Shell - 20-F annual report

deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Shell to market risks and statements expressing management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “goals”, “intend”, “may”, “objectives”, “outlook”, “plan”, “probably”, “project”, “risks”, “schedule”, “seek”, “should”, “target”, “will” and similar terms and phrases. There are a number of factors that could affect the future operations of Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this Report, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for Shell’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserves estimates; (f) loss of market share and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including regulatory measures addressing climate change; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. Also see “Risk factors” for additional risks and further discussion. All forward-looking statements contained in this Report are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of this Report. Neither the Company nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this Report.

This Report contains references to Shell’s website and to the Shell Sustainability Report. These references are for the readers’ convenience only. Shell is not incorporating by reference any information posted on www.shell.com or in the Shell Sustainability Report.

DOCUMENTS ON DISPLAY

Documents concerning the Company, or its predecessors for reporting purposes, which are referred to in this Report have been filed with the SEC and may be examined and copied at the public reference facility maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, USA. For further information on the operation of the public reference room and the copy charges, call the SEC at 1-800-SEC-0330. All of the SEC filings made electronically by Shell are available to the public on the SEC website at www.sec.gov (commission file number 001-32575). This Report is also available, free of charge, at www.shell.com/annualreport or at the offices of Shell in The Hague, the Netherlands and London, UK. Copies of this Report also may be obtained, free of charge, by mail.

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

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.

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

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.

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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”.

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

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

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

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

CRUDE OIL AND NATURAL GAS PRICES FOR INVESTMENT EVALUATION

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

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

REFINING AND PETROCHEMICAL MARKET TRENDS

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

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

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.

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

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

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

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

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

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

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.

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.

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

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

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

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

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

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

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

AVAILABLE-FOR-SALE PRODUCTION

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

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

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

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

PROVED RESERVES

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

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

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

ITALY

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

NETHERLANDS

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

NORWAY

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

UK

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

REST OF EUROPE

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

Asia (including the Middle East and Russia)

BRUNEI

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

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

CHINA

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

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

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

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

OMAN

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

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

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

QATAR

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

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

RUSSIA

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

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

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

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

Gulf of Mexico

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

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

Onshore

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

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

California

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

Alaska

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

REST OF NORTH AMERICA

Shell also has interests in Mexico.

South America

BRAZIL

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