Shell PLC — Annual Report 2013

Dec 31, 2013

Royal Dutch Shell plc Strategic Report for the year ended December 31, 2013

CONTENTS

02 STRATEGIC REPORT

• 02 Chairman's message
• 03 Chief Executive Officer's review
• 05 Business overview
• 07 Risk factors
• 11 Strategy and outlook
• 12 Market overview 14 Summary of results
• 16 Performance indicators
• 18 Selected financial data
• 19 Upstream
• 36 Downstream
• 43 Corporate
• 44 Liquidity and capital resources
• 48 Our people
• 50 Environment and society

54 SUPPLEMENTARY MATERIAL

54 Directors' remuneration for 2013

terms and Abbreviations

Currencies
\$	US dollar
€	euro
£	sterling
CHF	Swiss franc
	Units of Measurement
b(/d)	barrels (per day)
boe(/d)	barrels of oil equivalent (per day); natural
	gas volumes are converted to oil
	equivalent using a factor of 5,800 scf per barrel
MMBtu	million British thermal units
mtpa	million tonnes per annum
per day	volumes are converted to a daily basis
	using a calendar year
scf(/d)	standard cubic feet (per day)
Products
GTL	gas to liquids
LNG	liquefied natural gas
LPG	liquefied petroleum gas
NGL	natural gas liquids

Miscellaneous
ADS	American Depositary Share
AGM	Annual General Meeting
API	American Petroleum Institute
CCS	current cost of supplies
CO2	carbon dioxide
DBP	Deferred Bonus Plan
EMTN	euro medium-term note
EPS	earnings per share
HSSE	health, safety, security and environment
IAS	International Accounting Standard
IFRS	International Financial Reporting Standard(s)
IPIECA	the global oil and gas industry association for environmental and social issues
LTIP	Long-term Incentive Plan
OGP	International Association of Oil & Gas Producers
OML	oil mining lease
OPEC	Organization of the Petroleum Exporting Countries
OPL	oil prospecting licence
PSC	production-sharing contract
PSP	Performance Share Plan
R&D	research and development
REMCO	Remuneration Committee
TSR	total shareholder return

Cover photo

The photo shows staff at the gas-to-liquids plant that we operate in Bintulu, Malaysia. The plant uses our technology to turn natural gas into high-quality middle distillates, drilling fluids, waxes and other specialty products. It is one example of how we help make the most of energy resources.

ABOUT THIS REPORT

This Report comprises the Strategic Report, which is only part of the Royal Dutch Shell plc Annual Report and Form 20-F for the year ended December 31, 2013 (the Annual Report and Form 20-F), together with supplementary material as required by the Companies Act 2006 (the Act). This Report contains cross-references to other sections of the Annual Report and Form 20-F such as the "Directors' Remuneration Report", "Consolidated Financial Statements", and "Supplementary information – oil and gas (unaudited)". The auditor's report on the "Consolidated Financial Statements", including the auditor's statement under section 496 of the Act (whether the "Strategic Report" and "Directors' Report" were consistent with the "Consolidated Financial Statements") was unqualified.

In this Report Royal Dutch Shell plc (the Company) and its subsidiaries are collectively referred to as "Shell". The term "Shell" also is sometimes used for convenience where references are made to the Company and its subsidiaries in general. Likewise, the words "we", "us" and "our" are also used to refer to subsidiaries in general or to those who work for them. These expressions are also used where no useful purpose is served by identifying the particular company or companies. "Subsidiaries" and "Shell subsidiaries" as used in this Report refer to companies over which the Company, either directly or indirectly, has control through exposure or rights to their variable returns and the ability to affect those returns through its power over the companies. The Consolidated Financial Statements consolidate the financial statements of the Company and all subsidiaries. Companies over which Shell has joint control are generally referred to as "joint ventures" and companies over which Shell has significant influence but neither control nor joint control are referred to as "associates". The term "Shell interest" is used for convenience to indicate the direct and/or indirect ownership interest held by Shell in a venture, partnership or company, after exclusion of all third-party interests. The terms "A shares" and "B shares" are used to refer to Royal Dutch Shell plc A shares and B shares respectively.

Except as otherwise specified, the figures shown in the tables in this Report are in respect of subsidiaries only, without deduction of any non-controlling interest. However, the term "Shell share" is used for convenience to refer to the volumes of hydrocarbons that are produced, processed or sold through subsidiaries, joint ventures and associates. All of a subsidiary's share of production, processing or sales volumes are included in the Shell share, even if Shell owns less than 100% of the subsidiary. In the case of joint ventures and associates, however, Shell-share figures are limited only to Shell's entitlement. In all cases, royalty payments in kind are deducted from the Shell share.

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

This Report contains forward-looking statements (within the meaning of the US Private Securities Litigation Reform Act of 1995) concerning the financial condition, results of operations and businesses of Shell. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management's current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Shell to market risks and statements expressing management's expectations, beliefs, estimates, forecasts, projections and assumptions. These forwardlooking statements are identified by their use of terms and phrases such as "anticipate", "believe", "could", "estimate", "expect", "goals", "intend", "may", "objectives", "outlook", "plan", "probably", "project", "risks", "schedule", "seek", "should", "target", "will" and similar terms and phrases. There are a number of factors that could affect the future operations of Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this Report, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for Shell's products; (c) currency fluctuations; (d) drilling and production results; (e) reserves estimates; (f) loss of market share and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including regulatory measures addressing climate change; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. Also see "Risk factors" for additional risks and further discussion. All forward-looking statements contained in this Report are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Each forwardlooking 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

This Report and the Annual Report and Form 20-F are each available, free of charge, at www.shell.com/annualreport or at the offices of Shell in The Hague, the Netherlands and London, UK. Copies of this Report and the Annual Report and Form 20-F also may be obtained, free of charge, by mail.

CHAIRMAN'S MESSAGE

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

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

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

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

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

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

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

TAKING A LONG-TERM VIEW

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

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

TECHNOLOGY AND INNOVATION

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

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

INVESTING IN OUR PEOPLE

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

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

Jorma Ollila

Chairman

03 SHELL STRATEGIC REPORT 2013 CHIEF EXECUTIVE OFFICER'S REVIEW

CHIEF EXECUTIVE OFFICER'S REVIEW

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

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

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

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

• improving our financial performance, including restructuring our Oil Products and North American shale oil and gas businesses;
• enhancing our capital efficiency; and
• maintaining our strong track record of delivering new projects, while integrating our recent acquisitions.

2013 MILESTONES

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

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

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

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

IMPROVING OUR FINANCIAL PERFORMANCE AND CAPITAL EFFICIENCY

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

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

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

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

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

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

THE NEXT PHASE OF GROWTH: PROJECT DELIVERY

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

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

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

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

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

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

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

CHIEF EXECUTIVE OFFICER'S REVIEW CONTINUED

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

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

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

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

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

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

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

Ben van Beurden

Chief Executive Officer

BUSINESS OVERVIEW

HISTORY

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

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

ACTIVITIES

Shell is one of the world's largest independent oil and gas companies in terms of market capitalisation, operating cash flow and oil and gas production. We aim for strong operational performance and productive investments in countries around the world including Australia, Brazil, Brunei, Canada, China, Denmark, Germany, Malaysia, the Netherlands, Nigeria, Norway, Oman, Qatar, Russia, the UK and the USA.

We are bringing new oil and gas supplies on-stream from major field developments. We are also investing in growing our integrated gas activities. For example, in February 2013 we agreed to buy part of Repsol S.A.'s liquefied natural gas (LNG) portfolio, including supply positions in Peru, and Trinidad and Tobago. This acquisition was completed in January 2014. Our Downstream integrated gas activities include converting gas to high-value petrochemicals and liquid products such as fuels and lubricants.

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

We also have a diverse portfolio of refineries and chemical plants that enable us to capture value from the oil and natural gas that we produce. Furthermore, we are a leading biofuel producer and fuel retailer in Brazil, through our Raízen joint venture. We have a strong retail position not only in the major industrialised countries, but also in the developing ones. The distinctive Shell pecten, (a trademark in use since the early part of the twentieth century), and trademarks in which the word Shell appears, support this marketing effort throughout the world. A strong patent portfolio underlies the technology that we employ in our various businesses. In total, Shell currently has about 15,000 granted patents and pending patent applications.

BUSINESS OVERVIEW CONTINUED

BUSINESSES

Upstream International

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

Upstream Americas

Upstream Americas manages the Upstream businesses in North and South America. It explores for and recovers crude oil, natural gas and natural gas liquids, transports oil and gas and operates the upstream and midstream infrastructure necessary to deliver oil and gas to market. Upstream Americas also extracts bitumen from oil sands that is converted into synthetic crude oil. Additionally, it manages the US-based wind business. It manages its operations by line of business, supported by activities such as Exploration and New Business Development.

Downstream

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

Projects & Technology

Projects & Technology manages the delivery of Shell's major projects and drives research and innovation to create technology solutions. It provides technical services and technology capability covering both Upstream and Downstream activities. It is also responsible for providing functional leadership across Shell in the areas of safety and environment, and contracting and procurement. Since January 2013, it has also been responsible for all wells activities and CO2 management.

SEGMENTAL REPORTING

Upstream combines the operating segments Upstream International and Upstream Americas, which have similar economic characteristics, products and services, production processes, types and classes of customers, and methods of distribution. Upstream and Downstream earnings include their respective elements of Projects & Technology and of trading activities. Corporate represents the key support functions comprising holdings and treasury, headquarters, central functions and Shell's self-insurance activities.

REVENUE BY BUSINESS SEGMENT (INCLUDING INTER-SEGMENT SALES) \$ MILLION
	2013	2012	2011
Upstream
Third parties	47,357	43,431	42,260
Inter-segment	45,512	51,119	49,431
Total	92,869	94,550	91,691
Downstream
Third parties	403,725	423,638	427,864
Inter-segment	702	772	782
Total	404,427	424,410	428,646
Corporate
Third parties	153	84	47
Total	153	84	47

REVENUE BY GEOGRAPHICAL AREA (EXCLUDING INTER-SEGMENT SALES)						\$ MILLION
	2013	%	2012	%	2011	%
Europe	175,584 38.9		184,223	39.4	187,498	39.9
Asia, Oceania,
Africa	157,673 34.9		156,310	33.5	148,260	31.5
USA	72,552 16.1		91,571	19.6	91,946	19.6
Other Americas	45,426 10.1		35,049	7.5	42,467	9.0
Total	451,235100.0		467,153 100.0		470,171 100.0

RESEARCH AND DEVELOPMENT

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

For that reason we have been spending more than any other international oil and gas company to research and develop innovative technology – more than \$1 billion annually since 2007. In 2013, research and development (R&D) expenses were \$1,318 million, compared with \$1,307 million in 2012 and \$1,123 million in 2011 [A].

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

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

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

RISK FACTORS

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

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

Prices of crude oil, natural gas, oil products and chemicals are affected by supply and demand, both globally and regionally. Moreover, prices for oil and gas can move independently from each other. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, conflicts, economic conditions and actions by major oil-producing countries. Price fluctuations could have a material effect. For example, in a low oil and gas price environment, Shell would generate less revenue from its Upstream production, and as a result certain long-term projects might become less profitable, or even incur losses. Additionally, low oil and gas prices could result in the debooking of proved oil or gas reserves, if they become uneconomic in this type of environment. Prolonged periods of low oil and gas prices, or rising costs, could also result in projects being delayed or cancelled, as well as in the impairment of certain assets. In a high oil and gas price environment, we could experience sharp increases in cost, and under some production-sharing contracts our entitlement to proved reserves would be reduced. Higher prices could also reduce demand for our products which might result in lower profitability, particularly in our Downstream business.

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

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

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

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

Shell subsidiaries, joint ventures and associates are subject to differing economic and financial market conditions throughout the world. Political or economic instability affects such markets. Shell uses debt

instruments such as bonds and commercial paper to raise significant amounts of capital. Should our access to debt markets become more difficult, the potential impact on our liquidity could have an adverse effect on our operations. Commodity trading is an important component of our supply and distribution function. Treasury and trading risks include, among others, exposure to movements in interest rates, foreign exchange rates and commodity prices, counterparty default and various operational risks. As a global company doing business in more than 70 countries, we are exposed to changes in currency values and exchange controls. While we undertake some currency hedging, we do not do so for all of our activities. See Notes 6 and 20 to the "Consolidated Financial Statements". Shell has significant financial exposure to the euro and could be materially affected by a significant change in its value or any structural changes to the European Union (EU) or the European Economic and Monetary Union affecting the euro. While we do not have significant direct exposure to sovereign debt, it is possible that our partners and customers may have exposure which could impair their ability to meet their obligations to us. Therefore, a sovereign debt downgrade or default could have a material adverse effect on Shell.

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

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

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

OIL AND GAS PRODUCTION AVAILABLE FOR SALE			MILLION BOE [A]
	2013	2012	2011
Shell subsidiaries	850	825	811
Shell share of joint ventures and
associates	318	369	362
Total	1,168	1,194	1,173

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

RISK FACTORS CONTINUED

PROVED DEVELOPED AND UNDEVELOPED OIL AND GAS RESERVES [A][B] (AT DECEMBER 31) MILLION BOE [C]
	2013	2012	2011
Shell subsidiaries	10,835	9,873	10,320
Shell share of joint ventures and
associates	3,109	3,701	3,946
Total	13,944	13,574	14,266
Attributable to non
controlling interest [D]	12	18	16
Attributable to Royal Dutch Shell
plc shareholders	13,932	13,556	14,250

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

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

[C] Natural gas volumes are converted to oil equivalent using a factor of 5,800 scf per barrel. [D] Proved reserves attributable to non-controlling interest in Shell subsidiaries.

An erosion of our business reputation would have a negative impact on our brand, our ability to secure new resources and our licence to operate. Shell is one of the world's leading energy brands, and its brand and reputation are important assets. The Shell General Business Principles govern how Shell and its individual companies conduct their affairs, and the Code of Conduct instructs employees and contractors on how to behave in line with the principles. It is a challenge for us to ensure that all employees and contractors, well above 100,000 in total, comply with the principles. Failure – real or perceived – to follow these principles, or other real or perceived failures of governance or regulatory compliance, could harm our reputation. This could impact our licence to operate, damage our brand, harm our ability to secure new resources and limit our ability to access the capital market.

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

Technology and innovation are essential to Shell. If we do not develop the right technology, do not have access to it or do not deploy it effectively, the delivery of our strategy and our licence to operate may be adversely affected. We operate in environments where the most advanced technologies are needed. While these technologies are regarded as safe for the environment with today's knowledge, there is always the possibility of unknown or unforeseeable environmental impacts that could harm our reputation, licence to operate or expose us to litigation or sanctions.

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

In the future, in order to help meet the world's energy demand, we expect our production to rise and more of our production to come from higher energy-intensive sources than at present. Therefore, it is expected that both the CO2 intensity of our production, as well as our absolute Upstream CO2 emissions, will increase as our business grows. Examples of such developments are our in-situ Peace River project and our oil sands activities in Canada. Additionally, as production from Iraq increases, we expect that CO2 emissions from flaring will rise. We are working with our partners to find ways to capture the gas that is flared. Over time, we expect that a growing share of our CO2 emissions will be subject to regulation and result in increasing our costs. Furthermore, continued attention to climate change, including activities by nongovernmental and political organisations, is likely to lead to additional regulations designed to reduce greenhouse gas emissions. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our CO2 emissions for new and existing projects or products, we may experience additional costs, delayed projects, reduced production and reduced demand for hydrocarbons.

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

The health, safety, security and environment (HSSE) risks to which we are potentially exposed cover a wide spectrum, given the geographic range, operational diversity and technical complexity of Shell's daily operations. We have operations, including oil and gas production, transport and shipping of hydrocarbons, and refining, in difficult geographies or climate zones, as well as environmentally sensitive regions, such as the Arctic or maritime environments, especially in deep water. These and other operations expose us to the risk, among others, of major process safety incidents, effects of natural disasters, earth tremors, social unrest, personal health and safety lapses, and crime. If a major HSSE risk materialises, such as an explosion or hydrocarbon spill, this could result in injuries, loss of life, environmental harm, disruption to business activities and, depending on their cause and severity, material damage to our reputation and eventually loss of licence to operate. In certain circumstances, liability could be imposed without regard to Shell's fault in the matter. Requirements governing HSSE matters often change and are likely to become more stringent over time. The operator could be asked to adjust its future production plan, as we have seen in the Netherlands, impacting production and costs. We could incur significant additional costs in the future complying with such requirements or as a result of violations of, or liabilities under, HSSE laws and regulations, such as fines, penalties, clean-up costs and third-party claims.

Shell mainly self-insures its risk exposures.

Shell insurance subsidiaries provide insurance coverage to Shell entities, generally up to \$1.15 billion per event and usually limited to Shell's percentage interest in the relevant entity. The type and extent of the coverage provided is equal to that which is otherwise commercially available in the third-party insurance market. While from time to time the insurance subsidiaries may seek reinsurance for some of their risk exposures, such reinsurance would not provide any material coverage in the event of an incident like BP Deepwater Horizon. Similarly, in the event of a material environmental incident, there would be no material proceeds available from third-party insurance companies to meet Shell's obligations.

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

In our Nigerian operations we face various risks and adverse conditions, some of which have deteriorated during the year. These risks include: security issues surrounding the safety of our people, host communities, and operations; sabotage and theft; our ability to enforce existing contractual rights; limited infrastructure; and potential legislation that could increase our taxes or costs of operation. The Nigerian government is contemplating new legislation to govern the petroleum industry which, if passed into law, would likely have a significant adverse impact on Shell's existing and future activities in that country.

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

Developments in politics, laws and regulations can – and do – affect our operations. Potential developments include: forced divestment of assets; expropriation of property; cancellation or forced renegotiation of contract rights; additional taxes including windfall taxes, restrictions on deductions and retroactive tax claims; import and export restrictions; foreign exchange controls; and changing environmental regulations and disclosure requirements. In our Upstream activities these developments can and do affect land tenure, re-writing of leases, entitlement to produced hydrocarbons, production rates, royalties and pricing. Parts of our Downstream activities are subject to price controls

in some countries. From time to time, cultural and political factors play technical, contractual and economic information. Estimates may

a role in unprecedented and unanticipated judicial outcomes that could adversely affect Shell. If we do not comply with policies and regulations, this may result in regulatory investigations, litigation and ultimately sanctions. Certain governments, states and regulatory bodies have, in the opinion of Shell, exceeded their constitutional authority by attempting unilaterally to amend or cancel existing agreements or arrangements; by failing to honour existing contractual commitments; and by seeking to adjudicate disputes between private litigants. EU regulators have adopted regulations that, subject to UK implementation, require disclosure of information on payments to governments that we believe is immaterial to investors, but that could compromise confidential commercial arrangements and create conflicting legal requirements. The United States Securities and Exchange Commission (SEC) had adopted similar requirements, but these requirements were vacated by the US Federal District Court. Accordingly, the SEC must adopt new rules. Additional regulations targeted at the financial sector could have adverse consequences for our trading, treasury and pension operations.

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

As seen in recent years in Nigeria, north Africa and the Middle East, social and civil unrest, both within the countries in which we operate and elsewhere, can – and does – affect Shell. Potential developments that could impact our business include international sanctions, conflicts including war, acts of political or economic terrorism and acts of piracy on the high seas, as well as civil unrest, including disruptions by non-governmental and political organisations, and local security concerns that threaten the safe operation of our facilities and transport of our products. For example, EU sanctions have prohibited us from producing oil and gas in Syria, and the USA and the EU have imposed sanctions relating to transactions involving Iran and Sudan, among other countries. If such risks materialise, they could result in injuries and disruption to business activities.

We rely heavily on information technology systems for our operations.

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

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

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

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

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

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

A significant share of our capital is invested in joint arrangements or associates. In cases where we are not the operator we have limited influence over, and control of, the behaviour, performance and costs of operation of such joint arrangements or associates. Despite not having control, we could still be exposed to the risks associated with these operations. For example, our partners or members of a joint arrangement or an associate (particularly local partners in developing countries) may not be able to meet their financial or other obligations to the projects, threatening the viability of a given project.

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

Antitrust and competition laws apply to Shell and its joint ventures and associates in the vast majority of countries in which we do business. Shell and its joint ventures and associates have been fined for violations of antitrust and competition law. These include a number of fines by the European Commission Directorate-General for Competition (DG COMP). Due to the DG COMP's fining guidelines, any future conviction of Shell and its joint ventures or associates for violation of EU competition law could result in significantly larger fines. Violation of antitrust laws is a criminal offence in many countries, and individuals can be either imprisoned or fined. Furthermore, it is now common for persons or corporations allegedly injured by antitrust violations to sue for damages.

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

In 2010, Shell agreed to a Deferred Prosecution Agreement (DPA) with the U.S. Department of Justice (DOJ) for violations of the Foreign Corrupt Practices Act (FCPA), which arose in connection with its use of the freight-forwarding firm Panalpina. In November 2013, the DPA was successfully concluded. Shell's ethics and compliance programme was enhanced during the DPA and remains in full force and effect. Any violations of the FCPA or other relevant anti-bribery and corruption legislation could have a material adverse effect on the Company.

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

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

RISK FACTORS CONTINUED

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

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

STRATEGY AND OUTLOOK

STRATEGY

Our strategy seeks to reinforce our position as a leader in the oil and gas industry, while helping to meet global energy demand in a responsible way. We aim to grow our cash flow and deliver competitive returns through economic cycles, to finance a competitive dividend and fund investment for future growth. Safety and environmental and social responsibility are at the heart of our activities.

Intense competition exists for access to upstream resources and to new downstream markets. But we believe that our technology, project delivery capability and operational excellence will remain key differentiators for our businesses. We expect about 85% of our capital investment in 2014 to be in our Upstream businesses.

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

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

• our upstream and downstream "engines" are strongly cashgenerative, mature businesses, which will underpin our financial performance to at least the end of this decade. Here we only seek to make investments in selective growth positions, and we apply Shell's distinctive technology and operating performance to extend the productive lives of our assets and to enhance their profitability;
• our growth priorities follow two strategic themes: integrated gas and deep water. These will provide our medium-term growth, and we expect them to become core engines in the future. Here, we use the advantages of Shell's technological know-how and global scale to unlock highly competitive resources positions; and
• our longer-term strategic themes are resource plays such as shale oil and gas as well as future opportunities including the Arctic, Iraq, Kazakhstan, Nigeria, and heavy oil, where we believe large reserves positions could potentially become available, with the pace of development driven by market and local operating conditions, as well as the regulatory environment.

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

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

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

OUTLOOK

We continuously seek to improve our operating performance, with an emphasis on health, safety and environment, asset performance and operating costs. For 2014, we have set out three key priorities: improving our financial performance, enhancing our capital efficiency, including financial discipline when evaluating investment opportunities, and continuing our focus on project delivery.

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

Shell has built up a substantial portfolio of project options for future growth. This portfolio has been designed to capture energy price upside and manage Shell's exposure to industry challenges from cost inflation and political risk. Key elements of these opportunities are in global exploration and established resources positions in the Gulf of Mexico, Australian LNG, offshore Europe, and others. Shell is working to mature these projects, with an emphasis on financial returns.

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

MARKET OVERVIEW

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

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

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

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

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

CRUDE OIL AND NATURAL GAS PRICES

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

OIL AND GAS AVERAGE INDUSTRY PRICES [A]
	2013	2012	2011
Brent (\$/b)		108.66 111.67 111.26
West Texas Intermediate (\$/b)	97.99	94.13	95.04
Henry Hub (\$/MMBtu)	3.70	2.76	4.01
UK National Balancing Point (pence/therm)	68.12	59.74	56.35
Japan Customs-cleared Crude (\$/b)		110.21 114.77 109.10

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

The Brent crude oil price, an international crude-oil benchmark, traded in a range of \$97-118 per barrel during 2013, ending the year at \$109 per barrel. Both the Brent and the West Texas Intermediate (WTI) average crude oil prices for 2013 were little changed compared with 2012. WTI traded overall at a discount to Brent, but the discount was much narrower in the second half of 2013 as an expansion in pipeline capacity increased the ability to move oil from the landlocked area of Cushing, Oklahoma, where WTI is delivered.

Unlike crude-oil pricing, which is global in nature, gas prices vary significantly from region to region. In the USA, the natural gas price at Henry Hub in 2013 averaged \$3.7 per million British thermal units (MMBtu), 34% higher compared with 2012, and traded in a range of \$3.1-4.5 per MMBtu. At the start of 2013, the price was \$3.1 per MMBtu due to mild winter weather, before a late cold snap in March increased demand and pushed it up to almost \$4.4 per MMBtu. The price then trended downwards until December, when cold weather pushed it up to a peak of \$4.5 per MMBtu, before it fell slightly to end the year at \$4.4 per MMBtu.

In Europe, gas prices rose despite the fall in demand. In the UK, the average price at the UK National Balancing Point was 14% higher compared with 2012. In continental Europe, price increases at the main gas trading hubs in Belgium, Germany and the Netherlands were similar to those at the UK National Balancing Point. These prices reflected a tightening of global LNG markets and higher prices in Asia-Pacific. The use of oil-indexed gas pricing is decreasing in continental Europe, with many natural gas contracts now including spot market pricing as a major component.

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

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

CRUDE OIL AND NATURAL GAS PRICES FOR INVESTMENT EVALUATION

The range of possible future crude oil and natural gas prices used in project and portfolio evaluations within Shell is determined after an assessment of short-, medium- and long-term price drivers under different sets of assumptions. Historical analysis, trends and statistical volatility are considered in this assessment, as are analyses of possible future economic conditions, geopolitics, actions by the Organization of the Petroleum Exporting Countries (OPEC), supply costs and the balance of supply and demand. Sensitivity analyses are used to test the impact of low-price drivers, such as economic weakness, and highprice drivers, such as strong economic growth and low investment levels in new production capacity. Short-term events, such as relatively warm winters or cool summers affecting demand, and supply disruptions due to weather or politics, contribute to price volatility.

We expect oil and gas prices to remain volatile. For the purposes of making investment decisions, generally we test the economic performance of long-term projects against price ranges of \$70-110 per barrel for Brent crude oil and \$3-5 per MMBtu for gas at Henry Hub. As part of our normal business practice, the range of prices used for this purpose is subject to review and change, and was last confirmed in the fourth quarter of 2013.

REFINING AND PETROCHEMICAL MARKET TRENDS

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

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

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

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

SUMMARY OF RESULTS

INCOME FOR THE PERIOD			\$ MILLION
	2013	2012[A]	2011[A]
Earnings by segment [B]
Upstream	12,638	22,244	24,466
Downstream	3,869	5,382	4,170
Corporate	372	(203)	102
Total segment earnings [B]	16,879	27,423	28,738
Attributable to non-controlling interest	(134)	(259)	(205)
Earnings on a current cost of supplies basis attributable to Royal Dutch Shell plc
shareholders	16,745	27,164	28,533
Current cost of supplies adjustment [B]	(353)	(463)	2,355
Non-controlling interest	(21)	11	(62)
Income attributable to Royal Dutch Shell plc shareholders	16,371	26,712	30,826
Non-controlling interest	155	248	267
Income for the period	16,526	26,960	31,093

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements". [B] See Note 2 to the "Consolidated Financial Statements". Segment earnings are presented on a current cost of supplies basis.

EARNINGS 2013-2011

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

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

CCS earnings exclude the effect of changes in the oil price on inventory valuation, as the purchase price of the volumes sold during a period is based on the current cost of supplies during the same period, after making allowance for the tax effect. Accordingly, when oil prices increase during the period, CCS earnings are likely to be lower than earnings calculated on a first-in first-out (FIFO) basis. Similarly, in a period with declining oil prices, CCS earnings are likely to be higher than earnings calculated on a FIFO basis. This explains why 2013 CCS earnings were \$353 million higher than earnings calculated on a FIFO basis (2012: \$463 million higher; 2011: \$2,355 million lower).

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

charges and higher decommissioning provisions in 2012. In 2012, earnings decreased by 9% compared with 2011, reflecting higher depreciation charges, increased operating and exploration expenses, lower gains associated with the fair-value accounting of certain gas and derivative contracts, and additional tax charges, partly offset by higher contributions from our integrated gas activities (LNG and GTL).

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

BALANCE SHEET AND NET CAPITAL INVESTMENT

Shell's strategy to invest in the development of major growth projects, primarily in Upstream, explains the most significant changes to the balance sheet in 2013. Property, plant and equipment increased by \$20 billion. Net capital investment was \$44 billion, 49% higher than in 2012; see Note 4 to the "Consolidated Financial Statements". The effect of net capital investment on property, plant and equipment was partly offset by depreciation, depletion and amortisation of \$22 billion.

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

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

ADOPTION OF IFRS 11 JOINT ARRANGEMENTS

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

PROVED RESERVES AND PRODUCTION

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

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

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

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

KEY ACCOUNTING ESTIMATES AND JUDGEMENTS

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

LEGAL PROCEEDINGS

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

PERFORMANCE INDICATORS

KEY PERFORMANCE INDICATORS

		Total shareholder return

2013 8.6% 2012 0.2%

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

Net cash from operating activities (\$ billion)
2013	2012
40	46

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

	Project delivery
2013	88%	2012	90%

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

		Production available for sale (thousand boe/d)
2013	3,199	2012 3,262

Production is the sum of all average daily volumes of unrefined oil and natural gas produced for sale by Shell subsidiaries and the Shell share of joint ventures and associates. The unrefined oil comprises crude oil, natural gas liquids, synthetic crude oil and bitumen. The gas volume is converted into equivalent barrels of oil to make the summation possible. Changes in production have a significant impact on Shell's cash flow.

Equity sales of liquefied natural gas (million tonnes) 2013 19.6 2012 20.2

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

Refinery and chemical plant availability 2013 92.5% 2012 92.9%

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

Total recordable case frequency (injuries per million working hours) 2013 1.15 2012 1.26

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

ADDITIONAL PERFORMANCE INDICATORS

Earnings on a current cost of supplies basis attributable to Royal Dutch Shell plc shareholders (\$ million) 2013 16,745 2012 27,164 [A]

Earnings per share on a current cost of supplies basis (\$) 2013 2.66 2012 4.34 [A]

Earnings on a current cost of supplies (CCS) basis attributable to Royal Dutch Shell plc shareholders is the income for the period, adjusted for the after-tax effect of oil-price changes on inventory and non-controlling interest. CCS earnings per share is calculated by dividing CCS earnings attributable to shareholders by the average number of shares outstanding. See "Summary of results" and Note 2 to the "Consolidated Financial Statements".

Net capital investment (\$ million) 2013 44,303 2012 29,803

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

		Return on average capital employed
2013	7.9%	2012	13.6% [A]

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

Gearing
2013	16.1%	2012	9.8% [A]

Gearing is defined as net debt (total debt less cash and cash equivalents) as a percentage of total capital (net debt plus total equity), at December 31. It is a measure of the degree to which Shell's operations are financed by debt. See Note 15 to the "Consolidated Financial Statements".

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

Proved oil and gas reserves attributable to Royal Dutch Shell plc shareholders (million boe)

2013 13,932 2012 13,556

Proved oil and gas reserves attributable to Royal Dutch Shell plc shareholders are the total estimated quantities of oil and gas from Shell subsidiaries (excluding reserves attributable to non-controlling interest) and the Shell share of joint ventures and associates that geoscience and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs, as at December 31, under existing economic conditions, operating methods and government regulations. Gas volumes are converted into barrels of oil equivalent (boe) using a factor of 5,800 standard cubic feet per barrel. Reserves are crucial to an oil and gas company, since they constitute the source of future production. Reserves estimates are subject to change based on a wide variety of factors, some of which are unpredictable. See "Risk factors".

Operational spills of more than 100 kilograms 2013 174 2012 207

The operational spills indicator is the number of incidents in respect of activities where we are the operator in which 100 kilograms or more of oil or oil products were spilled as a result of those activities. The number for 2012 was updated from 204 to reflect the completion of investigations into spills.

Employees (thousand) 2013 92 2012 87

The employees indicator consists of the annual average full-time employee equivalent of the total number of people on full-time or parttime employment contracts with Shell subsidiaries including, from January 1, 2013, our share of employees of certain additional joint operations, as a result of the adoption of IFRS 11 Joint Arrangements.

STRATEGIC REPORT

SELECTED FINANCIAL DATA

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

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

CONSOLIDATED STATEMENT OF INCOME AND OF COMPREHENSIVE INCOME DATA \$ MILLION
	2013	2012	2011	2010	2009
Revenue	451,235	467,153	470,171	368,056	278,188
Income for the period	16,526	26,960	31,093	20,474	12,718
Income attributable to non-controlling interest	155	248	267	347	200
Income attributable to Royal Dutch Shell plc
shareholders [A]	16,371	26,712	30,826	20,127	12,518
Comprehensive income attributable to Royal Dutch
Shell plc shareholders	18,243	24,470	26,250	19,893	19,810

[A] All results are from continuing operations.

CONSOLIDATED BALANCE SHEET DATA					\$ MILLION
	2013	2012	2011	2010	2009
Total assets	357,512	350,294	337,474	317,271	286,650
Total debt	44,562	37,754	37,175	44,332	35,033
Share capital	542	542	536	529	527
Equity attributable to Royal Dutch Shell plc
shareholders	180,047	174,749	158,480	140,453	129,109
Non-controlling interest	1,101	1,433	1,486	1,767	1,704

EARNINGS PER SHARE					\$
	2013	2012	2011	2010	2009
Basic earnings per €0.07 ordinary share	2.60	4.27	4.97	3.28	2.04
Diluted earnings per €0.07 ordinary share	2.60	4.26	4.96	3.28	2.04

SHARES					NUMBER
	2013	2012	2011	2010	2009
Basic weighted average number of A and B shares	6,291,126,326	6,261,184,755	6,212,532,421	6,132,640,190	6,124,906,119
Diluted weighted average number of A and B shares	6,293,381,407	6,267,839,545	6,221,655,088	6,139,300,098	6,128,921,813

OTHER FINANCIAL DATA					\$ MILLION
	2013	2012	2011	2010	2009
Net cash from operating activities	40,440	46,140	36,771	27,350	21,488
Net cash used in investing activities	40,146	28,453	20,443	21,972	26,234
Dividends paid	7,450	7,682	7,315	9,979	10,717
Net cash used in financing activities	8,978	10,630	18,131	1,467	829
(Decrease)/increase in cash and cash equivalents	(8,854)	7,258	(2,152)	3,725	(5,469)
Earnings/(losses) by segment [A]
Upstream	12,638	22,244	24,466	15,935	8,354
Downstream	3,869	5,382	4,170	2,950	258
Corporate	372	(203)	102	91	1,310
Total segment earnings	16,879	27,423	28,738	18,976	9,922
Attributable to non-controlling interest	(134)	(259)	(205)	(333)	(118)
Earnings on a current cost of supplies basis
attributable to Royal Dutch Shell plc shareholders [B]	16,745	27,164	28,533	18,643	9,804
Net capital investment [A]
Upstream	39,217	25,320	19,083	21,222	22,326
Downstream	4,885	4,275	4,342	2,358	6,232
Corporate	201	208	78	100	324
Total	44,303	29,803	23,503	23,680	28,882

[A] See Notes 2 and 4 to the "Consolidated Financial Statements".

[B] See table in "Summary of results".

UPSTREAM

KEY STATISTICS			\$ MILLION
	2013	2012[A]	2011[A]
Segment earnings	12,638	22,244	24,466
Including:
Revenue (including inter-segment sales)	92,869	94,550	91,691
Share of profit of joint ventures and associates	6,120	8,001	7,127
Production and manufacturing expenses	18,471	16,354	15,586
Selling, distribution and administrative expenses	1,194	1,211	1,273
Exploration	5,278	3,104	2,266
Depreciation, depletion and amortisation	16,949	11,387	8,827
Net capital investment [B]	39,217	25,320	19,083
Oil and gas production available for sale (thousand boe/d)	3,199	3,262	3,215
Equity LNG sales volume (million tonnes)	19.6	20.2	18.8
Proved oil and gas reserves at December 31 (million boe) [C]	13,932	13,556	14,250

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

[B] See Notes 2 and 4 to the "Consolidated Financial Statements".

[C] Excludes reserves attributable to non-controlling interest in Shell subsidiaries.

OVERVIEW

Our Upstream businesses explore for and extract crude oil and natural gas, often in joint arrangements with international and national oil and gas companies. This includes the extraction of bitumen from mined oil sands which we convert into synthetic crude oil. We liquefy natural gas by cooling it, and transport the liquefied natural gas (LNG) to customers across the world. We also convert natural gas to liquids (GTL) to provide high-quality fuels and other products, and we market and trade natural gas (including LNG) in support of our Upstream businesses.

BUSINESS CONDITIONS

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

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

EARNINGS 2013-2012

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

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

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

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

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

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

EARNINGS 2012-2011

Segment earnings in 2012 of \$22,244 million included a net gain of \$2,137 million as described above. Segment earnings in 2011 of \$24,466 million included a net gain of \$3,855 million, mainly related to gains on divestments, the fair-value accounting of certain gas and derivative contracts, partly offset by the cost impact of the US offshore drilling moratorium.

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

UPSTREAM CONTINUED

NET CAPITAL INVESTMENT

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

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

PORTFOLIO ACTIONS AND BUSINESS DEVELOPMENT

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

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

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

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

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

Also in the UK, we acquired an additional 5.9% interest in the offshore Schiehallion field from Murphy Schiehallion Ltd bringing our interest in the field to 55%.

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

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

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

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

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

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

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

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

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

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

AVAILABLE-FOR-SALE PRODUCTION

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

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

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

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

PROVED RESERVES

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

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

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

Shell subsidiaries

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

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

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

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

SYNTHETIC CRUDE OIL

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

BITUMEN

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

Shell share of joint ventures and associates

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

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

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

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

Proved undeveloped reserves

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

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

DELIVERY COMMITMENTS

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

In the past three years, Shell met all contractual delivery commitments.

In the period 2014 to 2016, Shell is contractually committed to deliver to third parties and joint ventures and associates a total of approximately 4,400 thousand million scf of natural gas from Shell subsidiaries, joint ventures and associates. The sales contracts contain a mixture of fixed and variable pricing formulae that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery.

The shortfall between Shell's delivery commitments and its proved developed reserves is estimated at 24% of Shell's total gas delivery commitments. This shortfall is expected to be met through the development of proved undeveloped reserves as well as new projects and purchases on the spot market.

EXPLORATION

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

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

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

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

UPSTREAM CONTINUED

kilometres with notable (over 10,000 square kilometres) increases in Australia and Canada, and reductions of 75,100 square kilometres with notable reductions in Brazil and Libya due to relinquishments and exits respectively.

BUSINESS AND PROPERTY

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

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

• • Licences (or concessions), which entitle the holder to explore for hydrocarbons and exploit any commercial discoveries. Under a licence, the holder bears the risk of exploration, development and production activities, and is responsible for financing these activities. In principle, the licence holder is entitled to the totality of production less any royalties in kind. The government, government entity or government-run oil and gas company may sometimes enter as a participant in a joint arrangement sharing the rights and obligations of the licence but usually without sharing the exploration risk. In a few cases, the government entity, government-run oil and gas company or agency has an option to purchase a certain share of production.
• • Lease agreements, which are typically used in North America and are usually governed by similar terms as licences. Participants may include governments or private entities, and royalties are either paid in cash or in kind.
• • Production-sharing contracts (PSCs) entered into with a government, government entity or government-run oil and gas company. PSCs generally oblige the independent oil and gas company, as contractor, to provide all the financing and bear the risk of exploration, development and production activities in exchange for a share of the production. Usually, this share consists of a fixed or variable part that is reserved for the recovery of the contractor's cost (cost oil). The remaining production is split with the government, government entity or government-run oil and gas company on a fixed or volume/revenue-dependent basis. In some cases, the government, government entity or government-run oil and gas company will participate in the rights and obligations of the contractor and will share in the costs of development and production. Such participation can be across the venture, or on a field-by-field basis. Additionally, as the price of oil or gas increases above certain predetermined levels, the independent oil and gas company's entitlement share of production normally decreases, and vice versa. Accordingly, its interest in a project may not be the same as its entitlement.

Europe

DENMARK

We hold a non-operating interest in a producing concession in Denmark (Shell interest 36.8%), which was granted in 1962 and will expire in 2042. The Danish government is one of our partners with a 20% interest.

IRELAND

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

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

ITALY

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

NETHERLANDS

Shell and ExxonMobil are 50:50 shareholders in Nederlandse Aardolie Maatschappij B.V. (NAM), the largest hydrocarbon producer in the Netherlands. An important part of NAM's gas production comes from the onshore Groningen gas field, in which the Dutch government has a 40% interest and NAM a 60% interest. NAM also has a 60% interest in the Schoonebeek oil field, which has been redeveloped using enhanced oil recovery technology. NAM also operates a significant number of other onshore gas fields and offshore gas fields in the North Sea. It is expected that, later in 2014, the Minister of Economic Affairs of the Netherlands will formally approve NAM's production plan for the Groningen field. It would cap production in 2014 at 42.5 billion cubic metres, in an effort to diminish the potential for seismic activity.

NORWAY

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

UK

We operate a significant number of our interests on the UK Continental Shelf on behalf of a 50:50 joint arrangement with ExxonMobil. Most of our UK oil and gas production comes from the North Sea. We hold various non-operated interests in the Atlantic Margin area, principally in the West of Shetlands area. We also have interests in the nonoperated Schiehallion field (Shell interest 55%), and in the Beryl area fields, with interests ranging from 20% to 49%.

REST OF EUROPE

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

Asia (including the Middle East and Russia)

BRUNEI

Shell and the Brunei government are 50:50 shareholders in Brunei Shell Petroleum Company Sendirian Berhad (BSP). BSP holds long-term oil and gas concession rights onshore and offshore Brunei, and sells most of its natural gas production to Brunei LNG Sendirian Berhad (BLNG, Shell interest 25%). BLNG was the first LNG plant in Asia-Pacific, and sells most of its LNG on long-term contracts to customers in Asia.

We are the operator for the Block A concession (Shell interest 53.9%), which is under exploration and development, and also operator for exploration Block Q (Shell interest 50%). We have a 35% nonoperating interest in the Block B concession, where gas and condensate are produced from the Maharaja Lela Field. In addition, we have non-operating interests in deep-water exploration Block CA-2 (Shell interest 12.5%) and in exploration Block N (Shell interest 50%), both under PSCs.

CHINA

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

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

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

INDONESIA

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

IRAN

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

IRAQ

We have a 45% interest in the Majnoon oil field that we operate under a technical service contract that expires in 2030. The other Majnoon shareholders are PETRONAS (30%) and the Iraqi government (25%), which is represented by the Missan Oil Company. Majnoon is located in southern Iraq and is one of the world's largest oil fields. In 2013, we successfully restarted production and Majnoon has reached the milestone of first commercial production of 175 thousand b/d, which triggers the commencement of cost recovery. We also have a 15% interest in the West Qurna 1 field. According to the provisions of both contracts, Shell's equity entitlement volumes will be lower than the Shell interest implies.

In 2013, the Basrah Gas Company, a joint venture between Shell (44%), South Gas Company (51%) and Mitsubishi Corporation (5%) officially started operations. The Basrah Gas Company gathers, treats and processes raw gas produced from the Rumaila, West Qurna 1 and Zubair fields that was previously being flared. The processed natural gas and associated products, such as condensate and liquefied petroleum gas (LPG), will be sold primarily to the domestic market with the potential to export any surplus.

KAZAKHSTAN

We have a 16.8% interest in the offshore Kashagan field, where the North Caspian Operating Company is the operator. This shallowwater field covers an area of approximately 3,400 square kilometres. Phase 1 development of the field is expected to lead to plateau production of approximately 300 thousand boe/d, increasing further with additional phases of development. After the start of production from the Kashagan field in September 2013, operations had to be stopped in October due to gas leaks from the sour gas pipeline. Investigations and repair activities are ongoing.

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

MALAYSIA

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

Offshore Sabah, we operate four producing oil fields (Shell interest 50%). We also have additional interests ranging from 30% to 50% in PSCs for the exploration and development of five deep-water blocks.

These include the Gumusut-Kakap deep-water field (Shell interest 33%) and the Malikai field (Shell interest 35%). Both these fields are currently being developed with Shell as the operator. We began early production from Gumusut-Kakap in November 2012, by connecting two wells to the Kikeh production facility, which is operated by Murphy Sabah Oil. Production from Gumusut-Kakap via a dedicated floating production system is expected to commence during 2014. We also have a 21% interest in the Siakap North-Petai field, a 30% interest in the Kebabangan field and a 30% interest in offshore exploration PSC, SB311.

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

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

OMAN

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

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

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

QATAR

Pearl in Qatar is the world's largest GTL plant. Shell operates the plant under a development and production-sharing contract with the government of Qatar. The fully integrated facility includes production, transport and processing of approximately 1.6 billion scf/d of wellhead gas from Qatar's North Field with installed capacity of about 140 thousand boe/d of high-quality liquid hydrocarbon products and 120 thousand boe/d of NGL and ethane. We have a 30% interest in Qatargas 4, which comprises integrated facilities to produce approximately 1.4 billion scf/d of natural gas from Qatar's North Field, an onshore gas-processing facility and an LNG train with a collective production capacity of 7.8 mtpa of LNG and 70 thousand boe/d of NGL. The LNG is shipped mainly to markets in China, Europe and the United Arab Emirates.

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

RUSSIA

We have a 27.5% interest in Sakhalin-2, one of the world's largest integrated oil and gas projects. Located in a subarctic environment, the project produced approximately 320 thousand boe/d and more than 10 million tonnes of LNG in 2013.

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

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

UNITED ARAB EMIRATES

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

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

REST OF ASIA

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

Oceania

AUSTRALIA

We have interests in offshore production and exploration licences in the North West Shelf (NWS) and Greater Gorgon areas of the Carnarvon Basin, as well as in the Browse Basin and Timor Sea. Some of these interests are held directly and others indirectly through a shareholding of approximately 23% in Woodside Petroleum Ltd (Woodside). All interests in Australian assets quoted below are direct interests.

Woodside is the operator of the Pluto LNG project. Woodside is also the operator on behalf of six joint-venture participants in the NWS gas, condensate and oil fields, which produced more than 470 thousand boe/d in 2013. Shell provides technical support for the NWS development.

We have a 50% interest in Arrow Energy Holdings Pty Limited (Arrow), a Queensland-based joint venture with PetroChina. Arrow owns coalbed methane assets, a domestic power business and the site for a potential LNG plant on Curtis Island, near Gladstone.

We have a 25% interest in the Gorgon LNG project, which involves the development of some of the largest gas discoveries to date in Australia, beginning with the offshore Gorgon (Shell interest 25%) and Jansz-lo (Shell interest 19.3%) fields. It includes the construction of a 15.3 mtpa LNG plant on Barrow Island.

We are the operator of a permit in the Browse Basin in which two separate gas fields were found: Prelude in 2007, and Concerto in 2009. We are developing these fields on the basis of our FLNG technology. The Prelude FLNG project is expected to produce about 110 thousand boe/d of natural gas and NGL, delivering approximately 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG. During 2013, construction of the Prelude FLNG

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

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

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

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

REST OF OCEANIA

Shell also has interests in New Zealand.

Africa

NIGERIA

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

Onshore

The Shell Petroleum Development Company of Nigeria Ltd (SPDC) is the operator of a joint arrangement (Shell interest 30%) that holds more than 25 Niger Delta onshore oil mining leases (OMLs), which expire in 2019. To provide funding, modified carry agreements are in place for certain key projects, and are being reimbursed. Further new carry agreements with the Nigerian National Petroleum Corporation were put in place during 2013.

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

Offshore

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

SPDC also holds an interest in six shallow-water offshore leases, of which five expired on November 30, 2008. However, SPDC satisfied all the requirements of the Nigerian Petroleum Act to be entitled to an extension. Currently, the status quo is maintained following a court order issued on November 26, 2008. SPDC is pursuing a negotiated solution with the federal government of Nigeria. Production from the EA field, in one of the disputed leases, continued throughout 2013.

Liquefied natural gas

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

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

REST OF AFRICA

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

North America

CANADA

We hold more than 2,100 mineral leases in Canada, mainly in Alberta and British Columbia. We produce and market natural gas, NGL, synthetic crude oil and bitumen. In addition, we hold significant exploration acreage offshore. Bitumen is a very heavy crude oil produced through conventional methods as well as through enhanced oil recovery methods. Synthetic crude oil is produced by mining bitumen-saturated sands, extracting the bitumen from the sands, and transporting it to a processing facility where hydrogen is added to produce a wide range of feedstocks for refineries.

Gas and liquids-rich shale

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

Synthetic crude oil

We operate the Athabasca Oil Sands Project (AOSP) in north-east Alberta as part of a joint arrangement (Shell interest 60%). The bitumen is transported by pipeline for processing at the Scotford Upgrader, which is also operated by Shell and located in the Edmonton area. In 2013, the first phase of the AOSP debottlenecking project came online, adding an additional 10 thousand boe/d of capacity at peak production. The Quest carbon capture and storage project (Shell interest 60%), which is expected to capture and permanently store more than 1 mtpa of CO2 from the Scotford Upgrader, is currently under construction and is expected to start operation towards the end of 2015.

Shell also holds a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2018 to 2025. By completing a certain minimum level of development prior to their expiry, leases may be extended.

Bitumen

We produce and market bitumen in the Peace River area of Alberta, and have a steam-assisted gravity drainage project in operation near Cold Lake, Alberta. Additional heavy oil resources and advanced recovery technologies are under evaluation on approximately 1,200 square kilometres in the Grosmont oil sands area, also in northern Alberta. During 2013, we announced our final investment decision to proceed with our Carmon Creek project (Shell interest 100%), an in-situ project that is expected to produce up to 80 thousand boe/d.

Offshore

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

USA

We produce oil and gas in the Gulf of Mexico, heavy oil in California and primarily tight gas and liquid hydrocarbons in Louisiana, Pennsylvania, Texas and Wyoming. The majority of our oil and gas

production interests are acquired under leases granted by the owner of the minerals underlying the relevant acreage, including many leases for federal onshore and offshore tracts. Such leases usually run on an initial fixed term that is automatically extended by the establishment of production for as long as production continues, subject to compliance with the terms of the lease (including, in the case of federal leases, extensive regulations imposed by federal law).

Gulf of Mexico

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

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

Onshore

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

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

California

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

Alaska

We hold more than 410 federal leases for exploration in the Beaufort and Chukchi seas in Alaska. As a result of the grounding of the Kulluk drilling rig at the end of 2012, exploration drilling in 2013 was deferred. We have made the decision to dispose of the Kulluk and contracted a replacement rig. An impairment charge was recognised in 2013. A recent US Ninth Circuit Court decision against the Department of the Interior raises obstacles to our plans for drilling offshore Alaska. As a result, we have decided to suspend our exploration programme for Alaska for 2014, and we will continue to review the situation as we develop our plans for 2015.

REST OF NORTH AMERICA

Shell also has interests in Mexico.

South America

BRAZIL

We are the operator of several producing fields offshore Brazil. They include the Bijupirá and Salema fields (Shell interest 80%) and the BC-10 field (Shell interest 73%). We started production from the BC-10 Phase 2 project in October 2013, which aims to deliver peak production of 35 thousand boe/d. In 2013, we exercised our preemptive rights to acquire an additional 23% in the BC-10 project, and

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in January 2014 we agreed to sell a 23% interest to Qatar Petroleum International, which would return our interest to 50%, subject to completion. We also operate one offshore exploration block in the Santos Basin, BMS-54 (Shell interest 80%). We have interests in two offshore exploration blocks in the Espirito Santo basins, BMES-23 (Shell interest 20%) and BMES-27 (Shell interest 17.5%). We also operate one block in the São Francisco onshore basin area.

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

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

REST OF SOUTH AMERICA

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

Trading

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

SUMMARY OF PROVED OIL AND GAS RESERVES OF SHELL SUBSIDIARIES AND SHELL	SHARE OF JOINT VENTURES AND ASSOCIATES [A] (AT DECEMBER 31, 2013) BASED ON AVERAGE PRICES FOR 2013
	Oil and natural gas liquids (million barrels)	Natural gas (thousand million scf)	Synthetic crude oil (million barrels)	Bitumen (million barrels)	Total all products (million boe)[B]
Proved developed
Europe	418	10,798	–	–	2,280
Asia	1,258	14,026	–	–	3,676
Oceania	71	2,427	–	–	489
Africa	453	946	–	–	616
North America
USA	440	1,492	–	–	697
Canada	21	908	1,299	13	1,490
South America	74	52	–	–	83
Total proved developed	2,735	30,649	1,299	13	9,331
Proved undeveloped
Europe	380	2,477	–	–	807
Asia	466	2,135	–	–	834
Oceania	92	4,574	–	–	881
Africa	198	1,311	–	–	424
North America
USA	551	707	–	–	673
Canada	8	592	432	409	951
South America	38	28	–	–	43
Total proved undeveloped	1,733	11,824	432	409	4,613
Total proved developed and undeveloped
Europe	798	13,275	–	–	3,087
Asia	1,724	16,161	–	–	4,510
Oceania	163	7,001	–	–	1,370
Africa	651	2,257	–	–	1,040
North America
USA	991	2,199	–	–	1,370
Canada	29	1,500	1,731	422	2,441
South America	112	80	–	–	126
Total	4,468	42,473	1,731	422	13,944

[A] Includes 12 million boe of reserves attributable to non-controlling interest in Shell subsidiaries.

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

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LOCATION OF OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES [A] (AT DECEMBER 31, 2013)

		Development
	Exploration	and/or production	Shell operator[B]
Europe
Albania
Denmark
Germany
Greenland
Ireland
Italy
Netherlands
Norway
UK
Ukraine
Asia [C]
Brunei
China
Indonesia
Iraq
Jordan
Kazakhstan
Malaysia
Oman
Philippines
Qatar
Russia
Saudi Arabia
Turkey
United Arab Emirates
Oceania
Australia
New Zealand
Africa
Benin
Egypt
Gabon
Nigeria
South Africa
Tanzania
Tunisia
North America
USA
Canada
South America
Argentina
Brazil
Colombia
French Guiana
Guyana
Venezuela

[A] Includes joint ventures and associates. Where a joint venture or associate has properties outside its base country, those properties are not shown in this table.

[B] In several countries where "Shell operator" is indicated, Shell is the operator of some but not all exploration and/or production ventures.

[C] Shell suspended all exploration and production activities in Syria in December 2011.

CAPITAL EXPENDITURE ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES AND EXPLORATION EXPENSE OF SHELL SUBSIDIARIES BY GEOGRAPHICAL AREA [A] \$ MILLION 2013 2012 2011 Europe [B] 4,748 3,226 1,932 Asia 5,187 3,412 4,319

Oceania 5,832 5,534 3,349 Africa 2,639 2,277 1,701 North America – USA 9,118 11,344 6,445 North America – Canada 3,258 3,424 2,888 South America 3,676 907 487 Total 34,458 30,124 21,121

[A] Capital expenditure is the cost of acquiring property, plant and equipment for exploration and production activities, and – under the successful efforts method of accounting for exploration costs – includes exploration drilling costs capitalised pending determination of commercial reserves. See Note 2 to the "Consolidated Financial Statements". Exploration

expense is the cost of geological and geophysical surveys and of other exploratory work charged to income as incurred. Exploration expense excludes depreciation and release of cumulative currency translation differences.

[B] Includes Greenland. Capital expenditure and exploration expense for 2012 and 2011 have been reclassified from North America.

AVERAGE REALISED PRICE BY GEOGRAPHICAL AREA

OIL AND NATURAL GAS LIQUIDS \$/BARREL
		2013		2012		2011
	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates
Europe	105.23	99.27	108.13	104.60	106.77	103.97
Asia	96.46	70.34	107.76	67.33	103.73	62.81
Oceania	90.50	91.91[A]	91.62	90.14[A]	92.38	99.74[A]
Africa	110.14	–	112.45	–	111.70	–
North America – USA	101.00	–	103.59	110.00	104.93	109.49
North America – Canada	63.14	–	68.31	–	70.72	–
South America	97.17	94.01	100.01	97.33	100.44	97.76
Total	100.42	72.69	107.15	76.01	105.74	73.01

[A] Includes Shell's ownership of 23% of Woodside Petroleum Ltd as from April 2012 (previously: 24%), a publicly listed company on the Australian Securities Exchange. We have limited access to data; accordingly, the numbers are estimated.

NATURAL GAS						\$/THOUSAND SCF
		2013		2012		2011
	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates
Europe	10.29	9.17	9.48	9.64	9.40	8.58
Asia	4.51	10.73	4.81	10.13	4.83	8.37
Oceania	11.55	9.45[A]	11.14	9.48[A]	9.95	10.09[A]
Africa	2.84	–	2.74	–	2.32	–
North America – USA	3.92	–	3.17	7.88	4.54	8.91
North America – Canada	3.26	–	2.36	–	3.64	–
South America	2.91	0.42	2.63	1.04	2.81	0.99
Total	5.85	9.72	5.53	9.81	5.92	8.58

[A] Includes Shell's ownership of 23% of Woodside Petroleum Ltd as from April 2012 (previously: 24%), a publicly listed company on the Australian Securities Exchange. We have limited access to data; accordingly, the numbers are estimated.

SYNTHETIC CRUDE OIL			\$/BARREL
	2013	2012	2011
	Shell subsidiaries	Shell subsidiaries	Shell subsidiaries
North America – Canada	87.24	81.46	91.32

BITUMEN			\$/BARREL
	2013	2012	2011
	Shell subsidiaries	Shell subsidiaries	Shell subsidiaries
North America – Canada	67.40	68.97	76.28

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AVERAGE PRODUCTION COST BY GEOGRAPHICAL AREA

	OIL, NATURAL GAS LIQUIDS AND NATURAL GAS [A] \$/BOE
		2013		2012		2011
	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates
Europe	17.66	3.57	14.50	3.56	12.17	3.12
Asia	6.52	5.74	7.53	4.71	6.92	4.60
Oceania	11.55	13.17[B]	9.06	16.97[B]	8.50	14.46[B]
Africa	14.43	–	9.52	–	8.45	–
North America – USA	21.57	–	20.09	18.24	17.91	17.63
North America – Canada	22.20	–	19.47	–	18.12	–
South America	37.72	16.96	16.36	11.01	12.50	12.25
Total	14.35	5.52	12.47	6.05	11.00	5.60

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

[B] Includes Shell's ownership of 23% of Woodside Petroleum Ltd as from April 2012 (previously: 24%), a publicly listed company on the Australian Securities Exchange. We have limited access to data; accordingly, the numbers are estimated.

SYNTHETIC CRUDE OIL			\$/BARREL
	2013	2012	2011
	Shell subsidiaries	Shell subsidiaries	Shell subsidiaries
North America – Canada	38.22	40.40	46.19

BITUMEN			\$/BARREL
	2013	2012	2011
	Shell subsidiaries	Shell subsidiaries	Shell subsidiaries
North America – Canada	23.03	24.11	31.81

OIL AND GAS PRODUCTION (AVAILABLE FOR SALE)

CRUDE OIL AND NATURAL GAS LIQUIDS [A]						THOUSAND B/D
		2013		2012		2011
	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates
Europe
Denmark	57	–	73	–	88	–
Italy	33	–	39	–	35	–
Norway	40	–	40	–	37	–
UK	40	–	60	–	71	–
Other [B]	3	5	3	4	3	5
Total Europe	173	5	215	4	234	5
Asia
Brunei	2	55	2	73	2	76
Iraq	23	–	6	–	4	–
Malaysia	42	–	41	–	40	–
Oman	204	–	205	–	200	–
Russia	69	29	–	104	–	117
United Arab Emirates	–	159	–	145	–	144
Other [B]	68	23	53	23	36	20
Total Asia	408	266	307	345	282	357
Total Oceania	26	13	27	18	30	18
Africa
Gabon	30	–	38	–	44	–
Nigeria	175	–	240	–	262	–
Other [B]	11	–	12	–	20	–
Total Africa	216	–	290	–	326	–
North America
USA	237	–	155	67	141	70
Other [B]	21	–	15	–	18	–
Total North America	258	–	170	67	159	70
South America
Brazil	21	–	34	–	45	–
Other [B]	1	9	1	10	1	9
Total South America	22	9	35	10	46	9
Total	1,103	293	1,044	444	1,077	459

[A] Includes natural gas liquids. Royalty purchases are excluded. Reflects 100% of production attributable to subsidiaries except in respect of PSCs, where the figures shown represent the entitlement of the subsidiaries concerned under those contracts.

[B] Comprises countries where 2013 production was lower than 20 thousand b/d or where specific disclosures are prohibited.

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NATURAL GAS [A]						MILLION SCF/D
		2013		2012		2011
	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates	Shell subsidiaries	Shell share of joint ventures and associates
Europe
Denmark	146	–	202	–	256	–
Germany	200	–	217	–	253	–
Netherlands	–	1,976	–	1,808	–	1,767
Norway	703	–	713	–	618	–
UK	300	–	328	–	403	–
Other [B]	42	–	43	–	41	–
Total Europe	1,391	1,976	1,503	1,808	1,571	1,767
Asia
Brunei	51	451	51	512	52	524
China	164	–	131	–	174	–
Malaysia	655	–	572	–	763	–
Russia	12	347	–	374	–	382
Other [B]	1,036	317	795	317	363	246
Total Asia	1,918	1,115	1,549	1,203	1,352	1,152
Oceania
Australia	344	276	352	243	373	167
New Zealand	168	–	182	–	175	–
Total Oceania	512	276	534	243	548	167
Africa
Egypt	126	–	141	–	133	–
Nigeria	552	–	740	–	707	–
Total Africa	678	–	881	–	840	–
North America
USA	1,081	–	1,062	5	961	6
Canada	635	–	616	–	570	–
Total North America	1,716	–	1,678	5	1,531	6
Total South America	33	1	44	1	51	1
Total	6,248	3,368	6,189	3,260	5,893	3,093

[A] Reflects 100% of production attributable to subsidiaries except in respect of PSCs, where the figures shown represent the entitlement of the companies concerned under those contracts. [B] Comprises countries where 2013 production was lower than 115 million scf/d or where specific disclosures are prohibited.

SYNTHETIC CRUDE OIL			THOUSAND B/D
	2013	2012	2011
	Shell	Shell	Shell
	subsidiaries	subsidiaries	subsidiaries
North America – Canada	126	125	115

BITUMEN			THOUSAND B/D
	2013	2012	2011
	Shell subsidiaries	Shell subsidiaries	Shell subsidiaries
North America – Canada	19	20	15

LNG AND GTL PLANTS AT DECEMBER 31, 2013

LNG LIQUEFACTION PLANTS IN OPERATION

	Location	Shell interest (%)[A]	100% capacity (mtpa)[B][C]
Australia North West Shelf	Karratha	21	16.3
Australia Pluto 1	Karratha	21	4.3
Brunei LNG	Lumut	25	7.8
Malaysia LNG (Dua and Tiga) [D]	Bintulu	15	17.3
Nigeria LNG	Bonny	26	22.0
Oman LNG	Sur	30	7.1
Qalhat (Oman) LNG	Sur	11	3.7
Qatargas 4	Ras Laffan	30	7.8
Sakhalin LNG	Prigorodnoye	27.5	9.6

[A] Interest may be held via indirect shareholding.

[ B] As reported by the operator.

[C] In January 2014, we acquired an addition 4.2 mpta (Shell share) of capacity as a result of the acquisition of Repsol S.A.'s LNG portfolio outside of North America.

[D] Our interests in the Dua and Tiga plants are due to expire in 2015 and 2023 respectively.

LNG LIQUEFACTION PLANTS UNDER CONSTRUCTION
	Location	Shell interest (%)	100% capacity (mtpa)
Gorgon	Barrow Island	25	15.3
Prelude	Offshore Australia	67.5	3.6
Wheatstone [A]	Onslow	6.4	8.9

[A] In January 2014, we agreed to divest our interest in Wheatstone.

GTL PLANTS IN OPERATION

	Country	Shell interest (%)	100% capacity (b/d)
Bintulu	Malaysia	72	14,700
Pearl	Qatar	100	140,000

EQUITY LNG SALES VOLUMES

SHELL SHARE OF EQUITY LNG SALES VOLUMES	MILLION TONNES
	2013	2012	2011
Australia	3.7	3.6	3.1
Brunei	1.7	1.7	1.7
Malaysia	2.6	2.5	2.4
Nigeria	4.4	5.1	5.0
Oman	2.0	1.9	2.0
Qatar	2.3	2.4	1.7
Sakhalin	2.9	3.0	2.9
Total	19.6	20.2	18.8

UPSTREAM CONTINUED

EARNINGS AND CASH FLOW INFORMATION

2013								\$ MILLION
						North America	South
	Europe[A]	Asia	Oceania	Africa	USA	Other	America	Total
Revenue	23,144	35,916	3,414	11,007	9,762	8,878	748	92,869
Share of profit of joint ventures and
associates	1,469	3,235	111	1,162	1	55	87	6,120
Interest and other income	(123)	572	172	(14)	20	52	(20)	659
Total revenue and other income	24,490	39,723	3,697	12,155	9,783	8,985	815	99,648
Purchases excluding taxes	9,088	9,761	290	1,378	(1,175)	2,989	48	22,379
Production and manufacturing expenses	2,998	4,162	762	1,978	4,588	3,594	389	18,471
Taxes other than income tax	328	1,254	226	963	223	–	85	3,079
Selling, distribution and administrative
expenses	993	85	7	1	47	26	35	1,194
Research and development	648	15	–	–	178	106	–	947
Exploration	627	1,082	396	354	1,790	312	717	5,278
Depreciation, depletion and amortisation	1,444	3,114	434	1,293	7,954	2,550	160	16,949
Interest expense	359	76	47	133	210	61	24	910
Income before taxation	8,005	20,174	1,535	6,055	(4,032)	(653)	(643)	30,441
Taxation	4,883	10,977	475	3,100	(1,500)	(203)	71	17,803
Income after taxation	3,122	9,197	1,060	2,955	(2,532)	(450)	(714)	12,638
Net cash from operating activities	5,215	12,834	1,717	5,027	3,775	1,414	132	30,114
Less: working capital movements	1,251	(88)	(929)	1,391	(86)	(346)	119	1,312
Net cash from operating activities
excluding working capital movements	3,964	12,922	2,646	3,636	3,861	1,760	13	28,802
[A] Includes Greenland.

2012 [A]								\$ MILLION
						North America	South
	Europe[B]	Asia	Oceania	Africa	USA	Other	America	Total
Revenue	26,569	31,438	3,463	14,966	8,657	8,003	1,454	94,550
Share of profit of joint ventures and
associates	1,667	3,866	395	950	1,150	25	(52)	8,001
Interest and other income	70	793	2,107	984	569	149	164	4,836
Total revenue and other income	28,306	36,097	5,965	16,900	10,376	8,177	1,566	107,387
Purchases excluding taxes	10,689	8,699	277	1,878	659	2,958	85	25,245
Production and manufacturing expenses	2,651	3,761	834	1,915	3,477	3,434	282	16,354
Taxes other than income tax	350	410	318	1,248	39	–	144	2,509
Selling, distribution and administrative
expenses	843	196	4	3	126	19	20	1,211
Research and development	595	16	–	–	135	121	2	869
Exploration	398	460	175	699	802	372	198	3,104
Depreciation, depletion and amortisation	1,583	1,903	306	1,277	3,930	2,072	316	11,387
Interest expense	311	68	34	116	170	53	22	774
Income before taxation	10,886	20,584	4,017	9,764	1,038	(852)	497	45,934
Taxation	6,421	11,205	1,095	5,361	(121)	(408)	137	23,690
Income after taxation	4,465	9,379	2,922	4,403	1,159	(444)	360	22,244
Net cash from operating activities	6,677	11,457	2,107	6,615	4,483	1,047	675	33,061
Less: working capital movements	18	(587)	469	(410)	526	(73)	167	110
Net cash from operating activities
excluding working capital movements	6,659	12,044	1,638	7,025	3,957	1,120	508	32,951

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

[B] Includes Greenland. Earnings and cash flow information for 2012 have been reclassified from North America.

2011 [A]								\$ MILLION
						North America	South
	Europe[B]	Asia	Oceania	Africa	USA	Other	America	Total
Revenue	26,263	24,724	3,285	16,567	10,037	9,149	1,666	91,691
Share of profit of joint ventures and
associates	1,527	3,233	296	703	1,351	(14)	31	7,127
Interest and other income	42	929	104	861	1,598	111	505	4,150
Total revenue and other income	27,832	28,886	3,685	18,131	12,986	9,246	2,202	102,968
Purchases excluding taxes	9,687	4,684	252	1,860	1,983	3,658	(35)	22,089
Production and manufacturing expenses	2,836	3,850	857	1,634	2,856	3,300	253	15,586
Taxes other than income tax	390	592	297	1,499	59	–	180	3,017
Selling, distribution and administrative
expenses	1,012	94	3	8	127	15	14	1,273
Research and development	505	15	–	–	120	41	(1)	680
Exploration	313	326	178	493	745	85	126	2,266
Depreciation, depletion and amortisation	1,519	1,275	351	1,199	2,523	1,608	352	8,827
Interest expense	356	50	32	120	135	49	14	756
Income before taxation	11,214	18,000	1,715	11,318	4,438	490	1,299	48,474
Taxation	6,181	9,930	(24)	6,511	764	178	468	24,008
Income after taxation	5,033	8,070	1,739	4,807	3,674	312	831	24,466
Net cash from operating activities	6,680	8,130	1,954	5,680	5,310	1,791	1,034	30,579
Less: working capital movements	(876)	(1,277)	268	(1,349)	528	(131)	135	(2,702)
Net cash from operating activities
excluding working capital movements	7,556	9,407	1,686	7,029	4,782	1,922	899	33,281

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements". [B] Includes Greenland. Earnings and cash flow information for 2011 have been reclassified from North America.

DOWNSTREAM

KEY STATISTICS			\$ MILLION
	2013	2012[A]	2011[A]
Segment earnings [B]	3,869	5,382	4,170
Including:
Revenue (including inter-segment sales)	404,427	424,410	428,646
Share of earnings of joint ventures and associates [A]	1,525	1,354	1,577
Production and manufacturing expenses	9,807	9,539	10,662
Selling, distribution and administrative expenses	13,114	12,860	12,947
Depreciation, depletion and amortisation	4,421	3,083	4,251
Net capital investment [B]	4,885	4,275	4,342
Refinery availability (%)	92	93	92
Chemical plant availability (%)	92	91	89
Refinery processing intake (thousand b/d)	2,915	2,819	2,845
Oil products sales volumes (thousand b/d)	6,164	6,235	6,196
Chemicals sales volumes (thousand tonnes)	17,386	18,669	18,831

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

[B] See Notes 2 and 4 to the "Consolidated Financial Statements". Segment earnings are presented on a current cost of supplies basis.

OVERVIEW

Shell's Downstream organisation is made up of a number of different business activities, part of an integrated value chain, that collectively turn crude oil into a range of refined products, which are moved and marketed around the world for domestic, industrial and transport use. The products include gasoline, diesel, heating oil, aviation fuel, marine fuel, liquefied natural gas (LNG) for transport, lubricants, bitumen, sulphur and liquefied petroleum gas (LPG). In addition, we produce and sell petrochemicals for industrial use worldwide.

Our Refining activities comprise Manufacturing, Supply and

Distribution. Marketing includes Retail, Lubricants, Business to Business (B2B) and Alternative Energies. Chemicals has major manufacturing plants, located close to refineries, and its own marketing network. We also trade crude oil, oil products and petrochemicals, to optimise feedstocks for Manufacturing and Chemicals, to supply our Marketing businesses and for our own profit.

BUSINESS CONDITIONS

Industry refining margins were lower in 2013 than in 2012 in key refining hubs, except for US Gulf Coast margins, where increased domestic crude oil production lowered crude oil acquisition costs relative to international benchmarks. In 2014, increased demand for middle distillates is expected to be a key driver of refining margins, supported by demand for gasoline in the middle of the year. However, the overall outlook remains uncertain because of continuing economic fragility and geopolitical tensions in some regions that could lead to supply disruptions, amid global structural refining overcapacity. The overcapacity in Europe has been compounded by weaker regional demand, higher imports and lower exports of refined products to the USA as a result of the increase in the availability of liquids-rich shale. In Asia, new refining capacity has outstripped demand growth. As a result of this environment, we have commenced a review of our global refining portfolio which could potentially lead to asset sales, closures and/or impairments.

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

EARNINGS 2013-2012

Segment earnings in 2013 were \$3,869 million, 28% lower than in 2012. Excluding the impact of the net charge of \$597 million in 2013 and the net gain of \$39 million in 2012 described at the end of this section, earnings were 16% lower. The decrease in earnings was mostly due to Refining making a loss, driven by a weaker margin environment, partly offset by higher contributions from Chemicals and Trading. Continued strong contributions from Marketing were broadly similar to 2012.

Industry refining margins were lower in all regions, except for US Gulf Coast margins which were slightly higher. Lower US West Coast margins in 2013 reflected an excess supply of gasoline in the region. Additionally, US West Coast margins in 2012 were particularly high as a result of competitors' outages and weather events. Margins in 2013 were also impacted by a narrower spread between the Brent and West Texas Intermediate (WTI) crude oil benchmarks, as an expansion in pipeline capacity increased the ability to move oil from the landlocked area of Cushing, Oklahoma, where WTI is delivered. In Europe, margins remained weak due to: low regional demand; increased imports from Asia, Russia and the USA; and limited export opportunities to the USA due to high gasoline inventories there. Margins in Asia-Pacific were impacted by excess capacity and weak demand due to an economic slowdown.

Realised refining margins were significantly lower than in 2012 due to the deterioration in industry conditions described above. Refinery intake volumes were 3% higher compared with 2012. This was mainly due to the adoption of IFRS 11 Joint Arrangements leading to the inclusion, with effect from January 1, 2013, of our 50% share of the volumes of Saudi Aramco Shell Refinery, our joint venture in Saudi Arabia, and to new units being online as a result of the Port Arthur refinery expansion project in the USA. Refinery availability fell to 92% compared with 93% in 2012.

Chemicals earnings increased compared with 2012 mainly as a result of higher margins for most products. The improvement was driven by more favourable market conditions, helped by sustained industry supply constraints due to competitors' production outages, combined with strong operating performance. Chemicals sales volumes were 7% lower than in 2012, mainly due to the adoption of IFRS 11 Joint Arrangements with effect from January 1, 2013, and contract expirations, partly offset by higher trading volumes. Chemical plant availability increased to 92% compared with 91% in 2012.

Marketing earnings were broadly similar to 2012. Retail earnings were higher, with improved margins in all regions. Lubricants earnings were also higher, benefiting mainly from stronger unit margins. These increases were partly offset by lower earnings from: Raízen, our biofuel joint venture, which was impacted by negative fair value adjustments to biological assets (sugar-cane plantations) in 2013 compared with positive adjustments in 2012, and a weaker Brazilian real; and Business to Business, mainly due to lower sulphur prices.

Oil products sales volumes were 1% lower than in 2012, reflecting lower marketing and trading volumes, partly offset by the effect of the adoption of IFRS 11 Joint Arrangements with effect from January 1, 2013.

Overall, operating expenses were 2% higher than in 2012. Production and manufacturing expenses increased due to growth-stimulating spend and higher maintenance costs, coupled with inflation. Selling, distribution and administrative expenses increased due to inflation, spending related to higher volumes in some businesses and higher promotional costs in some of the marketing businesses.

Depreciation increased in 2013 compared with 2012, mainly due to impairments and to the adoption of IFRS 11 Joint Arrangements with effect from January 1, 2013.

Segment earnings in 2013 included a net charge of \$597 million, resulting primarily from impairments and deferred tax adjustments which were partly offset by a beneficial tax rate change in the UK and gains on divestments. The impairments were mainly in respect of the majority of our Downstream activities in Italy, the Geelong refinery in Australia and a bitumen refinery in the USA.

Segment earnings in 2012 included a net gain of \$39 million, resulting from net gains on divestments and a tax credit, partly offset by legal and environmental provisions.

EARNINGS 2012-2011

Segment earnings in 2012 were \$5,382 million, 29% higher than in 2011. This increase reflected a return to profitability in Refining, although marginal, as a result of higher realised refining margins and better refinery availability, which were partly offset by lower Chemicals earnings. Trading contributions were lower in 2012 than in 2011, while Marketing contributions were broadly unchanged. Both activities continued to contribute significantly to Downstream earnings.

Realised refining margins recovered strongly from their low level at the end of 2011, and improved across all regions apart from Asia. Chemicals earnings were lower in 2012, mainly as a result of the global economic slowdown, supply constraints of favourable feedstocks in the USA, and the impact of Hurricane Isaac on operations.

Segment earnings in 2012 included a net gain of \$39 million, described above. Segment earnings in 2011 included a net gain of \$15 million consisting of gains from fair-value accounting of commodity derivatives, formation of the Raizén joint venture, divestments and a tax credit, mostly offset by impairments, redundancy, decommissioning and legal provisions.

NET CAPITAL INVESTMENT

Net capital investment was \$4.9 billion in 2013 compared with \$4.3 billion in 2012. The increase was due to lower divestment proceeds in 2013.

Capital investment was \$5.5 billion in both 2013 and 2012. In both years \$3.2 billion was in Refining and Chemicals, and \$2.3 billion was in Marketing. In 2013, approximately 61% of our capital investment was used to maintain the integrity and performance of our asset base, compared with 56% in 2012.

Divestment proceeds were \$0.6 billion in 2013 compared with \$1.2 billion in 2012.

PORTFOLIO ACTIONS

In Chemicals, we announced final investment decisions on two projects in Singapore. The first will upgrade the Singapore production facilities for polyols, the raw materials used in the manufacture of high-quality foams in furniture, bedding and the automotive industry. The second will increase capacity at the Jurong Island petrochemicals facility, adding 140 thousand tonnes per annum (tpa) each of high-purity ethylene oxide and ethoxylation capacity. Additionally, with Qatar Petroleum we announced the award of the front-end engineering and design (FEED) contract for the Al-Karaana Petrochemicals Complex project in Ras Laffan Industrial City, Qatar.

In Business to Business, we finalised an agreement with TravelCenters of America to develop a nationwide network of LNG fuelling centres for heavy-duty road transport customers at up to 100 existing sites in the USA.

In Lubricants, we have formed a joint venture, Singapore Lube Park, to build and operate shared import, export and storage facilities. Alongside these shared facilities, we will build our own lubricants oil blending plant and grease manufacturing plant with initial capacities of 350 tpa and 10 tpa respectively. In China, we opened our largest grease plant worldwide, located in Zhuhai.

We continue to divest non-strategic positions. We completed the sale of the majority of our shareholding in retail and commercial fuels activities in Egypt, Ghana and Uganda. In Ghana, our lubricants will be marketed through our joint venture with Vitol; in Egypt, we will retain the lubricants business. The agreements form part of the divestment of our shareholding in most of our downstream activities in Africa as announced in 2011.

In Manufacturing, we sold the Harburg base oil manufacturing plant and some associated refinery facilities in Germany. In Norway, in January 2014, we completed the sale of our 21% interest in the Mongstad refinery. Under the same transaction, we acquired an additional 10% interest in the Pernis refinery in the Netherlands, making this refinery again 100% owned by Shell. Also in January, we signed an agreement for the sale of our shareholdings in the Kralupy and Litvinov refineries in the Czech Republic. In February 2014, we agreed to sell the majority of our downstream activities in Italy and Australia, subject to deal completion.

The sale of interests in these refineries is in line with our global strategy to concentrate investment on large-scale sites.

BUSINESS AND PROPERTY

Refining

MANUFACTURING

We have interests in more than 30 refineries worldwide with the capacity to process approximately 3.3 million barrels of crude oil per day. Approximately 40% of our refining capacity is in Europe and Africa, with 35% in the Americas and 25% in Asia and Oceania. The Port Arthur refinery expansion in Texas, USA, owned by Motiva Enterprises (Shell interest 50%), restarted operations in early 2013, following operational issues in 2012. The expansion brought an additional 320 thousand b/d of capacity online in the US Gulf Coast region, increasing the refinery's total capacity to 620 thousand b/d.

SUPPLY AND DISTRIBUTION

With more than 1,500 storage tanks and approximately 150 distribution facilities in approximately 25 countries, our Supply and Distribution infrastructure is well positioned for making deliveries throughout the world. Deliveries include feedstocks for our refineries as well as finished products for our Marketing businesses and customers worldwide.

DOWNSTREAM CONTINUED

Marketing

RETAIL

We have retail stations in more than 70 countries and more than 100 years' experience in fuel development. In recent years, we have concentrated on developing differentiated fuels with special formulations designed to clean engines and improve performance. We sell such fuels under the Shell V-Power brand in more than 60 countries.

LUBRICANTS

Across approximately 100 countries we make, market and sell technically advanced lubricants not only for passenger cars, trucks and coaches but also for industrial machinery in manufacturing, mining, power generation, agriculture and construction.

We lead the global market in branded lubricants. In 2012, independent research confirmed that Shell was the most preferred passenger car engine oil brand in China, Malaysia, Russia, Thailand and the USA. Shell was also the most preferred heavy-duty engine oil brand in China, Malaysia, Russia, Turkey and the USA.

Through our marine activities we primarily provide lubricants, but also fuels and related technical services, to the shipping and boating industries. We supply more than 100 grades of lubricants and 20 different types of fuel serving more than 15,000 vessels worldwide, ranging from large ocean-going tankers to small fishing boats.

BUSINESS TO BUSINESS

Our Business to Business (B2B) activities encompass the sale of fuels and speciality products and services to a broad range of commercial customers.

Shell Aviation provides fuel for approximately 7,000 aircraft every day at more than 800 airports in around 40 countries. On average, we refuel a plane every 12 seconds.

Shell Gas (LPG) provides liquefied petroleum gas and related services to retail, commercial and industrial customers for cooking, heating, lighting and transport.

Shell Commercial Fuels provides transport, industrial and heating fuels in 20 countries. Our wide range of products, from reliable main-grade fuels with standard quality to premium products, can offer tangible benefits. These include fuel economy, enhanced equipment performance, such as longer life and lower maintenance costs, and environmental benefits, such as reduced emissions. We continue to develop multiple projects in the LNG for transport industry, chosen in an effort to provide us and customers with the best commercial value.

Shell Bitumen supplies on average 11,000 tonnes of products every day to 1,600 customers worldwide and invests in technology research and development to create innovative, award-winning new products.

Shell Sulphur Solutions has developed a dedicated sulphur business to manage the complete value chain of sulphur, from refining to

marketing. The business provides sulphur for industries such as mining and textiles and also develops new products which incorporate sulphur, including road surfaces, fertilisers and concrete.

ALTERNATIVE ENERGIES

Our Raízen joint venture in Brazil produces ethanol from sugar cane, and manages a retail network. With an annual production capacity of more than 2 billion litres, it is one of the largest biofuel producers in the world. We also investigate alternative energy technologies with a long-term aspiration to develop them into profitable business opportunities. We were one of the first companies to invest in advanced biofuels and continue to research and explore the potential of hydrogen as a fuel.

Chemicals

MANUFACTURING

Our plants produce a range of base chemicals, including ethylene, propylene and aromatics, as well as intermediate chemicals, such as styrene monomer, propylene oxide, solvents, detergent alcohols, ethylene oxide and ethylene glycol. We have the capacity to produce nearly 6 mtpa of ethylene.

MARKETING

We sell petrochemicals to about 1,000 major industrial customers worldwide. Our Chemicals business is in the top 10 of chemicals enterprises in the world by revenue. Its products are used to make numerous everyday items, from clothing and cars, to bubble bath and bicycle helmets.

Trading

We trade crude oil, oil products and petrochemicals, to optimise feedstock for Manufacturing and Chemicals, to supply our Marketing businesses and for our own profit.

We trade in physical and financial contracts, lease storage and transportation capacities around the globe, and manage shipping activities.

DOWNSTREAM BUSINESS ACTIVITIES WITH IRAN, SUDAN AND SYRIA

Iran

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

Sudan

We ceased all operational activities in Sudan in 2008. We have, however, continued soil remediation in 2013 related to earlier operations in the country.

Syria

We are in compliance with all EU and US sanctions. We continue to supply limited quantities of polyols via a Netherlands-based distributor to private sector customers in Syria. Polyols are commonly used for the production of foam in mattresses and soft furnishings.

DOWNSTREAM DATA TABLES

The tables below reflect Shell subsidiaries, the 50% Shell interest in Motiva in the USA, and instances where Shell owns the crude oil or feedstocks processed by a refinery. Other joint ventures and associates are only included where explicitly stated.

OIL PRODUCTS – COST OF CRUDE OIL PROCESSED OR CONSUMED [A] \$ PER BARREL
	2013	2012	2011
Total	90.36	106.82	104.71

[A] Includes Upstream margin on crude oil supplied by Shell subsidiaries, joint ventures and associates.

CRUDE DISTILLATION CAPACITY [A]		THOUSAND B/CALENDAR DAY [B]
	2013	2012[C]	2011
Europe	1,033	1,084	1,243
Asia	810	664	664
Oceania	118	158	197
Africa	82	83	83
Americas	1,212	1,212	1,064
Total	3,255	3,201	3,251

[A] Average operating capacity for the year, excluding mothballed capacity. [B] Calendar day capacity is the maximum sustainable capacity adjusted for normal unit downtime.

[C] Crude distillation capacity in Europe has been corrected to exclude Stanlow refinery in the UK, which was divested in 2011.

ETHYLENE CAPACITY [A]	THOUSAND TONNES/YEAR
	2013	2012	2011
Europe	1,659	1,659	1,659
Asia	1,922	1,922	1,922
Oceania	–	–	–
Africa	–	–	–
Americas	2,212	2,212	2,212
Total	5,793	5,793	5,793

[A] Includes the Shell share of capacity entitlement (offtake rights) of joint ventures and

associates, which may be different from nominal equity interest. Nominal capacity is quoted as at December 31.

OIL PRODUCTS – CRUDE OIL PROCESSED [A]			THOUSAND B/D
	2013	2012	2011
Europe	1,010	1,069	1,058
Asia	706	761	701
Oceania	116	93	166
Africa	61	70	64
Americas	1,100	1,024	985
Total	2,993	3,017	2,974

[A] Includes natural gas liquids, share of joint ventures and associates and processing for others.

REFINERY PROCESSING
INTAKE [A]			THOUSAND B/D
	2013	2012	2011
Crude oil	2,732	2,620	2,652
Feedstocks	183	199	193
Total	2,915	2,819	2,845
Europe	933	970	1,041
Asia	634	520	489
Oceania	105	150	177
Africa	54	62	63
Americas	1,189	1,117	1,075
Total	2,915	2,819	2,845

[A] Includes crude oil, natural gas liquids and feedstocks processed in crude distillation units and in secondary conversion units.

REFINERY PROCESSING OUTTURN [A]			THOUSAND B/D
	2013	2012	2011
Gasolines	1,049	995	993
Kerosines	368	321	339
Gas/Diesel oils	1,014	996	977
Fuel oil	274	256	252
Other	389	452	385
Total	3,094	3,020	2,946

[A] Excludes "own use" and products acquired for blending purposes.

DOWNSTREAM CONTINUED

OIL PRODUCT SALES VOLUMES [A]			THOUSAND B/D
	2013	2012	2011
Europe
Gasolines	415	450	467
Kerosines	226	234	261
Gas/Diesel oils	962	909	876
Fuel oil	194	180	227
Other products	168	184	192
Total	1,965	1,957	2,023
Asia
Gasolines	325	352	291
Kerosines	191	172	191
Gas/Diesel oils	483	515	491
Fuel oil	322	355	305
Other products	255	220	214
Total	1,576	1,614	1,492
Oceania
Gasolines	87	93	102
Kerosines	51	48	46
Gas/Diesel oils	115	107	87
Fuel oil	–	4	7
Other products	19	26	28
Total	272	278	270
Africa
Gasolines	45	58	78
Kerosines	9	16	20
Gas/Diesel oils	43	53	81
Fuel oil	3	9	21
Other products	15	13	22
Total	115	149	222
Americas
Gasolines	1,149	1,123	1,136
Kerosines	234	264	265
Gas/Diesel oils	519	528	461
Fuel oil	96	89	91
Other products	238	233	236
Total	2,236	2,237	2,189
Total product sales [B]
Gasolines	2,021	2,076	2,074
Kerosines	711	734	783
Gas/Diesel oils	2,122	2,112	1,996
Fuel oil	615	637	651
Other products	695	676	692
Total	6,164	6,235	6,196

[A] Excludes deliveries to other companies under reciprocal sale and purchase arrangements, which are in the nature of exchanges. Sales of condensate and natural gas liquids are included.

[B] Certain contracts are held for trading purposes and reported net rather than gross. The effect in 2013 was a reduction in oil product sales of approximately 921,000 b/d (2012: 856,000 b/d; 2011: 925,000 b/d).

CHEMICALS SALES VOLUMES [A]		THOUSAND TONNES
	2013	2012	2011
Europe
Base chemicals	3,423	3,771	4,006
First-line derivatives and others	2,281	2,626	2,689
Total	5,704	6,397	6,695
Asia
Base chemicals	2,266	2,588	2,256
First-line derivatives and others	2,989	3,074	3,139
Total	5,255	5,662	5,395
Oceania
Base chemicals	–	–	–
First-line derivatives and others	62	75	81
Total	62	75	81
Africa
Base chemicals	–	–	–
First-line derivatives and others	47	54	62
Total	47	54	62
Americas
Base chemicals	3,218	3,336	3,405
First-line derivatives and others	3,100	3,145	3,193
Total	6,318	6,481	6,598
Total product sales
Base chemicals	8,907	9,695	9,667
First-line derivatives and others	8,479	8,974	9,164
Total	17,386	18,669	18,831

[A] Excludes feedstock trading and by-products.

MANUFACTURING PLANTS AT DECEMBER 31, 2013

REFINERIES IN OPERATION

			Thousand barrels/calendar day, 100% capacity[B]
	Location	Asset class	Shell interest (%)[A]	Crude distillation capacity	Thermal cracking/ visbreaking/ coking	Catalytic cracking	Hydro cracking
Europe
Czech Republic	Kralupy[C][D]	/	16	59	–	24	–
	Litvinov[C][D]	/	16	101	14	–	30
Denmark	Fredericia	Š	100	63	40	–	–
Germany	Harburg	Š	100	58	14	15	–
	Miro[C]		32	310	65	89	–
	Rheinland	Š	100	325	52	–	80
	Schwedt[C]		38	220	47	50	–
Netherlands	Pernis[E]	Š	90	404	45	48	81
Norway	Mongstad[C][E]	Š/	21	208	23	55	–
Asia
Japan	Mizue (Toa)[C]	Š/	18	64	24	38	–
	Yamaguchi[C]	/	13	110	–	25	–
	Yokkaichi[C]	Š/	26	193	–	55	–
Malaysia	Port Dickson	/	51	107	–	39	–
Pakistan	Karachi[C]		30	43	–	–	–
Philippines	Tabangao		67	96	31	–	–
Saudi Arabia	Al Jubail[C]	Š/	50	292	85	–	45
Singapore	Pulau Bukom	Š	100	462	77	34	55
Turkey	Batman[C]		1	23	–	–	–
	Izmir[C]		1	218	17	14	18
	Izmit[C]		1	216	–	13	25
	Kirikale[C]		1	104	–	–	16
Oceania
Australia	Geelong[F]	/	100	118	–	38	–
Africa
South Africa	Durban[C]	/	38	165	23	34	–
Americas
Argentina	Buenos Aires	Š/	100	100	18	20	–
Canada
Alberta	Scotford	/	100	92	–	–	62
Ontario	Sarnia	/	100	71	5	19	9
USA
California	Martinez	Š	100	144	42	65	37
Louisiana	Convent[C]	/	50	227	–	82	45
	Norco[C]		50	229	25	107	39
Texas	Deer Park	Š	50	312	79	63	53
	Port Arthur[C]	Š	50	569	138	81	67
Washington	Puget Sound	Š/	100	137	23	52	–

[A] Shell interest rounded to nearest whole percentage point; Shell share of production capacity may differ.

[B] Calendar day capacity is the maximum sustainable capacity adjusted for normal unit downtime.

[C] Not operated by Shell.

[D] In January 2014, we agreed to sell our 16% interest in the Kralupy and Litvinov refineries.

[E] In January 2014, we acquired the remaining 10% of the Pernis refinery, bringing our interest to 100%, and we sold our 21% interest in the Mongstad refinery.

[F] In February 2014, we agreed to sell our interest in the Geelong refinery subject to deal completion.

-Integrated refinery and chemical complex.

Š Refinery complex with cogeneration capacity.

/ Refinery complex with chemical unit(s).

DOWNSTREAM CONTINUED

MAJOR CHEMICAL PLANTS IN OPERATION [A]

				Thousand tonnes/year, Shell share capacity
	Location	Ethylene	Styrene monomer	Ethylene glycol	Higher olefins[B]	Additional products
Europe
Germany	Rheinland	272	–	–	–	A
Netherlands	Moerdijk	972	725	155	–	A, I
UK	Mossmorran[C]	415	–	–	–	–
	Stanlow[C]	–	–	–	330	I
Asia
China	Nanhai[C]	475	320	175	–	A, I, P
Japan	Yamaguchi[C]	–	–	–	11	A
Saudi Arabia	Al Jubail[C]	366	400	–	–	A, O
Singapore	Jurong Island[D]	281	734	1,005	–	A, I, P, O
	Pulau Bukom	800	–	–	–	A, I
Americas
Canada	Scotford	–	485	520	–	A, I
USA	Deer Park	836	–	–	–	A, I
	Geismar	–	–	400	920	I
	Norco	1,376	–	–	–	A
Total		5,793	2,664	2,255	1,261

[A] Includes joint-venture plants, with the exception of the Infineum additives joint ventures.

[B] Higher olefins are linear alpha and internal olefins (products range from C6-C2024).

[C] Not operated by Shell.

[D] Combination of 100% Shell-owned plants and joint ventures (Shell and non-Shell operated).

A Aromatics, lower olefins.

I Intermediates.

P Polyethylene, polypropylene.

O Other.

	OTHER CHEMICAL LOCATIONS
	Location	Products
Europe
Germany	Harburg	I
	Karlsruhe	A
	Schwedt	A
Netherlands	Pernis	A, I, O
Asia
Japan	Kawasaki	A, I
	Yokkaichi	A
Malaysia	Bintulu	I
	Port Dickson	A
Oceania
Australia	Geelong[A]	A, I
Africa
South Africa	Durban	I
Americas
Argentina	Buenos Aires	I
Canada	Sarnia	A, I
USA	Martinez	O
	Mobile	A
	Puget Sound	O

[A] In February 2014, we agreed to sell our interest in the Geelong chemical manufacturing unit subject to deal completion.

A Aromatics, lower olefins.

I Intermediates.

O Other.

CORPORATE

EARNINGS			\$ MILLION
	2013	2012[A]	2011[A]
Net interest and investment expense	(832)	(1,001)	(624)
Foreign exchange (losses)/gains	(189)	169	(77)
Other – including taxation	1,393	629	803
Segment earnings	372	(203)	102

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

OVERVIEW

The Corporate segment covers the non-operating activities supporting Shell. It comprises Shell's holdings and treasury organisation, its headquarters and central functions as well as its self-insurance activities. All finance expense and income as well as related taxes are included in the Corporate segment earnings rather than in the earnings of the business segments.

The holdings and treasury organisation manages many of the Corporate entities and is the point of contact between Shell and the external capital markets. It conducts a broad range of transactions – from raising debt instruments to transacting foreign exchange. Treasury centres in London, Singapore and Rio de Janeiro support these activities.

Headquarters and central functions provide business support in the areas of communications, finance, health, human resources, information technology, legal services, real estate and security. They also provide support for the shareholder-related activities of the Company. The central functions are supported by business service centres located around the world which process transactions, manage data and produce statutory returns, among other services. The majority of the headquarters and central-function costs are recovered from the business segments. Those costs that are not recovered are retained in Corporate.

Shell mainly self-insures its risk exposures. Shell insurance subsidiaries provide insurance coverage to Shell entities, generally up to \$1.15 billion per event and usually limited to Shell's percentage interest in the relevant entity. The type and extent of the coverage provided is equal to that which is otherwise commercially available in the third-party insurance market.

EARNINGS 2013-2011

Segment earnings for 2013 were a gain of \$372 million, compared with a loss of \$203 million in 2012 and a gain of \$102 million in 2011.

Net interest and investment expense decreased by \$169 million between 2012 and 2013. Interest expense was lower, mostly driven by an increase in the amount of interest capitalised due to the continued ramp-up of projects in Australia and the Gulf of Mexico, and an improvement in the liquidity premium associated with our currency swaps. These effects were partly offset by lower interest income. In 2012, net interest and investment expense increased by \$377 million compared with 2011. Interest expense was significantly higher, mostly driven by the liquidity premium associated with our currency swaps, and an increase in Shell's share of interest expense from joint ventures and associates. Further, the amount of interest capitalised on projects declined overall as major projects came on-stream in 2011, partly offset by the development of new projects. These effects were partly offset by higher interest income.

Foreign exchange losses of \$189 million in 2013 (2012: gains of \$169 million; 2011: losses of \$77 million) were mainly due to the impact of exchange rates on non-functional currency loans and cash balances in operating units.

Other earnings increased by \$764 million in 2013 compared with 2012, mainly due to a Danish tax credit and the recharge to the business segments of certain costs which were previously reported in Corporate. In 2012, other earnings were \$174 million lower than in 2011, mainly due to increased costs partly offset by higher tax credits.

LIQUIDITY AND CAPITAL RESOURCES

We manage our businesses to deliver strong cash flows to fund investment for profitable growth. Our aim is that, across the business cycle, "cash in" (including cash from operations and divestments) at least equals "cash out" (including capital investment, interest and dividends), while maintaining a strong balance sheet.

A key measure of our capital structure management is the proportion of debt to equity. Across the business cycle we aim to manage gearing (net debt as a percentage of total capital (net debt plus total equity)) within the range of 0-30%. During 2013, gearing ranged from 9.1% to 16.1% (2012: 8.6% to 13.9%, as restated for the retrospective application of revised IAS 19 Employee Benefits). See Note 15 to the "Consolidated Financial Statements".

With respect to the objective of maintaining a strong balance sheet, our priorities for applying our cash are servicing debt commitments, paying dividends, investing for organic and inorganic growth, and returning surplus cash to our shareholders.

OVERVIEW

The most significant factors affecting our operating cash flow are earnings and movements in working capital, which are mainly impacted by: realised prices for crude oil and natural gas; production levels of crude oil and natural gas; and refining and marketing margins.

Since the contribution of Upstream to earnings is larger than that of Downstream, changes affecting Upstream – particularly changes in realised crude oil and natural gas prices and production levels – have the largest impact on Shell's operating cash flow. While Upstream benefits from higher realised crude oil and natural gas prices, the extent of such benefit (and the extent of an impact from a decline in these prices) depends on: the extent to which contractual arrangements are tied to market prices; the dynamics of production-sharing contracts; the existence of agreements with governments or national oil and gas companies that have limited sensitivity to crude oil prices; tax impacts; and the extent to which changes in commodity prices flow through into operating costs. Changes in benchmark prices of crude oil and natural gas in any particular period therefore provide only a broad indicator of changes in Upstream earnings experienced in that period. In the

longer term, replacement of proved oil and gas reserves will affect our ability to maintain or increase production levels in Upstream, which in turn will affect our cash flow and earnings.

In Downstream, changes in any one of a range of factors derived from either within the industry or the broader economic environment can influence margins. The precise impact of any such changes depends on how the oil markets respond to them. The market response is affected by factors such as: whether the change affects all crude oil types or only a specific grade; regional and global crude-oil and refined-products inventories; and the collective speed of response of the industry refiners and product marketers in adjusting their operations. As a result, refinery and marketing margins fluctuate from region to region and from period to period. Downstream earnings are reported on a current cost of supplies basis, which excludes the effect of changes in the oil price on inventory carrying amounts. However, cash flow from operations is not affected by the reporting basis.

STATEMENT OF CASH FLOWS

Net cash from operating activities in 2013 was \$40.4 billion, a decrease from \$46.1 billion in 2012. This decrease mainly reflected the reduction in earnings and lower dividends from joint ventures and associates. In 2011, net cash from operating activities was \$36.8 billion. The increase in 2012 compared with 2011 mainly reflected movements in working capital.

Net cash used in investing activities was \$40.1 billion in 2013, an increase from \$28.4 billion in 2012. The increase was mainly the result of higher capital expenditure and lower proceeds from the sale of assets. In 2011, net cash used in investing activities was \$20.4 billion. The increase in 2012 compared with 2011 was mainly due to higher capital expenditure and investments in joint ventures and associates.

Net cash used in financing activities in 2013 was \$9.0 billion (2012: \$10.6 billion; 2011: \$18.1 billion). This included payment of dividends to Royal Dutch Shell plc shareholders of \$7.2 billion (2012: \$7.4 billion; 2011: \$6.9 billion), repurchases of shares of \$5.0 billion (2012: \$1.5 billion; 2011: \$1.1 billion) and interest paid of \$1.3 billion (2012: \$1.4 billion; 2011: \$1.7 billion), partly offset by net debt issued of \$5.4 billion (2012: issued debt offset by debt repaid; 2011: net repayments of debt of \$7.1 billion).

Cash and cash equivalents were \$9.7 billion at December 31, 2013 (2012: \$18.6 billion; 2011: \$11.3 billion).

CASH FLOW INFORMATION [A]			\$ BILLION
	2013	2012	2011
Net cash from operating activities excluding working capital movements
Upstream	28.8	32.9	33.3
Downstream	7.5	8.0	8.7
Corporate	1.2	1.8	1.2
Total	37.5	42.7	43.2
Decrease/(increase) in inventories	0.6	(1.7)	(1.9)
Decrease/(increase) in accounts receivable	5.6	14.1	(10.1)
(Decrease)/increase in accounts payable and accrued liabilities	(3.3)	(9.0)	5.6
Decrease/(increase) in working capital	2.9	3.4	(6.4)
Net cash from operating activities	40.4	46.1	36.8
Net cash used in investing activities	(40.1)	(28.4)	(20.4)
Net cash used in financing activities	(9.0)	(10.6)	(18.1)
Currency translation differences relating to cash and cash equivalents	(0.2)	0.2	(0.4)
(Decrease)/increase in cash and cash equivalents	(8.9)	7.3	(2.1)
Cash and cash equivalents at the beginning of the year	18.6	11.3	13.4
Cash and cash equivalents at the end of the year	9.7	18.6	11.3

[A] See the "Consolidated Statement of Cash Flows".

45 SHELL STRATEGIC REPORT 2013 LIQUIDITY AND CAPITAL RESOURCES

Our financial position is strong. In 2013, we generated a return on average capital employed (ROACE) of 7.9% (see "Return on average capital employed" in this section) and year-end gearing was 16.1% (2012: 9.8%, as restated). We returned \$11.3 billion to our shareholders through dividends in 2013. Some of those dividends were paid out as 125.6 million shares issued to shareholders who had elected to receive new shares instead of cash. To offset the dilution created by the issuance of those shares, 144.9 million shares were repurchased and cancelled as part of our share buyback programme.

The size and scope of our businesses require a robust financial control framework and effective management of our various risk exposures. Financial turbulence in the eurozone and the USA, and other international events continue to put significant stress on the business environment in which we operate.

Our treasury and trading operations are highly centralised, and seek to manage credit exposures associated with our substantial cash, foreign exchange and commodity positions.

We diversify our cash investments across a range of financial instruments and counterparties in an effort to avoid concentrating risk in any one type of investment or country. We carefully monitor our investments and adjust them in light of new market information.

Exposure to failed financial and trading counterparties was not material in 2013 (see Note 20 to the "Consolidated Financial Statements").

Total employer contributions to our defined benefit pension plans in 2013 were \$2.6 billion (2012: \$2.3 billion) and are estimated to be \$2 billion in 2014, reflecting current funding levels. See Notes 3 and 18 to the "Consolidated Financial Statements".

Cash and cash equivalents amounted to \$9.7 billion at the end of 2013 (2012: \$18.6 billion). Cash and cash equivalents are held in various currencies but primarily in dollars, euros and sterling. Total debt increased by \$6.8 billion in 2013 to \$44.6 billion at December 31, 2013. The total debt outstanding (excluding leases) at December 31, 2013, will mature as follows: 21% in 2014; 12% in 2015; 10% in 2016; 10% in 2017; and 47% in 2018 and beyond. The debt maturing in 2014 is expected to be repaid from a combination of cash balances and cash generated from operations.

We also maintain a \$7.48 billion committed credit facility that was undrawn as at December 31, 2013. This facility was put in place in December 2013, and replaced a \$5.1 billion facility; it expires in 2018 but may, by mutual agreement, be extended for a further one or two years.

We believe our current working capital is sufficient for present requirements. We satisfy our funding and working capital requirements from the cash generated by our businesses and through the issuance of external debt. Our external debt is principally financed from the international debt capital markets through central debt programmes consisting of:

• a \$10 billion global commercial paper (CP) programme, exempt from registration under section 3 (a)(3) of the US Securities Act of 1933, with maturities not exceeding 270 days;
• a \$10 billion CP programme, exempt from registration under section 4(2) of the US Securities Act of 1933, with maturities not exceeding 397 days;
• -\$25 billion euro medium-term note (EMTN) programme; and
• an unlimited US universal shelf (US shelf) registration.

All CP, EMTN and US shelf issuances have been undertaken by Shell International Finance B.V., the issuance company for Shell, and are guaranteed by Royal Dutch Shell plc.

Further information is included in Note 15 to the "Consolidated Financial Statements".

In 2013, we took advantage of favourable market conditions, including historically low interest rates, to pre-finance bond maturities in 2014 and issued \$7.75 billion of long-term bonds under the US shelf registration. Periodically, for working capital purposes, we issued commercial paper (2012: we issued commercial paper and \$4.25 billion of long-term bonds).

Our \$7.48 billion committed credit facility and internally available liquidity provide back-up coverage for commercial paper. Other than certain borrowings in local subsidiaries, we do not have any other committed credit facilities. We consider additional facilities to be neither necessary nor cost-effective for financing purposes, given our size, credit rating and cash-generative nature.

The maturity profile of our outstanding commercial paper is actively managed in an effort to ensure that the amount of commercial paper maturing within 30 days remains consistent with the level of supporting liquidity.

While our subsidiaries are subject to restrictions, such as foreign withholding taxes on the transfer of funds in the form of cash dividends, loans or advances, such restrictions are not expected to have a material impact on our ability to meet our cash obligations.

The consolidated ratio of earnings to fixed charges of Shell for each of five years ended December 31, 2009-2013, is as follows:

RATIO OF EARNINGS TO FIXED CHARGES
	2013	2012	2011	2010	2009
Ratio of earnings to fixed
charges [A]	20.11	31.12	35.71	21.75	12.90

[A] The ratio for 2012 and 2011 have been restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

For the purposes of the table above, earnings consist of pre-tax income from continuing operations (before adjustment for non-controlling interest) plus fixed charges (excluding capitalised interest) less undistributed income of joint ventures and associates. Fixed charges consist of expensed and capitalised interest (excluding accretion expense) plus interest within rental expenses (for operating leases). Refer to "Exhibit 7.1" regarding the calculation of the ratio of earnings to fixed charges.

CAPITALISATION TABLE		\$ MILLION
	Dec 31, 2013	Dec 31, 2012[A]
Equity attributable to Royal Dutch
Shell plc shareholders	180,047	174,749
Current debt	8,344	7,833
Non-current debt	36,218	29,921
Total debt [B]	44,562	37,754
Total capitalisation	224,609	212,503

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements". [B] Of total debt, \$40.0 billion (2012: \$33.4 billion) was unsecured and \$4.6 billion (2012: \$4.4 billion) was secured. Further disclosure on debt, including the amount guaranteed by Royal Dutch Shell plc, is in Note 15 to the "Consolidated Financial Statements".

LIQUIDITY AND CAPITAL RESOURCES CONTINUED

DIVIDENDS

Our policy is to grow the US dollar dividend through time in line with our view of Shell's underlying earnings and cash flow. When setting the dividend, the Board of Directors looks at a range of factors, including the macro environment, the current balance sheet and future investment plans. We have announced an interim dividend in respect of the fourth quarter of 2013 of \$0.45 per share, a 4.7% increase compared with the US dollar dividend for the same quarter of 2012. Shareholders have a choice to receive dividends in cash or in shares via our Scrip Dividend Programme. The Board expects that the first-quarter 2014 interim dividend will be \$0.47 per share, an increase of 4.4% compared with the US dollar dividend for the same quarter of 2013.

NET CAPITAL INVESTMENT

Our net capital investment was \$44.3 billion in 2013 (2012: \$29.8 billion; 2011: \$23.5 billion). Of the total net capital investment, \$39.2 billion (2012: \$25.3 billion; 2011: \$19.1 billion) related to Upstream; \$4.9 billion (2012: \$4.3 billion; 2011: \$4.3 billion) to Downstream; and \$0.2 billion (2012: \$0.2 billion; 2011: \$0.1 billion) to Corporate.

Our 2013 net capital investment comprised \$46.0 billion of capital investment (2012: \$36.8 billion; 2011: \$31.1 billion) less \$1.7 billion of divestment proceeds (2012: \$7.0 billion; 2011: \$7.5 billion).

See Note 4 to the "Consolidated Financial Statements".

PURCHASES OF SECURITIES

On May 21, 2013, the shareholders approved an authority, which will expire at the end of the 2014 Annual General Meeting (AGM), for the Company to repurchase up to 637 million of its shares. In accordance with a similar authority granted at the 2012 AGM, a share buyback programme was commenced in that year to offset the dilution created by the issuance of shares under our Scrip Dividend Programme. All of the shares purchased under the buyback programme are cancelled. A resolution will be proposed at the 2014 AGM to renew authority for the Company to purchase its own share capital up to specified limits for another year. Shares are also purchased by the employee share ownership trusts (see the "Directors Report") to meet delivery commitments under employee share plans. All share purchases are made in open-market transactions.

The table below provides information on purchases of shares in 2013 and up to February 18, 2014, by the issuer and affiliated purchasers. Purchases in euros and sterling are converted to dollars using the exchange rate at each transaction date.

PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS [A]

		A shares			B shares		A ADSs
Purchase period	Number purchased for employee share plans	Weighted average price (\$)[B]	Number purchased for employee share plans	Number purchased for cancellation[C]	Weighted average price (\$)[B]	Number purchased for employee share plans	Weighted average price (\$)[B]
2013
January	–	–	–	–	–	928,694	69.05
February	–	–	–	918,000	33.77	–	–
March	–	–	–	18,099,118	33.96	–	–
April	–	–	–	18,538,393	33.66	–	–
May	–	–	–	19,640,965	35.42	–	–
June	11,698,725	32.34	–	17,353,042	33.91	2,829,012	65.92
July	533,092	31.65	–	18,760,729	34.73	–	–
August	–	–	6,072,618	10,564,148	33.83	–	–
September	–	–	382,500	15,126,144	34.54	–	–
October	–	–	–	7,816,471	34.87	–	–
November	–	–	–	10,781,669	35.28	–	–
December	–	–	–	7,277,323	35.31	–	–
Total 2013	12,231,817	32.31	6,455,118	144,876,002	34.45	3,757,706	66.70
2014
January	–	–	–	10,838,990	37.58	938,671	70.81
February	–	–	–	9,416,625	37.33	–	–
Total 2014 [D]	–	–	–	20,255,615	37.46	938,671	70.81

[A] Excludes shares issued to affiliated purchasers pursuant to the Scrip Dividend Programme.

[B] Average price paid per share includes stamp duty and brokers' commission.

[C] Under the share buyback programme.

[D] As at February 18, 2014.

CONTRACTUAL OBLIGATIONS

The table below summarises Shell's principal contractual obligations at December 31, 2013, by expected settlement period. The amounts presented have not been offset by any committed third-party revenue in relation to these obligations.

CONTRACTUAL OBLIGATIONS	\$ BILLION
	Less than 1 year	Between 1 and 3 years	Between 3 and 5 years	5 years and later	Total
Debt [A]	7.9	8.7	10.1	12.0	38.7
Finance leases [B]	0.9	1.6	1.4	5.1	9.0
Operating leases [C]	5.8	8.9	6.1	11.7	32.5
Purchase obligations [D]	158.1	69.2	34.9	158.4 420.6
Other long-term
contractual liabilities [E]	–	1.3	0.2	0.3	1.8
Total	172.7	89.7	52.7	187.5 502.6

[A] Contractual repayments excluding \$5.1 billion of finance lease obligations. See Note 15 to the "Consolidated Financial Statements".

[B] Includes interest. See Note 15 to the "Consolidated Financial Statements".

[C] See Note 15 to the "Consolidated Financial Statements".

[D] Includes all significant items, including fixed or minimum quantities to be purchased; fixed, minimum or any agreement to purchase goods and services that is enforceable, legally binding and specifies variable price provisions; and the approximate timing of the purchase. [E] Includes all obligations included in "Trade and other payables" in "Non-current liabilities" on the "Consolidated Balance Sheet" that are contractually fixed as to timing and amount. In addition to these amounts, Shell has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans (see Note 18 to the "Consolidated Financial Statements") and obligations associated with decommissioning and restoration (see Note 19 to the "Consolidated Financial Statements").

The table above excludes interest expense related to debt, which is estimated to be \$1.2 billion payable in less than one year, \$2.0 billion payable between one and three years, \$1.6 billion payable between three and five years, and \$7.1 billion payable in five years and later. For this purpose, we assume that interest rates with respect to variable interest rate debt remain constant and that there is no change in the aggregate principal amount of debt other than repayment at scheduled maturity as reflected in the table.

GUARANTEES AND OTHER OFF-BALANCE SHEET ARRANGEMENTS

Guarantees at December 31, 2013, were \$3.1 billion (2012: \$3.3 billion). This includes \$2.2 billion (2012: \$2.2 billion) of guarantees of debt of joint ventures and associates, for which the largest amount outstanding during 2013 was \$2.2 billion (2012: \$2.2 billion).

RETURN ON AVERAGE CAPITAL EMPLOYED

ROACE measures the efficiency of Shell's utilisation of the capital that it employs. In this calculation, ROACE is defined as income for the

period adjusted for after-tax interest expense as a percentage of the average capital employed for the period. Capital employed consists of total equity, current debt and non-current debt. The tax rate is derived from calculations at the published segment level.

CALCULATION OF RETURN ON AVERAGE
CAPITAL EMPLOYED			\$ MILLION
	2013	2012[A]	2011[A]
Income for the period	16,526	26,960	31,093
Interest expense after tax	808	938	769
Income before interest expense	17,334	27,898	31,862
Capital employed – opening	213,936	197,141	186,552
Capital employed – closing	225,710	213,936	197,141
Capital employed – average	219,823	205,539	191,847
ROACE	7.9%	13.6%	16.6%

[A] Restated for the retrospective application of revised IAS 19 Employee Benefits, adopted with effect from January 1, 2013. See Note 28 to the "Consolidated Financial Statements".

In 2013, about 31% of our average capital employed was not generating any revenue, which reduced our ROACE by approximately 4%. These assets included projects being developed and exploration acreage.

FINANCIAL INFORMATION RELATING TO THE ROYAL DUTCH SHELL DIVIDEND ACCESS TRUST

The results of operations and financial position of the Royal Dutch Shell Dividend Access Trust (the Trust) are included in the consolidated results of operations and financial position of Shell. Certain condensed financial information in respect of the Trust is given below. See "Royal Dutch Shell Dividend Access Trust Financial Statements" for separate financial statements for the Trust.

For the years 2013, 2012 and 2011 the Trust recorded income before tax of £2,361 million, £2,383 million and £2,175 million respectively. In each period this reflected the amount of dividends received on the dividend access share.

At December 31, 2013, the Trust had total equity of £nil (2012: £nil; 2011: £nil), reflecting cash of £1,333,658 (2012: £1,202,271; 2011: £997,987) and unclaimed dividends of £1,333,658 (2012: £1,202,271; 2011: £997,987). The Trust only records a liability for an unclaimed dividend, and a corresponding amount of cash, to the extent that cheques expire, which is one year after their issuance, or to the extent that they are returned unpresented.

OUR PEOPLE

Our people are central to our aim of being the world's most competitive and innovative energy company. We recruit, train and recompense according to a people strategy based on three priorities: resourcing and developing talent now and in the future; strengthening leadership and professionalism; and enhancing individual and organisational performance.

EMPLOYEE OVERVIEW

During 2013, Shell employed an average of 92,000 people in more than 70 countries. We continued to recruit externally to execute our strategy and growth plans for the future, hiring approximately 1,200 graduates and 3,200 experienced professionals. The majority of each came from technical disciplines. More than 30% of our graduate recruits came from universities outside Europe and the Americas in response to increasing demand for skilled people in other regions.

The table below shows our average employee numbers by geographical area. The increase in 2013 compared with 2012 reflects our growth strategy in Asia and North America, as well as the impact of IFRS 11 Joint Arrangements, which resulted in the inclusion of the Shell share of the employees of certain additional joint operations from January 1, 2013.

EMPLOYEES BY GEOGRAPHICAL AREA
(AVERAGE NUMBERS)		THOUSAND
	2013	2012	2011
Europe	25	24	25
Asia	27	25	24
Oceania	3	3	3
Africa	3	3	6
North America	31	29	28
South America	3	3	4
Total	92	87	90

EMPLOYEE COMMUNICATION AND INVOLVEMENT

Shell strives to create and maintain a healthy employee relations climate, in which two-way dialogue between management and staff – directly and, where appropriate, via employee representative bodies – is important and embedded in our work practices. On a quarterly basis, senior management briefs employees on Shell's operational and financial results through various channels, including team meetings, face-to-face gatherings, a personal email from the Chief Executive Officer, webcasts and online publications.

The Shell People Survey is one of the principal tools used to measure employee engagement: the degree of affiliation and commitment to Shell. It provides insights into employees' views, and has had a consistently high response rate. The average employee engagement score in 2013 was 80% favourable, a three-point increase from 2012.

We promote safe reporting of views about our processes and practices. In addition to local channels, our global telephone helpline and website enable employees to report potential breaches of the Shell General Business Principles and Code of Conduct, confidentially and anonymously.

DIVERSITY AND INCLUSION

We have a culture that embraces diversity and fosters inclusion. By embedding these principles in our operations, we have a better understanding of the needs of our varied customers, partners and stakeholders throughout the world and can benefit from a wider talent pool. We provide equal opportunity in recruitment, career development, promotion, training and reward for all employees, including those with disabilities. Where possible, we make reasonable adjustments in job design and provide appropriate training for employees who have become disabled.

We actively monitor representation of women and local nationals in senior leadership positions, and have talent-development processes to support us in delivering more diverse representation. At the end of 2013, the proportion of women in senior leadership positions was 17.2% compared with 16.2% in 2012. In 32% of the countries where Shell subsidiaries, joint ventures and associates are based, local nationals filled more than half of the senior leadership positions, compared with 42% of those countries in 2012. From 2014, we will no longer apply this metric, as it does not reflect expatriation of local nationals for talent development purposes. Instead, we will start using a revised metric that better represents our activities in this respect.

Senior leadership positions is a Shell measure based on senior salary group levels and is distinct from the term "senior manager" in the statutory disclosures set out below.

GENDER DIVERSITY DATA (AT DECEMBER 31, 2013)			NUMBER
		Men	Women
Directors of the Company	10	91%	1	9%
Senior managers [A]	865	80%	217	20%
Employees (thousands)	67	71%	27	29%

[A] Senior manager is defined in section 414C(9) of the Companies Act 2006 and accordingly the number disclosed comprises the Executive Committee members who were not Directors of the Company as well as other directors of Shell subsidiaries.

EMPLOYEE SHARE PLANS

Shell has a number of share plans designed to align employees' interests with Shell's performance through share ownership. For information on the share-based compensation plans for Executive Directors, see the "Directors' Remuneration Report".

Performance Share Plan

The Performance Share Plan (PSP) was introduced in 2005. Conditional awards of the Company's shares are made under the terms of the PSP to some 15,000 employees each year. The extent to which the awards vest is determined over a three-year performance period. Half of the award is linked to the key performance indicators described in "Performance Indicators", averaged over the period. The other half of the award is linked to a comparison with four of our main competitors over the period on the basis of four relative performance measures. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards results in beneficial ownership until the shares vest. See Note 22 to the "Consolidated Financial Statements".

Restricted Share Plan

Under the Restricted Share Plan, awards are made on a highly selective basis to senior staff. Shares are awarded subject to a threeyear retention period. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date.

Global Employee Share Purchase Plan

Eligible employees in participating countries may participate in the Global Employee Share Purchase Plan. This plan enables them to make contributions from net pay towards the purchase of the Company's shares at a 15% discount to the market price either at the start or at the end of an annual cycle – whichever date offers the lower market price.

UK Sharesave Scheme

Eligible employees of participating companies in the UK may participate in the UK Sharesave Scheme. Options are granted over the Company's shares at market value on the invitation date. These options are normally exercisable after completion of a three-year or five-year contractual savings period.

UK Shell All Employee Share Ownership Plan

Eligible employees of participating companies in the UK may participate in the Shell All Employee Share Ownership Plan, under which monthly contributions from gross pay are made towards the purchase of the Company's shares.

ENVIRONMENT AND SOCIETY

Our success in business depends on our ability to meet a range of environmental and social challenges. We must show we can operate safely and manage the effect our activities can have on neighbouring communities and society as a whole. If we fail to do this, we may incur liabilities or sanctions, lose opportunities to do business, our reputation as a company may be harmed, and our licence to operate may be impacted.

The Shell General Business Principles include a commitment to sustainable development that involves balancing short- and long-term interests, and integrating economic, environmental and social aspects into our business decisions. We have rigorous standards and a firm governance structure in place to help manage potential impacts. We also work with communities, business partners, non-governmental organisations and other bodies to address potential impacts and share the benefits of our operations and projects.

Data in this section are reported on a 100% basis in respect of activities where we are the operator. Reporting on this operational control basis differs from that applied for financial reporting purposes in the "Consolidated Financial Statements". Detailed data and information on our 2013 environmental and social performance will be published in April 2014 in the Shell Sustainability Report.

SAFETY

Sustaining our licence to operate depends on maintaining the safety and reliability of our operations. We manage safety risk across our businesses through controls and compliance systems combined with a safety-focused culture. Our global standards and operating procedures define the controls and physical barriers we require to prevent incidents. For example, our offshore wells are designed with at least two independent barriers to mitigate the risk of an uncontrolled release of hydrocarbons. We regularly inspect, test and maintain these barriers to ensure they meet our standards. We also routinely prepare and practise our emergency response to potential incidents such as an oil spill or a fire. This involves working closely with local agencies to jointly test our plans and procedures. The tests continually improve our readiness to respond. If an incident does occur, we have procedures in place to reduce the impact on people and the environment.

We continue to strengthen the safety culture among our employees and contractors. We expect everyone working for us to intervene and stop work that may appear to be unsafe. In addition to our ongoing safety awareness programmes, we hold an annual global safety day to give workers time to reflect on how to prevent incidents. We expect everyone working for us to comply with our 12 mandatory Life-Saving Rules. If employees break these rules, they will face disciplinary action up to and including termination of employment. If contractors break the Life-Saving Rules, they can be removed from the worksite.

CLIMATE CHANGE

Growth in energy demand means that all sources of energy will be needed over the longer term. With hydrocarbons forecast to provide the bulk of the energy needed over coming decades, policymakers are focusing on regulations that balance energy demand with environmental concerns. The management of emissions of carbon dioxide (CO2) will become increasingly important as concerns over climate change lead to tighter environmental regulation.

We already assess potential costs associated with CO2 emissions when evaluating projects. But in the years to come, governments may impose a price on CO2 emissions that all companies will have to incorporate in their investment plans, and may also require companies to apply technical measures to reduce their CO2 emissions. This could result in higher energy, product and project costs. Currently enacted, proposed and future legislation are also expected to increase the cost

of doing business. Furthermore, in our own operations, we are working to understand the potential physical impact of climate change in the future on our facilities and new projects.

As energy demand increases and easily accessible oil and gas resources decline, we are developing resources that require more energy and require advanced technology to produce. As our production becomes more energy intensive, we expect there will be an associated increase in the direct CO2 emissions from the Upstream facilities we operate.

We are seeking cost-effective ways to manage CO2 emissions and see potential business opportunities in developing such solutions. Our main contributions to reducing CO2 emissions are in four areas: supplying more natural gas; supplying more biofuels; progressing carbon capture and storage (CCS) technologies; and implementing energy efficiency measures in our operations.

According to the International Energy Agency (IEA), nearly one-third of the world's CO2 emissions come from power generation. For many countries, using more gas in power generation instead of coal can make the largest contribution, at the lowest cost, to meeting their emission reduction objectives this decade. We expect that, in combination with renewables and use of CCS, natural gas will be essential for significantly lower CO2 emissions beyond 2020. With Shell's leading position in LNG and new technologies for recovering natural gas from tight rock formations, we can supply natural gas to replace coal in power generation.

We believe that low-carbon biofuels are one of the most viable ways to reduce CO2 from transport fuels in the coming years. Our Raízen joint venture in Brazil produces low-carbon biofuel from sugar cane. We are also investing in research to help develop and commercialise advanced biofuels.

The IEA has stated that CCS could contribute around 15% of the CO2 mitigation effort required by 2050. To advance CCS technologies, Shell is involved in CCS projects including the Quest project in Canada, the Mongstad test centre in Norway, and the Gorgon CO2 injection project in Australia. In 2012, we submitted a proposal for a project in Peterhead, in the UK, to store CO2 in a depleted gas reservoir in the North Sea. In 2014, Shell signed an agreement with the UK government to progress detailed design of the Peterhead CCS project. It could potentially capture and store around 10 million tonnes of CO2 over 10 years from a gas-fired power station. The current projects are part of an important demonstration phase for CCS, during which government support is essential. Initiatives such as the United Nations' acceptance of CCS as an offsetting activity under the Clean Development Mechanism are a positive step in progressing such technologies.

We continue to work on improving energy efficiency at our oil and gas production projects, oil refineries and chemical plants. Measures include our CO2 and energy management programme that focuses on the efficient operation of existing equipment by using monitoring systems which give us instant information that we can use to make energy-saving changes.

In addition, we work to help our customers conserve energy and reduce their CO2 emissions, including through the development and sale of advanced fuels and lubricants.

The flaring, or burning off, of gas in our Upstream business contributed to our overall greenhouse gas emissions in 2013. The majority of this flaring takes place at facilities where there is no infrastructure to capture the gas produced with oil, known as associated gas. Most of the continuous flaring takes place in Nigeria, where the security situation and lack of partner funding continues to slow progress on projects to capture associated gas. The Shell Petroleum Development Company of Nigeria Ltd (SPDC) has a multi-year programme in place to install new gas-gathering facilities and repair existing facilities damaged during the

militant crisis of 2006 to 2009, although progress in 2013 was hindered due to deterioration of the security situation in the Niger Delta. SPDC is also working on projects to further reduce flaring. Progress will depend on continued partner support, the local security conditions and the development of an effective market for gas in Nigeria.

In line with increased oil production, the amount of flaring of natural gas produced with oil at Majnoon, in Iraq, increased during 2013. We expect gas flaring from these operations to continue to rise in coming years as oil production increases. We are working with our joint-venture partners to evaluate options to capture the gas that is flared during operations, for use in power generation. In May 2013, the Basrah Gas Company (BGC) commenced operations in the south of Iraq. BGC is a joint venture between Shell, South Gas Company and Mitsubishi Corporation. It is the largest gas project in Iraq's history and the world's largest flaring reduction project. BGC aims to capture associated gas that is currently being flared from three non-operated oil fields in southern Iraq (Rumaila, West Qurna 1 and Zubair) for use in the domestic market.

Greenhouse gas emissions data are provided below in accordance with UK regulations introduced in 2013. Greenhouse gas emissions comprise carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride. The data are calculated using locally regulated methods where they exist. Where there is no locally regulated method, the data are calculated using the 2009 API Compendium which is the recognised industry standard under the GHG Protocol Corporate Accounting and Reporting Standard. There are inherent limitations to the accuracy of such data. Oil and gas industry guidelines (IPIECA/API/OGP) indicate that a number of sources of uncertainty can contribute to the overall uncertainty of a corporate emissions' inventory.

GREENHOUSE GAS EMISSIONS	2013
Emissions	million tonnes of CO2 equivalent
Direct [A]	73
Energy indirect [B]	10
Intensity ratios	tonne/tonne
All facilities [C]	0.22
Downstream refineries [D]	0.30
Upstream facilities [E]	0.12

[A] Emissions from the combustion of fuel and the operation of facilities.

[B] Emissions from the purchase of electricity, heat, steam and cooling for our own use. [C] In tonnes of total direct and energy indirect emissions per tonne of crude oil and feedstocks processed and petrochemicals produced in Downstream manufacturing, and oil and gas produced and gas processed by gas-to-liquid facilities in Upstream. The regulations require the reporting of a ratio which expresses the annual emissions in relation to a quantifiable factor associated with our activities. However, oil and gas industry guidelines (IPIECA/API/OGP) state that only presenting normalised environmental performance data separately for different business activities would generally provide meaningful information. As a result, we are also reporting the most appropriate ratio for our Downstream and Upstream businesses. [D] In tonnes of direct and energy indirect emissions per tonne of crude oil and feedstocks processed. The ratio includes chemical plants where they are integrated with refineries. [E] In tonnes of direct and energy indirect emissions per tonne of oil and gas produced. The ratio excludes gas-to-liquids facilities.

SPILLS

Large spills of crude oil, oil products and chemicals associated with our operations can result in major clean-up costs as well as fines and other damages. They can also affect our licence to operate and harm our reputation. We have clear requirements and procedures designed to prevent spills, and multibillion dollar programmes are underway to maintain or improve our facilities and pipelines.

Shell business units are responsible for organising and executing oil spill responses in line with Shell guidelines as well as with national legislation. All our offshore installations have plans in place to respond to a spill. These plans detail response strategies and techniques, available equipment, and trained personnel and contacts. We are

able to call upon significant resources such as containment booms, collection vessels and aircraft. We are also able to draw upon the contracted services of oil spill response organisations, if required. We conduct regular exercises to ensure these plans remain effective.

Shell is a founding member of the Marine Well Containment Company, a non-profit industry consortium to provide a containment response system for the Gulf of Mexico. In addition, Shell is operating the Subsea Well Response Project, an industry cooperative effort to enhance global well-containment capabilities.

Shell also maintains site-specific emergency response plans in the event of an onshore spill. Like the offshore response plans, these are designed to meet Shell guidelines as well as relevant legal and regulatory requirements. They also provide for the initial assessment of incidents and the mobilisation of resources needed to manage them.

In 2013, the number of operational spills of more than 100 kilograms decreased to 174, down from 207 in 2012. The number for 2012 was updated to 207 from 204 to reflect the completion of investigations into spills. At the end of February 2014, there were six spills under investigation in Nigeria that may result in adjustments.

Although oil spills in Nigeria resulting from sabotage and theft of crude oil remain a significant challenge, there are instances where spills occur in our operations due to operational failures, accidents or corrosion. SPDC has been working to reduce operational spills that are under its control. It maintains a public website to track the response, investigation and clean-up of every spill from its facilities due to operational failure, sabotage or theft.

In 2011, the United Nations Environment Programme (UNEP) released a study of oil spills in Ogoniland, where SPDC operated until 1993. SPDC accepted the recommendations of the UNEP report, and has established an independent scientific advisory panel to review SPDC practices in the rehabilitation and remediation of oil spill sites in the Niger Delta. In July 2012, the Federal Government of Nigeria established the Hydrocarbon Pollution Restoration Project – an essential first step to implement the recommendations of the UNEP report. Since the release of the UNEP report, SPDC has investigated the 15 sites identified in the report and, where required, they have been remediated despite cases of re-contamination from oil theft and illegal refining. The sites were subsequently certified by the local regulatory body as being in compliance with both soil and groundwater remediation requirements. In addition, SPDC has initiated a quarterly post-certification monitoring process for all 15 sites designed to detect re-contamination in a timely manner. SPDC has also undertaken a range of interim activities in Ogoniland where it was free to do so, including helping fund the provision of emergency water supplies and installing permanent water facilities in one affected area, launching a community health outreach programme across Ogoniland, and cleaning up a number of sites. The response to the UNEP report requires a joint effort by all stakeholders, and SPDC intends to play its full part.

HYDRAULIC FRACTURING

Over the last decade, we have expanded our onshore oil and gas portfolio using advances in technology to access previously uneconomic tight-oil and gas resources, including those locked in shale formations.

One of the key technologies applied in tight-oil and tight-gas fields is known as hydraulic fracturing, a technique that has been used since the 1950s. It involves pumping a mixture of water, sand and chemical additives at very high pressure into a rock formation, creating tiny fissures through which oil and gas can flow. To protect and isolate potable groundwater from hydraulic-fracturing fluids in the wellbore, we line our tight-oil and tight-gas wells with steel casing and cement.

ENVIRONMENT AND SOCIETY CONTINUED

All of our oil and gas wells are expected to have two or more subsurface barriers to protect groundwater. We monitor a wellbore's integrity during and, in many cases, after hydraulic fracturing. When we acquire assets, we evaluate the assets' wells for conformity with our safety and operating principles, and put in place a plan with a timeline for rectifying any inconsistencies.

We recycle or reuse as much water as we believe is reasonably practical. We store, treat or dispose of water in accordance with regulatory requirements.

To the extent allowed by our suppliers, Shell makes the material safety data sheet information available for locations where wells are being hydraulically fractured. Shell supports regulation to require suppliers to release such information. The chemicals used in hydraulic fracturing will vary from well to well and from contractor to contractor, but some can be toxic. For that reason, we have stringent procedures for handling hydraulic-fracturing chemicals in accordance with the design and assurance processes described above. The formations into which these additives may be injected are typically more than a thousand metres below freshwater aquifers. Our procedures require that potable groundwater must be isolated from well completion and production activities. Moreover, we only use air, water or a water-based liquid while drilling through the potable groundwater aquifer to a depth considerably below the aquifer. The casing and cement are then put in place before drilling is resumed and hydraulic fracturing is initiated.

There have been reports linking hydraulic fracturing to earth tremors. Most seismic events occur naturally due to motion along faults under stress in the earth's crust. Some areas are more seismically active than others. While around 1 million wells in the USA have been hydraulically fractured, there have been relatively few reported cases of seismicity detected at the surface near the time and vicinity of such operations. Shell analyses publicly available seismic, geologic and geophysical data to determine historical seismicity in areas where we plan to operate, and if seismic activity beyond historic levels is detected, we will investigate and review our operations.

Some jurisdictions are considering more stringent permitting, wellconstruction and other regulations relating to fracturing, as well as local bans and other land use restrictions. Such regulations could subject our operations to delays, increased costs or prohibitions. We have adopted a set of five operating principles for all our onshore tight-gas and oil activities. Our minimum current standards exceed the existing regulatory requirements of most jurisdictions.

OIL SANDS

We are developing mineable oil sands resources in Alberta, Canada. We use warm water to remove bitumen, which is a heavy oil. Tailings are the residual by-products that remain after the bitumen is separated from the mined oil sands ore. They are composed of some residual bitumen, water, sand, silt, heavy metals, and clay particles. Tailings are stored in an above-ground tailings pond or in mined-out pits. Tailings contain naturally occurring chemicals that are toxic. We monitor them continuously, assess their potential environmental impact, and take measures to protect wildlife and to prevent contamination of surface water and groundwater. The tailings management areas at the Athabasca Oil Sands Project's Muskeg River and Jackpine mines cover an area of approximately 24 square kilometres.

The land that is mined must be reclaimed – for example, through revegetation or reforestation – to a capability equivalent to that which existed prior to development, as required by the Alberta government.

When dried, tailings are blended and treated to produce material suitable for use in land reclamation. We continue to experience challenges with regard to certain tailings that are fine and have a high liquid content. We are working with the Alberta Energy Regulator to ensure that we are in compliance with all oil sands regulatory requirements, including those regarding tailings.

We also continue to work on tailings technology and collaborate with research institutions and other operators to advance solutions and ultimately accelerate the pace of land reclamation.

In late 2010, we found water at the bottom of a section of a pit at the Muskeg River Mine. The water was confirmed to be saline and to originate from an aquifer below the mine pit. There has been no inflow from or outflow to the aquifer since January 2012 and we continue to work closely with industry experts to develop a permanent solution. The water is contained within a segregated area in the pit.

EXPLORATION IN ALASKA

We hold more than 410 federal leases for exploration in the Beaufort and Chukchi seas in Alaska. We previously operated for almost 50 years in Alaska, including in both these seas, until 1998. We are therefore familiar with these shallow waters and the hydrocarbon reservoirs beneath them, which are of relatively low pressure. Our preparations to explore for oil in 2012 followed a number of years of work to lay the foundations for the responsible development of the area's potential resources. We have worked closely with regulators, local communities and other organisations as we move forward in the face of a changing regulatory environment.

To prepare for drilling off the coast of Alaska, we have developed a thorough oil spill response capability that includes capping and containment equipment, and oil spill response vessels.

In 2012, we completed top-hole drilling operations. These were conducted safely and in an environmentally responsible manner. This work has prepared the ground for continued drilling. However, there were challenges. For example, in consistently meeting all requirements of U.S. Environmental Protection Agency air permits and in moving the Kulluk drilling rig out of Alaska after the drilling season ended. In 2013, we paused our exploration drilling activity in Alaska's Beaufort and Chukchi seas to prepare equipment and plans for a resumption of activity.

The U.S. Coast Guard (USCG) is expected to issue a final report in 2014 on its Marine Casualty Investigation related to the grounding of the Kulluk. The USCG and the U.S. Department of Justice are conducting an investigation of potential marine pollution violations by one of Shell's drilling contractors. The timing of the conclusion and outcome of these investigations is unknown.

A US Ninth Circuit Court decision against the Department of the Interior in January 2014 raises obstacles to our plans for drilling offshore Alaska. As a result, we have decided to suspend our exploration programme for Alaska for 2014. We will look to relevant agencies and the court to resolve their open legal issues as quickly as possible, and review our options in going forward. If the legal and regulatory obstacles are sufficiently resolved, the next steps of our exploration programme will be determined by the readiness of our offshore Alaska fleet and the timeline to secure necessary permits.

WATER

Global demand for fresh water is growing while access to fresh water is becoming more constrained in some parts of the world. It is estimated by the United Nations that by 2025 two-thirds of the world's population will live in areas where the demand for fresh water exceeds the available supply, or where the water's poor quality restricts its use.

As world energy demand rises, the energy industry is becoming one of the larger industrial consumers of fresh water globally. Shell's water footprint may expand in the future with the further development of shale oil and gas, oil sands, and our biofuel business. A combination of increasing demand for water resources, growing stakeholder expectations and concerns, and water-related legislation may drive actions that affect our ability to secure access to fresh water and to discharge water from our operations.

At our major facilities in water-scarce areas, we are developing watermanagement plans that include ways to minimise water use and increase water recycling.

At our oil sands operations in Canada we use far less than our water allocation from the Athabasca River, and we minimise the amount withdrawn during the winter months, when the flow rate is low. We also reduce the amount of fresh water needed in operations by recycling water from the tailings ponds. About 80% of the water we use is recycled, and we are investigating new ways to further reduce fresh water intake.

Our Pearl GTL plant in Qatar does not take fresh water from its arid surroundings, and water produced in the GTL manufacturing process is recycled in the operation.

BIOFUELS

The international market for biofuels is growing, driven largely by the introduction of new energy policies in Europe and the USA that call for more renewable, lower-carbon fuels for transport. Shell predicts that biofuels will increase from 3% of the global transport fuel mix today to around 10% by 2050. Sustainable biofuels are expected to play an increasingly important role in helping to meet our customers' fuel needs and reduce CO2 emissions.

Sustainability challenges exist with today's biofuels. These include: CO2 emissions that vary according to the raw materials, and the production and distribution processes used; competition with food crops for available land; and labour rights.

We are one of the world's largest biofuels producers. We include our own long-established sustainability clauses in our supply contracts and, where possible, we source biofuels that have been certified against internationally recognised sustainability standards. These clauses are designed to prevent the sourcing of biofuels from suppliers that may not abide by human rights guidelines, or that may have cleared land rich in biodiversity.

We are also developing our own capabilities to produce sustainable biofuel components. The Raízen joint venture produces approximately 2 billion litres annually of ethanol from sugar cane in Brazil – the most sustainable and cost-competitive of today's biofuels. This ethanol can reduce CO2 emissions by around 70% compared with gasoline, from cultivation of the sugar cane to using the ethanol as fuel.

The joint-venture agreement includes developing joint sustainability principles, standards and operating procedures that also apply to thirdparty suppliers. We also continue to work with industry, governments and voluntary organisations towards the development of global sustainability standards for biofuels.

We continue to invest in developing more advanced biofuels for the future. These new technologies will take time to reach commercial scale. Government support will be required to accelerate their speed of development.

ENVIRONMENTAL COSTS

We are subject to a variety of environmental laws, regulations and reporting requirements in the countries where we operate. Infringing any of these laws, regulations and requirements could result in significant costs, including clean-up costs, fines, sanctions, and thirdparty claims, as well as harm our ability to do business and our reputation.

Our ongoing operating expenses include the costs of avoiding unauthorised discharges into the air and water, and the safe disposal and handling of waste.

We place a premium on developing effective technologies that are also safe for the environment. However, when operating at the forefront of technology, there is always the possibility that a new technology brings with it environmental impacts that have not been assessed, foreseen or determined to be harmful, when originally implemented. While we believe we take all reasonable precautions to limit these risks, we are subject to additional remedial environmental and litigation costs as a result of our operations' unknown and unforeseen impacts on the environment. Although these costs have so far not been material to Shell, no assurance can be made that this will always be the case.

In this regard, as oil and gas fields mature, it is possible in certain circumstances for seismic activity to increase based on the unique geology of individual fields. For example, after more than 60 years of developing the Groningen gas field in the Netherlands, seismic activity has recently increased leading to measurable earth tremors. Our Dutch joint venture will follow the production plan that is expected to be formally approved in 2014 by the Minister of Economic Affairs of the Netherlands.

NEIGHBOURING COMMUNITIES AND HUMAN RIGHTS

Earning the trust of local communities is essential to the success of our projects and operations. We have global requirements for social performance – how we perform in our relationship with communities. The requirements set clear rules and expectations for how we engage with and respect communities that may be impacted by our operations. Shell-operated major projects and facilities are required to have a social performance plan. This helps the business to understand the social context in which we plan to operate, identifies potential negative effects on the community, and manages impacts. In addition, we have specific requirements intended to minimise our impact on indigenous peoples' traditional lifestyles, and on handling involuntary resettlement and community feedback.

Shell has long been involved with developments in business and human rights in line with the UN Guiding Principles on Business and Human Rights. The Shell General Business Principles and Code of Conduct require our employees and contractors to respect the human rights of fellow workers and communities where we operate.

We have specific policies in place in areas across Shell's activities where respect for human rights is particularly important to the way we operate, such as communities, labour, procurement and security. We also work with other companies and non-governmental organisations to improve the way we apply these principles. Our approach to human rights helps us operate in a responsible way, delivering projects without delays and minimising the social impacts of our operations. It also enables us to better share the benefits of our activities, such as creating new jobs and contracts that help develop local economies.

Strategic Report signed on behalf of the Board

/s/ Michiel Brandjes

Michiel Brandjes Company Secretary March 12, 2014

SUPPLEMENTARY MATERIAL

DIRECTORS' REMUNERATION FOR 2013

Single total figure of remuneration for Executive

Directors

The table below shows the single total figure of remuneration for the Executive Directors.

€ SINGLE TOTAL FIGURE OF REMUNERATION FOR EXECUTIVE DIRECTORS (AUDITED) THOUSAND
		Peter Voser		Simon Henry
	2013[A]	2012[B]	2013	2012[B]
Salaries	1,640	1,600	985	940
Taxable benefits	229	186	52	62
Pension	683	–	508	300
Total fixed remuneration	2,552	1,786	1,545	1,302
Annual bonus [C]	1,800	3,300	900	1,500
LTIP and DBP [D]	4,104	13,160	1,986	6,254
Total variable remuneration	5,904	16,460	2,886	7,754
Total remuneration	8,456	18,246	4,431	9,056
in dollars	11,235	23,462	5,887	11,646
in sterling	7,183	14,804	3,764	7,348

[A] No payment for loss of office was made.

[B] UK regulations governing remuneration reporting changed for 2013. The amounts shown for each year have been prepared in accordance with applicable regulations then in force. [C] The full value of the bonus, comprising both the non-deferred and deferred value. For both years, each director elected to defer 50% of their bonuses into DBP shares. The market prices of A and B shares on January 31, 2014, (€25.61 and £22.25 respectively) were used to determine the number of DBP shares, resulting in 35,142 A shares for Peter Voser and 16,642 B shares for Simon Henry. At vesting, these DBP shares may be supplemented with performance matching shares, which vest on the same basis as the 2014 LTIP award.

[D] Remuneration for performance periods of more than one year, comprising the value of released LTIP awards and performance matching shares. The amounts reported for 2013 relate to the 2011 awards, which vested on February 27, 2014, at the market price of €26.54 and £23.36 for A and B shares respectively. To enable comparison, the amounts reported for 2012 relate to the 2010 awards, which vested on March 12, 2013, at the market price of €25.35 and £22.69 for A and B shares respectively. The value of the LTIP and DBP is calculated as the product of: the gross number of shares of the original award in the case of LTIP, or performance matching shares in the case of DBP, plus dividend shares accrued; the vesting percentage; and the closing market price of A or B shares at the vesting date. The market price of B shares is converted into euros using the exchange rate on the respective date. The original DBP award shares, which are those represented by deferred bonus and dividend shares accrued on these shares, are not considered as long-term remuneration, as they relate to the short-term annual bonus value. Only the performance matching shares and dividend shares accrued on those shares are considered as long-term remuneration, since they relate to performance periods of more than one year.

Single total figure of remuneration for Non-executive Directors

The table below shows the remuneration for the Non-executive Directors.

€ SINGLE TOTAL FIGURE OF REMUNERATION FOR NON-EXECUTIVE DIRECTORS (AUDITED) THOUSAND
		Fees		Taxable benefits[A]	Total
	2013	2012	2013	2012	2013	2012
Josef Ackermann	154	145	2	–	156	145
Guy Elliott	170	165	7	–	177	165
Charles O. Holliday	207	207	19	–	226	207
Gerard Kleisterlee	150	145	2	–	152	145
Christine Morin-Postel [B]	58	145	–	–	58	145
Jorma Ollila [C]	825	800	114	121	939	921
Sir Nigel Sheinwald [D]	142	69	8	–	150	69
Linda G. Stuntz	180	175	19	–	199	175
Jeroen van der Veer [B]	55	137	–	–	55	137
Hans Wijers	227	200	4	–	231	200
Gerrit Zalm [D]	142	–	4	–	146	–

[A] UK regulations governing remuneration reporting changed for 2013. The amounts shown for each year have been prepared in accordance with applicable regulations then in force. Specifically, the remuneration reporting regulations in force for 2013 require inclusion of benefits where these would be taxable in the UK, on the assumption that Directors are tax resident in the UK. On this premise, the 2013 taxable benefits amounts include the cost of Non-executive Director occasional business-required spouse travel. Shell also pays for travel between home and the head office in The Hague, where Board and committee meetings are typically held, as well as related hotel and subsistence costs. For consistency, these business expenses are not reported as taxable benefits as for most Non-executive Directors this is international travel and hence would not be taxable in the UK.

[B] Christine Morin-Postel and Jeroen van der Veer stood down with effect from May 21, 2013. No payments for loss of office were made.

[C] The taxable benefits amounts for Jorma Ollila include the use of an apartment (2013: €45,987) and company-provided transport (2013: €61,352).

[D] Sir Nigel Sheinwald was appointed with effect from July 1, 2012. Gerrit Zalm was appointed with effect from January 1, 2013.

Notes to the single total figure of remuneration tables (audited)

BASE SALARY

As disclosed in the 2012 Directors' Remuneration Report, REMCO reviewed Executive Directors' annual base salary levels and determined the base salaries, effective from January 1, 2013, as follows: Chief Executive Officer Peter Voser €1,640,000 (+2.5%); and Chief Financial Officer Simon Henry €985,000 (+4.8%). Pensionable salaries were also reviewed and, effective January 1, 2013, increased to CHF 2,540,000 (+2.2%) for Peter Voser and to £720,000 (+4.9%) for Simon Henry.

ANNUAL BONUS

The business scorecard shown below contains independent business measures grouped in three sections: operational cash flow, operational excellence and sustainable development.

At the start of the year, REMCO sets a target range and weighting for each scorecard measure. The actual outcome achieved results for each measure in a score of between 0 and 2, with a score of 1 representing "At target". These scores are multiplied by the respective weighting of each measure and aggregated, resulting in a mathematical scorecard outcome of between 0 and 2. REMCO may then make an adjustment to the overall scorecard outcome in view of the wider business performance for the year.

Individual performance

An Executive Director's individual performance is also taken into account in determining his annual bonus. Individual performance is assessed against personal targets. Retrospective disclosure of detailed personal targets is inappropriate as these are deemed to be commercially sensitive.

Conclusion of the 2013 annual bonus

The target 2013 bonus for Peter Voser at 150% of base salary had a value of €2,460,000 and for Simon Henry, at 110% of base salary, of €1,083,500. The maximum bonus opportunity for Peter Voser at 250% of base salary was €4,100,000, and for Simon Henry at 220% of base salary was €2,167,000.

The mathematical scorecard outcome for 2013 was 1.04. REMCO noted the strong delivery on key measures such as project delivery, plant availability, and sustainable development, including safety. However, in view of disappointing cash flow and production outcomes, REMCO determined to adjust the scorecard result to 0.85.

On the basis of this adjusted scorecard result, the annual bonus would have been €2,091,000 for Peter Voser and €920,975 for Simon Henry. Subsequently, REMCO determined no individual performance adjustment for Simon Henry, noting strong delivery in relation to functional leadership and delivery of Shell's strategic review considered alongside personal accountability for the below-target financial results. REMCO determined a downward adjustment to the bonus for Peter Voser. Despite strong personal performance in his closing year as Chief Executive Officer, Peter Voser's individual performance targets were closely tied to the delivery of Shell's financial results, which were below expectations.

The final, rounded, 2013 bonus outcomes for the Executive Directors were below target: €1,800,000 or 110% of base salary for Peter Voser and €900,000 or 91% of base salary for Simon Henry. Half of the bonus is deferred in shares under the DBP.

The table below summarises the 2013 annual bonus targets, the scorecard measures including their weightings, targets and outcomes for the year as well as REMCO's adjustments, to arrive at the final 2013 bonus payable to Peter Voser and Simon Henry.

2013 ANNUAL BONUS OUTCOME (AUDITED)

					Bonus as a % of base salary
	Weight	Target	Result			Peter Voser		Simon Henry
Measures	(% of scorecard)	set		achieved Score (0-2)	Target[A] Achieved			Target[A] Achieved
Operational cash flow (\$ billion) [B]	30%	43	41	0.68	45%	31%	33%	22%
Operational excellence	50%			1.02	75%	77%	55%	56%
Project delivery: identified projects on time and budget (%)	20%	75%	88%	1.65
Production (kboe/d)		12% 3,367	3,199	0.00
LNG sales (mtpa)	6%	20.2	19.6	0.30
Refinery and chemical plant availability (%)	12%	91.8	92.5	1.37
Sustainable development	20%			1.59	30%	48%	22%	35%
Total recordable case frequency (incidents/million hours)	10%	1.24	1.15	1.30
Targeted internal measures (score 0-2)	10%	1.00	1.88	1.88
	100%				150%		110%
Mathematical scorecard outcome				1.04
Scorecard outcome after REMCO adjustment				0.85
Final 2013 bonus [C]			€	(% of base salary) 1,800,000 (110%)				900,000 (91%)

[A] Target bonus for Peter Voser was 150% of base salary, and target bonus for Simon Henry was 110% of base salary.

[B] Excluding tax on divestments.

[C] Annual bonus = (base salary x target bonus % x scorecard result), adjusted for individual performance.

DIRECTORS' REMUNERATION CONTINUED

LONG-TERM INCENTIVE PLAN

In 2011, the Executive Directors were granted a conditional award of performance shares under the LTIP. The terms of this 2011 LTIP award are the same as those applying to the 2013 LTIP awards. These awards were based on 300% of base salary for Peter Voser (with a maximum vesting of 600%) and 240% for Simon Henry (with a maximum vesting of 480%).

At the end of the performance period, which was from January 1, 2011, to December 31, 2013, Shell was ranked fourth among its peer group in terms of TSR (30% weight), fifth in terms of EPS growth on a CCS basis (30% weight), second in terms of hydrocarbon production growth (20% weight) and second in terms of growth in net cash from operating activities (20% weight). REMCO also considered the underlying financial performance of Shell and decided to vest 60% of shares under the LTIP, using no discretion, resulting in 128,700 A shares for Peter Voser and 59,120 B shares for Simon Henry. At vesting, these shares (including accrued dividend) had a value of

€3,415,698 and €1,683,438 for Peter Voser and Simon Henry respectively. For current Executive Directors, the vested shares from the LTIP are subject to a further two-year holding period.

DEFERRED BONUS PLAN

In 2011, Executive Directors were granted performance matching shares under the DBP. The performance period was January 1, 2011, to December 31, 2013. Given that the performance condition of the DBP is the same as for the 2011 LTIP, REMCO decided to vest 60% of the performance matching shares under the DBP, using no discretion, resulting in 25,948 A shares for Peter Voser and 10,635 B shares for Simon Henry. At vesting, these shares (including accrued dividend) had a value of €688,660 and €302,831 for Peter Voser and Simon Henry respectively.

BENEFITS

Executive Directors received car allowances or lease cars, transport to and from home and office, occasional business-required spouse travel, as well as employer contributions to life and medical insurance plans. Where appropriate for employees outside their home country, tax equalisation and relocation support policies were applied. Peter Voser received tax compensation in respect of pension contributions (€173,657).

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