. If such risks materialise, they could result in injuries, loss of life, environmental harm and disruption to business activities. See “Environment and society” on page 59.

A further erosion of the business and operating environment in Nigeria could have a material adverse effect on us.

In our Nigerian operations, we face various risks and adverse conditions which could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. These risks and conditions include: security issues surrounding the safety of our people, host communities and operations; sabotage and theft; our ability to enforce existing contractual rights; litigation; limited infrastructure; potential legislation that could increase our taxes or costs of operations; the effect of lower oil and gas prices on the government budget; and regional instability created by militant activities. In addition, the Nigerian government is contemplating new legislation to govern the petroleum industry which, if passed into law, could have a material adverse effect on our existing and future activities in that country. See “Upstream” on page 29.

Rising climate change concerns have led and could lead to additional legal and/or regulatory measures which could result in project delays or cancellations, a decrease in demand for fossil fuels and additional compliance obligations, and therefore could adversely impact our costs and/or revenue.

There is continued and increased attention to climate change from all sectors of society. This attention has led, and we expect it to continue to lead, to additional regulations designed to reduce greenhouse gas (GHG) emissions and potential demand for fossil fuels. Furthermore, we expect that a growing share of our GHG emissions will be subject to regulation, resulting in increased compliance costs and operational restrictions. If our GHG emissions rise alongside our ambitions to increase the scale of our business, our regulatory burden will increase proportionally.

We also expect that GHG regulation will focus more on suppressing demand for fossil fuels. This could result in lower revenue. In addition, we expect that GHG emissions from flaring will rise where no gas-gathering systems are in place. We intend to continue to work with our partners to find ways to capture the gas that is flared. However, governmental support is fundamental to ensure the success of individual initiatives. There is no assurance that we will be able to obtain government support.

If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions and/or GHG intensity for new and existing projects or products, we could experience additional costs or financial penalties, delayed or cancelled projects,

and/or reduced production and reduced demand for hydrocarbons, which could have a material adverse effect on our operational performance, earnings, cash flows and financial condition.

See “Environment and society” on pages 54-56.

The nature of our operations exposes us, and the communities in which we work, to a wide range of health, safety, security and environment risks.

The health, safety, security and environment (HSSE) risks to which we, and the communities in which we work, are potentially exposed cover a wide spectrum, given the geographic range, operational diversity and technical complexity of our operations. These risks include the effects of natural disasters (including weather events), 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 of business activities, and loss or suspension of our licence to operate or ability to bid on mineral rights. Accordingly, this would have a material adverse effect on our operational performance, earnings, cash flows and financial condition.

Our operations are subject to extensive HSSE regulatory requirements that often change and are likely to become more stringent over time. Operators could be asked to adjust their future production plans, as the government of the Netherlands has done, affecting production and costs. We could incur significant additional costs in the future due to compliance with HSSE requirements or as a result of violations of, or liabilities under, laws and regulations, such as fines, penalties, clean-up costs and third-party claims. Therefore, HSSE risks, should they materialise, could have a material adverse effect on us.

See “Environment and society” on page 53.

The operation of the Groningen asset in the Netherlands continues to expose communities to earth tremor risks.

Production from the Groningen asset has resulted in earth tremors in the past and tremors are expected to continue. This has resulted in damage to buildings and complaints from local communities. The Dutch government, local authorities and the operator are implementing measures to address the concerns of the local communities. The government has ordered a cap on production and a further reduction of production is possible. If the government decides not to develop the full field as currently planned, it could have a material adverse effect on our earnings, cash flows, proved reserves and financial condition. See “Environment and society” on pages 58-59 and “Upstream” on page 27.

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

Technology and innovation are essential to our efforts to meet the world’s energy demands in a competitive way. If we do not develop the right technology and products, do not have access to it or do not deploy these effectively, there could be a material adverse effect on the delivery of our strategy and our licence to operate. We operate in environments where advanced technologies are utilised. While we take measures to ensure that such technologies and products are safe for the environment and public health based on today’s knowledge, there is always the possibility of unknown or unforeseeable technological failures or environmental and health effects that could harm our reputation and licence to operate or expose us to litigation or sanctions. We seek to benefit financially from developing and deploying advanced technology. The associated costs are sometimes underestimated or delays occur. Any of these occurrences could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Business overview” on page 14.

We are exposed to treasury and trading risks, including liquidity risk, interest rate risk, foreign exchange risk, commodity price risk and credit risk. We are affected by the global macroeconomic environment as well as financial and commodity market conditions.

Our subsidiaries, joint arrangements and associates are subject to differing economic and financial market conditions around the world. Political or economic instability affects such markets. If the associated risks set out below materialise, they could have a material adverse effect on our earnings, cash flows and financial condition.

We use 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 a material adverse effect on our operations. Our financing costs could also be affected by interest rate fluctuations or any credit rating deterioration.

We are exposed to changes in currency values and to exchange controls as a result of our substantial international operations. Our reporting currency is the dollar. However, to a material extent, we hold assets and are exposed to liabilities in other currencies. We have significant financial exposure to the eurozone and could be materially affected by a significant change in the euro’s value or any structural changes to the European Union (EU) or the European Economic and Monetary Union affecting the euro. Commodity trading is an important component of our Upstream and Downstream businesses and is integrated with our supply business. While we undertake some foreign exchange and commodity hedging, we do not do so for all of our activities. Furthermore, even where hedging is in place, it may not function as expected.

We are exposed to credit risk; our counterparties could fail or could be unable to meet their payment and/or performance obligations under contractual arrangements. Although 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, thereby having a material adverse effect on us. In addition, our pension funds may invest in government bonds. Therefore, a sovereign debt downgrade or other default could have a material adverse effect on us.

See “Liquidity and capital resources” on page 50.

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 requirement of such plans; both depend on various assumptions. Volatility in capital markets, and the resulting consequences for investment performance and interest rates, could result in significant changes to the funding level of future liabilities, and could also increase balance sheet liabilities. We operate a number of defined benefit pension plans and, in case of a shortfall, we could be required to make substantial cash contributions (depending on the applicable local regulations) resulting in a material adverse effect on our business, earnings and financial condition. See “Liquidity and capital resources” on page 50.

We mainly self-insure our risk exposure. We could incur significant losses from different types of risks that are not covered by insurance from third-party insurers.

Our insurance subsidiaries provide hazard insurance coverage to other Shell entities and only reinsure a portion 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 our obligations. Therefore, we may incur significant losses from different types of risks that are not covered by insurance from third-party insurers, potentially resulting in a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Corporate” on page 48.

An erosion of our business reputation could have a material adverse effect on our brand, our ability to secure new resources and our licence to operate.

Our reputation is an important asset. The Shell General Business Principles (Principles) govern how Shell and its individual companies conduct their affairs, and the Shell Code of Conduct (Code) instructs employees and contractors on how to behave in line with the Principles. Our challenge is to ensure that all employees and contractors, more than 100,000 in total, comply with these Principles and Code. Real or perceived failures of governance or regulatory compliance could harm our reputation. This could impact our licence to operate, damage our brand, reduce consumer demand for our branded products, harm our ability to secure new resources and contracts and limit our ability to access capital markets. Many other factors, including the materialisation of the risks discussed in several of the other risk factors, may impact our reputation and could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Corporate governance” on page 70.

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

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, including reputational, litigation (where joint and several liability could apply) and government sanction risks, which could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. 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. Where we are the operator of a joint arrangement, the other partner(s) could still be able to veto or block certain decisions, which could be to our overall detriment. See “Corporate governance” on page 74.

We rely heavily on information technology systems for our operations.

The operation of many of our business processes depends on 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, is the target of attempts to gain unauthorised access to our IT systems through the internet, including more sophisticated and coordinated attempts often referred to as advanced persistent threats. We seek to detect and investigate all such security incidents, aiming to prevent their recurrence. Disruption of critical IT services, or breaches of information security, could harm our reputation and have a material adverse effect on our operational performance, earnings and financial condition. See “Corporate” on page 48.

Violations of antitrust and competition laws 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. Any violation of these laws could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. Shell and its joint ventures and associates have been fined for violations of antitrust and competition laws. These include a number of fines in the past 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 and have a material adverse effect on us. 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. See “Corporate governance” on page 70.

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

In 2010, we agreed to a Deferred Prosecution Agreement (DPA) with the US Department of Justice (DOJ) for violations of the Foreign Corrupt Practices Act (FCPA), which arose in connection with our use of the freight-forwarding firm Panalpina. In 2013, following our fulfilment of the terms of the DPA, the criminal charges filed in connection with the DPA were dismissed. Our ethics and compliance programme was enhanced during the DPA and remains in full force and effect. The authorities in various countries are investigating our investment in Nigerian oil block OPL 245 and the 2011 settlement of litigation pertaining to that block. Any violation of the FCPA or other relevant anti-bribery and corruption legislation or anti-money laundering legislation could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Corporate governance” on page 70.

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 have data protection laws and regulations. Additionally, the impending EU Data Privacy Regulation proposes to increase penalties up to a maximum of 5% of global annual turnover for breach of the regulation. Non-compliance with data protection laws could expose us to regulatory investigations, which could result in fines and penalties. We could also 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. Any violation could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Corporate governance” on page 70.

Violations of trade controls, including sanctions, carry fines and expose us and our employees to criminal sanctions and civil suits.

We use “trade controls” as an umbrella term for various national and international laws designed to regulate the movement of items across national boundaries and restrict or prohibit trade and other dealings with certain parties. The number and breadth of trade controls which we face continues to expand. For example, the EU and the USA continue to impose restrictions and prohibitions on certain transactions involving Syria. Additional trade controls directed at defined oil and gas activities in Russia were imposed by the EU and the USA in 2014. In addition to the significant trade-control programmes administered by the EU and the USA, many other nations are also adopting such programmes. Any violation of one or more trade-control regimes could lead to significant penalties or prosecution of Shell or its employees, and could have a material adverse effect on our operational performance, earnings, cash flows and financial condition. See “Corporate governance” on page 70.

Investors should also consider the following, which could limit shareholder remedies.

The Company’s Articles of Association determine the jurisdiction for shareholder disputes. This could 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 to be determined invalid or unenforceable for any reason, the dispute could 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, could be determined in accordance with these provisions.

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 production.

We explore for crude oil and natural gas worldwide, both in conventional fields and from sources such as tight rock, shale and coal formations. We work to develop new crude oil and natural gas supplies from major fields. For example, in 2015, production began from the Bonga Phase 3 and Erha

North Phase 2 projects in Nigeria, and the Corrib gas field in Ireland. We also extract bitumen from oil sands, which we convert into synthetic crude oil.

We cool natural gas to provide liquefied natural gas (LNG) that can be safely shipped to markets around the world, and we convert gas to liquids (GTL).

Our portfolio of refineries and chemical plants enables us to capture value from the oil and gas that we produce, turning them into a range of refined and petrochemical products, which are moved and marketed around the world for domestic, industrial and transport use. The products we sell include gasoline, diesel, heating oil, aviation fuel, marine fuel, LNG for transport, lubricants, bitumen and sulphur. We also produce and sell ethanol from sugar cane in Brazil, through our Raízen joint venture.

The distinctive Shell pecten, (a trademark in use since the early part of the 20th century), and trademarks in which the word Shell appears, help raise the profile of our brand globally. A strong patent portfolio underlies the technology that we employ in our various businesses. In total, we have about 12,000 granted patents and pending patent applications.

BUSINESSES AND ORGANISATION

In 2016, the Upstream International and Upstream Americas businesses were reorganised into Integrated Gas and Upstream. Our businesses and organisations described below were in place until December 31, 2015, and are consistent with the discussion of our performance in 2015 and position at December 31, 2015, in this Report.

Upstream International

Our Upstream International business manages Shell’s Upstream activities outside the Americas. It explores for and extracts 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 the LNG and GTL businesses outside the Americas, and markets and trades natural gas, including LNG, outside the Americas. 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. See “Upstream” on pages 23-40.

Upstream Americas

Our Upstream Americas business manages Shell’s Upstream activities in North and South America. It explores for and extracts 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. It manages the LNG business in the Americas, and markets and trades natural gas in the Americas. 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. See “Upstream” on pages 23-40.

Downstream

Our Downstream business manages Shell’s Oil Products activities, comprising Refining, Trading and Supply, Pipelines and Marketing, and Chemicals activities. See “Downstream” on pages 41-47.

Projects & Technology

Our Projects & Technology organisation manages the delivery of our major projects and drives research and innovation to develop new 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, contracting and procurement, wells activities and CO₂ management.

Our future hydrocarbon production depends on the delivery of large and complex projects (see “Risk factors” on page 08). Systematic management of lifecycle technical and non-technical risks is in place for each opportunity, with assurance and control activities embedded throughout the project lifecycle. We focus on the cost-effective delivery of projects through quality commercial agreements, supply-chain management and construction and engineering productivity through effective planning and simplification of delivery processes. Development of our employees’ project management competencies is underpinned by project principles, standards and processes. A dedicated competence framework, training, standards and processes exist for exploration and appraisal activities. In addition, we provide governance support for our non-operated ventures or projects.

SEGMENTAL REPORTING

Our reporting segments at December 31, 2015, were Upstream, Downstream and Corporate. Upstream combines the operating segments Upstream International and Upstream Americas. Upstream and Downstream earnings include their respective elements of Projects & Technology and of trading and supply activities. Corporate comprises Shell’s holdings and treasury organisation, including its self-insurance activities as well as its headquarters and central functions. See Note 4 to the “Consolidated Financial Statements” on page 126.

[A] Revised following a reassessment of geographical allocation, resulting in an increase in the USA and a corresponding decrease in Other Americas of $9,320 million in 2014 and $7,029 million in 2013.

With effect from 2016, our reporting segments were amended to align with the reorganisation of the Upstream business and consist of Integrated Gas, Upstream, Downstream and Corporate.

RESEARCH AND DEVELOPMENT

In 2015, research and development expenses were $1,093 million, compared with $1,222 million in 2014, and $1,318 million in 2013. Our main technology centres are in India, the Netherlands and the USA, with other centres in Canada, China, Germany, Norway, Oman and Qatar.

Technology and innovation are essential to our efforts to meet the world’s energy demands in a competitive way. If we do not develop the right technology, do not have access to it or do not deploy it effectively, this could have a material adverse effect on the delivery of our strategy and our licence to operate (see “Risk factors” on page 10). We continuously scan the external environment for technologies and innovations of potential relevance to our business. Our Chief Technology Officer oversees the development and deployment of new and differentiating technologies and innovations across Shell, seeking to align business requirements and technology requirements throughout our technology maturation process.

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 balance growth with returns, by growing our cash flow and delivering 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.

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 from liquids and natural gas production.

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.

In April 2015, we announced a recommended cash and share offer for BG Group plc (BG), and the transaction was completed on February 15, 2016. It should add significant scale and profitability, particularly in LNG worldwide and deep-water oil and gas in Brazil. It presents an opportunity to accelerate portfolio refocusing through asset sales and reduced spending, resulting in a simpler, more focused company.

With effect from 2016, we have a new upstream organisation that reflects recent changes in our portfolio. This is the platform for integration with BG and will help speed up the streamlining of the portfolio.

In Integrated Gas, we focus on liquefying natural gas (LNG) so that it can be safely shipped to markets around the world, and we convert gas to liquids (GTL).

In Upstream, we focus on exploration for new crude oil and natural gas reserves and on developing major new projects where our technology and know-how add value to the resources holders.

In Downstream, we focus on turning crude oil into a range of refined products, which are moved and marketed around the world for domestic, industrial and transport use. In addition, we produce and sell petrochemicals for industrial use worldwide.

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

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.

Our ability to achieve strategic objectives depends on how we respond to competitive forces (see “Risk factors” on page 08). We continuously assess the external environment – the markets as well as the underlying economic, political, social and environmental drivers that shape them – to anticipate changes in competitive forces and business models. We undertake regular reviews of the markets we operate in, and analyses of our competitors’ strengths and weaknesses to understand our competitive position. We maintain business strategies and plans that focus on actions and capabilities to create and sustain competitive advantage.

OUTLOOK FOR 2016 AND BEYOND

We continuously seek to improve our operating performance, with an emphasis on health, safety, security and environment, asset performance and operating costs.

In 2016, we expect organic capital investment to be around $33 billion in the current environment. We have options to further reduce capital investment, should the evolving market outlook warrant that step. We are being highly selective on new investment decisions. We are leveraging our Projects & Technology organisation’s capabilities and taking opportunities presented by the downturn to reduce both our own costs and costs in the supply chain. Asset sales are a key element of our strategy, improving our capital efficiency by focusing our investments on the most attractive growth opportunities. Divestments of non-strategic assets in 2014-15 totalled over $20 billion, successfully completing our divestment programme for that period. We expect divestments to increase to $30 billion for 2016-2018.

In addition, we expect the combination with BG to generate pre-tax synergies of $3.5 billion in operating and exploration expenses in 2018, with further upside potential. A transition organisation is in place to track the delivery of the integration plans, including the expected synergies, identification of further value upside, and move to standardised operating arrangements (see “Risk factors” on page 08).

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, divestments 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” on page 05 and “Risk factors” on pages 08-12. Forward-looking information includes the impact of the BG acquisition.

We maintain a large business portfolio across a fully-integrated value chain and are therefore exposed to oil, gas and product prices as well as refining, chemicals and marketing margins (see “Risk factors” on page 08). This diversified portfolio helps us mitigate the impact of price volatility. Our annual planning cycle and periodic portfolio reviews aim to ensure that our levels of capital investment and operating expenses are affordable in the context of a volatile price environment. We test the resilience of our projects and other opportunities against a range of oil and gas prices. We also maintain a strong balance sheet to provide resilience in times of fluctuating oil and gas prices.

GLOBAL ECONOMIC GROWTH

According to the International Monetary Fund’s (IMF) January 2016 World Economic Outlook, global economic growth was 3.1% in 2015. This fell short of the IMF’s forecast of 3.5% made at the beginning of 2015. Lower than expected economic growth in the USA and China, together with recessions in Brazil and Russia, contributed to lower global economic growth than forecast.

The IMF estimated that the eurozone economy grew by 1.5% in 2015, compared with 0.9% in 2014, US economic growth was 2.5%, compared with 2.4% in 2014, while Chinese economic growth slowed from 7.3% in 2014 to 6.9%. The average economic growth rate for emerging markets and developing economies was 4.0%, compared with 4.6% in 2014.

The IMF expects global economic growth to rise to 3.4% in 2016, but that would still be less than the annual average of 3.7% for the previous 10 years.

GLOBAL OIL AND GAS DEMAND AND SUPPLY

Reflecting the combination of the economic conditions described above and of low crude oil prices during the year, global oil demand rose by 1.8% (1.7 million barrels per day (b/d)) in 2015, according to the International Energy Agency’s (IEA) January 2016 Oil Market Report. This annual oil demand growth was the highest since 2005. Lower crude oil prices are thought to have triggered additional demand not only from end-consumers, for example in the USA, but also strategic petroleum reserves building in Asia, particularly China. Demand grew in emerging and advanced economies.

The Brent crude oil price, an international crude-oil benchmark, averaged $52/b, the lowest level since 2005. As in 2014, oil supply continued to grow faster than demand. On the non-OPEC supply side, the US Energy Information Administration reported another year of continued supply growth albeit at a slower pace. Daily production in the USA declined in the second half of 2015, as light tight oil producers drilled fewer wells in response to lower prices. However, ongoing technical improvements and increased focus on the most productive areas helped increase recovery per well. OPEC oil production grew by 1 million b/d year-on-year driven primarily by Saudi Arabia and Iraq. At the June and December OPEC meetings, it was decided not to reduce production in support of oil prices. The market interpreted these decisions as an increased risk of oversupply: crude oil prices remained low and ended the year at around $36/b for Brent compared with $54/b at the start of the year.

We estimate that global gas demand grew by less than 1% in 2015, which is much lower than the average annual growth rate of about 2.3% in the past decade. A combination of mild weather and continued moderate global economic growth led to a lower rate of demand growth in most regions. We believe that most of the growth in demand was in the USA with an estimated 10% increase over 2014, driven by its power generation and industrial sectors. Asian gas demand growth weakened in the key markets of China, Japan and Korea. Chinese demand in the first nine months of 2015 grew by only 3% year-on-year, compared with the average

15% growth seen in previous years. Gas demand across the European Union is expected to have increased by about 7% in 2015 compared with 2014, according to the latest forecast from gas industry association Eurogas. The first half of 2015 saw a significant increase of approximately 9% in gas demand, compared with the same period in 2014.

CRUDE OIL AND NATURAL GAS PRICES

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

[A] Yearly average prices are based on daily spot prices. The 2015 average price for Japan Customs-cleared Crude excludes December data.

The Brent crude oil price traded in a range of $35-67/b in 2015, ending the year at about $36/b. Both the Brent and the West Texas Intermediate (WTI) average crude oil prices for 2015 were lower than in 2014, as a result of demand growth being outpaced by continued supply growth, which has resulted in crude oil and oil products inventory levels well above their historical five-year averages.

On a yearly average basis, WTI traded at a $3/b discount to Brent in 2015, compared with $6/b in 2014. The discount widened during the spring US refinery maintenance season to about $13/b as a consequence of reduced refinery crude oil intake and therefore higher crude oil inventory levels in the landlocked Cushing, Oklahoma, trading hub. Towards the end of the year, Brent and WTI crude oil prices were nearly equal.

Looking ahead, significant price volatility can be expected in the short to medium term. Crude oil prices may strengthen if the global economy accelerates, or if supply tightens as a result of a further deceleration in non-OPEC production growth due to the current price weakness, if OPEC countries reduce their production levels, or if supply disruptions occur in major producing countries. Alternatively, crude oil prices may weaken further if economic growth slows or production continues to rise, for example from Iran after the lifting of sanctions.

Unlike crude oil pricing, which is global in nature, natural gas prices vary significantly from region to region. In the USA, the natural gas price at the Henry Hub averaged $2.6 per million British thermal units (MMBtu) in 2015, 40% lower than in 2014, and traded in a range of $1.5-3.3/MMBtu. The year 2015 began with normal winter weather and gas at the Henry Hub traded between $2 and 3.3/MMBtu through the first half of the year. But robust growth in gas production and normal weather in the summer led to a gradual decline in prices during the second half as gas in storage reached a record high of some 4 trillion cubic feet by November 2015. A relatively very warm start of the 2015-2016 winter season led to a steep decline in Henry Hub prices which then remained below $2/MMBtu for prolonged periods. In the longer term, the US market may tighten due to exports of liquefied natural gas (LNG).

In Europe, natural gas prices fell during 2015. The average natural gas price at the UK National Balancing Point was 14% lower than in 2014. At the main continental European gas trading hubs – in the Netherlands, Belgium and Germany – prices were similarly weak. Lower prices reflected ample supply which was in part driven by lower oil-indexed contract prices.

Weather, a key driver for gas demand, was mixed during the year with unusually mild temperatures in the fourth quarter.

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 generally fell in 2015 as they are predominantly indexed to the price of Japan Customs-cleared Crude (JCC), which has fallen as global crude oil prices have weakened.

CRUDE OIL AND NATURAL GAS PRICE ASSUMPTIONS

Our ability to deliver competitive returns and pursue commercial opportunities depends in part on the robustness and, ultimately, the accuracy of our price assumptions (see “Risk factors” on page 08). The range of possible future crude oil and natural gas prices used in project and portfolio evaluations is determined after a rigorous assessment of short, medium and long-term market drivers. Historical analyses, trends and statistical volatility are considered in this assessment, as are analyses of market fundamentals such as possible future economic conditions, geopolitics, actions by OPEC and other major resource holders, production 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 in new production capacity. Short-term events, such as relatively warm winters or cool summers, affect demand. Supply disruptions, due to weather or political instability, contribute to price volatility.

REFINING AND PETROCHEMICAL MARGINS

Industry gross refining margins were higher on average in 2015 than in 2014 in each of the key refining hubs in Europe, Singapore and the USA. Oil products demand growth was stronger globally, driven in part by the sustained lower crude oil price environment compared with 2014. The refining industry has seen a period of generally tightening capacity, reducing the overcapacity that has been observed for several years. However, the improved gross margins have probably delayed some further capacity rationalisation, especially in Europe.

In 2016, demand for gasoline is expected to be a key driver of gross refining margins, especially in the middle of the year, supported by demand for middle distillates. The overall outlook remains unclear because of continuing economic uncertainty, geopolitical tensions in some regions that could lead to supply disruptions, and continued overcapacity in the global refining market.

In Chemicals, Asian naphtha cracker margins increased in 2015 compared with 2014 due to periods of reduced cracker availability. European naphtha cracker margins remained high in 2015, supported by periods of low cracker availability. US ethane cracker margins were significantly lower due to a narrower differential between crude oil prices and US natural gas prices.

The outlook for petrochemicals in 2016 will depend on economic growth, especially in Asia, and developments in relative raw material prices which will be influenced by crude oil prices.

EARNINGS 2015-2014

Global realised liquids prices in 2015 were 48% lower than in 2014. Global realised natural gas prices were 27% lower than in 2014. Oil and gas production available for sale in 2015 was 2,954 thousand barrels of oil equivalent per day (boe/d) compared with 3,080 thousand boe/d in 2014. Liquids production increased by 2% and natural gas production decreased by 9% compared with 2014.

Realised refining margins were significantly higher in 2015 than in 2014, driven by stronger industry gross margins and improved availability early in 2015, which allowed our refineries to capitalise on the strong margin environment.

Earnings on a current cost of supplies basis (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 2015 CCS earnings attributable to shareholders were higher than income attributable to shareholders calculated on a FIFO basis, as shown in “Non-GAAP measures and other definitions” on page 198.

CSS earnings attributable to Royal Dutch Shell plc shareholders were $3,842 million in 2015 compared with $19,041 million in 2014.

Upstream earnings in 2015 were a loss of $5,663 million, compared with an income of $15,841 million in 2014. Lower earnings in 2015 reflected the significant decline in oil and gas prices, charges associated with management’s decision to cease Alaska drilling activities for the foreseeable future and the Carmon Creek project in Canada, higher impairment charges, lower divestment gains and the weakening of the Australian dollar and Brazilian real on deferred tax positions, partly offset by lower operating expenses and depreciation, depletion and amortisation. See “Upstream” on page 23.

Downstream earnings in 2015 were $10,243 million compared with $3,411 million in 2014. The increase was principally driven by lower operating expenses, as a result of favourable exchange rates and divestments, higher realised refining margins, and a lower effective tax rate,

together with lower impairment charges and higher divestment gains. See “Downstream” on pages 41-42.

Corporate earnings in 2015 were a loss of $425 million, compared with a loss of $156 million in 2014. See “Corporate” on page 48.

As set out in Note 4 to the “Consolidated Financial Statements” on page 127, earnings included a taxation charge of $493 million in 2015, compared with $15,038 million in 2014. This reduction was due to the significant tax credits associated with the impairment charges, and other charges related to ceasing activities in Alaska and the Carmon Creek project, and to the overall reduction in Upstream earnings before taxation as a result of lower oil and gas prices.

EARNINGS 2014-2013

CCS earnings attributable to shareholders in 2014 were 14% higher than in 2013.

Upstream earnings in 2014 were $15,841 million, compared with $12,638 million in 2013. The increase was mainly driven by increased contributions from liquids production volumes, higher divestment gains, lower exploration expenses, increased contributions from Trading and Supply and lower impairment charges. These effects were partially offset by the impact of declining oil prices and higher depreciation (excluding impairments).

Downstream earnings in 2014 were $3,411 million compared with $3,869 million in 2013, reflecting significantly higher charges for impairment which were partially offset by higher realised refining margins, higher earnings from Trading and Supply and lower operating expenses.

Corporate earnings in 2014 were a loss of $156 million, compared with a gain of $372 million in 2013.

CAPITAL INVESTMENT AND OTHER INFORMATION

Capital investment was $28.9 billion in 2015, compared with $37.3 billion in 2014, reflecting our decision to curtail spending. See “Upstream” on page 24 and “Downstream” on page 42.

Divestments were $5.5 billion in 2015, compared with $15.0 billion in 2014. See “Upstream” on page 24 and “Downstream” on page 42.

The decrease in operating expenses from $45.2 billion in 2015 to $41.1 billion in 2014 included favourable exchange rate effects and the impact of divestments. See “Upstream” on page 23 and “Downstream” on page 41.

Our return on average capital employed (ROACE) decreased to 1.9% compared with 7.1% in 2014, due to lower earnings. In 2015, 31% of our average capital employed was not generating any revenue, which reduced our ROACE by 1%. These assets included projects being developed and exploration acreage.

Gearing was 14.0% at the end of 2015, compared with 12.2% at the end of 2014. Debt and cash increased by $12.8 billion and $10.1 billion respectively, and total equity decreased by $8.7 billion. See “Liquidity and capital resources” on page 50.

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” on pages 25-26 and set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 153-161.

In 2015, proved reserves before taking production into account decreased by 220 million boe, of which 157 million boe came from Shell subsidiaries and 63 million boe from the Shell share of joint ventures and associates, including a net reduction from sales and purchases of 84 million boe. The proved reserves changes in 2015 included an addition of 600 million boe as a result of an increased entitlement share due to the lower yearly average price applied to production-sharing contracts (PSC) and tax/variable royalty contracts.

In 2015, total oil and gas production was 1,114 million boe, of which 1,078 million boe was available for sale and 36 million boe was consumed in operations. Production available for sale from subsidiaries was 880 million boe and 27 million boe was consumed in operations. The Shell share of the production available for sale of joint ventures and associates was 198 million boe and 9 million boe was consumed in operations.

Accordingly, after taking production into account, our proved reserves decreased in 2015 by 1,334 million boe to 11,747 million boe at December 31, 2015, with a decrease of 1,064 million boe from subsidiaries and a decrease of 270 million boe from the Shell share of joint ventures and associates.

KEY ACCOUNTING ESTIMATES AND JUDGEMENTS

See Note 2 to the “Consolidated Financial Statements” on pages 120-125.

LEGAL PROCEEDINGS

See Note 25 to the “Consolidated Financial Statements” on page 151.

PUBLICATION OF PROFIT ESTIMATES

In our update on fourth quarter 2015 and full year 2015 unaudited results published on January 20, 2016, we made the following profit estimates for the full year 2015:

The actual results for the full year 2015, in respect of the above profit estimates, were within the ranges stated above, and were as follows:

Total shareholder return (TSR) is the difference between the share price at the beginning of the year and the share price at the end of the year (each averaged over 30 days), plus gross dividends delivered during the calendar year (reinvested quarterly), expressed as a percentage of the share price at the beginning of the year (averaged over 30 days). The data used are a weighted average in dollars for A and B shares. The TSRs of major publicly-traded oil and gas companies can be compared directly, providing a way to determine how we are performing in relation to our 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 our ability to generate cash for both distributions to shareholders and investments. See “Liquidity and capital resources” on page 49.

Project delivery reflects our capability to complete major projects on time and within budget on the basis of targets set in our 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) and are reflected in the above index.

Production is the sum of all average daily volumes of unrefined oil and natural gas produced for sale by Shell subsidiaries and Shell’s share of those produced for sale by 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 our cash flow. See “Upstream” on page 24.

Equity sales of liquefied natural gas (LNG) is a measure of the operational performance of our Upstream business and LNG market demand. See “Upstream” on page 24.

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 the operational excellence of our Downstream manufacturing facilities. See “Downstream” on page 42.

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. See “Environment and society” on pages 53-54.

Earnings on a current cost of supplies basis (CCS earnings) 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. See “Summary of results” on page 18.

CCS earnings per share, which is on a diluted basis above, is calculated by dividing CCS earnings attributable to shareholders by the average number of shares outstanding over the year, increased by the average number of dilutive shares related to share-based compensation plans.

Capital investment is a measure used to make decisions about allocating resources and assessing performance. It is defined as capital expenditure and investments in joint ventures and associates as reported in the “Consolidated Statement of Cash Flows” plus exploration expense, excluding exploration wells written off, new finance leases and other adjustments. See “Liquidity and capital resources” on page 52 and “Non-GAAP measures reconciliations and other definitions” on page 198.

Capital investment has replaced net capital investment as a performance indicator and is aligned with the basis for capital allocation in our annual Business Plan.

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 our utilisation of the capital that we employ and is a common measure of business performance. See “Summary of results” on page 19 and “Non-GAAP measures reconciliations and other definitions” on page 199.

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 our operations are financed by debt. See “Liquidity and capital resources” on page 50.

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 our share of employees of certain additional joint operations. See “Our people” on page 60.

Proved oil and gas reserves are the total estimated quantities of oil and gas from Shell subsidiaries and Shell’s share from joint ventures and associates that geoscience and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs, 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 due to a wide variety of factors, some of which are unpredictable. See “Summary of results” on page 19.

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. See “Environment and society” on page 56.

The Energy Intensity Index (EII^TM), as described in Solomon Associates Refinery Comparative Performance Analysis Methodology 2014, is a benchmark to compare energy efficiency of fuel refineries and paraffinic base oil plants. The Solomon EII^TM is defined as the energy consumed by a refinery divided by the energy standard for the specific individual refinery configuration. See “Environment and society” on page 56.

Direct greenhouse gas emissions from facilities operated by Shell, expressed in CO₂ equivalent. See “Environment and society” on pages 55-56.

A Tier 1 process safety event is an unplanned or uncontrolled release of any material, including non-toxic and non-flammable materials, from a process with the greatest actual consequence resulting in harm to members of our workforce or a neighbouring community, damage to equipment, or exceeding a threshold quantity as defined by the API Recommended Practice 754 and IOGP Standard 456. See “Environment and society” on pages 53-54.

OVERVIEW

Our Upstream businesses explore for and extract crude oil and natural gas, often in joint arrangements with international and state-owned oil and gas companies. We also extract 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 around the world. We also convert natural gas to liquids (GTL) to provide high-quality fuels and other products, and we market and trade crude oil and natural gas (including LNG) in support of our Upstream businesses.

BUSINESS CONDITIONS

Global oil demand rose by 1.8% (1.7 million barrels per day (b/d)) in 2015, according to the International Energy Agency’s January 2016 Oil Market Report. The Brent crude oil price averaged $52/b, the lowest level since 2005. It traded in a range of $35-67/b in 2015, ending the year at about $36/b. See “Market overview” on pages 16-17.

We estimate that global gas demand grew by less than 1% in 2015, which is much lower than the average annual growth rate of about 2.3% in the past decade. In the USA, the natural gas price at the Henry Hub averaged $2.6 per million British thermal units (MMBtu) in 2015, 40% lower than in 2014, and traded in a range of $1.5-3.3/MMBtu. In Europe, natural gas prices fell during 2015. The average natural gas price at the UK National Balancing Point was 14% lower than in 2014. At the main continental European gas trading hubs – in the Netherlands, Belgium and Germany – prices were similarly weak. See “Market overview” on pages 16-17.

EARNINGS 2015-2014

Segment earnings in 2015 were a loss of $5,663 million, which included a net charge of $7,443 million. This net charge included $4,616 million in the third quarter related to impairments, redundancy and restructuring, and other items such as contract provisions and well write-offs, associated with management’s decision in the quarter to cease Alaska drilling activities for the foreseeable future and the Carmon Creek project in Canada. Charges for Alaska were $2,584 million, which included $755 million associated with well write-offs, and charges for Carmon Creek were $2,032 million. The net charge also reflected other impairment charges of some $4,575 million, principally triggered by the downward revision of our long-term oil and gas price outlook. These charges were partly offset by net gains on divestments of around $1,640 million and a credit of $604 million reflecting a statutory tax rate reduction in the UK. Other net charges of

$496 million related to the negative impact of a statutory tax rate change in Canada, redundancy and restructuring costs and the impact of fair value accounting of certain commodity derivatives and gas contracts.

Segment earnings in 2014 of $15,841 million included a net charge of $664 million, reflecting impairment charges of $2,406 million and further charges of $718 million related to an update of an Australian deferred tax asset and a deferred tax liability related to an associate company. These charges were partly offset by divestment gains of $2,073 million, the net effect of fair value accounting of commodity derivatives and certain gas contracts and the impact of amendments to our Dutch pension plan.

Excluding the net charges as described above, segment earnings in 2015 decreased by 89% compared with 2014. Earnings were principally impacted by the significant decline in oil and gas prices (around $15,875 million) and the effect of the weakening of the Australian dollar and Brazilian real on deferred tax positions (around $440 million in total). Earnings benefited from lower operating expenses, including favourable exchange rate effects and divestments (around $1,655 million in total), and decreased depreciation, depletion and amortisation (around $515 million). Integrated Gas contributed significantly (around $5.2 billion) to 2015 earnings. Upstream Americas incurred a loss in 2015, primarily driven by low oil and gas prices and the weakening of the Brazilian real, and partly offset by lower operating expenses and a more liquids-based production mix.

Global realised liquids prices were 48% lower than in 2014. Global realised gas prices were 27% lower than in 2014, with a 47% decrease in the Americas and a 24% decrease outside the Americas.

EARNINGS 2014-2013

Segment earnings in 2014 of $15,841 million included a net charge of $664 million, as described above. Segment earnings in 2013 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 credits and gains on divestments.

Excluding the net charges described above, segment earnings in 2014 increased by 9% compared with 2013, driven by increased contributions from liquids production volumes from both the start-up of new high-margin deep-water projects and improved operational performance. Earnings also

reflected lower exploration expenses, primarily driven by fewer well write-offs, and increased contributions from Trading and Supply. Earnings were impacted by declining oil prices, losses in Upstream Americas tight-gas and liquids-rich shale, and higher depreciation.

CAPITAL INVESTMENT AND DIVESTMENTS

Capital investment in 2015 was $23.5 billion compared with $31.3 billion in 2014, reflecting our decision to curtail spending by reducing the number of new investment decisions and pursuing lower-cost development solutions.

Divestments in 2015 were $2.7 billion in 2015, compared with $10.6 billion in 2014. Divestments in 2015 were mainly from the sale of OMLs 18, 29, 71 and 72, and the Nembe Creek Trunk Line (NCTL) in Nigeria, and of our interest in Elba Liquefaction Company, LLC (Elba Liquefaction). In 2014, divestments related to a portion of our shareholding in Woodside and our interest in Wheatstone in Australia, to part of our interest in Parque das Conchas (BC-10) in Brazil and to Haynesville and Pinedale in the USA.

PORTFOLIO AND BUSINESS DEVELOPMENT

We took the following key portfolio decisions in 2015:

In January 2016, in the United Arab Emirates, we decided to exit the joint development of the Bab sour gas reservoirs (Shell interest 40%) with Abu Dhabi National Oil Company (ADNOC) in the emirate of Abu Dhabi, and to stop further work on the project. The development of the project no longer fits with our strategy, particularly in view of the economic climate prevailing in the energy industry.

In February 2016, we announced that we postponed the FID on the Bonga South West deep-water project in Nigeria and that, together with our partners, we elected to postpone the FID of the proposed LNG project in Canada to late 2016.

We achieved the following operational milestones in 2015:

In Australia, production of LNG and condensate started at the Gorgon LNG project on Barrow Island, off the northwest coast, in March 2016.

We continued to divest selected assets during 2015, including the following:

In New Zealand, we agreed to sell our 83.75% interest in the Maui natural gas pipeline to First State Investments for a consideration of around $0.2 billion. The transaction is expected to be completed in 2016, subject to regulatory approval.

PRODUCTION AVAILABLE FOR SALE

In 2015, production was 2,954 thousand boe/d compared with 3,080 thousand boe/d in 2014. Liquids production increased by 2% and natural gas production decreased by 9% compared with 2014.

Production in 2015 was impacted by the divestment of a number of assets (mainly shale assets in the USA and OMLs in Nigeria), field declines, curtailment of production at Groningen in the Netherlands, licence expiries in Malaysia in 2015 and Abu Dhabi in 2014, and higher maintenance activities.

These reductions were partly offset by new field start-ups and the continued ramp-up of existing fields, in particular Cardamom and Mars B in the Gulf of Mexico and Bonga in Nigeria, which together contributed approximately 120 thousand boe/d to production in 2015. Positive PSC price effects provided further offset.

EQUITY SALES OF LNG

Equity sales of LNG of 22.6 million tonnes were 6% lower than in 2014, mainly reflecting the expiry of the Malaysia LNG Dua Joint Venture Agreement (JVA), the divestment of a portion of our shareholding in Woodside Petroleum Limited (Woodside) in Australia and increased maintenance activities.

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 section on page 33 and set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 153-161.

In 2015, proved reserves before taking production into account decreased by 220 million boe, of which 157 million boe came from Shell subsidiaries and 63 million boe from the Shell share of joint ventures and associates.

In 2015, after taking production into account, our proved reserves decreased by 1,334 million boe to 11,747 million boe at December 31, 2015.

In order to illustrate the potential impact of falling commodity prices on our 2014 proved reserves base, we replaced the 2014 yearly average price with the 2015 yearly average price in the analysis below, holding all other variables, such as 2014 costs estimates, constant. Applying this methodology, 1,707 million boe of proved reserves would have been excluded from our SEC proved reserves at December 31, 2014, if the 2015 year average price had been used. This negative price effect of 1,707 million boe was the combined result of a decrease of 2,080 million boe due to earlier economic cut-off, a decrease of 279 million boe due to proved undeveloped reserves (PUD) no longer being economic, and an increase of 652 million boe due to a higher entitlement share as a result of the lower yearly average price. The 1,707 million boe negative price effect includes reductions of 446 million boe of proved reserves for Carmon Creek, and 950 million boe for Muskeg River Mine, both in Canada. Because of actions we took during 2015, our actual outcome does not reflect this significant price effect. For example, the 2014 proved reserves associated with the Muskeg River Mine remain part of our 2015 proved reserves base because we were able to obtain significant structural cost improvements in 2015 which offset the significant decline in prices.

Shell subsidiaries

Before taking production into account, Shell subsidiaries’ proved reserves decreased by 157 million boe in 2015. This comprised a reduction of 211 million barrels of oil and natural gas liquids and an addition of 54 million boe (315 thousand million scf) of natural gas. The reduction of 157 million boe was the net effect of a reduction of 150 million boe from revisions and reclassifications; an addition of 4 million boe from improved recovery; an addition of 89 million boe from extensions and discoveries; and a net decrease of 100 million boe related to purchases and sales.

After taking into account production of 907 million boe (of which 27 million boe were consumed in operations), Shell subsidiaries’ proved reserves decreased by 1,064 million boe to 9,117 million boe at December 31, 2015.

Shell subsidiaries’ proved developed reserves decreased by 210 million boe to 6,567 million boe, and PUD decreased by 854 million boe to 2,550 million boe.

The total reduction of 157 million boe proved reserves in Shell subsidiaries before taking production into account included an increase of 595 million boe due to an increased entitlement share in production sharing and tax/variable royalty contracts due to the lower yearly average price.

SYNTHETIC CRUDE OIL

The 220 million boe reduction in total proved reserves included an addition of 230 million barrels of synthetic crude oil, largely due to a reduction in variable royalty due to the lower yearly average price. In 2015, synthetic crude oil production was 52 million barrels, of which 2 million barrels were

consumed in operations. At December 31, 2015, synthetic crude oil proved reserves were 1,941 million barrels, of which 1,405 million barrels were proved developed reserves and 536 million barrels were PUD.

BITUMEN

The 220 million boe reduction in total proved reserves included a reduction of 420 million barrels of bitumen, largely caused by the cessation of the Carmon Creek project. In 2015, bitumen crude oil production was 5 million barrels with minimal volumes consumed in operations. At December 31, 2015, bitumen crude oil proved reserves were 3 million barrels.

Shell share of joint ventures and associates

Before taking production into account, the Shell share of joint ventures and associates’ proved reserves decreased by 63 million boe in 2015. This comprised a reduction of 63 million barrels of oil and natural gas liquids and a negligible reduction of natural gas (2 thousand million scf). The reduction of 63 million boe was the net effect of a reduction of 82 million boe from revisions and reclassifications, an addition of 2 million boe from extensions and discoveries, an increase of 1 million boe from improved recovery and an increase of 16 million boe from purchases.

After taking into account production of 207 million boe (of which 9 million boe were consumed in operations), the Shell share of joint ventures and associates’ proved reserves decreased by 270 million boe to 2,630 million boe at December 31, 2015.

The Shell share of joint ventures and associates’ proved developed reserves decreased by 151 million boe to 2,055 million boe, and PUD decreased by 119 million boe to 575 million boe.

The total reduction of 63 million boe proved reserves in joint ventures and associates before taking production into account included an increase of 5 million boe due to increased entitlement share in production sharing and tax/variable royalty contracts due to the lower yearly average price.

PROVED UNDEVELOPED RESERVES

In 2015, Shell subsidiaries’ and the Shell share of joint ventures and associates’ PUD decreased by 973 million boe to 3,125 million boe. A large number of Shell fields saw reductions in PUD as a result of the lower yearly average price, with the largest reductions due to the cessation of Carmon Creek (Canada), economic limit test (ELT) failure of Stones (USA); and volumes matured to proved developed reserves in Soku (Africa) and Troll and Corrib (Europe). The most significant additions to PUD occurred in Muskeg River Mine (Canada) and Caesar Tonga (USA). The 973 million boe decrease in PUD was the net effect of a reduction of 1,070 million boe from revisions and reclassifications, an addition of 96 million boe from extensions, discoveries and improved recovery; and a net increase of 1 million boe related to purchases and sales.

During 2015, a total of 463 million boe of PUD were matured to proved developed reserves from projects coming on stream. An amount of 112 million boe was matured to proved developed reserves from contingent resource as a result of project execution during the year.

PUD held for five years or more (PUD5+) at December 31, 2015, amounted to 1,432 million boe, a decrease of 168 million boe compared with the end of 2014. These PUD5+ remain undeveloped because development either: requires the installation of gas compression and the drilling of additional wells, which will be executed when required to support existing gas delivery commitments (in the Netherlands and Russia); requires gas cap blow down which is awaiting end-of-oil production (in Nigeria); or will take longer than five years because of the complexity and scale of the project (Australia and Kazakhstan).

The decrease in PUD5+ of 168 million boe was due to the maturation of 98 million boe PUD5+ to proved developed reserves and a net reduction of 70 million boe of PUD5+ as a result of certain projects no longer passing the ELT due to the lower yearly average price and technical downward revisions to certain PUD5+, partially offset by the ageing of a small amount of PUD that are now more than five years old. Three fields – Soku (Africa), Troll (Europe) and Malampaya (Asia) – were the main contributors to the reduction from PUD5+ to proved developed reserves from compression projects being brought on stream and PUD volumes being matured to proved developed reserves. The fields with the largest PUD5+ at December 31, 2015, were Muskeg River Mine (Canada), followed by Gorgon and Jansz-lo (Oceania), Groningen (Europe), and Kashaghan (Asia).

During 2015, we spent $13.9 billion on development activities related to PUD maturation.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our producing operations under a variety of contractual obligations. Most contracts generally commit us 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, with the exception of Brunei, we met all contractual delivery commitments. In the period 2016 to 2018, we are contractually committed to deliver to third parties and joint ventures and associates a total of approximately 3,700 thousand million scf of natural gas from our 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 our delivery commitments and our proved developed reserves is estimated at 29% of our 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

In 2015, we made six notable discoveries and appraisals, including in Australia, Brazil, the UK and the USA. Discoveries will be evaluated further in order to establish the extent of commercially producible volumes they contain.

In 2015, we participated in 148 productive exploratory wells with proved reserves allocated (Shell share: 114 wells). For further information, see “Supplementary information – oil and gas (unaudited)” on page 169.

In 2015, we participated in a further 185 wells (Shell share: 117 wells) that remained pending determination at December 31, 2015.

In total, the net undeveloped acreage in our exploration portfolio decreased by around 4.8 million acres in 2015, with the largest contributions comprising acreage relinquishment in Benin, China, Gabon, Russia, Saudi Arabia, Tunisia, Ukraine and the USA; and an acreage reduction in Canada. These effects were partially offset by acreage acquisitions in Algeria, Australia, Indonesia and Myanmar.

BUSINESS AND PROPERTY

Our 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, state-owned company 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 our interests:

Europe

DENMARK

We have 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%). Corrib has the potential to supply a significant proportion of the country’s gas requirements. Gas started to flow from the field, which is 83 kilometres off Ireland’s northwest coast, on December 30, 2015.

ITALY

We have 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 Val d’Agri Phase 2 project is currently in FEED phase and work is being carried out to manage key non-technical risks. The Tempa Rossa field is under development and first oil is expected in 2018.

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.

In the second quarter of 2015, the Minister of Economic Affairs of the Netherlands (the Minister) announced a further reduction in the Groningen production for 2015 to 30 billion cubic metres (bcm), in an effort to diminish the potential for seismic activity, while allowing a further 3 bcm to be taken from the Norg underground storage to ensure security of supply. The State Council (“Raad van State”) ruled in November 2015 that the Groningen production limit be set at 27 bcm for the gas year 2016, until the Minister takes a new resolution on NAM’s production plan. The Minister is expected to approve a new development plan for Groningen no later than October 1, 2016. NAM produced 28.1 bcm from the Groningen field in 2015. While the Dutch government currently supports the full development of the Groningen gas field, any decision to change the development plan to reduce the ultimate recovery of resources would adversely affect our proved reserves. See “Risk factors” on page 10.

NAM also has a 60% interest in the Schoonebeek oil field, which has been redeveloped using enhanced oil recovery (EOR) technology. In June 2015, due to pipeline integrity issues identified, NAM decided to shut-in the Schoonebeek field. Production is expected to resume by the end of 2016. NAM also operates a significant number of other onshore gas fields and offshore gas fields in the North Sea.

NORWAY

We are a partner in 30 production licences on the Norwegian continental shelf. We are the operator in 13 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 Troll, Gjøa, Kvitebjørn and Valemon. The Draugen field has an operational waterflood.

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 have various interests where we are not the operator in the Atlantic Margin area, principally in the West of Shetland area (Clair, Shell interest 28%, and Schiehallion, Shell interest approximately 55%). We also have interests ranging from 20% to 49% in the Beryl area fields.

Waterfloods are operational in the Beryl, Clair and Pierce fields. The Schiehallion and Loyal fields production and water injection is closed-in as the fields are being redeveloped; the fields are currently planned to resume production by mid-2017.

REST OF EUROPE

We also have interests in Albania, Germany and Greenland.

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 has long-term oil and gas concession rights onshore and offshore Brunei, and sells most of its 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. Production from the Champion field is supported by water injection, and gas injection is installed in the South West Ampa field.

In addition to our interest in BSP, we are the operator for the Block A concession (Shell interest 53.9%), which is under exploration and

development, and also the 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.

We also 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 jointly develop and produce from 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, we have agreed with CNPC to appraise, develop and produce from tight-gas and liquids-rich shale formations 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%).

We also have an interest in an offshore oil and gas block in the Yinggehai basin, under a PSC (Shell interest 49%).

INDONESIA

We have a 35% participating interest in the offshore Masela block where INPEX Masela is the operator. The Masela block contains the Abadi gas field. The operator has selected an FLNG concept for the field’s development phase. The development plan approval process is ongoing with the government of Indonesia.

In May 2015, we signed a PSC with the Indonesian government for the exploration and potential development of acreage called Pulau Moa, offshore in eastern Indonesia.

IRAN

Shell transactions with Iran are disclosed separately. See “Section 13(r) of the US Securities Exchange Act of 1934 Disclosure” on page 197.

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 shareholders in Majnoon 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. Production at Majnoon averaged 211 thousand boe/d in 2014 and 206 thousand boe/d in 2015.

We also have a 20% interest in the West Qurna 1 field, which is operated by ExxonMobil.

According to the provisions of both contracts, our equity entitlement volumes will be lower than our interest implies.

We also have a 44% interest in the Basrah Gas Company, which gathers, treats and processes associated gas, produced from the Rumaila, West Qurna 1 and Zubair fields, that was previously being flared. The processed gas and associated products, such as condensate and liquefied petroleum gas (LPG), are sold primarily to the domestic market with the potential to export any surplus.

KAZAKHSTAN

We have a 16.8% interest in the North Caspian Production Sharing Agreement which covers 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 about 300 thousand boe/d, on a 100% basis, with the possibility of increasing

further with additional phases of development. Following the completion of pipeline replacement and other preparation activities, the operator expects production to start around the end of 2016.

Kashagan production will be supported by gas injection.

We also 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.

We also have a 5.43% interest in Caspian Pipeline Consortium, which owns an oil pipeline running from the Caspian Sea to the Black Sea across parts of Kazakhstan and Russia.

MALAYSIA

We explore for and produce oil and gas offshore Sabah and Sarawak under 18 PSCs, in which our interests range from 20% to 85%.

Offshore Sabah, we operate five producing oil fields (Shell interests ranging from 29% to 50%). These include the Gumusut-Kakap deep-water field (Shell interest 29%) where production via a dedicated floating production system commenced in 2014. We have additional interests ranging from 30% to 50% in PSCs for the exploration and development of four blocks. These include the Malikai deep-water field (Shell interest 35%) which we are developing, as the operator. We also have a 21% interest in the Siakap North-Petai deep-water field and a 30% interest in the Kebabangan field, neither of which we operate.

Offshore Sarawak, we are the operator of 12 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 the Tiga LNG joint venture, and to our Shell MDS GTL plant in Bintulu. In May 2015, the Malaysia LNG Dua JVA expired, resulting in the transfer of our 15% shareholding to PETRONAS, in accordance with the original JVA terms. The Malaysia LNG Dua PSC expired in August 2015, at which time we handed over the operatorship and our 50% interest to PETRONAS.

Waterflood is operational in the St. Joseph field and is under installation at the Malikai field. In the Gumusut Kakap field, both gas and water injections were commissioned in 2015 and are operational.

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: deep-water block 2B, SK318, SK319, SK320 and SK408.

We operate a GTL plant (Shell interest 72%) adjacent to the Malaysia LNG facilities in Bintulu. Using Shell technology, the plant converts 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 114,000 square kilometres. The concession expires in 2044. In various assets in PDO, production is supported by water injection, gas injection, steam injection or polymer flood projects.

We are also participating in the Mukhaizna oil field (Shell interest 17%) where steam flooding, an EOR method, is being applied.

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, which is part of the Oman LNG complex.

QATAR

Pearl in Qatar is the world’s largest GTL plant. We operate it under a development and production-sharing contract with the government. The fully-integrated facility has capacity for production, processing and transportation of 1.6 billion scf/d of gas from Qatar’s North Field. It has an installed capacity of about 140 thousand boe/d of high-quality liquid hydrocarbon products and 120 thousand boe/d of natural gas liquids (NGL) and ethane. In 2015, Pearl produced 4.1 million tonnes of GTL products.

Of Pearl’s two trains, the second train will undergo planned maintenance, starting in March 2016 and continuing into the second quarter of 2016, for an estimated two-month period. The first train underwent similar planned maintenance in 2015, which was completed in April 2015.

We have a 30% interest in Qatargas 4, which comprises integrated facilities to produce about 1.4 billion scf/d of 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 condensate and NGL. The LNG is shipped mainly to China, Europe and the United Arab Emirates.

RUSSIA

We have a 27.5% interest in Sakhalin-2, an integrated oil and gas project located in a subarctic environment. In 2015, the project produced approximately 320 thousand boe/d and the output of LNG exceeded 10 million tonnes.

Our 100% interest in an exploration and production licence for the Lenzitsky block in the Yamalo Nenets Autonomous District was relinquished in 2015. We have a 100% interest in the North Vorkutinsky 1 and North Vorkutinsky 2 exploration and production licences in Komi Republic (Timan Pechora). We also have a 50% interest through Khanty-Mansiysk Petroleum Alliance (a 50:50 joint venture with Gazprom Neft) in three exploration licence blocks in western Siberia: South Lungorsky 1, Yuilsky 4 and Yuilsky 5.

We have a 50% interest in the Salym fields in western Siberia, Khanty Mansiysk Autonomous District, where production was approximately 120 thousand boe/d in 2015. In the Salym fields, production is supported by water injection.

As a result of European Union and US sanctions prohibiting certain defined oil and gas activities in Russia, we suspended our shale oil exploration activities undertaken through Salym and Khanty-Mansiysk Petroleum Alliance in 2014.

UNITED ARAB EMIRATES

In Abu Dhabi, we 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 gas associated with the oil produced by the Abu Dhabi Company for Onshore Oil Operations (ADCO).

We were working with ADNOC on the development of the Bab sour gas reservoirs in Abu Dhabi (Shell interest 40%). However, following a careful and thorough evaluation of technical challenges and costs, we have decided to exit the joint development of the Bab sour gas reservoirs with ADNOC and to stop further work on the project.

REST OF ASIA

We also have interests in Jordan, Kuwait, Myanmar, the Philippines and Turkey.

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 about 14% in 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 the joint-arrangement participants in the NWS gas, condensate and oil fields, which produced more than 500 thousand boe/d in 2015. We provide 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 coal-bed methane assets and a domestic power business.

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 19.6%) fields. The Gorgon LNG project on Barrow Island started LNG and condensate production in March 2016.

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. Our development concept for these fields is based on our FLNG technology. The Prelude FLNG project (Shell interest 67.5%) is expected to produce about 110 thousand boe/d of gas and NGL, delivering 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG. Major milestones during 2015 were the lifting of all topsides onto the FLNG facility and the conclusion of the well drilling campaign.

We are also a partner in the Browse joint arrangement (Shell interest 27%) covering the Brecknock, Calliance and Torosa gas fields. In 2015, the Browse partners supported a FEED decision for an FLNG development.

Our other interests include a joint arrangement, with Shell as the operator, of the undeveloped Crux gas and condensate field (Shell interest 82%), and the Woodside-operated, undeveloped Sunrise gas field in the Timor Sea (Shell interest 26.6%).

We are a partner in both Shell-operated and other exploration joint arrangements where we are not the operator in multiple basins including Bonaparte, Browse, Exmouth Plateau, Greater Gorgon, Outer Canning and Outer Exmouth.

REST OF OCEANIA

We also have interests in New Zealand.

Africa

NIGERIA

Our share of production, onshore and offshore, in Nigeria was approximately 278 thousand boe/d in 2015, compared with approximately 300 thousand boe/d in 2014. Security issues and crude oil theft in the Niger Delta continued to be significant challenges in 2015.

Onshore

The Shell Petroleum Development Company of Nigeria Limited (SPDC) is the operator of a joint arrangement (Shell interest 30%) that has 17 Niger Delta onshore OMLs, which expire in 2019. Of the Nigeria onshore proved reserves, 196 million boe are expected to be produced before the expiry of

the current licences and 402 million boe beyond. To provide funding, modified carry agreements are in place for certain key projects and are being reimbursed.

SPDC supplies gas to Nigeria LNG Ltd (NLNG) mainly through its Gbaran-Ubie and Soku projects. As part of the strategic review of its interests in the eastern Niger Delta, SPDC has divested its 30% interest in OMLs 18, 29, and the NCTL. OML 25 is held for sale, subject to the resolution of pending litigation. Additional divestments may occur as a result of the strategic review.

The level of crude oil theft activities and sabotage in 2015 was significantly lower than in 2014, following the divestment of OMLs 18 and 29, and the NCTL in 2015.

In our Nigerian operations, we face various risks and adverse conditions which could have a material adverse effect on our operational performance, earnings, cash flows and financial condition (see “Risk factors” on page 09). These risks and conditions include: security issues surrounding the safety of our people, host communities and operations; sabotage and theft; our ability to enforce existing contractual rights; litigation; limited infrastructure; potential legislation that could increase our taxes or costs of operations; the effect of lower oil and gas prices on the government budget; and regional instability created by militant activities. In addition, the Nigerian government is contemplating new legislation to govern the petroleum industry which, if passed into law, could have a material adverse effect on our existing and future activities in that country. There are limitations to the extent to which we can mitigate these risks. We carry out regular portfolio assessments to remain a competitive player in Nigeria for the long term. We support the Nigerian government’s efforts to improve the efficiency, functionality and domestic benefits of Nigeria’s oil and gas industry, and monitor legislative developments for possible contribution. We monitor the security situation and liaise with host communities, governmental and non-governmental organisations to help promote peace and safe operations. We continue to provide transparency of spills management and reporting, along with our deployment of oil spill response capability and technology. We execute a maintenance strategy to support sustainable equipment reliability, and have implemented a multi-year programme to support sustainable reduction in the routine flaring of associated gas. See “Environment and society” on pages 55-56.

Offshore

Our main offshore deep-water activities are carried out by SNEPCO (Shell interest 100%) which has interests in four deep-water blocks, under PSC terms. SNEPCO operates OMLs 118 (including the Bonga field, Shell interest 55%) and 135 (Bolia and Doro, Shell interest 55%) and has a 43.75% interest in OML 133 (Erha), where we are not the operator, and a 50% interest in oil production lease 245 (Zabazaba, Etan). SNEPCO also has an approximate 43% interest in the Bonga South West/Aparo development via its 55% interest in OML 118. After close consultation with our partners, it is clear that the Bonga South West deep-water project requires further project cost reductions to make it economically viable in the current business environment. An FID is not expected before 2017.

First oil was produced in the third quarter of 2015 from the Bonga Phase 3 development. It is expected to contribute some 50 thousand boe/d at peak production through the existing Bonga FPSO export facility.

First oil was also achieved in the third quarter of 2015 from the Erha North Phase 2 development. The project, in which SNEPCO has a 43.75% interest, is a tie-back to the Erha FPSO. The Phase 2 development is expected to result in around 120 million recoverable barrels of oil from the field.

Production from the Bonga and Erha North fields is supported by water

injection. The Erha Main field production is supported by a combination of water and gas injection.

Five shallow-water licences (OMLs 71, 72, 74, 77 and 79) were renewed in December 2014 and will expire in 2034. In 2015, we sold OMLs 71 and 72, both of which were non-producing.

Liquefied natural gas

We have a 25.6% interest in NLNG, which operates six LNG trains with a total capacity of 22.0 mtpa.

REST OF AFRICA

We also have interests in Algeria, Egypt, Gabon, Namibia, South Africa and Tanzania.

North America

CANADA

We have more than 1,800 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 have significant exploration acreage offshore. Bitumen is a very heavy crude oil produced through conventional methods as well as through EOR 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 2015 through drilling programmes and investment in infrastructure to facilitate new production. We own and operate natural gas processing and sulphur-extraction plants in Alberta and natural gas processing plants in British Columbia. In 2014, we entered into a joint venture (Shell interest 50%) to evaluate an investment in an LNG export facility in Kitimat on the west coast of Canada. Together with our partners, we have elected to postpone the FID of the proposed LNG project to late 2016.

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 we also operate and is located in the Edmonton area.

We also have a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2018 to 2025. By completing the Alberta Department of Energy’s prescriptive development requirements prior to their expiry, leases may be extended.

Carbon capture and storage

The Quest carbon capture and storage project (Shell interest 60%), which is expected to capture and permanently store more than 1 mtpa of carbon dioxide from the Scotford Upgrader, began operations in late 2015.

Bitumen

We produce and market bitumen in the Peace River area of Alberta. We also have heavy oil resources in approximately 1,200 square kilometres in the Grosmont oil sands area, also in northern Alberta. We announced that we will not continue construction of the 80 thousand boe/d Carmon Creek thermal in-situ project (Shell interest 100%). We have retained the Carmon Creek leases and preserved some equipment while continuing to evaluate options for these assets.

Offshore

We have a 31.3% interest in the Sable Offshore Energy project, a natural- gas complex off the east coast of Canada, and other acreages in deep-water offshore Nova Scotia and Newfoundland. We have a 50% interest and operatorship in the Shelburne exploration project offshore Nova Scotia. We also have 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 oil from liquids-rich shales in Pennsylvania and Texas. 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 our major production area in the USA, and accounts for over 62% of our oil and gas production in the country. We have an interest in approximately 400 federal offshore production leases and our share of production averaged 253 thousand boe/d in 2015. Key producing assets are Auger, Brutus, Enchilada, Mars, Mars B, Perdido, Ram Powell and Ursa, which we operate, and Caesar Tonga and Na Kika, which we do not operate. Production from the Ursa and Perdido-Great White fields is supported by water injection. Efforts are ongoing to reinstate water injection at the Mars field.

We continued exploration, development and abandonment activities in the Gulf of Mexico in 2015, with an average contracted offshore rig fleet of seven mobile rigs and seven platform rigs. We also secured 17 blocks in the central Gulf of Mexico lease sales in 2015.

Onshore

We have significant tight-gas and liquids-rich shale acreage, centred on Pennsylvania in north-east USA and in the Delaware Permian Basin in west Texas.

California

We have a 51.8% interest in Aera Energy LLC (Aera), which operates in the San Joaquin Valley in California. Aera operates approximately 15,000 wells, producing around 130 thousand boe/d of heavy oil and gas.

Aera fields Belridge, Lost Hills, Cymric, McKittrick, Coalinga, Midway Sunset, Ventura and San Ardo are all operated under a combination of water and steam injection.

Alaska

We operated for almost 50 years off the coast of Alaska, including in the Cook Inlet, and the Beaufort and Chukchi seas, until 1998. Between 2005 and 2012, we acquired our current Alaska portfolio, which includes 339 federal leases for exploration in the Beaufort and Chukchi Seas, and 18 state leases in North Slope Beaufort coastal waters. The federal Chukchi leases expire in 2020. The vast majority of federal Beaufort leases end in 2017 and the remaining two in 2019. The state Beaufort leases end in 2022.

In September 2015, we safely drilled the Burger J well in the Chukchi Sea to a depth of 2,073 metres. The well was deemed a dry hole, and the result renders the Burger prospect uneconomic. The well was sealed and abandoned in accordance with regulations. We will not conduct further exploration offshore Alaska for the foreseeable future. This decision reflects

not only the outcome of the Burger J well, but also the high costs associated with the project, and the challenging and unpredictable federal regulatory environment for the Alaska outer continental shelf.

Subsequently, we safely demobilised all personnel and vessels from the Chukchi Sea. All operations were conducted without significant injury or environmental issues. We conveyed the results of the exploration season to stakeholders and worked closely with them in the subsequent winding down of operations.

Our leasehold in Alaska remains material and prospective, and strategies to generate value from this acreage – including lease extensions – will be developed and progressed accordingly. In October 2015, the Bureau of Safety and Environmental Enforcement denied our request to extend expiration dates for the federal leases. We have appealed the decision.

South America

BRAZIL

Offshore

We operate several deep-water producing fields in the Campos Basin. They include the BC-10 field (Shell interest 50%), which is supported with water injection, and the Bijupirá and Salema fields (Shell interest 80%). We expect to start production from the BC-10 Phase 3 project in 2016.

In January 2015, we signed a purchase and sale agreement to divest our interest in the Bijupirá and Salema fields, pending regulatory approvals. The agreement was cancelled in February 2016 and these assets therefore remain in our portfolio.

In the Santos Basin, we have a 20% interest in a 35-year PSC to develop the Libra pre-salt oil field and operate exploration block BM-S-54 (Shell interest 80%).

In August 2015, we ceased exploration on block BM-ES-27 (Shell interest 17.5%) in the Espirito Santos basins.

Onshore

In February 2015, we returned our block in the São Francisco basin area (Shell interest 60%) to the regulator.

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

REST OF SOUTH AMERICA

We also have interests in Argentina, Colombia and French Guiana. Furthermore, we have an interest in the LNG plants in Peru and Trinidad and Tobago.

Trading and Supply

We market a portion of our share of equity production of LNG and trade LNG volumes around the world through our hubs in Dubai and Singapore. We also market and trade natural gas, power, carbon-emission rights and crude oil from certain of our Upstream operations in the Americas and Europe.