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, 2014, 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 106-141), the Parent Company Financial Statements of Shell (pages 162-170) and the Financial Statements of the Royal Dutch Shell Dividend Access Trust (pages 174-178). Cross references to Form 20-F are set out on pages 2-3 of this Report.

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”.

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.

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” 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.

The energy landscape has fundamentally transformed in the nearly nine years that I have served as Chairman.

Technological advances have enabled a surge in gas and oil production from deep beneath the ocean and unlocked important new shale resources over the last few years, for example.

Shell plans to continue to invest in innovative technology, talented people and the development of new energy sources that will be vital to meet rising long-term demand, while limiting carbon emissions.

But the short-term outlook for energy markets is uncertain.

The International Monetary Fund (IMF) estimates that the world economy grew by 3.3% in 2014, unchanged from 2013. In January 2015, the IMF revised its forecast for 2015 down from 3.8% to 3.5%, pointing to concerns over the Russian and eurozone economies, combined with slowing growth in China.

Concerns over economic growth, coupled with buoyant global oil production, drove a decline in crude oil prices during the second half of 2014, ending a three-year spell of relatively high prices. Although the Brent crude oil price averaged $99 per barrel in 2014, down from $109 in 2013, it ended the year at $55.

Shell will continue to look carefully at how and where to allocate capital in an economic environment that remains fragile.

A sustained period of low oil prices could, of course, challenge the economics of some of our planned projects and make them less attractive. But we must continue to take a long-term view in a world where energy demand continues to rise.

ROBUST STRATEGY

In 2014, our steps to improve capital discipline helped deliver solid returns to shareholders. We delivered strong cash flow for the year and also completed our programme of divesting some parts of our portfolio ahead of schedule and before oil prices fell in the second half of the year.

Our strong balance sheet allows us to continue to invest, despite short-term price volatility, while our emphasis on employing innovative technologies will help make our new projects competitive sources of supply.

Many new energy resources will be needed in the longer term. Global primary energy demand could grow by 37% from 2012 to 2040, according to the International Energy Agency (IEA).

The IEA expects renewable energy to meet an increasing share of global energy needs. But its central scenario, which takes into account existing government commitments and plans, points to a 14% rise in oil consumption and a 55% rise in gas consumption by 2040.

Gas will be increasingly in demand partly because of the important role it can play in reducing carbon emissions when replacing coal, particularly in power plants.

Becoming the most competitive and innovative gas supplier has been a clear strategic goal for Shell throughout my time as Chairman, especially in liquefied natural gas (LNG), which is now central to the global trade in gas. Shell has evolved from being predominantly an oil producer to a company that produces more gas than oil.

We are building a large floating LNG production facility, called Prelude, which will help access gas resources in remote waters. Prelude is one example of the technological advances we are making to help meet future demand.

Our deep-water technology is another. It enabled us to start production in 2014 at major projects in the Gulf of Mexico and off the coasts of Malaysia and Nigeria.

Through our joint venture Raízen in Brazil, we are also now one of the world’s largest producers of low-carbon biofuel.

CLIMATE CHANGE

It is clear that new technologies will be needed to tackle climate change effectively. For example, carbon capture and storage (CCS) technology to store carbon dioxide (CO₂) safely underground could substantially reduce the amount of CO₂ emitted in energy production at lower cost than many other technologies.

But widespread government and industry support is needed to ensure that enough CCS plants are built around the world to make a substantial contribution to the wider drive to reduce CO₂.

All sectors of society must work together to combat climate change effectively. One vital and pressing step is to set up effective systems for putting a price on carbon emissions. It is an efficient way to encourage companies to change their activities in ways that have a deep and lasting impact on emissions.

I was encouraged to hear at the United Nations (UN) Climate Summit in New York in September 2014 that the need for effective carbon pricing systems had broad support. I hope that significant progress can be made on this at the crucial UN Climate Change Conference in Paris in December 2015.

INNOVATION AND INNOVATORS

I have had the privilege of working with many talented, creative and forward-thinking people at Shell. Their focus on developing innovative ways to produce and refine new energy resources should benefit our shareholders and customers in the years ahead by keeping our products competitive in any economic environment.

Perhaps the best example is the Pearl gas-to-liquids (GTL) complex in Qatar. The final decision to go ahead with the project was taken at the first Board meeting I chaired in 2006. Back then, there was some scepticism, outside Shell at least, about the project’s ambitious scope and viability as a major investment.

We proved the sceptics wrong. Today we know that a GTL project on this scale, it is the largest such plant in the world, does work. Watching Pearl develop and seeing its products now benefiting customers around the world has been one of the most rewarding experiences during my time at Shell.

Pearl’s success underscores the importance of continuing our strategy of making disciplined investments in key projects and new technologies. This is how we can compete more effectively on the global stage as we continue to create value for our customers, partners and investors.

Jorma Ollila

Chairman

After my first year as Chief Executive Officer, I am pleased to see that we are delivering on our three key priorities of improved financial performance, enhanced capital efficiency and continued strong project delivery.

We have come a long way. Shell’s earnings on a current cost of supplies basis attributable to shareholders improved in 2014 compared with 2013, largely thanks to our prudent investment strategy and delivery of major new projects around the world.

We achieved these better results despite the fall in oil prices during the second half of 2014, a decline mainly caused by plentiful supply and weak global demand.

Our improved operational performance, prudent spending and sales of assets that are not central to our strategy helped us enter this period of low oil prices from a position of strength.

But there is still work to be done. I want to see more competitive performance across Shell in 2015 and beyond.

We continued our focus on safety, but sadly five people working for Shell in 2014 lost their lives. There was also an explosion at our Moerdijk chemical plant in the Netherlands, but thankfully it caused no serious injuries.

Tragically, we lost four colleagues and eight of their family members in the Malaysia Airlines disaster over Ukraine in July. That was a deeply saddening experience for all.

2014 MILESTONES

For 2014, our earnings on a current cost of supplies basis attributable to shareholders were $19 billion, which included impairments of $5 billion and gains on divestments of $2 billion, compared with $17 billion in 2013, which included impairments of $4 billion. Net cash flow from operating activities rose to $45 billion from $40 billion in 2013.

We reduced our capital investment from $46 billion in 2013 to $37 billion.

Underlining our ongoing commitment to shareholder returns, we distributed $12 billion to shareholders in dividends, including those taken as shares under our Scrip Dividend Programme, and spent $3 billion on share repurchases in 2014. This compares with $11 billion of dividends and $5 billion of share repurchases in 2013.

Our Upstream earnings rose from 2013 to 2014, reflecting improved operational performance and the start of production from new deep-water projects. These included Gumusut-Kakap in Malaysia, which is expected to produce up to 135 thousand barrels per day of oil equivalent (boe/d) and the 40 thousand boe/d Bonga North West development off the coast of Nigeria. We also began production from the Cardamom and Olympus platforms in the Gulf of Mexico. However, production from new projects was more than offset by the expiry of a licence in Abu Dhabi and the impact of asset sales. Our oil and gas production averaged 3.1 million boe/d in 2014, 4% less than in 2013.

The integration of the Repsol liquefied natural gas (LNG) businesses acquired in January helped boost our LNG sales to 24 million tonnes, up 22% on 2013.

It was a good year for our exploration drive, with 10 notable discoveries. The resources we uncovered – including in the USA, Gabon and Malaysia – could be important sources of gas and oil for decades to come.

We continued to streamline our Downstream operations, selling most of our businesses in Australia and Italy, for example. While there is some growth potential in businesses such as chemicals, lubricants and in China, we continue to look for opportunities to reduce our costs and optimise our Downstream portfolio.

PRUDENT PATH OF GROWTH

The fall in oil prices in 2014 was part of the volatility our industry has always faced. But it underlined the importance of being selective in our investments and keeping a tight grip on costs.

Divestments, together with the initial public offering in Shell Midstream Partners, L.P., generated $15 billion in proceeds in 2014. They included shale oil and gas interests in North America and downstream businesses in several countries, meeting our target for 2014-15 well ahead of schedule. We plan to continue to divest assets in 2015.

To improve returns and control costs during this period of low prices, we have also reduced our potential spending on organic growth by $15 billion for 2015-2017. For example, together with our partners Qatar Petroleum, we have decided not to proceed with the proposed Al Karaana petrochemicals project in Qatar because it is too costly in the current environment.

We expect organic capital investment to be lower in 2015 than 2014 levels of around $35 billion. But we want to preserve our growth to ensure we continue to generate cash flow and dividends for our shareholders. That is why we are still planning to invest in economically-sound projects this year in key growth areas, such as deep water and LNG.

Clearly, we do not want to miss future growth opportunities simply because they may seem unaffordable in the low oil price world we see today.

However, in this period of economic uncertainty, we also need to remain cautious and are prepared to curb spending further if warranted by the evolving market outlook.

STRONG LONG-TERM DEMAND

In the long term, we expect demand for energy to continue to rise as populations and prosperity increase. Billions of people across the developing world need better access to energy to improve their lives.

We expect the global energy supply mix to evolve significantly in the decades ahead with gas, the cleanest-burning fossil fuel, becoming more widely used for power generation. While we expect renewables such as wind, solar and biofuels to play an increasing role, oil and gas will be vital to meet the considerable expected increase in energy demand.

At the same time, the need to tackle climate change requires effective policies that help meet the world’s energy needs while significantly reducing carbon dioxide (CO₂) emissions.

Facilities to capture and store CO₂ should be a key part of the global solution. Our Quest project to capture and safely store CO₂ from a Canadian oil sands facility is expected to be completed in 2015. We are also planning a carbon capture and storage (CCS) facility at the Peterhead gas-fired power plant in the UK.

Effective carbon-pricing systems are needed. They can drive a shift from coal- to gas-fired power generation, encourage greater energy efficiency and create the frameworks for the widespread use of CCS.

In the shorter term, the world economy is going through a period of relatively slow growth. There is no change in the long-term outlook for energy demand, however, as the global population rises and living standards improve.

We will continue our strategy of strengthening our position as a leader in the oil and gas industry while supplying energy in a responsible way.

By stepping up our drive to improve our financial performance and continuing to invest in good projects and opportunities, we are working hard to add more value for our shareholders.

This may mean making tough choices during a testing time for the energy industry. But it will help Shell deliver where it matters – the bottom line. I am determined that we can and will combine the disciplined pursuit of efficiency today with a vision of long-term sustainability which will secure our leadership role in the decades to come.

Ben van Beurden

Chief Executive Officer

HISTORY

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

Royal Dutch Shell plc (the Company) is a public limited company registered in England and Wales and headquartered in The Hague, the Netherlands.

ACTIVITIES

Shell is one of the world’s largest independent oil and gas companies in terms of market capitalisation, operating cash flow and production. We aim for strong operational performance and productive investments around the world.

We explore for oil and gas worldwide, both from conventional fields and from sources such as tight rock, shale and coal formations.

We work to develop new oil and gas supplies from major fields. For example, in 2014 we began production from the Gumusut-Kakap deep-water project in Malaysia, the Mars B and Cardamom developments in the deep-water Gulf of Mexico, USA, and the Bonga North West project off the coast of Nigeria. We also invest in expanding our integrated gas business. For example, in January 2014, we acquired a part of Repsol S.A.’s liquefied natural gas (LNG) portfolio, including supply positions in Peru and Trinidad and Tobago.

Our portfolio of refineries and chemical plants enables us to capture value from the oil and gas that we produce. Furthermore, we are a leading biofuel producer and fuel retailer in Brazil, through our Raízen joint venture. We have a strong retail position not only in the major industrialised countries, but also in developing countries. 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, Shell has more than 15,000 granted patents and pending patent applications.

BUSINESSES AND ORGANISATION

Upstream International

Our Upstream International business manages Shell’s Upstream activities outside the Americas. It explores for and recovers crude oil, natural gas and natural gas liquids, transports oil and gas, and operates the upstream and midstream infrastructure necessary to deliver oil and gas to market. Upstream International also manages 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.

Upstream Americas

Our Upstream Americas business manages Shell’s Upstream activities in North and South America. It explores for and recovers crude oil, natural gas and natural gas liquids, transports oil and gas and operates the upstream and midstream infrastructure necessary to deliver oil and gas to market. Upstream Americas also extracts bitumen from oil sands that is converted into synthetic crude oil. It manages the LNG business in the Americas, including assets in Peru and Trinidad and Tobago acquired in 2014. It also 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.

Downstream

Our Downstream business manages Shell’s refining and marketing activities for oil products and chemicals. These activities are organised into globally managed classes of business. Refining includes manufacturing, supply and shipping of crude oil. Marketing sells a range of products including fuels, lubricants, bitumen and liquefied petroleum gas (LPG) for home, transport and industrial use. Chemicals produces and markets petrochemicals for industrial customers, including the raw materials for plastics, coatings and detergents. Downstream also trades Shell’s hydrocarbons and other energy-related products, supplies the Downstream businesses and provides shipping services. Additionally, Downstream oversees Shell’s interests in alternative energy (including biofuels but excluding wind).

Projects & Technology

Our Projects & Technology organisation manages the delivery of Shell’s major projects and drives research and innovation to create technology solutions. It provides technical services and technology capability covering both Upstream and Downstream activities. It is also responsible for providing functional leadership across Shell in the areas of safety and environment, contracting and procurement, and for all wells activities and CO₂ management.

SEGMENTAL REPORTING

Our reporting segments are 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 activities. Corporate comprises Shell’s holdings and treasury organisation,

including its self-insurance activities as well as its headquarters and central functions. See Note 2 to the “Consolidated Financial Statements”.

RESEARCH AND DEVELOPMENT

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

Since 2007, we have spent more to research and develop innovative technology than any other international oil and gas company. In 2014, research and development (R&D) expenses were $1,222 million, slightly down from $1,318 million in 2013 and $1,307 million in 2012.

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

As in 2014, in 2015 we continue to focus strongly on technologies that support our various businesses and reduce the environmental footprint of our operations and products.

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

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

Prices of crude oil, natural gas, oil products and chemicals are affected by supply and demand, both globally and regionally. Moreover, prices for oil and gas can move independently from each other. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, conflicts, economic conditions and actions by major oil-producing countries. Price fluctuations could have a material effect on our business, including on our cash flows and earnings. For example, in a low oil and gas price environment, Shell would generate less revenue from its Upstream production, and as a result some long-term projects might become less profitable, or even incur losses. Additionally, low oil and gas prices could result in the debooking of proved oil or gas reserves, if they become uneconomic in this type of environment. Prolonged periods of low oil and gas prices, or rising costs, could result in projects being delayed or cancelled and/or in the impairment of some assets. They may also impact our ability to maintain our long-term investment programme. 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 might result in lower profitability, particularly in our Downstream business.

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

Shell reviews the oil and gas price assumptions it uses to evaluate project decisions and commercial opportunities on a periodic basis. We generally test projects and other opportunities against a long-term price range of $70-110 per barrel for Brent crude oil and $3.5-5.0 per million British thermal units for gas at the Henry Hub. While we believe our current long-term price assumptions are prudent, if such assumptions proved to be incorrect it could have a material adverse effect on Shell. For near-term planning purposes, we stress test the financial framework against a wider range of prices.

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

We face competition in each of our businesses. While we seek to differentiate our products, many of them are competing in commodity-type markets. If we do not manage our expenses adequately, our cost efficiency could deteriorate and our unit costs may increase. This in turn could erode our competitive position. Increasingly, we compete with government-run oil and gas companies, particularly in seeking access to oil and gas resources. Today, these government-run companies control vastly greater quantities of oil and gas resources than the major, publicly held oil and gas companies. Government-run entities have access to significant resources and may be motivated by political or other factors in their business decisions, which may harm our competitive position or hinder our access to desirable projects.

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

Shell subsidiaries, joint ventures and associates are subject to differing economic and financial market conditions throughout the world. Political or economic instability affects such markets. Shell uses debt instruments such as bonds and commercial paper to raise significant amounts of capital. Should our access to debt markets become more difficult, the potential impact on our liquidity could have an adverse

effect on our operations. Commodity trading is an important component of our Upstream and Downstream businesses and is integrated with our supply business. Treasury and trading risks include, among others, exposure to movements in interest rates, foreign exchange rates and commodity prices, counterparty default and various operational risks. As a global company doing business in more than 70 countries, we are exposed to changes in currency values and exchange controls. While we undertake some currency hedging, we do not do so for all of our activities. See Notes 6 and 19 to the “Consolidated Financial Statements”. Shell has significant financial exposure to the euro and could be materially affected by a significant change in its value or any structural changes to the European Union (EU) or the European Economic and Monetary Union affecting the euro. While we do not have significant direct exposure to sovereign debt, it is possible that our partners and customers may have exposure which could impair their ability to meet their obligations to us. Therefore, a sovereign debt downgrade or default could have a material adverse effect on Shell.

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

We face numerous challenges in developing capital projects, especially large ones. Challenges include uncertain geology, frontier conditions, the existence and availability of necessary technology and engineering resources, availability of skilled labour, project delays, expiration of licences and potential cost overruns, as well as technical, fiscal, regulatory, political and other conditions. These challenges are particularly relevant in certain developing and emerging market countries, such as Iraq and Kazakhstan, and in frontier areas, such as the Arctic. Such potential obstacles may impair our delivery of these projects, as well as our ability to fulfil related contractual commitments. Future oil and gas production will depend on our access to new proved reserves through exploration, negotiations with governments and other owners of proved reserves and acquisitions, as well as developing and applying new technologies and recovery processes to existing fields and mines. Failure to replace proved reserves could result in lower future production, cash flow and earnings.

In 2014, we have reduced our tight-gas and liquids-rich shale portfolio. If future well results do not meet our expectations, there could be additional asset sales and/or impairments.

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

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

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

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

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

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

Shell is one of the world’s leading energy brands, and its brand and reputation are important assets. The Shell General Business Principles (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. Failure – real or perceived – to follow these Principles, or other real or perceived failures of governance or regulatory compliance, could harm our reputation. This could impact our licence to operate, damage our brand, harm our ability to secure new resources and limit our ability to access the capital markets. Many other factors may impact our reputation, including those discussed in several of the other risk factors.

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

Technology and innovation are essential to Shell 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, the delivery of our strategy and our licence to operate may be adversely affected. We operate in environments where the most advanced technologies are needed. While these technologies are regarded as safe for the environment with today’s knowledge, there is always the possibility of unknown or unforeseeable environmental impacts that could harm our reputation, licence to operate or expose us to litigation or sanctions.

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

In the future, in order to help meet the world’s energy demand, we expect our production to rise and more of our production to come from higher energy-intensive sources than at present. Therefore, it is expected that both the CO₂ intensity of our production, as well as our absolute Upstream CO₂ emissions, will increase as our business grows. Examples of such developments are our in-situ Peace River project and our oil sands activities in Canada. Additionally, as production from Iraq increases, we expect that CO₂ emissions from flaring will rise as long as no gas gathering systems are in place. We continue to work with our partners to find ways to capture the gas that is flared. Over time, we expect that a growing share of our CO₂ emissions will be subject to regulation and result in increasing our costs. Furthermore, continued and increased attention to climate change, including activities by non-governmental and political organisations, as well as more interest by the broader public, is likely to lead to additional regulations designed to reduce greenhouse gas emissions. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our CO₂ emissions for new and existing projects or products, we may experience additional costs, delayed projects, reduced production and reduced demand for hydrocarbons.

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

The health, safety, security and environment (HSSE) risks to which we are potentially exposed cover a wide spectrum, given the geographic range, operational diversity and technical complexity of Shell’s daily operations. We have operations, including oil and gas production, transport and shipping of hydrocarbons, and refining, in difficult geographies or climate zones, as well as environmentally sensitive regions, such as the Arctic or maritime environments, especially in deep water. These and other operations expose the communities in which we work and us to the risk, among others, of major process safety incidents, effects of natural disasters, earth tremors, social unrest, personal health and safety lapses, and crime. If a major HSSE risk

materialises, such as an explosion or hydrocarbon spill, this could result in injuries, loss of life, environmental harm, disruption to business activities and, depending on their cause and severity, material damage to our reputation, exclusion from bidding on mineral rights and eventually loss of licence to operate. In certain circumstances, liability could be imposed without regard to Shell’s fault in the matter. Requirements governing HSSE matters often change and are likely to become more stringent over time. The operator could be asked to adjust its future production plan, as we have seen in the Netherlands, impacting production and costs. We could incur significant additional costs in the future complying with such requirements or as a result of violations of, or liabilities under, HSSE laws and regulations, such as fines, penalties, clean-up costs and third-party claims.

Shell mainly self-insures its risk exposures.

Shell insurance subsidiaries provide hazard insurance coverage to Shell entities. While from time to time the insurance subsidiaries may seek reinsurance for some of their risk exposures, such reinsurance would not provide any material coverage in the event of an incident like BP Deepwater Horizon. Similarly, in the event of a material environmental incident, there would be no material proceeds available from third-party insurance companies to meet Shell’s obligations.

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

In our Nigerian operations we face various risks and adverse conditions, some of which deteriorated during 2014. 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 impact of lower oil and gas prices on the government budget; and regional instability created by militant activities. The Nigerian government is contemplating new legislation to govern the petroleum industry which, if passed into law, would likely have a significant adverse impact on Shell’s existing and future activities in that country.

We operate in more than 70 countries that have differing degrees of political, legal and fiscal stability. This exposes us to a wide range of political developments that could result in changes to laws and regulations. In addition, Shell and its joint ventures and associates face the risk of litigation and disputes worldwide.

Developments in politics, laws and regulations can – and do – affect our operations. Potential developments include: forced divestment of assets; expropriation of property; cancellation or forced renegotiation of contract rights; additional taxes including windfall taxes, restrictions on deductions and retroactive tax claims; trade controls; local content requirements; foreign exchange controls; and changing environmental regulations and disclosure requirements. In our Upstream activities these developments can and do affect land tenure, re-writing of leases, entitlement to produced hydrocarbons, production rates, royalties and pricing. Parts of our Downstream activities are subject to price controls in some countries. From time to time, cultural and political factors play a role in unprecedented and unanticipated judicial outcomes that could adversely affect Shell. If we do not comply with policies and regulations, this may result in regulatory investigations, litigation and ultimately sanctions.

Certain governments and regulatory bodies have, in the opinion of Shell, exceeded their constitutional authority by attempting unilaterally to amend or cancel existing agreements or arrangements; by failing to honour existing contractual commitments; and by seeking to adjudicate disputes between private litigants. Additionally, certain governments have adopted laws and regulations that could potentially force us to violate other countries’ laws and regulations, thus potentially subjecting us to both criminal and civil sanctions.

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

As seen in recent years in Nigeria, north Africa and the Middle East, social and civil unrest, both in the countries in which we operate and elsewhere, can – and does – affect Shell. Such potential developments that could impact our business include acts of political or economic terrorism, acts of piracy on the high seas, conflicts including war, 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. The risks of pandemic diseases, such as Ebola, can impact our operations directly and indirectly. If such risks materialise, they could result in injuries and disruption to business activities.

We rely heavily on information technology systems for our operations.

The operation of many of our business processes depends on the availability of information technology (IT) systems. Our IT systems are increasingly concentrated in terms of geography, number of systems, and key contractors supporting the delivery of IT services. Shell, like many other multinational companies, is the target of attempts to gain unauthorised access through the internet to our IT systems, including more sophisticated and coordinated attempts often referred to as advanced persistent threats. Shell seeks to detect and investigate all such security incidents, aiming to prevent their recurrence. Disruption of critical IT services, or breaches of information security, could have adverse consequences for Shell.

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

Liabilities associated with defined benefit plans can be significant, as can the cash funding of such plans; both depend on various assumptions. Volatility in capital markets, and the resulting consequences for investment performance and interest rates, may result in significant changes to the funding level of future liabilities. In case of a shortfall, Shell might be required to make substantial cash contributions, depending on the applicable local regulations. See Note 17 to the “Consolidated Financial Statements”.

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

The estimation of proved oil and gas reserves involves subjective judgements and determinations based on available geological, technical, contractual and economic information. Estimates may change because of new information from production or drilling activities, or changes in economic factors, including changes in the price of oil or gas and changes in the taxation or regulatory policies of host governments or other events. Estimates may also be altered by acquisitions and divestments, new discoveries, and extensions of existing fields and mines, as well as the application of improved recovery techniques. Published proved oil and gas reserves estimates may also be subject to correction due to errors in the application of published rules and changes in guidance. Any downward adjustment would indicate lower future production volumes and may lead to impairment of some assets.

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

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 may apply) and government sanction risks. For example, our partners or members of a joint arrangement or an associate (particularly local partners in developing countries) may not be able to meet their financial or other obligations to the projects, threatening the viability of a given project.

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

Antitrust and competition laws apply to Shell and its joint ventures and associates in the vast majority of countries in which we do business. Shell and its joint ventures and associates have been fined for violations of antitrust and competition law. These include a number of fines 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. Violation of antitrust laws is a criminal offence in many countries, and individuals can be either imprisoned or fined. Furthermore, it is now common for persons or corporations allegedly injured by antitrust violations to sue for damages.

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

In 2010, Shell agreed to a Deferred Prosecution Agreement (DPA) with the US Department of Justice (DOJ) for violations of the Foreign Corrupt Practices Act (FCPA), which arose in connection with its use of the freight-forwarding firm Panalpina. In November 2013, following Shell’s fulfilment of the terms of the DPA, the criminal charges filed in connection with the DPA were dismissed. Shell’s ethics and compliance programme was enhanced during the DPA and remains in full force and effect. Any violations of the FCPA or other relevant anti-bribery and corruption legislation or anti-money laundering legislation could have a material adverse effect on the Company.

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

Data protection laws apply to Shell and its joint ventures and associates in the vast majority of countries in which we do business. Over 100 countries 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 Shell to regulatory investigations, which may result in fines and penalties. Shell 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.

Violations of trade controls, including sanctions, 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 faced by Shell continues to expand. For example, the EU and the USA continue to impose restrictions and prohibitions on certain transactions involving Iran and 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 may lead to significant penalties or prosecution of Shell or its employees.

We execute acquisitions and divestments in the pursuit of our strategy. A number of risks impact the success of such acquisitions and divestments.

Acquisitions may not succeed due to reasons such as difficulties in integrating activities and realising synergies, outcomes varying from key assumptions, host governments reacting or responding in a different manner from that envisaged, or liabilities and costs being

underestimated. Any of these would reduce our ability to realise the expected benefits. We may not be able to successfully divest non-core assets at acceptable prices, resulting in increased pressure on our cash position. In the case of divestments, 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.

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

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

Our Articles of Association generally require that all disputes between our shareholders in such capacity and the Company or our subsidiaries (or our Directors or former Directors), or between the Company and our Directors or former Directors, be exclusively resolved by arbitration in The Hague, the Netherlands, under the Rules of Arbitration of the International Chamber of Commerce. Our Articles of Association also provide that, if this provision is for any reason determined to be invalid or unenforceable, the dispute may only be brought to the courts of England and Wales. Accordingly, the ability of shareholders to obtain monetary or other relief, including in respect of securities law claims, may be determined in accordance with these provisions. See “Corporate governance”.

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.

Intense competition exists for access to upstream resources and to new downstream markets. But we believe that our technology, project delivery capability and operational excellence will remain key differentiators for our businesses. We expect over 80% of our capital investment in 2015 to be in our Upstream businesses.

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

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:

Meeting the growing demand for energy worldwide in ways that minimise environmental and social impact is a major challenge for the global energy industry. We aim to improve energy efficiency in our own operations, support customers in managing their energy demands and continue to research and develop technologies that increase efficiency and reduce emissions in liquids and natural gas production.

Our commitment to technology and innovation continues to be at the core of our strategy. As energy projects become more complex and more technically demanding, we believe our engineering expertise will be a deciding factor in the growth of our businesses. Our key strengths include the development and application of technology, the financial and project-management skills that allow us to deliver large field development projects, and the management of integrated value chains.

We aim to leverage our diverse and global business portfolio and customer-focused businesses built around the strength of the Shell brand.

OUTLOOK

We continuously seek to improve our operating performance, with an emphasis on health, safety and environment, asset performance and operating costs. For 2015, we will continue to focus on the three key priorities set out in 2014: improving our financial performance, enhancing our capital efficiency and continuing our focus on project delivery.

In 2015, we expect organic capital investment to be lower than 2014 levels of around $35 billion. We are considering further reductions to capital investment should the evolving market outlook warrant that step, but are aiming to retain growth potential for the medium term. Asset sales are a key element of our strategy, improving our capital efficiency by focusing our investment on the most attractive growth opportunities. Proceeds from sales of non-strategic assets in 2014, and from the initial public offering in Shell Midstream Partners, L.P., totalled $15 billion, successfully completing our divestment programme for 2014-2015. The completed divestment programme will result in various production and tax effects in 2015. We also expect higher levels of downtime in 2015, especially in Upstream and Chemicals, driven by increased maintenance activities. We will continue the initiatives started in 2014, which are expected to improve our North America resource plays and Oil Products businesses. We have new initiatives underway in 2015 that are expected to improve our upstream engine and resource plays outside the Americas. The focus of these initiatives will be on the profitability of our portfolio and growth potential.

Shell has built up a substantial portfolio of project options for future growth. This portfolio has been designed to capture energy price upside and manage Shell’s exposure to industry challenges from cost inflation and political risk. Today’s lower oil prices are creating opportunities to reduce our own costs and to take costs out of the supply chain.

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

GLOBAL ECONOMIC GROWTH

According to the International Monetary Fund’s (IMF) January 2015 World Economic Outlook, global economic growth was 3.3% in 2014, unchanged from 2013. The IMF estimated that the eurozone’s gross domestic product (GDP) grew by 0.8% in 2014 compared with a contraction of 0.5% in 2013, US growth was 2.4%, up from 2.2% in 2013, while Chinese growth slowed from 7.8% in 2013 to 7.4%. The average GDP growth rate for emerging markets and developing economies fell to 4.4%, compared with 4.7% in 2013.

Growth in 2014 fell short of the IMF’s forecast of 3.7% made at the beginning of 2014. Harsh winter weather in the first quarter weighed on US growth for the year, Japan’s growth was hampered by a substantial increase in value added tax in the second quarter, while the eurozone’s return to growth has been slow. Meanwhile, growth has slowed in important markets such as China, Russia and Brazil.

The IMF expects global economic growth to rise to 3.5% in 2015, but that would still be less than the annual average of 3.9% for the previous 10 years.

GLOBAL OIL AND GAS DEMAND AND SUPPLY

Reflecting the economic conditions described above, global oil demand rose by 0.7% (0.6 million barrels per day (b/d)) in 2014, according to the International Energy Agency’s (IEA) January 2015 Oil Market Report. The IEA repeatedly revised down its oil demand growth estimate for the year from 1.4 million b/d in early 2014. Demand grew in emerging economies, while remaining almost flat in advanced economies.

On the non-OPEC supply side, the US Energy Information Administration reported another year of continued supply growth in the Lower 48 US states: in 2014 supply grew by some 1 million b/d year-on-year. As a consequence of somewhat reduced demand growth and strong non-OPEC supply growth, oil prices fell from about $110 per barrel (/b) in mid-2014 to $75/b just ahead of the November OPEC meeting at which the members decided to maintain their production at 30 million b/d, rather than to reduce their production to balance non-OPEC supply growth. The market interpreted this decision as an increased risk of oversupply and oil prices further declined to lows of around $54/b in December.

We estimate that global gas demand grew by about 1% in 2014, similar to growth in 2013, which is much lower than the average annual growth rate of about 2.5% in the past decade. A combination of unusually mild weather, except in the USA, a decline in natural gas production and weak 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 China and the USA, driven by their power generation and industrial sectors. European gas demand has weakened over the last few years and this trend is likely to have continued in 2014, according to gas industry association Eurogas.

CRUDE OIL AND NATURAL GAS PRICES

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

[A] Yearly average prices are based on daily spot prices. The 2014 average price for Japan Customs-cleared Crude excludes December data.

The Brent crude oil price, an international crude-oil benchmark, traded in a range of $54-115/b in 2014, ending the year at $55/b. Both the Brent and the West Texas Intermediate (WTI) average crude oil prices for 2014 were lower than in 2013, as a result of demand growth being outpaced by continued non-OPEC supply growth, in particular in North America.

WTI continued to trade at a discount to Brent, and followed the Brent price trajectory. The discount narrowed compared with 2013 after an expansion in pipeline capacity helped improve access for refineries on the US Gulf Coast to WTI that is delivered to the landlocked Cushing, Oklahoma, trading hub.

Looking ahead, substantial price volatility can be expected in the short to medium term. Oil prices may strengthen if the global economy accelerates, or if supply tightens as a result of a deceleration in non-OPEC production growth due to current price weakness, in particular US light tight oil, or if supply disruptions occur in major producing countries. Alternatively, oil prices may weaken further if economic growth slows or production continues to rise.

Unlike crude oil pricing, which is global in nature, gas prices vary significantly from region to region. In the USA, the natural gas price at the Henry Hub averaged $4.3 per million British thermal units (MMBtu) in 2014, 16% higher than in 2013, and traded in a range of $2.7-7.9/MMBtu. The year began with one of the coldest winters on record and Henry Hub average monthly gas prices peaked in February at $5.8/MMBtu. But robust growth in gas production and normal weather in the summer led to a steep decline in prices from a high of $4.7/MMBtu in mid-June to $3.8/MMBtu by the end of July. An early cold snap caused a price spike to $4.4/MMBtu in mid-November, but it had fallen to $3.0/MMbtu by the end of the year.

In Europe, gas prices fell. In the UK, the average price at the UK National Balancing Point was 21% lower than in 2013. In continental Europe, price decreases at the main gas trading hubs in Belgium, Germany and the Netherlands were similar to those at the UK National Balancing Point. Lower prices reflected milder than expected weather and improved supplies of LNG on the global market. The dominance of oil-indexed gas pricing is decreasing in continental Europe, with many natural gas contracts now including spot market pricing as a major component.

We also produce and sell natural gas in regions where supply, demand and regulatory circumstances differ markedly from those in the USA or Europe. Long-term contracted LNG prices in Asia-Pacific are predominantly indexed to the price of Japan Customs-cleared Crude (JCC). In Japan, LNG import contracts have historically been indexed to the JCC benchmark.

We see growing demand for LNG in China, India, the Middle East, South America and South-east Asia. In these markets, LNG supply is offered on term and spot bases. North American export projects have been offering future gas supply linked to US Henry Hub prices.

CRUDE OIL AND NATURAL GAS PRICES FOR INVESTMENT EVALUATION

The range of possible future crude oil and natural gas prices used in project and portfolio evaluations by Shell is determined after an assessment of short-, medium- and long-term price drivers under different sets of assumptions. Historical analysis, trends and statistical volatility are considered in this assessment, as are analyses of possible future economic conditions, geopolitics, actions by OPEC, 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.

We expect oil and gas prices to remain volatile. For the purposes of making investment decisions, generally we test the economic performance of long-term projects against price ranges of $70-110/b for Brent crude oil and $3.5-5.0/MMBtu for gas at the Henry Hub. As part of our normal business practice, the range of prices used for this purpose is subject to review and change, and was last confirmed in the fourth quarter of 2014. See “Risk factors”.

REFINING AND PETROCHEMICAL MARKET TRENDS

Industry refining margins were higher on average in 2014 than in 2013 in the key refining hubs of the USA and Singapore, and were little changed in Europe. In particular, margins improved in the USA where increased domestic crude oil and natural gas production lowered oil acquisition costs (relative to international prices). Some demand growth, especially around the summer driving season in the USA, also contributed to higher US Gulf Coast margins. In 2015, increased demand for middle distillates is expected to be a key driver of refining margins, supported by demand for gasoline in the middle of the year. However, the overall outlook remains unclear because of continuing economic uncertainty, geopolitical tensions in some regions that could lead to supply disruptions and overcapacity in the global refining market.

In Chemicals, industry naphtha cracker margins increased from 2013, particularly in Asia where there was less cracker capacity available. US ethane cracker margins were high relative to naphtha cracker margins in other regions due to ample ethane supply. The outlook for petrochemicals for 2015 is dependent on the growth of the global economy, especially in Asia, and developments in raw material prices.

EARNINGS 2014-2012

Global realised liquids prices were 8% lower in 2014 than in 2013. Global realised natural gas prices were 6% lower than in 2013, with a 20% increase in the Americas and an 11% decrease outside the Americas.

Oil and gas production available for sale in 2014 was 3,080 thousand barrels of oil equivalent per day (boe/d), compared with 3,199 thousand boe/d in 2013. Liquids production was down 4% and natural gas production decreased by 4% compared with 2013. Excluding the impact of divestments, the Abu Dhabi licence expiry, production-sharing contract price effects and security impacts in Nigeria, production volumes in 2014 increased by 2% compared with 2013.

Realised refining margins in 2014 were significantly higher overall and higher in all regions apart from the US West Coast compared with 2013. The increase was driven by operational improvements and a stronger margin environment in most regions.

Earnings on a current cost of supplies basis (CCS earnings) attributable to shareholders in 2014 were 14% higher than in 2013, which in turn were 38% lower than in 2012. Segment earnings are presented on this 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 2014 CCS earnings were $4,366 million higher than earnings calculated on a FIFO basis (2013: $353 million higher; 2012: $463 million higher).

Upstream earnings in 2014 were $15,841 million, compared with $12,638 million in 2013 and $22,244 million in 2012. The 25% increase from 2013 to 2014 was mainly driven by increased contributions from liquids production volumes from both the start-up of new high-margin deep-water projects and improved operational performance, higher divestment gains, lower exploration expenses, primarily driven by fewer well write-offs, increased contributions from Trading and lower impairment charges. These effects were partially offset by the impact of declining oil prices and higher depreciation (excluding impairments). The 43% decrease from 2012 to 2013

reflected higher depreciation charges (partly driven by impairments), lower divestment gains, higher exploration expenses (mainly driven by well write-offs), higher operating expenses and lower liquids and LNG realisations. Earnings in 2013 were also impacted by a deterioration in the operating environment in Nigeria and the impact of the weakening Australian dollar on a deferred tax liability. These effects were partly offset by the contribution of our Pearl GTL plant in Qatar and higher gas price realisations in the Americas, together with net tax gains in 2013 compared with net tax charges and higher decommissioning provisions in 2012.

Downstream earnings in 2014 were $3,411 million compared with $3,869 million in 2013 and $5,382 million in 2012. The 12% decrease from 2013 to 2014 reflected significantly higher charges for impairment which were partially offset by higher realised refining margins, higher earnings from Trading and Supply and lower costs (mainly as a result of divestments). The 28% decrease from 2012 to 2013 reflected significantly lower realised refining margins and higher charges for impairment, partly offset by higher contributions from Chemicals and Trading.

Corporate earnings in 2014 were a loss of $156 million, compared with a gain of $372 million in 2013 and a loss of $203 million in 2012. Compared with 2013, Corporate earnings in 2014 reflected lower tax credits, higher net interest expense and adverse currency exchange rate effects. Compared with 2012, earnings in 2013 were higher mainly due to a tax credit, the recharge to the business segments of certain costs and lower net interest expense, partly offset by adverse currency exchange rate effects.

NET CAPITAL INVESTMENT AND GEARING

Net capital investment was $23.9 billion, 46% lower than in 2013. This was driven by higher proceeds from divestments and lower capital investment (see “Non-GAAP measures reconciliations”).

Gearing was 12.2% at the end of 2014, compared with 16.1% at the end of 2013, as a result of a significant increase in cash and cash equivalents (driven by the lower net capital investment), combined with a 2% increase in total debt and a 5% decrease in equity.

PROVED RESERVES AND PRODUCTION

Shell subsidiaries’ and the Shell share of joint ventures and associates’ estimated net proved oil and gas reserves are summarised in “Upstream” and set out in more detail in “Supplementary information – oil and gas (unaudited)”.

Total shareholder return (TSR) is the difference between the share price at the start of the year and the share price at the end of the year, plus gross dividends delivered during the calendar year (reinvested quarterly), expressed as a percentage of the year-start share price. The TSRs of major publicly traded oil and gas companies can be directly compared, providing a way to determine how Shell is performing against its industry peers.

Net cash from operating activities is the total of all cash receipts and payments associated with our sales of oil, gas, chemicals and other products. The components that provide a reconciliation from income for the period are listed in the “Consolidated Statement of Cash Flows”. This indicator reflects Shell’s ability to generate cash for both investment and distribution to shareholders.

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

Production is the sum of all average daily volumes of unrefined oil and natural gas produced for sale by Shell subsidiaries and 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 to equivalent barrels of oil to make the summation possible. Changes in production have a significant impact on Shell’s cash flow.

Equity sales of liquefied natural gas (LNG) is a measure of the operational performance of Shell’s Upstream business and LNG market demand.

Refinery and chemical plant availability is the weighted average of the actual uptime of plants as a percentage of their maximum possible uptime. The weighting is based on the capital employed adjusted for cash and non-current liabilities. It excludes downtime due to uncontrollable factors, such as hurricanes. This indicator is a measure of the operational excellence of Shell’s Downstream manufacturing facilities.

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

Earnings on a current cost of supplies 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. CCS earnings per share is calculated by dividing CCS earnings attributable to shareholders by the average number of shares outstanding. See “Summary of results” and Note 2 to the “Consolidated Financial Statements”.

Net capital investment is a measure used to make decisions about allocating resources and assessing performance. It is defined as net cash used in investing activities as reported in the “Consolidated Statement of Cash Flows” plus exploration expense, excluding exploration wells written off, new finance leases and other adjustments. See “Non-GAAP measures reconciliations”.

Return on average capital employed (ROACE) is defined as annual income, adjusted for after-tax interest expense, as a percentage of average capital employed during the year. Capital employed is the sum of total equity and total debt. ROACE measures the efficiency of Shell’s utilisation of the capital that it employs and is a common measure of business performance. See “Liquidity and capital resources – Return on average capital employed”.

Gearing is defined as net debt (total debt less cash and cash equivalents) as a percentage of total capital (net debt plus total equity), at December 31. It is a measure of the degree to which Shell’s operations are financed by debt. See Note 14 to the “Consolidated Financial Statements”.

Proved oil and gas reserves attributable to Royal Dutch Shell plc shareholders are the total estimated quantities of oil and gas from Shell subsidiaries (excluding reserves attributable to non-controlling interest) and 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, as at December 31, under existing economic conditions, operating methods and government regulations. Gas volumes are converted to barrels of oil equivalent (boe) using a factor of 5,800 standard cubic feet per barrel. Reserves are crucial to an oil and gas company, since they constitute the source of future production. Reserves estimates are subject to change based on a wide variety of factors, some of which are unpredictable. See “Risk factors”.

The operational spills indicator is the number of incidents in respect of activities where we are the operator in which 100 kilograms or more of oil or oil products were spilled as a result of those activities.

The 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.

OVERVIEW

Our Upstream businesses explore for and extract crude oil and natural gas, often in joint arrangements with international and national oil and gas companies. This includes the extraction of bitumen from mined oil sands which we convert into synthetic crude oil. We liquefy natural gas by cooling it and transport the liquefied natural gas (LNG) to customers 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 0.7% (0.6 million barrels per day (b/d)) in 2014, according to the International Energy Agency’s January 2015 Oil Market Report. Demand grew in emerging economies while remaining almost flat in advanced economies. The Brent crude oil price, an international crude-oil benchmark, traded in a range of $54-115 per barrel (/b) in 2014, ending the year at $55/b.

We estimate that global gas demand grew by about 1% in 2014, similar to growth in 2013, which is much lower than the average annual growth rate of about 2.5% in the past decade. A combination of unusually mild weather, except in the USA, a decline in natural gas production and weak 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 China and the USA, driven by their power generation and industrial sectors. European gas demand has weakened over the last few years and this trend is likely to have continued in 2014, according to gas industry association Eurogas.

EARNINGS 2014-2013

Segment earnings of $15,841 million included a net charge of $664 million, reflecting impairment charges of $2,406 million, predominantly related to tight-gas shale properties in the USA, 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 mainly related to Wheatstone and to a portion of our shareholding in Woodside Petroleum Limited (Woodside) in Australia, Oil Mining Lease (OML) 24 in Nigeria and Haynesville in the USA. Other favourable impacts mainly related to the net effect of fair value accounting of commodity derivatives and certain gas contracts, and to amendments to our Dutch pension plan.

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 gains 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. Earnings were impacted by declining oil prices, losses in Upstream Americas tight-gas and liquids-rich shale, and higher depreciation.

Global realised liquids prices were 8% lower than in 2013. Global realised gas prices were 6% lower than in 2013, with a 20% increase in the Americas and an 11% decrease outside the Americas.

Equity LNG sales volumes of 24.0 million tonnes were 22% higher than in 2013, mainly reflecting the contribution from the Atlantic LNG and Peru LNG assets following the acquisition from Repsol S.A. in January 2014, and higher volumes from Nigeria LNG which in 2013 was impacted by reduced feed gas supply and the impact of a blockade of shipments.

EARNINGS 2013-2012

Segment earnings in 2013 of $12,638 million included a net charge of $2,479 million, as described above. Segment earnings in 2012 of $22,244 million included a net gain of $2,137 million, mainly related to gains on divestments, partly offset by impairments for onshore gas assets in the USA, net tax charges and decommissioning provisions.

Excluding the net charge and net gain described above, segment earnings in 2013 decreased by 25% compared with 2012 because of higher exploration expenses (mainly driven by well write-offs), operating expenses and depreciation, and lower liquids and LNG realisations. Earnings were also impacted by a deterioration in the operating environment in Nigeria and the impact of the weakening Australian dollar on a deferred tax liability. This was partly offset by an increased contribution from our Pearl GTL plant (Pearl) in Qatar and higher gas prices in the Americas.

NET CAPITAL INVESTMENT

Net capital investment was $21 billion in 2014, compared with $39 billion in 2013. Capital investment in 2014 was $31 billion (of which $8 billion was exploration expenditure, including acquisitions of unproved properties). Capital investment in 2013 was $40 billion. Divestment proceeds were $11 billion in 2014 compared with $1 billion in 2013.

Net capital investment was lower than in 2013 mainly due to higher divestment proceeds and lower expenditure on acquisitions. Major divestment proceeds in 2014 relate to a portion of our shareholding in Woodside and to Wheatstone in Australia, Parque das Conchas (BC-10) in Brazil and Haynesville and Pinedale in the USA. In 2014, acquisition expenditure was lower than in 2013 which included the acquisition of interests in Libra and BC-10 in Brazil and expenditure for the acquisition of LNG businesses from Repsol S.A.

PORTFOLIO ACTIONS AND BUSINESS DEVELOPMENT

We achieved the following operational milestones in 2014:

In Malaysia, first oil was produced from the Shell-operated Gumusut-Kakap deep-water development (Shell interest 29%). Peak production of around 135 thousand barrels of oil equivalent per day (boe/d) is expected. Work on the gas injection facilities is continuing.

Also in Malaysia, the Siakap North-Petai development (Shell interest 21%) commenced production and is expected to deliver peak production of around 30 thousand boe/d.

In Nigeria, first oil was produced from the Shell-operated Bonga North West deep-water development (Shell interest 55%) which is expected to deliver peak production of around 40 thousand boe/d. Oil from the subsea facilities is transported by a new undersea pipeline to the existing Bonga floating production, storage and offloading (FPSO) export facility, which has been upgraded to handle the additional oil flow.

In the USA, there were two major start-ups in the deep-water Gulf of Mexico with first oil produced from the Mars B (Shell interest 71.5%) and Cardamom (Shell interest 100%) developments. Production from these developments is planned to ramp up to 80 thousand boe/d and 50 thousand boe/d respectively.

The acquisition of part of Repsol S.A.’s LNG portfolio was completed in January 2014, including LNG supply positions in Peru and Trinidad and Tobago, for a net cash purchase price of $3.8 billion, adding 7.2 million tonnes per annum (mtpa) of directly managed LNG volumes through long-term off-take agreements, including 4.2 mtpa of equity LNG plant capacity.

We also took several final investment decisions during 2014, including the following:

In Brunei, the final investment decision was taken on the Maharaja Lela South development (Shell interest 35%). The development is expected to deliver peak production of 35 thousand boe/d.

In Nigeria, we took the final investment decision on the Bonga Main Phase 3 project (Shell interest 55%). The development is expected to deliver some 40 thousand boe/d at peak production through the existing Bonga FPSO.

In the USA, we took the final investment decision on the Coulomb Phase 2 project (Shell interest 100%) in the Gulf of Mexico. The development is a subsea tie-back into the Na Kika semi-submersible storage platform and is expected to deliver some 20 thousand boe/d at peak production.

We continued to divest selected Upstream assets during 2014, including the following:

In Australia, we sold 78.27 million shares in Woodside for $3.0 billion, reducing Shell’s interest from 23% to 14%.

Also in Australia, we sold our 8% interest in the Wheatstone-lago joint venture and our 6.4% interest in the Wheatstone LNG project, which is under development, for $1.5 billion.

In Brazil, we sold a 23% interest in the Shell-operated deep-water project BC-10 to Qatar Petroleum International for $1.2 billion, including closing adjustment.

Also in Brazil, we sold our non-operated 20% interest in the BM-ES-23 concession in the Espirito Santos basin offshore for $0.2 billion.

In Canada, we sold our 100% interest in the Orion steam assisted gravity drainage project for $0.3 billion.

In Nigeria, we sold our 30% interest in OML 24 and related onshore facilities for $0.6 billion.

In Upstream Americas tight-gas and liquids-rich shale, we completed a review of our portfolio and strategy. Major divestments of non-core positions are now complete and in 2014 included our interests in:

AVAILABLE-FOR-SALE PRODUCTION

In 2014, production was 3,080 thousand boe/d compared with 3,199 thousand boe/d in 2013. Liquids and natural gas production both decreased by 4% compared with 2013.

Production was reduced by 10% as a result of the ADCO licence expiry in Abu Dhabi in January 2014, field declines and the divestment of a number of assets (mainly shale assets in the Americas and the reduction in our shareholding in Woodside).

This reduction was partly offset by new field start-ups and the continuing ramp-up of existing projects, in particular Majnoon in Iraq and Mars B and BC-10 Phase 2 in the Americas, which contributed some 130 thousand boe/d to production in 2014. Improved operational performance in 2014 provided further offset.

PROVED RESERVES

Shell subsidiaries’ and the Shell share of joint ventures and associates’ estimated net proved oil and gas reserves are summarised later in this Upstream section and set out in more detail in “Supplementary information – oil and gas (unaudited)”.

In 2014, Shell added 301 million boe of proved reserves before taking production into account, of which 271 million boe came from Shell subsidiaries and 30 million boe from the Shell share of joint ventures and associates.

The change in the yearly average commodity prices between 2013 and 2014 resulted in a net positive impact on the proved reserves of 44 million boe.

In 2014, after taking into account production, our total proved reserves declined by 863 million boe.

Shell subsidiaries

Before taking production into account, Shell subsidiaries added 271 million boe of proved reserves in 2014. This comprised 42 million barrels of oil and natural gas liquids and 229 million boe (1,329 thousand million scf) of natural gas. Of the 271 million boe: 276 million boe were from the net effects of revisions and reclassifications; 9 million boe were from improved recovery; 191 million boe came from extensions and discoveries; and a net decrease of 205 million boe related to purchases and sales.

After taking into account production of 925 million boe (of which 30 million boe were consumed in operations), Shell subsidiaries’ proved reserves decreased by 654 million boe in 2014.

Shell subsidiaries’ proved developed reserves decreased by 12 million boe to 6,777 million boe, while proved undeveloped reserves decreased by 642 million boe to 3,404 million boe.

The total addition of 271 million boe before taking production into account included a net positive impact from commodity price changes of 43 million boe of proved reserves.

SYNTHETIC CRUDE OIL

Of the 301 million boe added to proved reserves, 81 million barrels were synthetic crude oil. In 2014, we had synthetic crude oil production of 49 million barrels of which 2 million barrels were consumed in operations. At December 31, 2014, we had synthetic crude oil proved reserves of 1,763 million barrels, of which 1,273 million barrels were proved developed reserves and 490 million barrels were proved undeveloped reserves.

BITUMEN

Of the 301 million boe added to proved reserves, 12 million barrels were bitumen. The addition of 12 million barrels comprised an increase of 17 million barrels from net effects of revisions and reclassifications, and an addition of 1 million barrels from extensions and discoveries and a decrease from sales of 6 million barrels. After taking into account production of 6 million barrels, bitumen proved reserves were 428 million barrels at December 31, 2014.

Shell share of joint ventures and associates

Before taking production into account, there was an increase of 30 million boe in the Shell share of joint ventures and associates’ proved reserves in 2014. This comprised 11 million barrels of oil and natural gas liquids and 19 million boe (112 thousand million scf) of natural gas. Of the 30 million boe, 91 million boe came from the net effects of revisions and reclassifications, 8 million boe came from extensions and discoveries and a decrease of 69 million boe from sales.

After taking into account production of 239 million boe (of which 10 million boe were consumed in operations), the Shell share of joint ventures and associates’ proved reserves decreased by 209 million boe in 2014.

The Shell share of joint ventures and associates’ proved developed reserves decreased by 336 million boe to 2,206 million boe, and proved undeveloped reserves increased by 127 million boe to 694 million boe.

The total addition of 30 million boe before taking production into account was impacted by net positive impact from commodity price changes of 1 million boe of proved reserves.

Proved undeveloped reserves

In 2014, Shell subsidiaries’ and the Shell share of joint ventures and associates‘ proved undeveloped reserves (PUD) decreased by 515 million boe to 4,098 million boe. A number of Shell fields saw some changes to proved undeveloped reserves, with the largest reductions occurring in the USA in Mars and in Europe in Schiehallion. The most significant additions to the PUD occurred in Champion and Champion West in Asia and in Canada in Muskeg River Mine. The 515 million boe decrease in proved undeveloped reserves comprised: a reduction of 259 million boe from revisions; a net reclassification of 125 million boe from proved undeveloped to proved developed reserves; a net reclassification of 266 million boe from proved undeveloped reserves to contingent resource; an addition of 208 million boe from extensions, discoveries and improved recovery; and a net decrease of 73 million boe related to purchases and sales.

An amount of 174 million boe was matured to proved developed reserves from contingent resource as a result of project execution during the year.

Shell proved undeveloped reserves held for five years or more (PUD5+) at December 31, 2014, amount to 1,600 million boe, a net increase of 774 million boe compared with the end of 2013. 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 Netherlands, Norway, the Philippines 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 (in countries like Kazakhstan). The increase in PUD5+ reflects the ageing of 808 million boe PUD booked in 2009 and the transfer of 34 million boe PUD to proved developed reserves. The largest contributors to the increase of PUD5+ are Muskeg River Mine, Gorgon and Jansz-lo. Two fields, Bonga and Val d’Agri, contribute to a reduction in PUD5+ due to projects being brought on stream. The Shell fields with the largest PUD5+ are now Muskeg River Mine, followed by Gorgon, Groningen (second and third stage compression), Jansz-lo and Kashaghan.

During 2014, Shell spent $17.3 billion on development activities related to PUD maturation.

DELIVERY COMMITMENTS

Shell sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit Shell to sell quantities based on production from specified properties, although some natural gas sales contracts specify delivery of fixed and determinable quantities, as discussed below.

In the past three years, with the exception of Brunei, Shell met all contractual delivery commitments.

In the period 2015 to 2017, Shell is contractually committed to deliver to third parties and joint ventures and associates a total of

approximately 4,000 thousand million scf of natural gas from Shell subsidiaries, joint ventures and associates. The sales contracts contain a mixture of fixed and variable pricing formulae that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery.

The shortfall between Shell’s delivery commitments and its proved developed reserves is estimated at 21% of Shell’s total gas delivery commitments. This shortfall is expected to be met through the development of proved undeveloped reserves as well as new projects and purchases on the spot market.

EXPLORATION

In 2014, Shell made 10 notable discoveries, including in the USA, Gabon and Malaysia. Discoveries will be evaluated further in order to establish the extent of commercially producible volumes they contain.

In 2014, Shell participated in 151 productive exploratory wells with proved reserves allocated (Shell share: 99 wells). For further information, see “Supplementary information – oil and gas (unaudited) – Acreage and wells”.

In 2014, Shell participated in a further 126 wells (Shell share: 77 wells) that remained pending determination at December 31, 2014.

In total, the net acreage in Shell’s exploration portfolio decreased by 34,000 square kilometres, comprising acreage decreases of 13,000 square kilometres in South America (withdrawal), 11,500 square kilometres in Australia (divestment), 8,000 square kilometres in Turkey (relinquishment), 5,000 square kilometres in Canada (divestment), and increases in acreage of 11,500 square kilometres in Namibia (licence award) and 9,000 square kilometres in Greenland (equity increase).

BUSINESS AND PROPERTY

Shell subsidiaries, joint ventures and associates are involved in all aspects of upstream activities, including matters such as land tenure, entitlement to produced hydrocarbons, production rates, royalties, pricing, environmental protection, social impact, exports, taxes and foreign exchange.

The conditions of the leases, licences and contracts under which oil and gas interests are held vary from country to country. In almost all cases outside North America the legal agreements are generally granted by or entered into with a government, government entity or government-run oil and gas company, and the exploration risk usually rests with the independent oil and gas company. In North America these agreements may also be with private parties that own mineral rights. Of these agreements, the following are most relevant to Shell’s interests:

Europe

DENMARK

We 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%), which is at an advanced stage of construction. Corrib has the potential to supply a significant proportion of the country’s gas requirement. The pipeline connection between the offshore wells and the onshore processing terminal is complete. Initial operation and testing of equipment has commenced at the terminal, using gas from the national grid in advance of first gas production from the field, which is expected in 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%). During the second quarter of 2014 we entered the front-end engineering and design (FEED) phase on the non-operated project Val d’Agri Phase 2, which is expected to deliver peak production of some 65 thousand boe/d. 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. NAM also has a 60% interest in the Schoonebeek oil field, which has been redeveloped using enhanced oil recovery technology. NAM also operates a significant number of other onshore gas fields and offshore gas fields in the North Sea. In January 2015, the Minister of Economic Affairs of the Netherlands approved NAM’s production plan for the Groningen field for 2014 to 2016. This caps production levels at 42.5 billion cubic metres for 2014 and 39.4 billion cubic metres in each of 2015 and 2016, in an effort to diminish the potential for seismic activity. Since issuing his decision on the Groningen production plan, the Minister of Economic Affairs has stated that he intends to cap production at 16.5 billion cubic metres for the first half of 2015.

NORWAY

We are a partner in more than 30 production licences on the Norwegian continental shelf. We are the operator in 14 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.

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 non-operated interests in the Atlantic Margin area, principally in the West of Shetlands 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.

REST OF EUROPE

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

Asia (including the Middle East and Russia)

BRUNEI

Shell and the Brunei government are 50:50 shareholders in Brunei Shell Petroleum Company Sendirian Berhad (BSP). BSP 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.

We are the operator for the Block A concession (Shell interest 53.9%), which is under exploration and development, and also operator for exploration Block Q (Shell interest 50%). We have a 35% non-operating interest in the Block B concession, where gas and condensate are produced from the Maharaja Lela Field. In February 2014, the final investment decision was taken on the Maharaja Lela South development (Shell interest 35%). It is expected to deliver a total peak production of 35 thousand boe per day.

In addition, we have non-operating interests in deep-water exploration Block CA-2 (Shell interest 12.5%) and in exploration Block N (Shell interest 50%), both under PSCs.

CHINA

We operate the onshore Changbei tight-gas field under a PSC with China National Petroleum Corporation (CNPC). The PSC includes the development of tight gas in different geological layers of the block. In Sichuan, Shell and CNPC have agreed to appraise, develop and produce 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 three offshore oil and gas blocks in the Yinggehai basin, each 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 a floating LNG (FLNG) concept for the field’s development phase.

IRAN

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

IRAQ

We have a 45% interest in the Majnoon oil field that we operate under a technical service contract that expires in 2030. The other Majnoon shareholders are PETRONAS (30%) and the Iraqi government (25%), which is represented by the Missan Oil Company. Majnoon is located in southern Iraq and is one of the world’s largest oil fields. In 2013, we successfully restarted production and Majnoon reached the milestone of first commercial production of 175 thousand boe/d. In 2014, production at Majnoon averaged 194 thousand boe/d.

We also have a 20% interest in the West Qurna 1 field. Our participating interest in the West Qurna concession has increased from 15% to 20% when the contract was renegotiated in 2014 and the government share reduced from 25% to 5% and prorated to the funding shareholders.

According to the provisions of both contracts, Shell’s equity entitlement volumes will be lower than the Shell 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 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, increasing further with additional phases of development. After the start of production from the Kashagan field in September 2013, operations had to be stopped in October 2013 due to gas leaks from the sour gas pipeline. Following investigations, it has been decided that both the oil and the gas pipeline will be replaced. Replacement activities are ongoing, with production expected to restart in 2017.

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

MALAYSIA

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

Offshore Sabah, we operate 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 October 2014. We have additional interests ranging from 30% to 50% in PSCs for the exploration and development of four deep-water blocks. These include the Malikai field (Shell interest 35%) which is being developed with Shell as the operator. We also have a 21% interest in the Siakap North-Petai field, which commenced production in 2014, and a 30% interest in the Kebabangan field.

Offshore Sarawak, we are the operator of 17 producing gas fields (Shell interests ranging from 37.5% to 70%). Nearly all of the gas produced is supplied to Malaysia LNG in Bintulu where we have a 15% interest in the Dua (where our licence is due to expire in 2015) and Tiga LNG plants. We also have a 40% interest in the 2011 Baram Delta EOR PSC and a 50% interest in Block SK-307. Additionally, we have interests in five exploration PSCs: Deepwater Block 2B, SK318, SK319, SK408 and SK320.

We operate a gas-to-liquids (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. During 2014, the Amal steam enhanced oil recovery project has been ramping up towards its expected peak production following a successful start-up in 2013.

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

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

QATAR

Pearl in Qatar is the world’s largest GTL plant. Shell operates it under a development and production-sharing contract with the government. The fully integrated facility includes production, transport and processing 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 NGL and ethane. In 2014, Pearl produced 4.5 million tonnes of GTL products.

Of Pearl’s two trains, the first train is undergoing maintenance in the first quarter of 2015, for an estimated two month period.

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 2014, the project produced 320 thousand boe/d and the output of LNG exceeded 10 million tonnes.

We have a 100% interest in an exploration and production licence for the Lenzitsky block in the Yamalo Nenets Autonomous District. In 2014, we returned the Arkatoisky (also in the Yamalo Nenets Autonomous District) and the Barun-Yustinsky (in Kalmykia) licence blocks to the government.

We also have a 50% interest through Khanty-Mansiysk Petroleum Alliance V.O.F. (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, where production was 130 thousand boe/d in 2014.

As a result of EU and US sanctions prohibiting defined oil and gas activities in Russia, in 2014 we paused our liquids-rich shales exploration activities, which were being undertaken through Salym and Khanty-Mansiysk Petroleum Alliance V.O.F.

UNITED ARAB EMIRATES

In Abu Dhabi, we held a concessionary interest of 9.5% in the oil and gas operations run by Abu Dhabi Company for Onshore Oil Operations (ADCO) from 1939 to January 2014, when the licence expired. We also have a 15% interest in the licence of Abu Dhabi Gas Industries Limited (GASCO), which expires in 2028. GASCO exports propane, butane and heavier-liquid hydrocarbons, which it extracts from the wet gas associated with the oil produced by ADCO.

We also participate in a 30-year joint venture to potentially develop the Bab sour gas reservoirs in Abu Dhabi (Shell interest 40%). Shell and the Abu Dhabi National Oil Company are in a period of commercial and technical work that may lead to development, subject to the signing of the respective joint-venture agreements.

REST OF ASIA

Shell also has interests in India, Japan, Jordan, the Philippines, Saudi Arabia, Singapore, South Korea 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 14% in Woodside, reduced from 23% by a sale of shares in 2014. All interests in Australian assets quoted below are direct interests.

Woodside is the operator of the Pluto LNG project. Woodside is also the operator on behalf of six joint-venture participants in the NWS gas, condensate and oil fields, which produced more than 500 thousand boe/d in 2014. Shell provides technical support for the NWS development.

We have a 50% interest in Arrow Energy Holdings Pty Limited (Arrow), a Queensland-based joint venture with PetroChina. Arrow owns 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 is under construction on Barrow Island and is expected to start before the end of 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. We are developing these fields on the basis of 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. During 2014, construction of the Prelude FLNG project continued, with a major milestone being the lifting of the first topside modules onto the deck of the hull.

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

Our other interests include: a joint venture with Shell as the operator of the Crux gas and condensate field (Shell interest 82%); the Shell-operated AC/P41 block (Shell interest 75%); and the Sunrise gas field in the Timor Sea (Shell interest 26.6%). We sold our interest in the Wheatstone-Iago joint venture and our 6.4% interest in the Wheatstone LNG project during the second quarter of 2014.

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

REST OF OCEANIA

Shell also has interests in New Zealand.

Africa

NIGERIA

Shell’s share of production, onshore and offshore, in Nigeria was approximately 300 thousand boe/d in 2014, compared with

approximately 265 thousand boe/d in 2013. Security issues and crude oil theft in the Niger Delta continued to be significant challenges in 2014.

Onshore

The Shell Petroleum Development Company of Nigeria Ltd (SPDC) is the operator of a joint arrangement (Shell interest 30%) that has more than 25 Niger Delta onshore oil mining leases (OMLs), which expire in 2019. To provide funding, modified carry agreements are in place for certain key projects and are being reimbursed.

SPDC supplies gas to Nigeria LNG Ltd (NLNG) mainly through its Gbaran-Ubie and Soku projects. SPDC is undertaking a strategic review of its interests in the eastern Niger Delta and has divested its 30% interest in OML 24. Agreements have been signed for the divestment of the SPDC interests in three other onshore OMLs; completion is subject to the consent of the Federal Government of Nigeria. Additional divestments may occur as a result of the strategic review.

While the level of crude oil theft activities and sabotage in 2014 was similar to 2013, the impact on production was smaller due to various mitigation measures. During 2014, force majeure related to security issues, sabotage and crude oil theft was only declared once, compared with four times in 2013.

Offshore

Our main offshore deep-water activities are carried out by Shell Nigeria Exploration and Production Company (SNEPCO, Shell interest 100%) which has interests in four deep-water blocks. SNEPCO operates OMLs 118 (including the Bonga field, Shell interest 55%) and 135 (Bolia and Doro, Shell interest 55%) and holds a 43.75% interest in OML 133 (Erha) and a 50% interest in oil production lease 245 (Zabazaba, Etan). SNEPCO also has an approximate 43% interest in the Bonga Southwest/Aparo development via its 55% interest in OML 118. Deep-water offshore activities are typically governed through PSCs.

First oil was produced from the Bonga North West deep-water development in the third quarter of 2014, while in October the final investment decision on the Bonga Main phase 3 project was taken, which is expected to contribute some 40 thousand boe/d at peak production through the existing Bonga FPSO export facility.

SPDC also has an interest in six shallow-water offshore leases, of which five are under final negotiation for extension for a period of 20 years.

Liquefied natural gas

Shell has a 25.6% interest in NLNG, which operates six LNG trains with a total capacity of 22.0 mtpa. In 2014, LNG production was higher than in 2013, as 2013 was impacted by gas supply constraints and the impact of a blockade of NLNG export facilities by the Nigerian Maritime Administration and Safety Agency.

REST OF AFRICA

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

North America

CANADA

We have more than 1,900 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 enhanced oil recovery methods. Synthetic crude oil is produced by mining bitumen-saturated sands, extracting the bitumen from the sands and transporting it to a processing facility where hydrogen is added to produce a wide range of feedstocks for refineries.

Gas and liquids-rich shale

We continued to develop fields in Alberta and British Columbia during 2014 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 Colombia. During 2014, we began decommissioning our Burnt Timber gas facility in Alberta. Also 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. This project completed FEED in 2014, with the final investment decision expected not earlier than 2016 and cash flows expected early next decade.

Synthetic crude oil

We operate the Athabasca Oil Sands Project (AOSP) in north-east Alberta as part of a joint arrangement (Shell interest 60%). The bitumen is transported by pipeline for processing at the Scotford Upgrader, which is also operated by Shell and located in the Edmonton area. The Quest carbon capture and storage project (Shell interest 60%), which is expected to capture and permanently store more than 1 mtpa of CO₂ from the Scotford Upgrader, is under construction and is expected to start operation towards the end of 2015.

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 a certain minimum level of development prior to their expiry, leases may be extended.

Bitumen

We produce and market bitumen in the Peace River area of Alberta. Additional heavy oil resources and advanced recovery technologies are under evaluation on approximately 1,200 square kilometres in the Grosmont oil sands area, also in northern Alberta. Construction of our Carmon Creek project (Shell interest 100%), which began in 2013, continues. Carmon Creek is an in-situ project that is expected to produce up to 80 thousand boe/d.

Offshore

We have a 31.3% interest in the Sable Offshore Energy project, a natural-gas complex off the east coast of Canada and other acreages in deep-water offshore Nova Scotia and Newfoundland. During 2014, we sold a 50% interest in the Shelburne project offshore Nova Scotia and retain a 50% interest as operator. 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 50% of Shell’s oil and gas production in the country. We have an interest in approximately 450 federal offshore leases and our share of production averaged almost 225 thousand boe/d in 2014. Key producing assets are Auger, Brutus, Enchilada, Mars, Na Kika, Olympus, Perdido, Ram-Powell and Ursa.

We continued significant exploration and development activities in the Gulf of Mexico in 2014, with an average contracted offshore rig fleet of nine mobile rigs and five platform rigs. We also secured five blocks in the central and western lease sales in 2014.

Onshore

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

During 2014, we divested our interests in the Eagle Ford shale formation in Texas, the Mississippi Lime in Kansas, the Utica shale position in Ohio and our acreage in the Sandwash Niobrara basins in Colorado. In addition, we sold our Haynesville gas assets in Louisiana for cash and sold our Pinedale gas assets in Wyoming in exchange for cash and additional acreage in the Marcellus and Utica shale areas in Pennsylvania.

In recent years, we have invested significant amounts in our tight-gas and liquids-rich shale portfolio. There is still a large amount of drilling that must be conducted in our properties in order to establish our future plans. Following the asset sales in 2014, the current focus is on de-risking and future development of our core assets, while continuing to look for options to enhance the value of our portfolio in the current market.

California

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

Alaska

We have more than 410 federal leases for exploration in the Beaufort and Chukchi seas in Alaska. In January 2014, we decided to suspend our 2014 drilling campaign due to obstacles raised by the Ninth Circuit Court of Appeal’s decision with regard to the Department of the Interior’s (DOI) 2008 oil and gas lease sale in the Chukchi Sea. In August 2014, we submitted an Exploration Plan for a two-rig programme in the Chukchi Sea. In November 2014, the DOI issued a draft Supplemental Environmental Impact Statement (SEIS) and the comment period closed in December 2014. We anticipate that the DOI will continue to work in accordance with their proposed timeline to complete the SEIS in sufficient time to allow us to pursue our plans to drill in 2015.

REST OF NORTH AMERICA

Shell also has interests in Mexico.

South America

BRAZIL

We are the operator of several producing fields in the Campos Basin, offshore Brazil. They include the Bijupirá and Salema fields (Shell interest 80%) and the BC-10 field (Shell interest 50%). We started production from the BC-10 Phase 2 project in October 2013, which reached peak production of 41 thousand boe/d in 2014. In 2013, we exercised our pre-emptive rights to acquire an additional 23% in the BC-10 project and in 2014 we sold a 23% interest to Qatar Petroleum International, which returned our interest to 50%.

We operate one block in the São Francisco onshore basin area (Shell interest 60%) and operate one offshore exploration block in the Santos Basin, BM-S-54 (Shell interest 80%). We also have an interest in one offshore exploration block in the Espirito Santo basins, BM-ES-27 (Shell interest 17.5%). In November 2014, we divested our 20% interest in BM-ES-23.

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

We have a 20% interest in a 35-year PSC to develop the Libra pre-salt oil field located in the Santos Basin.

In January 2015, we reached an agreement to divest our operating interest in our deep-water production asset Bijupira Salema, pending regulatory approvals.

REST OF SOUTH AMERICA

The acquisition of part of Repsol S.A.’s LNG portfolio was completed in January 2014, including LNG supply positions in Peru and Trinidad and Tobago, adding 7.2 mtpa of directly managed LNG volumes through long-term off-take agreements, including 4.2 mtpa of equity LNG plant capacity.

Shell also has interests in Argentina, Colombia, French Guiana and Venezuela.

Trading

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