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, 2016, 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 117-152), the Parent Company Financial Statements of Shell (pages 171-179) and the Financial Statements of the Royal Dutch Shell Dividend Access Trust (page 183-186). Cross references to Form 20-F are set out on pages 02-03 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”. “Joint ventures” and “joint operations” are collectively referred to as “joint arrangements”.

The acquisition of BG Group plc (BG) was completed on February 15, 2016. For practical purposes, BG was consolidated within Shell’s results with effect from February 1, 2016. The additional period is immaterial to the financial and operational performance of Shell.

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

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

This Report contains forward-looking statements (within the meaning of the US Private Securities Litigation Reform Act of 1995) concerning the financial condition, results of operations and businesses of Shell. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Shell to market risks and statements expressing

management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “goals”, “intend”, “may”, “objectives”, “outlook”, “plan”, “probably”, “project”, “risks”, “schedule”, “seek”, “should”, “target”, “will” and similar terms and phrases. There are a number of factors that could affect the future operations of Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this Report, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for Shell’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserves estimates; (f) loss of market share and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including regulatory measures addressing climate change; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. Also see “Risk factors” on pages 12-15 for additional risks and further discussion. There can be no assurance that future dividend payments will match or exceed previous dividend payments. 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 successful completion of our acquisition of BG Group plc (BG) was a transformational step for Shell. It is a bold and compelling stride forward in our liquefied natural gas and deep-water growth strategy.  

The overarching goal of buying BG was to create value for shareholders. The effective integration of BG into our portfolio, which has now been completed, will help deliver that value and accelerate the reshaping of Shell into a world-class investment. The foundations for building this investment case are now set.

Shell’s management, under the leadership of our Chief Executive Officer Ben van Beurden, is tightly controlling capital investment and operating expenses while still investing in growth opportunities. The priority is on reducing debt and generating higher returns for shareholders.

As we move into the next decade, cash flow from our core businesses will help fund further investments while continuing to generate returns for shareholders, including dividends.

Shell Board members met with shareholders during 2016 to explain our refreshed strategy and update them on the progress of the BG integration. Members also discussed with investors how the Board sees Shell’s role in powering sustainable economic growth in the decades ahead.

I would like to take this opportunity to thank our outgoing Chief Financial Officer, Simon Henry, for the dedication, drive and professionalism he has shown throughout nearly eight years of service to the Board.  He has played a key role in strengthening and streamlining Shell.

SUSTAINABLE PROGRESS

Sustained global co-operation is vital for providing better living standards for a growing population, while limiting the accumulation of greenhouse gases (GHG). The entry into force in November of the United Nations (UN) Paris Agreement on climate change is an important foundation for developing ways to reduce global emissions effectively over the years ahead.

Meeting the long-term challenge of providing more and cleaner energy will require sustained, collaborative effort by governments, businesses and non-governmental groups. Governments can help accelerate progress around the world by establishing policy frameworks that help the private sector play a greater role through profitable competition.  

There are many ways this could be accomplished, including regulations on emissions, government-led carbon pricing mechanisms and initiatives to encourage more widespread use of carbon capture and storage (CCS) technology. But any framework for combating climate change must have strong global support.

Sustainable development is about more than providing low-carbon energy to those who can afford it. It is also about reducing inequality by creating better employment opportunities, education and medical services, including for the hundreds of millions of people who still lack access to basic infrastructure. Better access to energy can play an important role in meeting these needs.    

The UN has adopted 17 sustainable development goals in a major initiative to tackle the world’s most serious environmental, economic and social challenges over the next decade. Society can only achieve these goals by working together.

Companies can do their part by contributing positively to the environments and communities in which they work. But no company, however large, can meet these challenges alone.

A good example of co-operation is our involvement in the Basrah Gas Company (BGC), a joint venture with the government of Iraq and Japan’s Mitsubishi Corporation. BGC captures gas that would otherwise be flared from three non-

Shell-operated oil fields in southern Iraq. It processed an average of 574 million standard cubic feet per day of gas in 2016. Thanks to gas it supplies to local power plants, people living in the city of Basrah benefit from much-improved supplies of electricity.

As with activities in other parts of the world that we are involved in, such projects also promote sustainable development by creating jobs for local people and supporting local suppliers, while helping provide electricity for businesses, schools and medical facilities.

ENERGY SOLUTIONS FOR A SHARED FUTURE

Shell has been working to reduce overall GHG emissions from its own operations for well over a decade and has helped to develop technology that can reduce emissions from a range of industries. For example, our Quest project in Canada captured and safely stored more than 1 million tonnes of carbon dioxide (CO₂) deep underground in 2016, its first full year of operation.

Cleaner and lower-carbon fuels such as natural gas and biofuels, combined with more widespread use of technologies such as CCS, are needed for limiting CO₂ emissions across the global economy.

We created a New Energies business in 2016 to further explore opportunities in alternative transport fuels, such as biofuels and hydrogen, along with new ways to connect energy producers and consumers, including through increased use of digital technology.

All types of energy will be required to meet the needs of the world’s growing population over the decades ahead. So our New Energies business is also looking at how new technologies could work more effectively together, for example, by using gas as a partner with renewables to ensure steady power supplies when the sun does not shine or the wind does not blow. It will also act as an incubator for potentially game-changing technologies of the future.

There is no single solution to meeting the challenges of climate change and a growing population. Building a better quality of life for more people on a healthy planet will require a patchwork of energy solutions.

For many countries, replacing coal with gas for power generation can make the most dramatic cuts to emissions at lowest cost. The successful completion of the BG integration has significantly increased our ability to deliver gas around the world.

We are determined to provide shareholders with a world-class investment while contributing to sustainable global growth.

Chad Holliday

Chair

Strict capital discipline, substantial cost savings and our integrated business model helped support earnings during another challenging year for the oil and gas industry.

Completing the BG Group plc (BG) acquisition in February was a great achievement and undoubtedly the highlight of the year. I was also impressed by how well Shell and BG teams worked together to complete the integration well ahead of plan. BG has proven to be an important growth accelerator, as well as a catalyst for the changes we are making to our work practices, cost structure and global portfolio.

We also continued our unrelenting efforts to ensure safety wherever we work, but sadly three people still lost their lives while working for Shell in 2016. Another person was seriously injured in one of those incidents.  Tragic events such as these underscore the paramount importance of focusing on safety.

RESULTS

Income for the period was $4.8 billion in 2016 compared with $2.2 billion in 2015. Earnings on a current cost of supplies basis were $3.7 billion, compared with $4.2 billion in 2015. We distributed $15 billion to shareholders in dividends in 2016, including those taken as shares under our Scrip Dividend Programme.

The portfolio acquired with BG, combined with the start-up of the Gorgon liquefied natural gas production facility in Australia, strengthened our role in the growing global market for gas. Our oil and gas production also increased in 2016, driven by the portfolio we acquired with BG and the major deep-water projects we started up in the Gulf of Mexico and off the coasts of Malaysia and Brazil.

Overall, our production averaged 3.7 million barrels of oil equivalent per day (boe/d), compared with 3.0 million boe/d in 2015.  This increase was largely driven by the acquisition of BG.

Refining margins were weaker in our Downstream business, while a modest rise in crude oil prices gave some support to our Upstream earnings as the year progressed. This again shows the strength of the integrated energy company model.

MORE FOCUSED

We continued to streamline our Downstream business – including divestments in Japan, Denmark and Malaysia – as part of our ongoing effort to improve efficiency by lowering costs and concentrating on our most competitive businesses.

We also sold Upstream assets, including in the Gulf of Mexico and in Canada, and decided not to go ahead with the Bab gas project in the United Arab Emirates. Our divestment drive gained momentum during the year and we plan to continue selling assets in 2017 as part of our overall divestment programme of $30 billion for the 2016-18 period. In March 2017, we agreed to sell, in a series of transactions, all of our in-situ and undeveloped oil sands interests in Canada and to reduce our interest in the Athabasca Oil Sands Project from 60% to 10%. This is a significant step in reshaping Shell’s portfolio in line with our long-term strategy. See Note 30 to the “Consolidated Financial Statements” on page 152.

The oil and gas market outlook remains uncertain. But it is important to continue investing to achieve the most competitive portfolio. That is why we took final investment decisions on petrochemicals projects in China and the USA in 2016.

Excluding the acquisition of BG, our capital investment was around $27 billion in 2016, which was about $20 billion below the combined level for Shell and BG in 2014. We will maintain strict capital discipline and expect capital investment to be around $25 billion in 2017, at the lower end of our $25-30 billion range for 2017-2020.

Our priority is to reduce debt following the BG deal and support shareholder returns into the future.

RESHAPING SHELL

We remain ready to invest in the most competitive projects. But we are working to reshape Shell into a more focused and resilient company by capping our investments for the next few years, while continuing to drive down costs and to sell assets.

Following the integration of BG, our Integrated Gas business has become an engine for generating cash and returns. The increased strength of our global gas business, combined with our other cash engines, should deliver rising free cash flow from around 2020.

We plan to continue prioritising growth in our deep-water and chemicals businesses beyond 2020. But we expect them to become major cash engines over the next decade.

This should enable Shell to achieve the scale and profitability that will help us to adapt and thrive in the transition to a lower-carbon global energy system. The evolving energy landscape offers exciting potential for future growth and further integration in our business. That is why we created a New Energies business in 2016 to explore and develop attractive commercial opportunities.

We expect demand for oil and gas to continue to grow. But we also intend to build upon our portfolio and will continue to look at the potential of low-carbon biofuels, hydrogen, solar and wind as the energy transition unfolds. Our New Energies business intends to act with conviction and commercial realism – when the value for shareholders and society is clear.

In the meantime, Shell’s existing oil and gas portfolio will help drive growth in free cash flow over the next few years, across a range of possible oil prices. The integration of BG has also reinforced the foundations for generating competitive returns from our core oil and gas businesses over the longer term.

We have set an ambitious and clear path for the years ahead. We revitalised Shell in 2016 and I am confident that 2017 will be another year of progress in building our world-class investment case.  

Ben van Beurden

Chief Executive Officer

STRATEGY

Our strategy seeks to create a world-class investment case for shareholders. This strategy is underpinned by Shell’s outlook for the energy sector and the need to adapt to substantial changes in the world around us. Rising global population and standards of living should continue to drive demand growth for oil and gas for decades to come. At the same time, there is a transition underway to: a lower-carbon energy system; a world with increased customer choice; continued energy price volatility; and, with the advent of low-cost shale reserves, a new dynamic in value creation in oil and gas. Safety and environmental and social responsibility are at the heart of our activities.

The ability to achieve our strategic objectives depends on how we respond to competitive forces (see “Risk factors” on page 12). We continuously assess the external environment – the markets as well as the underlying economic, political, social and environmental drivers that shape them – to anticipate changes in competitive forces and business models. We undertake regular reviews of the markets we operate in and analyse our competitors’ strengths and weaknesses to understand our competitive position. We maintain business strategies and plans that focus on actions and capabilities to create and sustain competitive advantage.

STRATEGIC AMBITIONS

Against this backdrop, Shell has the following strategic ambitions:

We have defined our strategy to deliver against these long-term ambitions and believe that success will lead to sustaining a world-class investment case.

STRATEGIC THEMES

We focus on a series of strategic themes, described in categories of cash engines, growth priorities and future opportunities, each requiring distinctive technologies and risk management:

Cash engines need to deliver strong and stable returns and strong and stable free cash flow that can cover the dividend and share buybacks throughout macroeconomic cycles and leave us with enough cash to fund the future.

Growth priorities have a clear pathway towards delivering strong returns and free cash flow in the medium term.

Future opportunities should provide us with material growth in free cash flow in the next decade or beyond when the energy transition opens up new areas of value for us.

Through all of our strategic themes, our intention is to be in fundamentally advantaged and resilient positions. We allocate capital to each of these strategic themes to drive an optimal cash flow and returns profile over multiple timelines. When we set our plans and goals, we do so on the basis of delivering sustained returns over decades.

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

OUTLOOK FOR 2017 AND BEYOND

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

We have identified four levers to manage through the market down-cycle: divestments, reduced capital investment and operating expenses, and delivering new projects that will add significant cash flow.  

We welcome the efforts made by all parties to take the Paris Agreement forward and establish the necessary work programmes. We look forward to progress being made on Article 6 in particular, which has the potential to deliver the foundation elements for carbon trading at a global level. This is essential to stimulate and accelerate further development of lower carbon fuels, technologies and innovations to provide the full range of energy needs for a growing and more prosperous global population.

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, free cash flow, capital investment, divestments, production and BG pre-tax synergies, are based on management’s current expectations and certain material assumptions and, accordingly, involve risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied herein. See “About this Report” on page 05 and “Risk factors” on pages 12-15. Forward-looking information includes the expected impact of the BG acquisition.

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

We explore for crude oil and natural gas worldwide, both in conventional fields and from sources such as tight rock, shale and coal formations. We work to develop new crude oil and natural gas supplies from major fields. We also extract bitumen from oil sands, which we convert into synthetic crude oil.

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

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

The distinctive Shell pecten, a trademark in use since the early part of the 20th century, and trademarks in which the word Shell appears, help raise the profile of our brand globally. A strong patent portfolio underlies the technology that we employ in our various businesses. In total, we have around 11,500 granted patents and pending patent applications.

ORGANISATION

Integrated Gas AND NEW ENERGIES

Our Integrated Gas and New Energies organisation manages LNG activities and the conversion of natural gas into GTL fuels and other products, as well as our New Energies portfolio. It includes natural gas exploration and extraction, when contractually linked to the production and transportation of LNG, and the operation of the upstream and midstream infrastructure necessary to deliver gas to market. It markets and trades crude oil, natural gas, LNG, electricity, carbon-emission rights and also markets and sells LNG as a fuel for heavy-duty vehicles and marine vessels.

Upstream

Our Upstream organisation explores for and extracts crude oil, natural gas and natural gas liquids. It also markets and transports oil and gas, and operates the infrastructure necessary to deliver them to market.

Downstream

Our Downstream organisation manages different Oil Products and Chemicals activities as part of an integrated value chain, including trading activities, that turns crude oil and other feedstocks into a range of products which are moved and marketed around the world for domestic, industrial and transport use. The products we sell include gasoline, diesel, heating oil, aviation fuel, marine fuel, lubricants, bitumen and sulphur. In addition, we produce and sell petrochemicals for industrial use worldwide. Our Downstream organisation also manages our Oil Sands operations, which extract bitumen from mined oil sands and convert this into synthetic crude oil.

Projects & Technology

Our Projects & Technology organisation manages the delivery of our major projects and drives research and innovation to develop new technology solutions. It provides technical services and technology capability for our Integrated Gas, Upstream and Downstream activities. It is also responsible for providing functional leadership across Shell in the areas of safety and environment, contracting and procurement, wells activities and greenhouse gas management.

Our future hydrocarbon production depends on the delivery of large and complex projects (see “Risk factors” on page 12). Systematic management of lifecycle technical and non-technical risks is in place for each opportunity, with assurance and control activities embedded throughout the project lifecycle. We focus on the cost-effective delivery of projects through quality commercial agreements, supply-chain management, and construction and engineering productivity through effective planning and simplification of delivery processes. Development of our employees’ project management competencies is underpinned by project principles, standards and processes. A dedicated competence framework, training, standards and processes exist for exploration and appraisal activities. In addition, we provide governance support for our non-Shell-operated ventures or projects.

SEGMENTAL REPORTING

Our reporting segments are Integrated Gas, Upstream, Downstream and Corporate. Upstream combines the operating segments Upstream (managed by our Upstream organisation) and Oil Sands (managed by our Downstream organisation), which have similar economic characteristics. Integrated Gas, Upstream and Downstream include their respective elements of our Projects & Technology organisation. The Corporate segment comprises our holdings and treasury organisation, self-insurance activities, and headquarters and central functions. See Note 5 to the “Consolidated Financial Statements” on page 129-130.

Segmental reporting has been changed with effect from 2016, in line with a change in the way Shell’s businesses are managed. Integrated Gas was previously part of Upstream. Comparative information in this Report has been reclassified.

RESEARCH AND DEVELOPMENT

In 2016, research and development expenses were $1,014 million, compared with $1,093 million in 2015, and $1,222 million in 2014. Our main technology centres are in India, the Netherlands and the USA, with other centres in Canada, China, Germany, Norway, Oman and Qatar.

Technology and innovation are essential to our efforts to meet the world’s energy demands in a competitive way. If we do not develop the right technology, do not have access to it or do not deploy it effectively, this could have a material adverse effect on the delivery of our strategy and our licence to operate (see “Risk factors” on page 14). We continuously look for technologies and innovations of potential relevance to our business. Our Chief Technology Officer oversees the development and deployment of new and differentiating technologies and innovations across Shell, seeking to align business and technology requirements throughout our technology maturation process.

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

Measures that we use to manage or mitigate our various risks are set out in the relevant sections of this Report. The Board’s responsibility for identifying, evaluating and managing our significant risks is discussed in “Corporate governance” on page 71.

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

The prices of crude oil, natural gas, oil products and chemicals are affected by supply and demand, both globally and regionally. Moreover, prices for oil and gas can move independently of each other. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, conflicts, economic conditions and actions by major oil and gas producing countries. Additionally, in a low oil and gas price environment, we would generate less revenue from our Upstream and Integrated Gas businesses, and, as a result, parts of those businesses could become less profitable, or could incur losses. Additionally, low oil and gas prices have resulted, and could continue to result, in the debooking of proved oil or gas reserves, if they become uneconomic in this type of price environment. Prolonged periods of low oil and gas prices, or rising costs, can result in projects being delayed or cancelled. In addition, assets have been impaired in the past, and there could be impairments in the future. Low oil and gas prices could also affect our ability to maintain our long-term capital investment programme and dividend payments. In a high oil and gas price environment, we could experience sharp increases in costs, and, under some production-sharing contracts, our entitlement to proved reserves would be reduced. Higher prices could also reduce demand for our products, which could result in lower profitability, particularly in our Downstream business. Accordingly, price fluctuations could have a material adverse effect on our earnings, cash flows and financial condition.

See “Market overview” on page 16.

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

We use oil and gas price range assumptions, which we review on a periodic basis, to evaluate project decisions and commercial opportunities. If our assumptions prove to be incorrect, it could have a material adverse effect on our earnings, cash flows and financial condition.

See “Market overview” on page 17.

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

We face competition in each of our businesses. We seek to differentiate our products; however, many of them are competing in commodity-type markets. Accordingly, failure to manage our costs as well as our operational performance could result in a material adverse effect on our earnings, cash flows and financial condition. Increasingly, we compete with state-owned oil and gas entities, particularly in seeking access to oil and gas resources. These entities control vastly greater quantities of oil and gas resources than the major independent oil and gas companies. State-owned entities have access to significant resources and could be motivated by political or other factors in their business decisions, which could harm our competitive position or reduce our access to desirable projects, which in turn could have a material adverse effect on our earnings, cash flows and financial condition.

See “Strategy and outlook” on page 08.

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

We may not be able to successfully divest assets at acceptable prices or within the timeline envisaged due to market conditions or credit risk, resulting in increased pressure on our cash position and potential impairments. 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. Accordingly, if we are unable to divest assets at acceptable prices or within our envisaged timeframe, this could have a material adverse effect on our earnings, cash flows and financial condition.

See “Strategy and outlook” on pages 08-09.

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

We face numerous challenges in developing capital projects, especially those which are large and complex. Challenges include uncertain geology, frontier conditions, the existence and availability of necessary technology and engineering resources, the availability of skilled labour, the existence of transportation infrastructure, project delays, the expiration of licences and potential cost overruns, as well as technical, fiscal, regulatory, political and other conditions. These challenges are particularly relevant in certain developing and emerging-market countries such as Iraq, in frontier areas and in deep-water fields, such as off the coast of Brazil. We may fail to assess or manage these and other risks properly. Such potential obstacles could impair our delivery of these projects, our ability to fulfil the value potential at the time of the project investment approval, and/or our ability to fulfil related contractual commitments. These could lead to impairments and could have a material adverse effect on our earnings, cash flows and financial condition.

Future oil and gas production will depend on our access to new proved reserves through exploration, negotiations with governments and other owners of proved reserves and acquisitions, as well as on developing and applying new technologies and recovery processes to existing fields and mines. Failure to replace proved reserves could result in lower future production, potentially having a material adverse effect on our earnings, cash flows and financial condition.

See “Business overview” on page 11.

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

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

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

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

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

The estimation of proved oil and gas reserves involves subjective judgements and determinations based on available geological, technical, contractual and economic information. Estimates could change because of new information from production or drilling activities, or changes in economic factors, including changes in the price of oil or gas and changes in the regulatory policies of host governments, or other events. Estimates could also be altered by acquisitions and divestments, new discoveries, and extensions of existing fields and mines, as well as the application of improved recovery techniques. Published proved oil and gas reserves estimates could also be subject to correction due to errors in the application of published rules and changes in guidance. Downward adjustments could indicate lower future production volumes and could also lead to impairment of some assets. This could have a material adverse effect on our earnings, cash flows and financial condition.

See “Supplementary information – oil and gas (unaudited)” on page 153.

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

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

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

If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions and/or GHG intensity for new and existing projects or products, we could experience additional costs or financial penalties, delayed or cancelled projects, and/or reduced production and reduced demand for hydrocarbons, which could have a material adverse effect on our earnings, cash flows and financial condition.

See “Environment and society” on pages 54-55.

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

As seen in recent years in Nigeria, North Africa and the Middle East, social and civil unrest, both in the countries in which we operate and elsewhere, can and do affect us. Such potential developments that could have a material adverse effect on our earnings, cash flows and financial condition include: acts of political or economic terrorism; acts of maritime piracy; conflicts including war and civil unrest (including disruptions by non-governmental and political organisations); and local security concerns that threaten the safe operation of our facilities and transport of our products. Pandemic diseases can also affect our operations directly and indirectly. If such risks materialise, they could result in injuries, loss of life, environmental harm and disruption to business activities, which in turn could have a material adverse effect on our earnings, cash flows and financial condition.

See “Environment and society” on page 58.

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

Developments in politics, laws and regulations can and do affect our operations. Potential impacts 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; antitrust claims; changes to trade compliance regulations; price controls; local content requirements; foreign exchange controls; changes to environmental regulations; changes to regulatory interpretations and enforcement; and changes to disclosure requirements. A prolonged period of lower oil and gas prices could affect the financial, fiscal, legal, political and social stability of countries that rely significantly on oil and gas revenue. This could, in turn, have a material adverse effect on our earnings, cash flows and financial condition. It also could have an adverse effect on the ultimate value derived from the assets acquired from BG Group plc.

From time to time, cultural and political factors play a role in unprecedented and unanticipated judicial outcomes that could adversely affect Shell. Non-compliance with policies and regulations could result in regulatory investigations, litigation and ultimately sanctions. Certain governments and regulatory bodies have, in Shell’s opinion, exceeded their constitutional authority by: attempting unilaterally to amend or cancel existing agreements or arrangements; failing to honour existing contractual commitments; and seeking to adjudicate disputes between private litigants. Additionally, certain governments have adopted laws and regulations that could potentially force us to violate other countries’ laws and regulations, therefore potentially subjecting us to both criminal and civil sanctions. Such developments and outcomes could have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate governance” on page 72.

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

The health, safety, security and environment (HSSE) risks to which we, and the communities in which we work, are potentially exposed cover a wide spectrum, given the geographic range, operational diversity and technical complexity of our operations. These risks include the effects of natural disasters (including weather events), earth tremors, social unrest, personal health and safety lapses, and crime. If a major HSSE risk materialises, such as an explosion or hydrocarbon spill, this could result in injuries, loss of life, environmental harm, disruption of business activities, and loss or suspension of our licence to operate or ability to bid on mineral rights. Accordingly, this would have a material adverse effect on our earnings, cash flows and financial condition.

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

See “Environment and society” on page 54.

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

In our Nigerian operations, we face various risks and adverse conditions. These include: security issues surrounding the safety of our people, host communities and operations; sabotage and theft; our ability to enforce existing contractual rights; litigation; limited infrastructure; potential legislation that could increase our taxes or costs of operations; the effect of lower oil and gas prices on the government budget; and regional instability created by militant activities. Any of these risks or adverse conditions could have a material adverse effect on our earnings, cash flows and financial condition

See “Upstream” on page 31.

Production from the Groningen field in the Netherlands continues to cause earthquakes that affect local communities.

Shell and ExxonMobil are 50:50 shareholders in Nederlandse Aardolie Maatschappij B.V. (NAM), which Shell operates. An important part of NAM’s gas production comes from the onshore Groningen gas field, in which EBN, a Dutch government entity, has a 40% interest and NAM a 60% interest. Production from the Groningen field has caused earthquakes in the past which are expected to continue. The earthquakes have caused damage to houses and other structures in the region and complaints from the local community. Additional earthquakes could have a material adverse effect on our earnings, cash flows and financial condition. Since 2013, the Minister of Economic Affairs (Minister) has imposed a cap on production from the Groningen field in order to reduce the impact of the earthquakes on the neighbouring communities. In September 2016, the Minister approved the production of 24 billion cubic metres per annum from the Groningen field until October 1, 2021. At the request of the Dutch parliament, the Minister will review annually whether new circumstances have arisen that call for a further reduction of the production. The first such annual review is expected by October 1, 2017.

See “Upstream” on page 29.

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

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

See “Business overview” on page 11.

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

Our subsidiaries, joint arrangements and associates are subject to differing economic and financial market conditions around the world. Political or economic instability affects such markets.

We use debt instruments, such as bonds and commercial paper, to raise significant amounts of capital. Should our access to debt markets become more difficult, the potential impact on our liquidity could have a material adverse effect on our operations. Our financing costs could also be affected by interest rate fluctuations or any credit rating deterioration.

We are exposed to changes in currency values and to exchange controls as a result of our substantial international operations. Our reporting currency is the dollar. However, to a material extent, we hold assets and are exposed to liabilities in other currencies. See Note 20 to the “Consolidated Financial Statements” on page 144. Commodity trading is an important component of our Upstream, Integrated Gas and Downstream businesses and is integrated with our supply business. While we undertake some foreign exchange and commodity hedging, we do not do so for all of our activities. Furthermore, even where hedging is in place, it may not function as expected.

We are exposed to credit risk; our counterparties could fail or could be unable to meet their payment and/or performance obligations under contractual arrangements. Although we do not have significant direct exposure to sovereign debt, it is possible that our partners and customers may have exposure which could impair their ability to meet their obligations. In addition, our pension plans may invest in government bonds, and therefore could be affected by a sovereign debt downgrade or other default.

If any of the risks set out above materialise, they could have a material adverse effect on our earnings, cash flows and financial condition.

See “Liquidity and capital resources” on page 50.

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

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

See “Liquidity and capital resources” on page 49.

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

Our insurance subsidiaries provide hazard insurance coverage to other Shell entities and only reinsure a portion of their risk exposures. Such reinsurance would not provide any material coverage in the event of a large-scale safety and environmental incident. Similarly, in the event of a material safety and environmental incident, there would be no material proceeds available from third-party insurance companies to meet our obligations. Therefore, we may incur significant losses from different types of risks that are not covered by insurance from third-party insurers, potentially resulting in a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate” on page 48.

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

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

See “Corporate governance” on page 68.

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

In cases where we are not the operator, we have limited influence over, and control of, the behaviour, performance and costs of operation of such joint arrangements or associates. Despite not having control, we could still be exposed to the risks associated with these operations, including reputational, litigation (where joint and several liability could apply) and government sanction risks. For example, our partners or members of a joint arrangement or an associate (particularly local partners in developing countries) may not be able to meet their financial or other obligations to the projects, threatening the viability of a given project. Where we are the operator of a joint arrangement, the other partner(s) could still be able to veto or block certain decisions, which could be to our overall detriment. Accordingly, where we have limited influence, we are exposed to operational risks that could have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate governance” on page 72.

We rely heavily on information technology systems for our operations.

The operation of many of our business processes depends on reliable information technology (IT) systems. Our IT systems are increasingly concentrated in terms of geography, number of systems, and key contractors supporting the delivery of IT services. Shell, like many other multinational companies, is the target of attempts to gain unauthorised access to our IT systems and our data through various channels, including more sophisticated and coordinated attempts often referred to as advanced persistent threats. Timely detection is becoming increasingly complex but we seek to detect and investigate all such security incidents, aiming to prevent their recurrence. Disruption of critical IT services, or breaches of information security, could harm our reputation and have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate” on page 48.

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

Antitrust and competition laws apply to Shell and its joint ventures and associates in the vast majority of countries in which we do business. Shell and its joint ventures and associates have been fined for violations of antitrust and competition laws. These include a number of fines in the past by the European Commission Directorate-General for Competition (DG COMP). Due to the DG COMP’s fining guidelines, any future conviction of Shell or any of its joint ventures or associates for violation of European Union (EU) competition law could result in significantly larger fines and have a material adverse effect on us. Violation of antitrust laws is a criminal offence in many countries, and individuals can be imprisoned or fined. Furthermore, it is now common for persons or corporations allegedly injured by antitrust violations to sue for damages. Any violation of these laws or harm to our reputation could have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate governance” on page 68.

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

In 2010, we agreed to a Deferred Prosecution Agreement (DPA) with the US Department of Justice for violations of the Foreign Corrupt Practices Act (FCPA), which arose in connection with our use of the freight-forwarding firm Panalpina. In 2013, following our fulfilment of the terms of the DPA, the criminal charges filed in connection with the DPA were dismissed.

Authorities in various countries are investigating our investment in Nigerian oil block OPL 245 and the 2011 settlement of litigation pertaining to that block.

On January 27, 2017, the Nigeria Federal High Court issued an Interim Order of Attachment for oil block OPL 245, pending the conclusion of the investigation. Shell has applied to discharge this order on constitutional and procedural grounds. On February 14, 2017, we received notice of the request of indictment from the Italian prosecution office in Milan with respect to this matter.

Any violation of the FCPA or other relevant anti-bribery and corruption legislation or anti-money laundering legislation could harm our reputation and have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate governance” on page 69.

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 EU General Data Protection Regulation, which will be applicable from May 2018, increases penalties up to a maximum of 4% of global annual turnover for breach of the regulation. Non-compliance with data protection laws could expose us to regulatory investigations, which could result in fines and penalties. Regulators may also issue orders to stop processing personal data in addition to imposing fines, which could disrupt operations. We could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offence in some countries, and individuals can be imprisoned or fined. Any violation of these laws or harm to our reputation could have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate governance” on page 68.

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

We use “trade compliance” 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 such laws continue to expand. For example, the EU and the USA continue to impose restrictions and prohibitions on certain transactions involving Syria. In addition, the USA continues to have sanctions in place against Iran. Additional restrictions and controls directed at defined oil and gas activities in Russia, which were imposed by the EU and the USA in 2014, are still in force. 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 of these regimes could lead to loss of import or export privileges, significant penalties on or prosecution of Shell or its employees, and could harm our reputation and have a material adverse effect on our earnings, cash flows and financial condition.

See “Corporate governance” on page 68.

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

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

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

We maintain a large business portfolio across a fully-integrated value chain and are therefore exposed to crude oil, natural gas, oil product and chemical prices (see “Risk factors” on page 12). This diversified portfolio helps us mitigate the impact of price volatility. Our annual planning cycle and periodic portfolio reviews aim to ensure that our levels of capital investment and operating expenses are affordable in the context of a volatile price environment. We test the resilience of our projects and other opportunities against a range of crude oil, natural gas, oil product and chemical prices and costs. We also aim to maintain a strong balance sheet to provide resilience against weak market prices.

GLOBAL ECONOMIC GROWTH

One of the key drivers of oil and gas demand is economic activity. According to the International Monetary Fund’s (IMF) January 2017 World Economic Outlook, global economic growth was 3.1% in 2016, compared with 3.2% in 2015. Growth in 2016 fell short of the IMF’s forecast of 3.4% made at the beginning of the year. Lower than expected economic growth in the USA, together with recessions in Brazil and Russia, contributed to lower global economic growth than forecast.

The IMF estimated that the eurozone economy grew by 1.7% in 2016, compared with 2.0% in 2015, US economic growth was 1.6%, compared with 2.6% in 2015, and Chinese economic growth was 6.7% compared with 6.9% in 2015. The average economic growth rate for advanced economies slowed to 1.6% in 2016 from 2.1% in 2015, while growth in emerging markets and developing economies was 4.1%, unchanged from 2015.

The IMF expects global economic growth to rise to 3.4% in 2017, which is close to the annual average of 3.5% for the previous 10 years. The IMF expects growth of 1.6% in the eurozone, 6.5% in China and 2.3% in the USA.

GLOBAL Prices, DEMAND AND SUPPLY

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

[A] Yearly average prices are based on daily spot prices. The 2016 average price for Japan Customs-cleared Crude excludes December data.

CRUDE OIL

Brent crude oil, an international benchmark, traded between $26 per barrel and $56/b in 2016, ending the year at $55/b. It averaged $44/b, the lowest level since 2004 and $8/b less than in 2015.

On a yearly average basis, West Texas Intermediate crude oil traded at a $0.4/b discount to Brent in 2016, compared with $3/b in 2015. The discount narrowed as production in the USA declined in response to lower oil prices and logistical bottlenecks were removed due to added pipeline capacity between the landlocked trading hub in Cushing, Oklahoma, and demand centres such as refineries and export terminals.

Reflecting the economic conditions described above, global oil demand grew by 1.5% (or 1.5 million barrels per day) to 96.5 million b/d, according to the International Energy Agency’s (IEA) January 2017 Oil Market Report. This annual oil demand growth was mainly driven by emerging economies, where demand grew by 1.2 million b/d, due to increased use by final consumers and continued strategic petroleum reserves building in Asia, particularly China. Annual oil demand growth in 2016 was 0.5 million b/d less than in 2015 when demand rose by 2.0 million b/d. The effect of lower crude oil prices on crude oil demand growth was less in 2016 than in 2015 because the average price was only $8/b lower than in 2015, whereas the average price in 2015 was $47/b lower than in 2014.

Oil supply in 2016 is estimated at 96.9 million b/d, an increase of 0.3 million b/d compared with 2015. Oil markets remained well supplied in 2016 because oil supply was 0.4 million b/d higher than demand, according to the IEA. In 2015, oil supply was 1.6 million b/d higher than demand. Consequently, crude oil and oil products inventory levels remained well above the average of the last five years. The IEA reported in the January 2017 Oil Market Report that commercial and government-controlled inventory levels for OECD countries for September 2016 were estimated at around 4,650 million barrels, some 300 million barrels above the average of the last five years, putting downward pressure on prices.

On the non-OPEC supply side, the US Energy Information Administration reported a continuation of a decline in US supply, which started in mid-2015, until the end of the third quarter of 2016. US production increased towards the end of the year as prices rose. US production fell by 0.5 million b/d in 2016 compared with 2015. Other non-OPEC producers also responded to the low oil price environment, contributing to a year-on-year fall in total non-OPEC production of 0.8 million b/d.

OPEC oil production grew by 1 million b/d year-on-year driven mainly by rising output in Saudi Arabia and Iraq, as well as in Iran following the lifting of sanctions. OPEC oil production reached a record high of about 33.4 million b/d in October 2016, according to the IEA. At a meeting in Vienna in November, OPEC announced its intention to support prices by reducing its collective production level by as much as 1.2 million b/d. Several non-OPEC producers, most notably Russia, agreed in December to also reduce production by a total of around 0.6 million b/d, which helped to drive up prices in that month.

Looking ahead, higher global economic activity as indicated by IMF’s global economic outlook and moderate oil price levels at the beginning of 2017 could attract around 1.3 million b/d of additional demand growth in 2017, according to the IEA. If OPEC and the co-operating non-OPEC resource holders reduce production as agreed at the end of 2016, then the global production level in 2017 could be similar to that in 2016, leading to market tightening and withdrawals from storage. This would support prices. Looking further ahead, the low oil price environment has led to postponements and cancellations of new supply projects, which could lead to further market tightening three to five years from now. In such a scenario, we believe the Brent crude oil price around 2020 may average 60-80% higher than the 2016 average. We believe that price weakening, possibly to 2016 levels, could occur if OPEC and those non-OPEC resource holders abandon their production cut pledges, the global economy accelerates less quickly, or if other non-OPEC producers, such as US shale producers, effectively manage costs and deliver cheaper oil to the market. Further price upside can be expected if markets tighten more rapidly due to a faster acceleration of the global economy, continued supply cuts from major resource holders or occurrence of more supply disruptions in major producing countries.

NATURAL GAS

Global gas demand grew by about 1% in 2016, which is much lower than the average annual growth rate of 2.3% in the past decade. A combination of mild weather and continued moderate global economic growth led to a lower rate of demand growth in most regions. The global liquefied natural gas (LNG) market grew by 17 million tonnes year on year. Supply growth was primarily driven by the start-up of new projects in Australia and, to a lesser extent, in the USA. The majority of additional LNG supply was absorbed by China, India and the Middle East, offsetting a decline in imports by Japan and Latin America, and resulting in lower than expected LNG volumes delivered to Europe.

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

In the USA, the natural gas price at the Henry Hub averaged $2.5 per million British thermal units (MMBtu) in 2016, 4% lower than in 2015, and traded in a range of $1.5-3.8/MMBtu. Mild winter weather led to a record of 2.5 trillion cubic feet (tcf) of gas in storage at the end of March. Henry Hub prices remained below $2.3/MMBtu until June. Thereafter, prices increased steadily to $3.1/MMBtu in September due to warm summer weather driving gas demand for electricity generation, declining domestic gas production and new demand from LNG exports as two liquefaction trains on the US Gulf Coast began operations. Prices averaged $3.6/MMBtu in December, driven by weather-related demand growth and falling gas production.

In Europe, natural gas prices fell during 2016. The average price at the UK National Balancing Point was 23% lower than in 2015. At the main continental European gas trading hubs – in the Netherlands, Belgium and Germany – prices were also weaker. Lower prices reflected the net effect of abundant supply, for example from Russia and Algeria, despite some demand growth driven by electricity generation, other industrial-sector demand and increased gas use for transportation.

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 the Asia-Pacific region generally fell in 2016 as they are predominantly indexed to the price of Japan Customs-cleared Crude, which has fallen as global crude oil prices have weakened.

Looking ahead, we expect gas markets in North America, Europe and Asia Pacific to be well supplied over the next few years, despite LNG demand growth in the Middle East and in Asia, in particular. Price developments are very uncertain and dependent on many factors. In the USA, we believe that Henry Hub gas prices in 2020 could average 20-60% higher than the 2016 average, at which level demand growth for LNG exports, pipeline exports to Mexico and domestic/industrial use could balance supply growth from, in particular, the Marcellus and Utica shale plays. In Europe, we believe gas prices in 2020 could be driven by LNG imports from the USA, and the price at the UK National Balancing Point could average 15-70% higher than the 2016 average. In the LNG markets of Asia Pacific, gas prices are expected to continue to be strongly influenced by oil prices, but also increasingly by Henry Hub gas prices. In 2020, we expect the price of LNG delivered under contract to Asia-Pacific markets to be 10-70% higher than the 2016 average.

CRUDE OIL AND NATURAL GAS PRICE ASSUMPTIONS

Our ability to deliver competitive returns and pursue commercial opportunities ultimately depends on the accuracy of our price assumptions (see “Risk factors” on page 12). The range of possible future crude oil and natural gas prices used in project and portfolio evaluations is determined after a rigorous assessment of short-, medium- and long-term market drivers. Historical analyses, trends and statistical volatility are considered in this assessment, as are analyses of market fundamentals such as possible future economic conditions, geopolitics, actions by OPEC and other major resource holders, production costs and the balance of supply and demand. Sensitivity analyses are used to test the impact of low-price drivers, such as economic weakness, and high-price drivers, such as strong economic growth and low investment in new production capacity. Short-term events, such as relatively warm winters or cool summers, affect demand. Supply disruptions, due to weather or political instability, contribute to price volatility

REFINING MARGINS

Industry gross refining margins were lower on average in 2016 than in 2015 in each of the key refining hubs of Europe, Singapore and the USA. Oil products demand growth was stronger globally, with an increase of 1.5 million b/d compared with 2015, driven in part by the lower crude oil price environment. In spite of overcapacity in the refining industry, some new refinery capacity came on line in 2016, which could weaken margins going forward.

In 2017, we expect demand for products such as gasoline and middle distillates to continue to grow and support margins, driven by increasing economic activity as well as freight and passenger transport. However, ample refining capacity and potentially strengthening feedstock prices could narrow margins. Overall, we believe margins could be similar to 2016, but demand and supply-side uncertainty may drive significant volatility.

PETROCHEMICAL MARGINS

Asian naphtha cracker margins rose strongly in 2016 for the second consecutive year due to rising demand and periods of reduced cracker capacity availability. European naphtha cracker margins remained at similar levels to 2015, supported by demand growth. US ethane cracker margins declined as lower crude oil prices reduced the margin available in the ethane to polyethylene value chain.

The outlook for petrochemical margins in 2017 is very uncertain. Demand for petrochemicals is closely linked to economic growth as well as product prices. Product prices reflect prices of raw materials, which are closely linked to crude oil and natural gas prices. The balance of these factors will drive margins.

The statements in this “Market overview” section, including those related to our price forecasts, are based on management’s current expectations and certain material assumptions and, accordingly, involve risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied herein. See “About this Report” on page 05 and “Risk factors” on pages 12-15.

EARNINGS 2016-2015

BG Group plc (BG) was consolidated within Shell’s results with effect from February 2016 following its acquisition.

Income for the period was $4,777 million in 2016 compared with $2,200 million in 2015. After current cost of supplies adjustment, total segment earnings were $3,692 million in 2016 compared with $4,155 million in 2015.

Earnings on a current cost of supplies basis (CCS earnings) exclude the effect of changes in the oil price on inventory carrying amounts, after making allowance for the tax effect. The purchase price of volumes sold in the period is based on the current cost of supplies during the same period, rather than on the historic cost calculated on a first-in, first-out (FIFO) basis. Therefore, when oil prices are decreasing CCS earnings are likely to be higher than earnings calculated on a FIFO basis, and when prices are increasing CCS earnings are likely to be lower than earnings calculated on a FIFO basis.

Integrated Gas earnings in 2016 were $2,529 million, compared with $3,170 million in 2015. Compared with 2015, earnings in 2016 were mainly impacted by higher operating expenses and depreciation, mainly due to the consolidation of BG, lower oil and liquefied natural gas (LNG) prices and higher taxation. These impacts were partly offset by higher production and LNG liquefaction volumes, mainly as a result of the BG acquisition, and lower impairment charges and well write-offs. See “Integrated Gas” on page 22.

Upstream earnings in 2016 were a loss of $3,674 million, compared with a loss of $8,833 million in 2015. The lower loss in 2016 was partly explained by the significant charges in 2015 associated with the decision to cease Alaska drilling activities and the Carmon Creek project in Canada and other impairments. In addition, compared with 2015, earnings in 2016 benefited from higher production volumes, mainly as a result of the BG acquisition, and lower operating expenses, despite the consolidation of BG. These impacts were partly offset by lower oil and gas prices and higher depreciation, mainly due to the consolidation of BG, and lower gains on divestments. See “Upstream” on page 27.

Downstream earnings in 2016 were $6,588 million compared with $10,243 million in 2015. The decrease in earnings was mainly due to lower realised refining and trading margins and a higher effective tax rate. There was a partial offset from stronger marketing margins, in turn partly offset by the impact of divestments and unfavourable exchange rate effects and fair-value accounting of commodity derivatives. See “Downstream” on pages 41-42.

Corporate earnings in 2016 were a loss of $1,751 million, compared with a loss of $425 million in 2015. Interest expense was significantly higher in 2016, due to additional debt for the BG acquisition and debt assumed on the acquisition, partly offset by lower foreign exchange losses. There were also BG acquisition costs and

lower tax credits in 2016, and a gain in 2015 on the sale of an office building. See “Corporate” on page 48.

EARNINGS 2015-2014

Income for the period was $2,200 million in 2015 compared with $14,730 million in 2014. After current cost of supplies adjustment, total segment earnings were $4,155 million in 2015 compared with $19,096 million in 2014.

Integrated Gas earnings in 2015 were $3,170 million, compared with $10,610 million in 2014. Lower earnings in 2015 reflected the significant decline in oil and gas prices, lower divestment gains and the impact of the weakening of the Australian dollar on a deferred tax position and a deferred tax liability related to an associate company.

Upstream earnings in 2015 were a loss of $8,833 million, compared with an income of $5,231 million in 2014. Lower earnings in 2015 reflected the significant decline in oil and gas prices, charges associated with management’s decision to cease Alaska drilling activities and the Carmon Creek project in Canada, higher impairment charges, lower divestment gains and the impact of the weakening of the Brazilian real on a deferred tax position.

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

Corporate earnings in 2015 were a loss of $425 million, compared with a loss of $156 million in 2014.

production available for sale

Oil and gas production available for sale in 2016 was 1,342 million barrels of oil equivalent (boe), or 3,668 thousand boe per day (boe/d), compared with 1,078 million boe, or 2,954 thousand boe/d, in 2015. The increase was mainly driven by the BG acquisition. Liquids production increased by 22% and natural gas production by 27% compared with 2015.

[A] See “Oil and gas information” on pages 37-38.

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

PROVED RESERVES

The proved oil and gas reserves of Shell subsidiaries and the Shell share of the proved oil and gas reserves of joint ventures and associates are summarised in “Oil and gas information” on pages 33-35 and set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 151-161.

Before taking production into account, our proved reserves increased by 2,887 million boe in 2016. This comprised an increase of 3,117 million boe from Shell subsidiaries (of which 2,431 million boe were added with the acquisition of BG), which was partly offset by a decrease of 230 million boe from the Shell share of joint ventures and associates. The increase in proved reserves included an increase of 139 million boe as a result of an increased entitlement share due to the lower yearly average price applied to production-sharing and tax/ variable royalty contracts.

In 2016, total oil and gas production was 1,386 million boe, of which 1,342 million boe was available for sale and 44 million boe was consumed in operations. Production available for sale from subsidiaries was 1,158 million boe and 36 million boe was consumed in operations. The Shell share of the production available for

sale of joint ventures and associates was 184 million boe and 8 million boe was consumed in operations.

Accordingly, after taking production into account, our proved reserves increased by 1,501 million boe in 2016, to 13,248 million boe at December 31, 2016, with an increase of 1,923 million boe from subsidiaries and a decrease of 422 million boe from the Shell share of joint ventures and associates.

CAPITAL INVESTMENT AND OTHER INFORMATION

Capital investment was $79.9 billion in 2016, including $52.9 billion related to the BG acquisition, compared with $28.9 billion in 2015.

Divestments were $4.7 billion in 2016, compared with $5.5 billion in 2015.

Operating expenses increased by $1 billion in 2016, to $42 billion. This included redundancy and restructuring charges of $1.9 billion and BG acquisition costs of $0.4 billion. The impact of the consolidation of BG was offset by steps taken to reduce expenses, realising synergies and follow-on benefits from the acquisition.

Our return on average capital employed (ROACE) increased to 3.0% compared with 1.9% in 2015, driven by a higher income in 2016.

Gearing was 28.0% at the end of 2016, compared with 14.0% at the end of 2015. There was an increase of 9.7% on the acquisition of BG.

KEY ACCOUNTING ESTIMATES AND JUDGEMENTS

See Note 2 to the “Consolidated Financial Statements” on pages 122-127.

LEGAL PROCEEDINGS

See Note 26 to the “Consolidated Financial Statements” on page 151.

KEY PERFORMANCE INDICATORS

Total shareholder return (TSR) is the difference between the share price at the beginning of the year and the share price at the end of the year (each averaged over 30 days), plus gross dividends delivered during the calendar year (reinvested quarterly), expressed as a percentage of the share price at the beginning of the year (averaged over 30 days). The data used are a weighted average in dollars for A and B shares. The TSRs of major publicly traded oil and gas companies can be compared directly, providing a way to determine how we are performing in relation to our industry peers.

Cash flow from operating activities is the total of all cash receipts and payments associated with our sales of oil, gas, chemicals and other products. The components that provide a reconciliation from income for the period are listed in the “Consolidated Statement of Cash Flows”. This indicator reflects our ability to generate cash to service and reduce our debt and for distributions to shareholders and investments. See “Liquidity and capital resources” on page 50.

Project delivery reflects our capability to complete major projects on time and within budget on the basis of targets set in our annual Business Plan. The set of projects reflected in this indicator 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 into equivalent barrels of oil to make the summation possible. Changes in production have a significant impact on our cash flow. See “Summary of results” on pages 18-19.

Liquefied natural gas (LNG) liquefaction volumes is a measure of the operational performance of our Integrated Gas business and LNG market demand. See “Integrated Gas” on page 22.

Refinery and chemical plant availability is the weighted average of the actual uptime of plants as a percentage of their maximum possible uptime. The weighting is based on the capital employed, adjusted for cash and non-current liabilities. It excludes downtime due to uncontrollable factors, such as hurricanes. This indicator is a measure of the operational excellence of our Downstream manufacturing facilities. See “Downstream” on page 41.

Total recordable case frequency (TRCF) is the number of employees and contract staff injuries requiring medical treatment or time off for every million hours worked. It is a standard measure of occupational safety. See “Environment and society” on page 54.

ADDITIONAL PERFORMANCE INDICATORS

Earnings on a current cost of supplies basis (CCS earnings) is the income for the period, adjusted for the after-tax effect of oil-price changes on inventory. Segment earnings presented on a current cost of supplies basis is the earnings measure used by the Chief Executive Officer for the purposes of making decisions about allocating resources and assessing performance. See “Summary of results” on page 18 and “Non-GAAP measures reconciliations” on page 195.

CCS earnings per share, which is on a diluted basis above, is calculated by dividing CCS earnings attributable to shareholders (see “Non-GAAP measures reconciliations” on page 195) by the average number of shares outstanding over the year, increased by the average number of dilutive shares related to share-based compensation plans.

Capital investment is a measure used to make decisions about allocating resources and assessing performance. It is defined as capital expenditure and investments in joint ventures and associates as reported in the “Consolidated Statement of Cash Flows” plus exploration expense, excluding exploration wells written off, new finance leases and other adjustments. In 2016, capital investment also included the respective amount for the acquisition of BG Group plc. See “Liquidity and capital resources” on page 50 and “Non-GAAP measures reconciliations” on page 195.

Return on average capital employed (ROACE) is defined as annual income, adjusted for after-tax interest expense, as a percentage of average capital employed during the year. Capital employed is the sum of total equity and total debt. ROACE measures the efficiency of our utilisation of the capital that we employ and is a common measure of business performance. See “Summary of results” on page 19 and “Non-GAAP measures reconciliations” on page 196.

Gearing is defined as net debt (total debt less cash and cash equivalents) as a percentage of total capital (net debt plus total equity) at December 31. It is a measure of the degree to which our operations are financed by debt. See “Liquidity and capital resources” on page 49.

The employee number indicator is 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 joint operations. It excludes employees working for Shell’s joint ventures and associates. See “Our people” on page 59.

Proved oil and gas reserves are the total estimated quantities of oil and gas from Shell subsidiaries and Shell’s share from joint ventures and associates that geoscience and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs, at December 31, under existing economic conditions, operating methods and government regulations. Gas volumes are converted into barrels of oil equivalent (boe) using a factor of 5,800 standard cubic feet per barrel. Reserves are crucial to an oil and gas company, since they constitute the source of future production. Reserves estimates are subject to change due to a wide variety of factors, some of which are unpredictable. See “Summary of results” on page 19, “Oil and gas information” on pages 33-35 and “Supplementary information – oil and gas (unaudited)” on pages 153-161.

The operational spills indicator is the number of incidents in respect of activities where we are the operator in which 100 kilograms or more of oil or oil products were spilled as a result of those activities. See “Environment and society” on page 56.

The Energy Intensity Index (EII^TM), as described in Solomon Associates Refinery Comparative Performance Analysis Methodology 2014, is a benchmark to compare energy efficiency of fuel refineries and paraffinic base oil plants. The Solomon EII^TM is defined as the energy consumed by a refinery divided by the energy standard for the specific individual refinery configuration. See “Environment and society” on page 55.

Direct greenhouse gas emissions from facilities operated by Shell, expressed in carbon dioxide (CO₂) equivalent. See “Environment and society” on page 55.

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

Overview

Our Integrated Gas business manages liquefied natural gas (LNG) activities and the conversion of natural gas into gas-to-liquids (GTL) fuels and other products, as well as our New Energies portfolio. It includes natural gas exploration and extraction, when contractually linked to the production and transportation of LNG, and the operation of the upstream and midstream infrastructure necessary to deliver gas to market. It markets and trades crude oil, natural gas, LNG, electricity, carbon-emission rights and also markets and sells LNG as a fuel for heavy-duty vehicles and marine vessels.

Business conditions

Global oil demand grew by 1.5% in 2016, with the Brent crude oil price averaging $44 per barrel.

Global gas demand grew about 1% in 2016, a much lower rate than the average annual growth rate of 2.3% in the past decade. A combination of mild weather and continued moderate global economic growth led to a lower rate of demand growth in most regions.

The global LNG market grew by 17 million tonnes, or 6.9%, year on year. Supply growth was primarily driven by the start-up of new projects in Australia and, to a lesser extent, in the USA. The majority of additional LNG supply was absorbed by China, India and the Middle East, offsetting a decline in imports by Japan and Latin America and resulting in lower than expected LNG volumes delivered to Europe.

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

In the USA, the natural gas price at the Henry Hub averaged $2.5 per million British thermal units (MMBtu) in 2016, 4% lower than in 2015, and traded in a range of $1.5-3.8/MMBtu.

In Europe, the average price at the UK National Balancing Point was $4.3/MMBtu, 23% lower than in 2015. At the main continental European gas trading hubs – in the Netherlands, Belgium and Germany – prices were also weaker.

Long-term contracted LNG prices in the Asia-Pacific region generally fell in 2016 as they are predominantly indexed to the price of Japan Customs-cleared Crude , which has fallen as global crude oil prices have weakened.

See “Market overview” on pages 16-17.

PRODUCTION AVAILABLE FOR SALE

In 2016, production was 323 million barrels of oil equivalent (boe), or 884 thousand boe per day (boe/d), compared with 230 million boe, or 631 thousand boe/d in 2015. Liquids production increased by 9% and natural gas production increased by 55% compared with 2015, mainly due to the acquisition of BG Group plc (BG).

LNG LIQUEFACTION VOLUMES

LNG liquefaction volumes of 30.9 million tonnes in 2016 were 37% higher than in 2015, mainly reflecting the contribution of assets acquired with BG and our strong operational performance. There were also incremental volumes from the start-up of Gorgon trains 1 and 2 in Australia. These impacts were partly offset by the expiry of the Malaysia LNG Dua joint venture agreement in 2015, lower feedgas availability at Atlantic LNG in Trinidad and Tobago, and a higher level of planned maintenance activity.

LNG sales volumes of 57.1 million tonnes in 2016 were 46% higher than in 2015, mainly reflecting our enlarged portfolio following the acquisition of BG.

Earnings 2016-2015

BG was consolidated within Shell’s results with effect from February 2016, following its acquisition.

Segment earnings in 2016 were $2,529 million, which included a net charge of $1,171 million. The net charge included impairments of $451 million, reported mainly in share of profit of joint ventures and associates, the reassessment of a deferred tax asset in Australia of $533 million, onerous contract provisions in Europe and the USA of $390 million, and redundancy and restructuring charges of $245 million, partly offset by gains on divestments of $212 million and on the accounting reclassification of Shell’s interest in Woodside Petroleum Limited (Woodside) in Australia of $479 million (both reported in interest and other income).

Segment earnings in 2015 were $3,170 million, which included a net charge of $1,887 million, including impairments of $1,109 million and the impact of the weakening of the Australian dollar on deferred tax positions of $560 million.

Excluding the net charges described above, segment earnings were $3,700 million in 2016 compared with $5,057 million in 2015. Earnings were impacted by higher operating expenses and depreciation mainly due to the consolidation of BG (around $1,860 million), lower oil and LNG prices (around $1,730 million), higher taxation (around $570 million), and other net negative impacts of around $120 million. These impacts were partly offset by higher oil and gas production and LNG liquefaction volumes (around $2,260 million), mainly as a result of the BG acquisition, and lower well write-offs (around $660 million).

Earnings 2015-2014

Segment earnings in 2015 were $3,170 million, which included a net charge of $1,887 million as described above. Segment earnings in 2014 of $10,610 million included a net gain of $278 million, principally driven by divestment gains of $1,411 million, mainly related to a portion of our shareholding in Woodside and to Wheatstone LNG in Australia, which was partly offset by charges of $718 million related to an update of a deferred tax asset and the recognition of a deferred tax liability related to an associate company, and the $429 million impact of the weakening of the Australian dollar on deferred tax positions.

Excluding the net charge and net gain described above, segment earnings were $5,057 million in 2015 compared with $10,332 million in 2014, principally as a result of the significant decline in oil and gas prices.

capital investment AND DIVESTMENTS

Capital investment in 2016 was $26.2 billion, compared with $5.2 billion in 2015, mainly reflecting $21.8 billion related to the acquisition of BG.

Divestments in 2016 were $0.4 billion, compared with $0.3 billion in 2015.

Portfolio and business development

Following the acquisition of BG in February 2016, the assets have been integrated into our portfolio. Notable acquired interests are identified in the Business and property section.

Key portfolio events in 2016 included the following:

We reached the following milestones in 2016:

The Pearl gas-to-liquids (GTL) plant (Shell interest 100%) in Qatar operated at a reduced rate of production from December 2016, due to unforeseen maintenance required on the gasifier units, until a controlled shutdown on February 1, 2017. We expect Pearl to ramp back up during the second quarter of 2017.

We continued to divest selected assets during 2016, including:

In January 2017, we reached an agreement with KUFPEC Thailand Holdings Pte Limited, a subsidiary of Kuwait Foreign Petroleum Exploration Company, for the sale of Shell Integrated Gas Thailand Pte Limited and Thai Energy Co Limited (Shell interests 100%), which together have an approximate 22% interest in the Bongkot field and adjoining acreage offshore Thailand, for a consideration of $900 million.

Business and property

EUROPE

Greece

We have a 49% interest in Attiki Gas Supply Company S.A., a natural gas distribution company in Athens. Under Greek law, it will be unbundled into separate supply and distribution companies in 2017.

Netherlands

We have access to import and storage capacity at the GATE LNG terminal in the Netherlands (Shell capacity rights 1.4 million tonnes per annum, mtpa), enabling us to supply LNG to marine and road transport customers in northwest Europe. We are also using the terminal to supply LNG to our growing truck-refuelling network in the Netherlands. In 2016, GATE’s third jetty became operational and we carried out our first loading from it.

As part of our New Energies business (see page 25), we have an interest in the consortium that, in December 2016, was awarded the concession by the Dutch government to develop the Borssele III and IV offshore wind farm projects, which are to be located about 20 kilometres off the Dutch coast.

Norway

Gasnor (Shell interest 100%) provides LNG fuel for ships and industrial customers and has a natural gas pipeline network.

UK

As a result of the BG acquisition, we have a 50% interest in the Dragon LNG regasification terminal, with long-term arrangements in place governing the use of capacity rights.

ASIA (INCLUDING THE MIDDLE EAST AND RUSSIA)

Brunei

We have a 25% interest in Brunei LNG Sendirian Berhad which sells most of its LNG on long-term contracts to customers in Asia.

China

We jointly develop and produce from the onshore Changbei tight-gas field under a production-sharing contract (PSC) with China National Petroleum Corporation (CNPC). In 2016, we completed the Changbei I development programme under the PSC and subsequently handed over the production operatorship to CNPC. We also completed drilling appraisal wells for Changbei II Phase I under the PSC, and have submitted a development plan to CNPC.

In Sichuan, we completed a significant drilling programme in all three blocks in 2016, in accordance with provisions of the PSCs with CNPC. The geology is challenging and the mixed evaluation results do not justify further investment.

We also have a 49% interest in an offshore oil and gas block in the Yinggehai basin, under a PSC with China National Offshore Oil Corporation (CNOOC). Based on the results from the second deep-water exploration well, LD11-1-1 block 62/17, we decided not to pursue this opportunity further.

India

As a result of the acquisition of BG, we have a 30% interest in each of the producing oil and gas fields Panna/Mukta, Mid Tapti and South Tapti. The Tapti fields ceased production in the first quarter of 2016.

Also as a result of the acquisition, we gained a 49.75% interest in MGL, a natural gas distribution company in Mumbai. As result of an IPO, our interest was reduced to 32.5% in June 2016.

Hazira is a regasification terminal, in which we have a 74% interest, in the state of Gujarat on the west coast of India.

Indonesia

We have a 35% interest in the INPEX Masela Ltd joint venture which owns and operates the offshore Masela block. In April 2016, the joint venture received a notification from the Indonesian government authorities instructing it to re-propose a plan for the Abadi gas field based on an onshore LNG project. The partners are committed to working together with the Indonesia government to move the project forward.

Iran

Shell transactions with Iran are disclosed separately. See “Section 13(r) of the US Securities Exchange Act of 1934 Disclosure” on page 194.

Malaysia

We have a 15% interest in Malaysia LNG Tiga located in Bintulu. We also operate a gas-to-liquids (GTL) plant, Shell MDS (Shell interest 72%), adjacent to the Malaysia LNG facilities. Using Shell technology, the plant converts gas into high-quality middle distillates, drilling fluids, waxes and specialty products.

Oman

We have a 30% interest in Oman LNG, which mainly supplies Asian markets under long-term contracts. We also have an 11% interest in Qalhat LNG, which is part of the Oman LNG complex.

Qatar

We operate the Pearl GTL plant (Shell interest 100%) in Qatar under a development and production-sharing contract with the government. The fully-integrated facility has capacity for production, processing and transportation of 1.6 billion standard cubic feet per day (scf/d) of gas from Qatar’s North Field. It has an installed capacity of about 140 thousand boe/d of high-quality liquid hydrocarbon products and 120 thousand boe/d of natural gas liquids (NGL) and ethane. In 2016, Pearl GTL produced 5 million tonnes of GTL products.

Of Pearl’s two trains, the second underwent planned maintenance from March to May 2016.

Pearl operated at a reduced rate of production from December 2016, due to unforeseen maintenance required on the gasifier units, until a controlled shutdown on February 1, 2017. We expect Pearl to ramp back up during the second quarter of 2017.

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 one LNG train with a collective production capacity of 7.8 mtpa of LNG and 70 thousand boe/d of condensate and NGL.

Russia

We have a 27.5% interest in Sakhalin-2, an integrated oil and gas project located in a subarctic environment.

We have a 50% interest in the Salym fields in western Siberia, Khanty Mansiysk Autonomous District, where production was approximately 125 thousand boe/d in 2016.

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

Singapore

In 2016, Shell and Keppel Offshore & Marine secured the licence to supply LNG fuel for vessels in the Port of Singapore after submitting a joint bid to the Maritime and Port Authority of Singapore. With the granting of the licence, Shell and Keppel have formed a 50:50 joint venture to fuel ships with LNG. We currently have an exclusive role as the aggregator of LNG demand for the Singapore market. In October 2016, we won a licence to import a further 1 mtpa, starting in 2017.

Thailand

As a result of the acquisition of BG, we have a 22.2% interest in the Bongkot and G12/48 fields in the Gulf of Thailand and a 66.7% interest in exploration Blocks 7 and 8 where activity is currently suspended due to overlapping claims by Thailand and Cambodia. We have an agreement over Block 9a under which we receive royalties. Production from the Bongkot field supplies around 20% of the country’s gas demand.

In January 2017, we reached an agreement with KUFPEC Thailand Holdings Pte Limited for the sale of our interest in the Bongkot field and adjoining offshore acreage.

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. Woodside (Shell interest 13.3%) is the operator on behalf of the joint arrangement participants in the NWS gas, condensate and oil fields, which produced more than 500 thousand boe/d in 2016.

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 and Jansz-lo fields. Gorgon LNG began production in March 2016.

We are the operator of a permit in the Browse Basin in which two separate gas fields were found: Prelude in 2007 and Concerto in 2009. Our development concept for these fields is based on our floating liquefied natural gas (FLNG) technology. The Prelude FLNG project (Shell interest 67.5%) is expected to produce about 110 thousand boe/d of gas and NGL, 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of liquefied petroleum gas. Major milestones during 2016 were the lifting of all modules on to the FLNG facility in South Korea, completion of wells and subsea installation, and starting to commission some of the facilities.

We are also a partner in the Browse joint arrangement (Shell interest 27%) covering the Brecknock, Calliance and Torosa gas fields. In 2016, the Browse partners decided not to move forward with the selected development concept, given the prevailing economic and market conditions.

Our other interests include a joint arrangement, with Shell as the operator, for the undeveloped Crux gas and condensate field (Shell interest 82%), and the Woodside-operated undeveloped Sunrise gas field in the Timor Sea (Shell interest 26.6%). We are a partner in both Shell-operated and other exploration joint arrangements in multiple basins including Bonaparte, Browse, Exmouth Plateau, Greater Gorgon and Outer Canning.

We have a 50% interest in Arrow Energy Holdings Pty Limited, a Queensland-based joint venture with CNPC. Arrow owns coal-bed methane assets and a domestic power business.

As a result of the BG acquisition, we have a 50% interest in train one and a 97.5% interest in train two of the Shell-operated Queensland Curtis LNG venture. The two-train liquefaction plant has an installed capacity of 8.5 mtpa. Our production of onshore natural gas from the Surat Basin supplies both this plant and the domestic market.

New Zealand

Our interests include the Maui (83.75%), Kapuni (50%) and Pohokura (48%) natural gas fields. We are an operator with an approximate 60% interest in two exploration licences in the Great South Basin and a 37.5% interest in the petroleum prospecting permit in the New Caledonia Basin.

The business is under strategic review and we sold our 83.75% interest in the Maui natural gas pipeline in 2016.

AFRICA

Egypt

As a result of the BG acquisition, we have interests of 35.5% and 38%, respectively, in trains one and two of the Egyptian LNG (ELNG) plant. In January 2014, force majeure notices were issued under the LNG agreements as a result of domestic gas diversions severely restricting volumes available to ELNG. These notices remain in place. See “Oil and gas information” on page 35.

Nigeria

We have a 25.6% interest in Nigeria LNG Ltd, which operates six LNG trains.

Tanzania

As a result of the BG acquisition, we have a 60% interest in, and are the operator of, Blocks 1 and 4 offshore southern Tanzania. The blocks cover approximately 7,000 square kilometres of the Mafia Deep Offshore Basin and the northern part of the Rovuma Basin. In 2014, a heads of agreement (HoA) was signed and subsequently extended between the partners of Blocks 1, 4 and 2 to develop a potential LNG project. A memorandum of understanding was also signed between the HoA partners and the Tanzania government to lease an agreed site for the project. In 2016, we completed drilling on all remaining wells.

Rest of Africa

We have a 17.9% share in the West African Gas Pipeline Company.

NORTH AMERICA

Canada

In 2014, we entered into a joint venture (Shell interest 50%) to evaluate an investment in an LNG export facility in Kitimat on the west coast of Canada. Together with our partners, we have elected to postpone the FID on the project.

USA

We have offtake rights to 100% of the capacity (2.5 mtpa) of the Elba Island liquefaction plant, which is under construction. Elba Island also has a regasification terminal in which we have contracted capacity of 11.6 mtpa.

We have 13.1 mtpa contracted capacity in the Lake Charles regasification terminal in Louisiana. Also, as a result of the acquisition of BG, we are involved in the Lake Charles LNG project. In 2016, we decided to delay the FID on this project to convert the existing regasification facility into a liquefaction plant in which we would have capacity rights.

SOUTH AMERICA

Bolivia

As a result of the BG acquisition, we have a 100% interest in the La Vertiente, Los Suris and Tarija XX East blocks and the La Vertiente gas processing plant. We have a 37.5% interest in the Caipipendi block where we mainly produce from the Margarita field. We also have a 25% interest in the Tarija XX West block where we produce from the Itaú field. We have the rights to explore and further develop the onshore Huacareta block.

Trinidad and Tobago

As a result of the BG acquisition, we are now the largest shareholder in all four trains at Atlantic LNG. We have an interest in three concessions with producing fields – Central Block (Shell interest 65%), East Coast Marine Area (Shell interest

50%) and North Coast Marine Area (Shell interest 45.88%). We also have an interest in exploration activities in blocks 5(c), 5(d), 6(d), and Atlantic Area blocks 3, 5, 6 and 7, with interests ranging from 35% to 100%.

Rest of South America

We have a 17% interest in Brazil’s Companhia de Gas de São Paulo (Comgás), a natural gas distribution company in the state of São Paulo.  In Peru, we have a 20% interest in an LNG liquefaction plant. We have interests in a gas pipeline connecting Uruguay to Argentina.

TRADING AND SUPPLY

We market a portion of our share of equity production of LNG and trade LNG volumes around the world through our hubs in the UK, Dubai and Singapore. We also market and trade natural gas, power and carbon-emission rights mainly in North America and Europe, of which a portion includes equity volumes from our upstream operations.

NEW ENERGIES

In 2016, we formed a New Energies business to pursue three main areas of opportunities: new fuels for transport, such as biofuels and hydrogen; integrated energy solutions, where wind and solar energy can partner with gas to manage intermittency; and connecting customers with new business models for energy, enabled by digitalisation and the decentralisation of energy systems.

Our focus remains on areas that share aspects with our core businesses, such as our biofuels joint venture Raízen (Shell interest 50%) in Brazil that produces ethanol from sugar cane, as well as hydrogen as a transport fuel. Working with the H2 Mobility joint venture in Germany, we aim to grow the hydrogen fuel network and are exploring other opportunities in the UK and USA. We are looking at how best to combine wind and solar power with our existing business and capabilities. Our share of capacity from wind power projects in the USA is more than 400 megawatts. In the Netherlands, we have an interest in the consortium that in December 2016 was awarded the concession by the Dutch government to develop the Borssele III and IV offshore wind farm projects, which are to be located 20 kilometres off the Dutch coast. We are exploring ways to deploy solar technologies to lower the carbon intensity of our operations.

INTEGRATED GAS DATA tables