bg group annual report and accounts 2015 - shell · capital of bg group plc (the combination) to be...

BG Group Annual Report and Accounts 2015

NON-GAAP MEASURESBG Group publishes certain additional information in a non-statutory format. Business Performance financial information excludes discontinued operations, disposals, certain re-measurements and impairments and certain other exceptional items, and is published in order to provide a clear and consistent presentation of the underlying operating performance of the Group’s ongoing business. Unless otherwise stated, financial information for the Group and its business segments presented in the Strategic Report is based on BG Group’s Business Performance results. See Presentation of non-GAAP measures, page 79. See also note 1, page 42, and note 8, page 53, for a reconciliation of the differences between Business Performance and Total Results.

LEGAL NOTICE Certain statements included in this Annual Report and Accounts may contain forward-looking statements concerning BG Group’s strategy, operations, financial performance or condition, outlook, growth opportunities or circumstances in the countries, sectors or markets in which the Group operates. By their nature, forward-looking statements involve risk and uncertainty because they depend on future circumstances, and relate to events, not all of which are within the Company’s control or can be predicted by the Company. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct. Actual results could differ materially from those set out in the forward-

looking statements. For a description of certain factors that may affect BG Group’s business, financial performance or results of operations, we urge you to look at the Principal risks and uncertainties included in this Annual Report and Accounts, see pages 14 to 16. For a description of certain factors that may affect the business, financial performance or results of operations of the Shell Group (of which BG Group is now part) please refer to Shell’s latest regulatory filings, in particular, Shell’s Annual Report on Form 20-F for the year ended 31 December 2015. The Company undertakes no obligation to update any forward-looking statements.

References in this report to other reports or materials, such as a website address, have been provided to direct the reader to other sources of BG Group information which may be of interest. Neither the content of BG Group’s website nor any website accessible by hyperlinks from BG Group’s website nor any additional materials contained or accessible thereon, are incorporated in, or form part of, this report.

During the period to which this report relates, BG Group was subject to the regulatory requirements of the Financial Conduct Authority of the United Kingdom.

EXPLANATORY NOTE FOR US INVESTORS RELATING TO GAS AND OIL RESERVES AND RESOURCESFrom the year ended 31 December 2013, BG Group adopted the reserves definitions and guidelines consistent with the internationally recognised Petroleum Resources Management System published by the Society of Petroleum Engineers,

American Association of Petroleum Geologists, World Petroleum Council and the Society of Petroleum Evaluation Engineers, known as the SPE-PRMS, in accordance with recommendations issued by the European Securities and Markets Authority (ESMA) and to achieve greater consistency across its reporting of reserves and resources. Prior to this, BG Group had voluntarily used the SEC definition of proved reserves and of probable reserves (from 2009), to report proved gas and oil reserves and disclose certain unaudited supplementary information.

BG Group has used gas and crude oil price forecasts that are based on its reference conditions to determine reserves estimates for the years ended 31 December 2013, 2014 and 2015. Therefore reserves (proved and probable) as at 31 December 2015 are measured in accordance with SPE-PRMS definitions and guidelines. This report also contains additional information about other BG Group gas and oil reserves and resources that would not be permitted in SEC filings.

Gas and oil reserves cannot be measured exactly since estimation of reserves involves subjective judgement. Therefore, all estimates are subject to revision. Changes in gas and oil prices in fields subject to Production Sharing Contracts (PSCs) may result in changes to entitlements and therefore proved reserves.

For an explanation of the terms used in connection with the reserves and resources information, see the Glossary, page 80.

BG Group Annual report and accounts 2015

2 Introduction 4 BG Group’s performance6 2015 Business model and strategy7 Operating review7 – Upstream10 – LNG Shipping & Marketing

11 Financial review14 Principal risks

and uncertainties

STRATEGIC REPORT

Performance and operating information, principal risks faced, and an overview of the 2015 business model and strategy.

17 Board of Directors18 Remuneration report19 – Annual remuneration report27 Other disclosures30 Disclosure statement

CORPORATE GOVERNANCE

The Board of Directors and the Group’s approach to remuneration.

31 Independent auditor’s report32 Principal accounting policies36 Financial statements36 – Consolidated income statement37 – Consolidated statement

of comprehensive income

38 – Balance sheets40 – Statements of changes in equity41 – Cash flow statements42 Notes to the accounts

FINANCIAL STATEMENTS

Financial statements, notes and other key data.

79 Presentation of non-GAAP measures80 Glossary of terms

ADDITIONAL INFORMATION

BG GROUP ANNUAL REPORT AND ACCOUNTS 2015

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Contents

OVERVIEWIn 2015, Exploration and Production (E&P) production volumes increased 16% primarily as a result of the ramp-up of production in Australia, Brazil and Norway, and a higher share of production in Kazakhstan, partly offset by lower production in Egypt, Trinidad and Tobago, and the UK. The LNG business increased delivered volumes by 63%, despite challenging market conditions.

SHELL OFFEROn 8 April 2015, the Boards of Royal Dutch Shell plc (Shell) and BG Group plc announced that they had reached agreement on the terms of a recommended cash and share offer to be made by Shell for the entire issued and to be issued share capital of BG Group plc (the Combination) to be effected by way of a court-sanctioned scheme of arrangement under Part 26 of the Companies Act 2006 (the Scheme).

Under the terms of the Combination, BG Group plc shareholders were entitled to receive, for each BG Group plc share, 383 pence in cash and 0.4454 Shell B Shares.

On 27 January 2016, Shell shareholders voted to approve the Combination and on 28 January 2016, BG Group plc shareholders voted to approve the Scheme at a court-convened meeting and to approve a special resolution to implement the Scheme, including amendments to the BG Group plc articles, at a general meeting of BG Group plc.

Following a court hearing on 11 February 2016, the Scheme became effective on 15 February 2016 (the Effective Date).

DELISTING AND RE-REGISTRATIONOn 15 February 2016, the UK Listing Authority cancelled the listing of BG Group shares on the premium listing segment of the Official List and the London Stock Exchange cancelled the trading of BG Group shares on the London Stock Exchange’s main market for listed securities.

On 30 March 2016, BG Group plc re-registered as a private limited company, BG Group Limited.

2015 Operating performanceThrough the course of 2015, BG Group commissioned each of the two LNG trains at QCLNG in Australia, assuming operational control and commencing full commercial operations of Train 1 in May and Train 2 in November. The ramp up of both LNG trains, together with the ramp up in Brazil of the fourth and fifth FPSOs and the start-up of the sixth FPSO, drove a strong E&P operational performance. E&P production volumes averaged 704 kboed, up 16% on 2014. The addition of new low cash cost volumes in Australia and Brazil and delivery of operating and capital cost savings helped partly to mitigate the impact of lower commodity prices.

The LNG Shipping & Marketing business delivered 282 cargoes, 104 more cargoes than in 2014. The increase included 77 cargoes from QCLNG.

DIVIDENDSThe final dividend of 14.37 cents per ordinary share ($499 million) in respect of the year ended 31 December 2014 was paid on 22 May 2015 to shareholders on the register at the close of business on 24 April 2015. The interim dividend of 14.38 cents per ordinary share ($483 million) in respect of the year ending 31 December 2015 was paid on 11 September 2015 to shareholders on the register as at 14 August 2015.

As the Effective Date of the Combination with Shell occurred prior to the record date for Shell’s fourth quarter dividend (being 19 February 2016), BG Group shareholders were entitled to receive that Shell dividend and would not receive a further BG Group plc dividend for 2015. On 4 February 2016, Shell announced a fourth quarter dividend of 47.00 cents per Shell share (equivalent to 20.93 cents per BG Group share, based on the default consideration of 383 pence in cash and 0.4454 Shell B shares for each BG Group plc share held).

Market trendsFor market trends and factors that are likely to affect the future performance of BG Group as part of the Shell Group following the Effective Date, please refer to Shell’s latest regulatory filings, in particular, Shell’s Annual Report on Form 20-F for the year ended 31 December 2015.

GLOBAL ECONOMYModest – and less energy intensive – growth, particularly among leading emerging markets such as China, was an important factor impacting energy markets during 2015.

The USA experienced solid growth, particularly with respect to consumption, employment and the construction sector. However, industrial production weakened due to the lagged effects of the strong dollar and weaknesses in the wider global economy.

China endured a third year of slowing growth – particularly in investment and manufacturing, despite a series of currency devaluations – as its economy continued to rebalance.

Growth in Europe improved overall (from a low base), with employment and consumption strengthening. However, industrial production continues to stagnate despite a weak euro. The crisis in Greece appears to have receded following a governmental agreement over the summer.

OIL PRICESOil prices began 2015 at $48/bbl (average monthly spot price), and reached a high of $66/bbl in May. Having traded in a range of $45–$50/bbl for much of the year, prices again deteriorated in November reaching $35–$37/bbl by late December.

The weak price environment resulted from a classic imbalance of demand and supply. Key factors on the supply side included robust production from US shale and tight oil fields (despite the weaker price environment), and continued pursuit of production maximisation by OPEC, led by Saudi Arabia.

On the demand side, weak growth and a structural slowdown in manufacturing and investment across major markets, such as China, contributed to modest demand growth, despite the low price environment.

LNG MARKETS During 2015, LNG demand growth slowed in China, and declined year-on-year in Asian markets. Europe (led by the UK), India and the new markets of Egypt, Jordan and Pakistan all increased shipments in 2015.

LNG supply in 2015 was up by around 7.5 million tonnes from 2014, coming in particular from Australia. LNG prices under long-term contracts fell rapidly during 2015, given common linkages to lagged oil prices. Spot prices also declined over 2015, driven by mild weather in North Asia and Europe early in the year, the fall in oil prices, the economic slowdown in Asia and expansion of supply.

SustainabilityIn 2015, BG Group consolidated its core sustainability approach and activities under a single corporate function, ‘Safety and Sustainability’. The Group amended all of its sustainability policies to align with the new structure. The Safety and Sustainability function reported to the Chief Executive, with additional oversight from the Board’s Sustainability Committee. Reference is made to the GLossary of terms on page 80 for the explanation of definitions applied.

BG Group Life Savers continue to apply from Day 1 of the Combination as transition to Shell Life Saving Rules will be completed within one year. BG Group assets and ventures continue to deliver to existing BG Group Standards from Day 1, but all operated assets should have risk-based ‘gap disclosure plans’ against the Shell HSSE&SP Control Framework with agreed, risk based dates to close the gaps within a year. These decisions were based on a high-level gap assessment of the BG Group and Shell systems and standards.

RESPONSIBLE OPERATORHealth, safety and security Safety remained BG Group’s highest priority in 2015. Safety performance improved, with the total recordable case frequency (TRCF) measure reducing to 1.14 incidents per million work hours in 2015 from 1.38 in 2014. However, five major (Tier 1) losses of primary containment were recorded. Three of these incidents were considered high potential incidents. These incidents were fully investigated with lessons shared across the Group.

The Group maintained its focus on the security of employees and contractors, with enhanced measures in the assets with security challenges, such as Egypt and Tunisia. Regular training and simulations were conducted across the Group to prepare for crisis situations.

Human rightsDuring 2015, BG Group published a public position to explain its approach to managing human rights issues. BG Group has a human rights policy, which is applicable across all countries in which the Group operates.

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Strategic report Introduction

Ethical ConductDuring 2015, BG Group continued to assess and manage exposure to corruption and bribery risks in existing operations and new ventures, as well as monitoring compliance with ethical conduct standards.

ENVIRONMENT AND CLIMATE CHANGEClimate changeIn 2015, BG Group focused on improving operational emissions performance through energy efficiency.

Greenhouse gas (GHG) emissionsData in this section is reported on a 100% basis in respect of activities where BG Group was the operator and 50% of the data where it was joint operator. BG Group reported from offices with more than 100 people and/or from those sites capable of influencing and monitoring GHG emissions. Reporting on this operational control basis differs from that applied for financial reporting purposes in the “Consolidated Financial Statements” on pages 32 to 78.

The BG Group scope 1 and 2 greenhouse gas (GHG) emissions from Group-operated businesses for 2015 were 10.8 million tonnes (mt) CO2e and 1.3 mt CO2e, respectively, compared with 7.6 mt CO2e and 260 thousand tonnes (kt) CO2e, respectively in 2014. The Group’s combined operated scope 1 and 2 GHG emissions intensity for the year was 21.0 kt of CO2e per mmboe, compared with 19.8 kt CO2e per mmboe in 2014, an increase of 6%.

The increase in GHG emissions intensity for operated assets reflects the impact of lower throughput from some operations, increased energy required to extract gas in maturing fields, and increased emissions in Australia as a result of temporarily increased flaring of gas during the commissioning of the QCLNG project.

The Group reported in line with the GHG Protocol Corporate Accounting Reporting Standard (2004) and the IPIECA Oil and Gas Industry Voluntary Guidance on Sustainability Reporting (2010). All of the Group’s operated and joint-operated businesses reported quarterly on fuel use, flaring, venting and fugitives into a central environmental database to calculate carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O) emissions.

The Group used emission factors supplied by the 2009 API Compendium wherever available, in line with good industry practice. These emission factors were built into the calculations in the Group’s environmental reporting database as default values. While the Group used generic emission factors as a default, it aimed to improve the accuracy of calculations by inputting other information specific to the fuel and the facility in question, as different fuel compositions will result in different emission levels.

The calculation used to derive scope 1 (direct) GHGs from all emissions sources for 2015 was: GHG (or CO2e) = CO2 + (CH4 x 25) + (N2O x 298). These are the three Kyoto protocol gases relevant to the Group’s businesses. BG Group’s 2014 reporting was based on the GWPs from the Second Assessment Report published by the International Panel on Climate Change (IPCC). Consistent with updated UK regulations, BG Group’s 2015 reporting is based on the GWPs from the Fourth Assessment Report. For example, as a result, GWP for methane increased from 21 to 25. The Group calculated scope 2 (indirect) CO2 emissions from electricity consumption in its operated businesses by applying a country-specific default emission (grid) factor from IEA CO2 Emissions from Fuel Combustion (2012 Edition), Electricity and Heat Generation, IEA, Paris. These were updated in the Group’s database on an annual basis.

The Group used emissions intensity per unit of gross production (mmboe) as a ratio to relate emissions to its activities. Emissions intensity is an indication of the energy efficiency of a facility or process. This normalisation allows the Group to see whether its activities are more or less carbon intensive. Gross production data includes gross upstream production, liquefaction and regasification volumes, electricity production, shipping cargoes and throughput volumes from pipelines converted into mmboe using default calculation values for all activities.

Environmental managementIn 2015, BG Group maintained 100% certification of its environmental management system to ISO 14001 for its operated assets. The Group had no major environmental incidents, including no major oil spills.

POSITIVE SOCIO-ECONOMIC IMPACTTransparencyBG Group continued to support transparency of payments to governments in 2015. The Group remained committed to the Extractive Industries Transparency Initiative (EITI), a global standard to promote accountable management of natural resources.

Social performanceWe assess potential social and economic impacts and develop mitigation measures for planned or proposed projects, in consultation with stakeholders and local communities. Our approach to consultation and engagement is transparent, inclusive and culturally appropriate. It contributes to a wider goal of developing broad community support for our presence in all locations where we operate.

Our community grievance mechanisms aim to provide a proactive and structured approach to receive, acknowledge, investigate, respond to and remedy grievances about our projects from affected stakeholders in a planned, timely and respectful manner.

Oil spill preventionWe have in place a wide range of precautionary measures to ensure the risks of an oil spill are reduced to a level that is as low as reasonably practicable. Through the design, operation and maintenance of our facilities, we work to achieve asset integrity, or the ability of our physical assets to perform their required function effectively whilst safeguarding life and the environment. All BG Group-operated wells have a management system in place for well integrity, which is the safety, reliability, efficiency and general fitness for service of every well. These plans stipulate how well integrity will be managed throughout the lifecycle of a well with the aim of reducing the risk of uncontrolled releases or spills.

During 2015, we continued the focus on well integrity by updating the software that provides live data from all our wells to facilitate enhanced management of well integrity and early detection of potential incidents.

Oil spill preparedness and responseWe put in place measures to ensure that if a spill occurs it will be contained and not discharged to the environment. All of our facilities or operations that produce, store or transfer oil have an oil spill contingency plan which assesses the potential risks of oil pollution and outlines response procedures. We also regularly train staff with pollution response roles and run drill exercises for the contractors who provide pollution response services in order to practice oil spill response procedures.

People and skillsAs at 31 December 2015, BG Group employed 4 566 people worldwide. In 2015, the Group recruited 23 graduates to its Graduate Development Programme and actively managed university relationships to attract high-quality candidates. In 2015, 26% of the organisation as a whole, 13% of senior management and 23% of the Board was female. For further information on diversity, see page 17.


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For the year ended 31 December.

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10

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Earnings before interest, tax, depreciation and amortisation (EBITDA) ($m)

9 176

2014

5 633

2015


2.0

2.5

1.5

1.0

0.5

Total recordable case frequency(incidents per million work hours)

1.92

20122011

2.26

2013

1.64

2014

1.381.14

2015

1215

96

-6

3

-9

20122011 2013 2014 2015

Total shareholder return – three-year average to 31 August (%)

-2.7

0.7

10.212.1

7.9

-1.4

Peer group(a) (weighted average)BG Group

(a) For constituents of the peer group, see page 22.

8.6

2.7 2.9

-7.9

0-3

For the year ended 31 December. See note 8, page 53.

120

150

90

60

30

Business Performance earnings per share (cents)

128.9

2012

124.9

2011

128.6

2013

118.4

2014

49.7

2015

BG Group identified both financial and non-financial key performance indicators (KPIs) it believed were useful in assessing the Group’s performance against its strategic aims. Consistent with BG Group’s focus in 2015 on improving return on capital and delivering earnings

EARNINGS PER SHARE (EPS)Business Performance EPS is the amount of earnings attributable to each individual share in issue and has been calculated by dividing BG Group’s Business Performance earnings by the weighted average number of ordinary shares in issue and ranking for dividend during the financial year.

Business Performance EPS in 2015 declined 58% to 49.7 cents (2014: 118.4 cents). The 39% reduction in EBITDA combined with increased depreciation, depletion and amortisation (DD&A) costs and higher net finance costs were only partially offset by a reduction in the Group’s effective tax rate from 37% to 24% (excluding BG Group’s share of joint ventures and associates’ results and tax).

Total Results EPS for 2015 was 68.2 cents (2014: loss of 30.8 cents) and included a post-tax gain of

$631 million in respect of disposals, re-measurements and impairments. This included a $1 672 million gain from disposal of non-current assets, primarily in relation to the QCLNG pipeline sale, and exceptional one-off and prior period taxation credits of $692 million, partly offset by $691 million of post-tax impairment charges and a net $659 million charge reflecting the impact of foreign exchange movements on deferred and current tax balances.

For further information, see the Financial review on pages 11 to 13.

TOTAL SHAREHOLDER RETURN (TSR)TSR is defined as the percentage return on investment obtained from holding a company’s shares over a period of time. It includes the change in capital value of the shares, dividends paid and other payments made to or by shareholders. It was used to measure BG Group’s

performance relative to its peers. The Group’s TSR performance over a three-year period was used, inter alia, to determine vesting levels under the Group’s Long-Term Incentive Plan (LTIP). For LTIP awards granted in early September, TSR performance was measured to 31 August. For further information, see the Remuneration report on pages 18 to 26.

The graph shows, for the past five years, the annualised US Dollar TSR of BG Group shares over a three-year performance period and the corresponding average TSR of the Group’s industry peers. For the three-year period ending 31 August 2015, BG Group underperformed the weighted peer group index by 10.41% per annum. For details of BG Group’s TSR in Pounds Sterling relative to the FTSE 100 index see the TSR chart on page 23.

SAFETYTotal recordable case frequency (TRCF) measures the number of incidents per million work hours and is the headline indicator of the success of the Group’s safety programmes, measuring the ratio of injuries to working hours.

In 2015, the Group’s TRCF further improved to 1.14, versus a target of 1.20 and a 2014 performance of 1.38. This progress reflected good safety performance in a number of assets but particularly in Australia during the important phase of start-up of the QCLNG project. Active and visible

leadership across teams was a key enabler of the improved safety performance, especially in the light of the ‘distraction’ risk for the workforce following the announcement of Shell’s intention to acquire the entire issued and to be issued share capital of BG Group.

EARNINGS BEFORE INTEREST, TAX, DEPRECIATION AND AMORTISATION (EBITDA)Business Performance EBITDA includes the post-tax results of joint ventures and associates.

In 2015, Business Performance EBITDA decreased 39% to $5 633 million (2014: $9 176 million) primarily reflecting the significant fall in commodity prices, impacting realised sales prices, which were only partly offset by higher volumes in both segments. Upstream EBITDA declined 35% to $4 167 million and included the positive impact of the start-up of liquefaction operations at QCLNG.

LNG Shipping & Marketing EBITDA was down 46% to $1 456 million and included the impact of a greater proportion of relatively lower margin spot cargoes.

For further information, see the Financial review on pages 11 to 13.

and cash-flow growth, return on average capital employed (ROACE) and earnings before interest, tax, depreciation and amortisation (EBITDA) were adopted as additional KPIs for the business in 2015.

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Exploration and production volumes (net) (kboed)

600

800

400

200

641

20122011

657

2013

633

2014

606

704

2015


18 000

12 000

6 000

Total reserves and resources (mmboe)

Proved reserves(a)

Probable reserves(a)

Discovered resources(a)

Risked exploration(a)

(a) For an explanation of these terms, refer to page 80.

2013SPE-PRMS

18 511

2014SPE-PRMS

17 771

2012SEC

17 130

2011SEC

2015SPE-PRMS

17 016 16 220

Liquefied natural gas delivered volumes(mtpa)

12

18

9

6

3

For more information on delivered volumes, see page 10.


12.8

20122011

12.1

2013

10.9

2014

11.0

17.9

2015

15


8

10

6

4

2

Return on average capital employed (ROACE) (%)

9.7

2014 2015

4.6

RETURN ON AVERAGE CAPITAL EMPLOYEDThis measure represents Business Performance earnings over the past 12 months, excluding net finance costs/income on net borrowings, as a percentage of average capital employed over the past 12 months.

Business Performance ROACE in 2015 was 4.6% (2014: 9.7%). The reduction reflects lower Business Performance results, mainly as a result of the significant fall in commodity prices.

LNG VOLUMESThis is a measure of the volume of LNG that BG Group has delivered, excluding fuel gas. The Group has a portfolio of flexible, long-term LNG supply, sourced from its own liquefaction plants in Australia and Trinidad and Tobago, as well as from third-party suppliers in Equatorial Guinea and Nigeria. Delivered volumes also includes third-party spot purchases. It is measured in millions of tonnes per annum (mtpa).

LNG delivered volumes in 2015 were 17.9 mtpa compared to 11.0 mtpa in 2014, equating to 282 cargoes in 2015, 104 more cargoes than in 2014. Increased supply included 77 cargoes from QCLNG and 31 additional spot cargoes, partially offset by four fewer cargoes from the Group’s Atlantic Basin supply contracts. Of the 282 cargoes (2014: 178), 208 were supplied to Asian markets (2014: 121).

PRODUCTION VOLUMESThe graph shows BG Group’s net production from all of its producing E&P interests and is measured in thousands of barrels of oil equivalent per day (kboed).

In 2015, E&P production was 704 kboed, up 16% year-on-year. Growth was driven by Australia, Brazil and Norway. Volumes in Australia more than doubled to 88 kboed and in Brazil, increased 87% to 146 kboed. In Norway, Knarr continued to ramp up

producing an average of 12 kboed in the year. This growth was partially offset by the expected decline in Egypt, down 18 kboed to 44 kboed, combined with lower volumes in Trinidad and Tobago, down 13 kboed to 52 kboed.

TOTAL RESOURCESThe size of BG Group’s total reserves and resources is a key determinant of the Group’s ability to replace production and deliver production growth in the future. It is measured in mmboe. From the year ended 31 December 2013 onwards, BG Group adopted the reserves definitions and guidelines consistent with the Petroleum Resources Management System published by the Society of Petroleum Engineers (SPE-PRMS).

In 2015, BG Group’s total reserves and resources decreased to 16 220 mmboe. This corresponds to a reduction of 3% excluding production. The Group’s proved and probable reserves at year-end 2015 were 6 028 mmboe. This represents a 4% year-on-year reduction excluding production.

Proved reserves at year-end 2015 were 3 512 mmboe giving a one year reserves replacement ratio of 61% allowing for price effect. The Group monetised 257 mmboe through production and additions and revisions to proved reserves were 156 mmboe including price effect. This included technical revisions due to new data and field performance updates (126 mmboe increase), extensions, discoveries and reclassifications (3 mmboe decrease) and the net effect of price movements (33 mmboe increase).


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The strategy that the Board and Corporate Executive Team (CET) focused on delivering during 2015 and up to the Effective Date of the Combination is described below. For a description of the forward-looking strategy applicable to the Group following Effective Date, please refer to Shell’s latest regulatory filings, in particular, Shell’s Annual Report on Form 20-F for the year ended 31 December 2015.

The Group’s strategy, up to Effective Date, was driven by two distinctive capabilities: the Group’s world-class exploration and its highly competitive LNG business.

BG Group’s distinctive capabilities

WORLD-CLASS EXPLORATIONThe Group’s exploration strategy, which has been consistent for more than 15 years, was in two parts.

Existing areasWhere the Group was already actively operating and/or exploring, it looked for new opportunities by capitalising on:

● The Group’s detailed knowledge of local geology;

● The Group’s infrastructure already in place; and

● The Group’s relationships with governments and others affected by or involved in its operations.

New basinsThe Group sought large frontier acreage, where it could find giant gas and oil opportunities at a relatively low cost of entry:

● The Group had wide geological and technical expertise;

● The Group had simple, consistent and robust screening processes that enabled it to make fast decisions and then establish positions rapidly; and

● The Group’s people and culture were a key part of its competitive advantage.

HIGHLY COMPETITIVE LNG BUSINESSThe Group was well positioned to capitalise on the rapidly evolving and growing LNG market, through its competitive advantage in commercialising gas and its highly competitive LNG model.

The Group’s LNG strategy created and delivered value in three ways:

● Through a portfolio of competitively priced supply sources and an attractive set of new supply options;

● Through a flexible portfolio that enabled the Group to optimise these supply and market positions to maximise value and ensure reliable supply for customers; and

● Through the Group’s market knowledge and extensive customer relationships, which enabled the Group to build strong positions in higher-value, growing LNG markets.

This knowledge of gas markets and skills across the whole gas chain enabled the Group to unlock resources and connect them to markets.

The Group’s Strategy

VALUE-DRIVEN EXPLORATION AND PRODUCTION AND LNG COMPANY

World-class exploration and highly competitive LNG business:

● Within exploration, the Group aimed to deliver one new material opportunity on average each year;

● In 2015, the Group restocked its exploration portfolio with acreage in Cyprus, Mongolia and Canada. It also completed eight conventional and three unconventional Exploration & Appraisal (E&A) wells;

● Within LNG, the Group continued to use its flexible supply portfolio to grow and deliver value;

● In 2015, the Group achieved first LNG from QCLNG Train 2 and continued to ramp-up production from Train 1, producing 83 cargoes from QCLNG through the year; and

● The Group also received Federal Energy Regulatory Commission (FERC) approval for Lake Charles LNG.

Actively manage the Group’s portfolio to reinvest in growth:

● The Group was committed to monetising value through active portfolio management in order to realise value from exploration and production (E&P) and LNG assets; and

● The objective was to have a focused and balanced portfolio and to accelerate growth.

Prioritise value over production: ● The Group screened all projects rigorously

and aimed to invest in those judged to be most capital-efficient; and

● In 2015, the Group was coming to the end of a capital intensive phase that supported the ramp-up of QCLNG. Through 2015, the Group continued to invest in Australia and Brazil, while reducing total capital investment partly to reflect lower oil prices.

Focused portfolio of high-quality assets: ● The Group was committed to value creation

from its portfolio of high-quality businesses in upstream gas and oil, and in LNG; and

● The portfolio focused on growth assets, such as Australia and Brazil, assets with high-value optimisation opportunities and material, mature assets that provided strong cash flow. From 2013, all producing assets were reviewed for strategic fit and recommendations made to maximise value over the full life cycle.

Focus on areas where the Group had a competitive advantage:

● In 2015, the Group completed the sale of its interests in the QCLNG pipeline in Australia that followed the disposal of the CATS pipeline and associated infrastructure in the UK in 2014. These were divested as they were not core businesses; and

● The Group remained focused on areas where it had a distinctive competitive advantage – particularly early stage origination and discovery and across the LNG value chain.

Lean and agile organisation: ● BG Group was a lean and agile organisation,

with strong commercial and technical abilities, simple processes and clear accountabilities;

● 2015 saw the appointment of Helge Lund as Chief Executive and an ongoing drive to rationalise and streamline decision making and management structure; and

● Under Helge’s leadership, BG Group appointed a new Corporate Executive Team, embedded new corporate values across the business and established a new operating model (including simplified procedures, a late-life asset model, and integrated performance model).

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Strategic report 2015 Business model and strategy

UPSTREAM

BUSINESS PERFORMANCE EBITDA

$4 167m2015: −35% 2014: $6 453m

E&P VOLUMES

704 kboed2015: +16% 2014: 606 kboed

BRAZIL

● 2015 net production 146 kboed (2014: 78 kboed). ● BG Group holds significant acreage positions

with interests in three offshore blocks in the Santos Basin with permanent production facilities on the Lula, Iracema and Sapinhoá discoveries.

● Operator of 10 offshore exploration blocks in the Barreirinhas Basin, offshore northern Brazil.

2015 Key events ● The first three leased FPSO vessels continued

to operate at around plateau oil production through 2015.

● In July, the sixth FPSO, Cidade de Itaguaí, started up. During the fourth quarter, average

target depth in 2015 was 42 days, down from 52 in 2014 with six wells achieving the Group’s 30 day spud-to-target depth objective.

● During the year, the Group farmed down 10% equity on four frontier exploration blocks in the Barreirinhas Basin. BG Group remains operator with 65% equity in these blocks.

● In April 2015, Petrobras issued its final audited 2014 financial statements, which included a write-off in respect of overpayments on the acquisition of property, plant and equipment incorrectly capitalised according to testimony obtained as part of the Lava Jato investigations. The impact of this write-off on BG Group’s various interests remains unknown.

production of around 63 kbopd was achieved with three producer and three injector wells connected.

● In the fourth quarter, the FPSO Cidade de Mangaratiba reached plateau production and gross production averaged 130 kbopd from five producer and five injector wells, while the FPSO Cidade de Ilhabela averaged 87 kbopd with three producer wells and one injector well connected.

● In December, BG Group achieved record net production from the Santos Basin, reaching 188 kboed from the six installed FPSO vessels. Across the Santos Basin, BG Group had 25 wells in production which flowed at an average rate of around 26 kbopd (gross).

● Drilling performance for development wells continued to improve. The average spud-to-

AUSTRALIA

● 2015 net production 88 kboed (2014: 34 kboed). ● The Group is majority owner and operator of

the two-train 8.5 million tonnes per annum Queensland Curtis liquefaction plant (QCLNG).

● Exploration and development of onshore coal seam gas (CSG) acreage in the Surat Basin.

2015 Key events ● Following start-up of QCLNG Train 1 in

December 2014 and Train 2 in July 2015, BG Group assumed operational control and commenced full commercial operations of both

● In November, BG Group and partners announced approval of a $1.4 billion (gross) development programme, known as Charlie, as part of the continuous development of tenements in the Surat Basin to sustain gas supply to both domestic customers and to QCLNG.

● In June, BG Group completed the sale of the QCLNG pipeline, with gross proceeds of $4.6 billion received, which were used to reduce net debt.

LNG trains. Both trains have reached plateau, with output equivalent to around 8.0 million tonnes per annum.

● QCLNG produced 83 cargoes during 2015 and delivered 77, primarily to the Group’s long-term customers in Asia.

● BG Group has contracted third-party gas supplies to maximise volumes through the LNG trains. During the ramp-up phase, less than 20% of gas supplied to QCLNG was from third-party contracts, in line with expectations.

BOLIVIA

● 2015 net production 52 kboed (2014: 48 kboed). ● BG Group is operator and 100% holder of the

La Vertiente block (three fields), Tarija XX East (two fields), Los Suris (one field) and the Huacareta block.

2015 Key events ● In August, BG Group achieved record daily

net production in Bolivia, reaching 58.3 kboed. ● In October, BG Group commenced a seismic

acquisition programme in the Huacareta block.

● BG Group is a consortium member of the Caipipendi (37.5% interest, containing the Margarita field), Charagua (20% interest, in the process of being relinquished) and Tarija XX West (25% interest, containing the Itaú field) blocks.

PRODUCTION VOLUMES (kboed)

2015 % 2014 %

Oil 205 29 136 22

Liquids 91 13 86 14

Gas 408 58 384 64

Total 704 100 606 100

In 2015, E&P production was 704 kboed, up 16% year-on-year. Growth was driven by Australia, Brazil and Norway. This growth was partially offset by the expected decline in Egypt, combined with lower volumes in Trinidad and Tobago. The Operating review provides an operational update on the major events and activities during 2015.


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EGYPT

● 2015 net production 44 kboed (2014: 62 kboed). ● Operatorship of two gas-producing areas

offshore the Nile Delta – Rosetta and West Delta Deep Marine (WDDM) concessions.

● BG Group holds major shareholdings in the Egyptian LNG project (Train 1 at 35.5% and Train 2 at 38%).

the Egyptian authorities and other stakeholders to seek a long-term solution, including the repayment of $1.1 billion owed by the Egyptian government ($0.9 billion overdue at 2015 year end) and negotiation of an acceptable domestic gas price.

● The Force Majeure notices issued in January 2014 under the Group’s LNG agreements in Egypt remain in place.

2015 Key events ● Production volumes in Egypt were significantly

lower in 2015 due to continued reservoir decline. ● All nine of the WDDM Phase 9a development

wells are now onstream. The nine-well development has only temporarily offset underlying gas production declines.

● BG Group remains committed to its Egyptian LNG business and will continue to negotiate with

INDIA

● 2015 net production 16 kboed (2014: 18 kboed). ● BG Group holds a 30% interest in, and is joint

operator of, the Panna/Mukta oil and gas fields and the Mid and South Tapti gas fields (PMT fields).

● Mahanagar Gas Limited filed a draft prospectus with the Securities Exchange Board India in November 2015 in preparation for a potential initial public offering.

2015 Key events ● BG Group exited the deep water exploration

block MB-DWN-2010/1 having fulfilled all necessary contractual obligations.

NORWAY

● 2015 net production 13 kboed (2014: 1 kboed). ● BG Group has eight licences, five as operator.

2015 Key events ● Production through the Knarr FPSO (63 kboed

gross capacity, BG Group 45% and operator), commenced in March 2015 and ramped up through the year, producing 27 kboed (net) in the fourth quarter.

THAILAND

● 2015 net production 41 kboed (2014: 39 kboed). ● 22.22% interest in the Bongkot field. The field

supplies over 25% of Thailand’s gas demand.

2015 Key events ● In the second quarter, first gas was achieved

from Greater Bongkot North Phase 3M. ● In the third quarter, first gas was achieved from

Greater Bongkot South Phase 4C.

● Operator of Blocks 7, 8 and 9 (66.67% interest) in the Thailand-Cambodia Overlapping Claims Area.

● BG Group holds an overriding royalty agreement over Block 9a.

KAZAKHSTAN

● 2015 net production 92 kboed (2014: 85 kboed). ● Joint operator of the Karachaganak oil and gas

condensate field (BG Group 29.25%), one of the largest condensate fields in the world.

Agreement from 2023 to January 2038. This agreement helps extend the liquid production plateau into the next decade and underpins the implementation of the next phase of development, which partners are looking to progress into front-end engineering and design.

2015 Key events ● Gross production in 2015 reached an average of

389 kboed. With the decline in oil prices during the year, production sharing contract (PSC) effects increased BG Group’s net entitlement.

● In June, the Karachaganak partners agreed a 15-year extension to the Karachaganak Gas Sales

TRINIDAD AND TOBAGO

● 2015 net production 52 kboed (2014: 65 kboed). ● Three concessions with fields currently

producing – Central Block, East Coast Marine Area (ECMA) and North Coast Marine Area (NCMA).

● Exploration activities in Blocks 5(a), 5(c), 5(d), 6(b), 6(d) and E, and Atlantic Area Blocks 3, 5, 6 and 7.

start-up of the Starfish field in December 2014 where production has been lower than anticipated with only one development well now on production, and at the Dolphin field where decline rates have been higher than expected.

● BG Group holds major shareholdings in all four trains of the Atlantic LNG project.

2015 Key events ● During the third quarter, BG Group revised

downwards its proved and probable reserves in Trinidad and Tobago. This revision follows the

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TUNISIA

● 2015 net production 30 kboed (2014: 32 kboed). ● BG Group holds the Miskar and Hasdrubal

concessions, in the Gulf of Gabès. BG Group is operator and owns 100% of the Miskar field and operates the Hasdrubal field on behalf of a 50%-owned joint-venture.

2015 Key events ● A two well rig workover and a three well rigless

stimulation campaign was conducted on Miskar.

● BG Group is the largest gas producer in Tunisia, supplying more than 65% of domestic gas production.

UK

● 2015 net production 97 kboed (2014: 105 kboed). ● BG Group holds extensive interests focused

in the UK’s central North Sea, including a number of operated production hubs (Armada, Everest and Lomond) and exploration and appraisal interests, with minor interests in pipeline and processing facilities.

● BG Group participates in ventures operated by others including Buzzard, Elgin/Franklin, J-Block and Jasmine.

● The Armada and Everest fields were shut in for the duration of the first quarter as a result of repairs to a valve on the CATS Riser Tower which had shut in the main gas export route. Production from Lomond and Erskine was also shut in during the quarter due to the extensive asset integrity programme on the Lomond platform. Armada and Everest were successively brought back onstream in April. Lomond and Erskine came back onstream later in the second quarter.

2015 Key events ● First production from the West Franklin

Phase 2 development was achieved in January 2015. The project consists of three wells and installing a new well head platform tied-back to existing facilities. The project delivered 8 kboed (net) production from two wells, with drilling of the third well underway.

USA

● 2015 net production 33 kboed (2014: 39 kboed). ● BG Group develops shale gas in east Texas/

north Louisiana (Haynesville and Bossier) and Pennsylvania/West Virginia (Marcellus).

2015 Key events ● Production declined during 2015 as a result

of a reduced level of drilling activity due to the continued low gas prices. At year end 2015, three rigs were operating.

DISCOVERIES AND EXPLORATION ACREAGE/NEW DEVELOPMENTS

During 2015, BG Group entered three new basins, advanced its opportunity set by undertaking and analysing seismic data, improved its understanding of its interests through drilling exploration and appraisal wells and high-graded the opportunity set through exiting or relinquishing licences.

of gas to Egypt where BG Group holds equity in the two-train LNG export facility at Idku as well as LNG offtake rights to lift 3.6 million tonnes per annum.

In Mongolia, BG Group farmed in to Blocks IV and V, acquiring a 78% interest in each. These blocks cover approximately 28 900 square kilometres and 21 100 square kilometres, respectively. A 2D seismic acquisition programme commenced during the year.

In Canada, BG Group acquired five adjacent non-operated positions offshore Newfoundland with equity stakes of 10% in blocks EL 1125 and EL 1126, 25% in blocks EL 1123 and EL 1139 and 30% in block EL 1138.

In Cyprus, BG Group signed a farm-in agreement to acquire a 35% holding in Block 12 offshore Cyprus, which includes the Aphrodite gas discovery. This upstream position provides a potential source


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LNG SHIPPING & MARKETING

BUSINESS PERFORMANCE EBITDA

$1 456m2015: –46% 2014: $2 683m

LNG DELIVERED VOLUMES

17.9mt2015: +63% 2014: 11.0mt

In 2015, delivered LNG volumes totalled 17.9 million tonnes (mt), an increase of 63% over 2014. This growth was due to new supplies from the Group’s QCLNG project in Australia and an increase in spot cargo purchases, partially offset by slightly fewer cargoes from the Group’s Atlantic Basin supply contracts. The Operating review provides an operational update on the major events and activities during 2015.

LNG SUPPLY SOURCES AND DESTINATIONS 2015

SOURCE 2015 2014

Atlantic LNG 54 56

Egyptian LNG 0 1

Equatorial Guinea 57 55

Nigeria 35 38

QCLNG 77 0

Spot purchases 59 28

Total 282 178

DESTINATION 2015 2014

Asia 208 121

Europe and other 11 9

North America 5 4

South America 58 44

Total 282 178

LNG SHIPPING

● BG Group has a core fleet of LNG ships that it owns or has under charter. In addition, the Group contracts additional shipping as required on a short or medium-term basis to capture business opportunities and maintain a balanced shipping position.

2015 Key events ● In March, BG Group completed the sale of two

of its LNG ships for proceeds of $460 million, as announced in December 2014. BG Group will charter back the two vessels for nine and eleven years, respectively, with further options to extend the term for each vessel by either three or five years.

SUPPLY AND MARKETING

● BG Group sources LNG from its equity projects in Australia and Trinidad and Tobago, together with long-term purchases from third-party projects in Equatorial Guinea and Nigeria and numerous spot market opportunities.

● BG Group is engaged in marketing LNG to buyers throughout the world, both on a long-term and short-term basis. The combination of flexible supply, shipping capacity and commercial capability enable BG Group’s strategic approach to LNG marketing. In addition to marketing its own committed portfolio of volumes, BG Group also buys and sells spot LNG cargoes.

● BG Group has regasification capacity at the Lake Charles and Elba Island terminals in the USA, the Dragon LNG terminal in the UK and Singapore LNG.

● In December, the Lake Charles LNG project received approval from the US Federal Energy Regulatory Commission to construct and operate a gas liquefaction and export facility in Lake Charles, Louisiana. The project has conditional authorisation from the US Department of Energy for the export of up to 2 billion cubic feet of gas per day or approximately 15 million tonnes of LNG per annum.

● Supply under three long-term sales contracts began in 2015: the 20-year sale of 5.0 million tonnes per annum to CNOOC, 1.2 million tonnes per annum to Tokyo Gas and up to 2.5 million tonnes per annum to GSPC.

2015 Key events ● Delivered LNG volumes increased in 2015 due

to new supplies from the Group’s QCLNG project in Australia (77 cargoes) and an increase in spot purchases (an additional 31 cargoes). In total, BG Group delivered 282 (2014: 178) cargoes to 19 (2014: 17) countries during the year. 74% of cargoes were delivered to Asian markets in 2015 (2014: 68%) and the Group delivered cargoes to three new markets (Egypt, Jordan and Pakistan) during the year.

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2015 Financial Highlights* ● Lower commodity prices impacted financial

results

– Upstream EBITDA** $4 167 million, down 35%

– LNG Shipping & Marketing EBITDA $1 456 million, down 46%

● Business Performance earnings $1 697 million; EPS 49.7 cents; both down 58%

● Total Results earnings of $2 328 million; Total Results EPS 68.2 cents

● Capex down 32% to $6 387 million; cost and efficiency savings of $300 million achieved

● Free cash outflow** of $2 408 million, down 8%; lower net cash flow from operating activities offset by lower capex

● Gross disposal proceeds of $5 186 million; net cash inflow before dividends and financing of $3 363 million

● No final 2015 BG Group dividend

* Unless otherwise set out in this Financial review, financial information for BG Group is based on the Group’s Business Performance. For a reconciliation between Business Performance and Total Results, see note 1, page 42 and note 8, page 53. Total Results earnings and EPS figures set out in this Financial review are the Group’s Total Results for continuing operations including disposals, certain re-measurements and impairments.

** See Glossary, page 80.

Financial results BUSINESS PERFORMANCE

In 2015, BG Group’s revenue and other operating income decreased 16% to $16 419 million, reflecting the significant fall in realised sales prices impacting both the Upstream and LNG Shipping & Marketing segments. The impact of lower prices was partly offset by higher volumes in both segments, the start-up of liquefaction operations at QCLNG and weather-related gains in North America in the LNG Shipping & Marketing segment. E&P production volumes were up 16% and LNG delivered volumes were up 63%.

EBITDA decreased 39% to $5 633 million. In the Upstream segment, EBITDA fell 35% to $4 167 million primarily reflecting the lower revenues, partly offset by the increased liquefaction contribution from QCLNG. In the LNG Shipping & Marketing segment, EBITDA fell 46% to $1 456 million as margins reduced through a combination of lower sales prices and a greater proportion of relatively lower margin spot cargoes.

EBIT decreased by $3 948 million to $2 429 million, reflecting the reduction in EBITDA combined with increased DD&A charges, which resulted from higher E&P production volumes and the start-up of QCLNG.

Net finance costs of $260 million (2014: $109 million) increased, reflecting the reduction in the amount of interest on borrowings that can be capitalised against assets under construction following the start-up of QCLNG. The tax charge for the year reduced to $472 million and reflects the lower profit before tax and a reduction in the Group’s effective tax rate (excluding BG Group’s share of joint ventures and associates’ results and tax) to 24.0% (2014: 36.9%).

Group earnings of $1 697 million and EPS of 49.7 cents both decreased 58%, with the reduction in EBIT and higher net finance costs only partially offset by the reduction in the Group’s tax charge.

Total Results earnings of $2 328 million profit (2014: $1 051 million loss) and EPS of 68.2 cents (2014: loss per share of 30.8 cents) increased, mainly reflecting lower non-cash post-tax impairment charges of $691 million (2014: $5 928 million) partly offset by lower Business Performance earnings. Impairments in 2015 primarily reflected the impact of further falls in commodity prices and reserves revisions on certain of BG Group’s E&P assets, mainly in the North Sea and Tunisia. Impairments in 2014 were mainly driven by the significant fall in global commodity prices, primarily impacting the Group’s Upstream assets in Australia, Egypt, the North Sea and Tunisia.

Net cash flow from operating activities deteriorated by $3 096 million to $4 303 million as a result of lower Business Performance EBITDA and lower working capital inflows, partially offset by lower tax payments. Capital investment on a cash basis was 32% lower at $6 387 million and was predominately focused on key projects in Australia and Brazil. In 2015, the Group realised gross cash proceeds of $4.6 billion associated with the sale of QCLNG Pipeline Pty in Australia, which were used to reduce net debt. The Group also realised proceeds of $460 million from the sale and charter back of two LNG ships, the majority of which were used to support the funding of the BG Pension Scheme, with $119 million used to reduce net debt. As a result, the Group ended the year with $7 200 million of cash and cash equivalents and lower gearing of 25.3% (2014: 29.2%).

DIVIDENDBG Group plc shareholders were paid an interim dividend in respect of the six-month period up to 30 June 2015 of 14.38 cents (9.22 pence) per BG Group plc share on 11 September 2015. Following the Combination with Shell on 15 February 2016, BG Group shareholders will not receive a further BG Group dividend for 2015. However, as the effective date of the Combination** with Shell occurred prior to the record date for Shell’s fourth quarter dividend (being 19 February 2016), BG Group shareholders were entitled to receive that Shell dividend. On 4 February 2016 Shell announced a fourth quarter 2015 dividend of 47 cents per Shell share (equivalent to 20.93 cents per BG share based on the default consideration of 383 pence in cash and 0.4454 Shell B shares for each BG share held). For further information on BG Group’s dividend, see note 7, page 53.

Revenue and other operating income(a) EBIT/earnings(b)

2015$m

2014$m

2015$m

2014$m

Upstream 9 792 12 026 1 075 3 801

LNG Shipping & Marketing 8 339 8 217 1 348 2 540

Other activities 4 7 6 36

Less: intra-Group revenue (1 716) (704) – –

16 419 19 546 2 429 6 377

Net finance costs (260) (109)

Taxation (472) (2 233)

Earnings 1 697 4 035

(a) Includes other operating income of $67 million (2014: $164 million) in the Upstream segment and $204 million (2014: $93 million) in the LNG Shipping & Marketing segment.(b) See Glossary, page 80.


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UPSTREAM E&P production volumes increased 16% to 256.9 mmboe primarily as a result of the ramp-up in Australia, Brazil and Norway, and a higher share of production in Kazakhstan, partly offset by lower production in Egypt, Trinidad and Tobago, and the UK.

Revenue and other operating income decreased 19% to $9 792 million. E&P revenues fell 27% to $8 540 million, reflecting significantly lower commodity prices, partly offset by higher volumes and an improved product mix with additional oil, particularly from Brazil. This was partly offset by the growth in liquefaction revenues, which increased by $875 million to $1 252 million following the start-up of QCLNG.

E&P EBITDA before exploration was 40% lower at $4 257 million, primarily reflecting the decrease in revenues.

E&P operating costs increased 1% to $3 482 million as a 12% increase in lifting costs was largely offset by a 11% reduction in royalties and other costs mainly as a result of lower commodity prices. The 12% increase in lifting costs reflected the ramp-up of production in Australia and Brazil, partially offset by lower maintenance costs in the UK. Other E&P costs decreased 26% to $866 million reflecting the impacts in Brazil of movements in the volume of oil held in stock, with around 6.8 mmboe of oil in stock at the end of 2015 (2014: 2.5 mmboe), partially offset by higher Brazil oil shipping costs. In addition, Other E&P costs in 2014 included the elimination of profit on oil sales associated with the Lula and Iara extended well tests, together with a number of one-off items.

E&P DD&A increased 12% to $2 733 million reflecting the higher production volumes, including new production from higher rate fields, partly offset by favourable changes in the mix of fields, including increased production from Australia and Brazil.

The Group’s average realised oil price decreased 46% to $52.98 per barrel, the liquids price decreased 46% to $43.73 per barrel and the gas price per produced therm decreased 28% to 35.39 cents, reflecting lower market prices. As a result, unit revenues reduced $19.45 per boe to $33.24 per boe.

Unit operating expenditure decreased to $13.55 per boe (2014: $15.54 per boe). Lifting costs per boe decreased primarily as a result of the reduction in shutdowns in the UK. Lower commodity prices led to a decrease in royalty costs, although this was partly offset by an increased proportion of production from royalty paying fields, principally in Brazil. Other E&P unit costs decreased to $3.37 per boe (2014: $5.29 per boe). Consequently, the Group’s unit E&P EBITDA margin was $15.44 per boe lower at $16.57 per boe.

The unit DD&A charge decreased to $10.64 per boe (2014: $10.99 per boe) as a result of a change in the mix of production, with lower production from higher rate fields in the UK and increased production from lower rate fields in Australia and Brazil. This was partly offset by reserve revisions in Trinidad and Tobago, and higher-rate new developments coming onstream in Trinidad and Tobago and in the North Sea.

* See Glossary page 80.

The Total tax charge for the year was $643 million (2014: $1 279 million credit) and included a net charge of $171 million (2014: $3 512 million credit) in relation to disposals, re-measurements and impairments. The net charge in 2015 comprised a net charge of $204 million relating to disposals, re-measurements and impairments, a net charge of $659 million reflecting the impact of foreign exchange movements on deferred and current tax balances, especially in Australia and Brazil, a $388 million credit relating to changes in deferred tax balances due to changes in UK taxation rates and a net $304 million credit resulting from a number of exceptional one-off and prior period taxation items. The net credit in 2014 included a net credit of $3 031 million in relation to disposals and impairments and a net credit of $449 million resulting from a number of exceptional one-off and prior period taxation items.

CAPITAL INVESTMENTCapital investment on a cash basis was 32% lower at $6 387 million and was almost entirely in the Upstream segment ($6 377 million), consisting of $5 779 million on development and other activities, and $598 million on exploration. The development spend was concentrated primarily on projects in Brazil ($2 656 million) and Australia ($1 585 million), together with investments in the UK ($267 million) and Kazakhstan ($240 million).

CASH FLOW Net cash flow from operating activities deteriorated by $3 096 million to $4 303 million as a result of lower Business Performance EBITDA and lower working capital inflows, partially offset by lower tax payments. Net interest paid was $585 million (2014: $556 million).

Investing activities in 2015 included payments to acquire property, plant and equipment and intangible assets of $5 596 million (2014: $8 510 million) and capital expenditure on investments of $791 million (2014: $892 million), partially offset by dividends received and other repayments of $261 million (2014: $331 million). Free cash flow* deteriorated by $180 million to a $2 408 million outflow, primarily reflecting the decrease in net cash flow from operating activities, partly offset by the lower capital investment. Disposal proceeds in 2015 amounted to $5 186 million (2014: $855 million), including $4 597 million gross proceeds from the disposal of the QCLNG pipeline.

Dividends paid to the Group’s shareholders in 2015 accounted for cash outflows of $980 million (2014: $1 024 million). Net cash inflows from borrowings and other financing amounted to $72 million (2014: $1 489 million).

As at 31 December 2015, the Group held cash and cash equivalents of $7 200 million (2014: $5 295 million). Net debt of $10 068 million fell by $1 930 million as a result of the QCLNG pipeline disposal, and gearing was lower at 25.3% (2014: 29.2%) reflecting the reduction in net debt.

The E&P EBIT margin (excluding exploration charge) was $15.09 per boe lower at $5.93 per boe.

The exploration charge decreased 10% to $676 million primarily as a result of reduced seismic activities. Gross exploration expenditure decreased 25% to $942 million and included spend in Trinidad and Tobago ($274 million), Canada ($119 million), the UK ($111 million), Australia ($110 million) and Tanzania ($57 million).

Liquefaction EBITDA increased $460 million to $586 million, with the start of production from QCLNG only partly offset by lower prices and volumes at Atlantic LNG.

LNG SHIPPING & MARKETING Delivered volumes increased 63% with 282 cargoes delivered. The increase included 77 cargoes from QCLNG and 31 additional spot cargoes, partially offset by four fewer cargoes from the Group’s Atlantic Basin supply contracts. Revenue and other operating income increased 1% to $8 339 million as the benefit of higher delivered volumes and weather-related gains in the Group’s North American gas marketing business due to particularly cold weather in the first quarter of 2015 were offset by lower LNG sales prices.

LNG Shipping & Marketing EBITDA decreased 46% to $1 456 million, reflecting lower margins primarily as a result of the fall in sales prices combined with a greater proportion of relatively lower margin spot cargoes. The majority of EBITDA associated with supply from QCLNG is recorded in the Upstream segment. LNG Shipping & Marketing EBITDA unit margin fell 67% to $81 per tonne.

Business development and other costs of $132 million (2014: $124 million) include expenditure on the Lake Charles liquefaction project.

DD&A decreased 24% to $108 million following the sale and leaseback of six LNG vessels during 2014 and two further vessels in the first quarter of 2015.

LNG Shipping & Marketing EBIT decreased to $1 348 million (2014: $2 540 million), as the fall in EBITDA was partially offset by the lower DD&A charges.

FINANCE COSTSIn 2015, BG Group’s net finance costs were $260 million (2014: $109 million) and included foreign exchange gains of $nil (2014: $49 million). Excluding the impact of foreign exchange, net finance costs increased by $102 million to $260 million, reflecting the reduction in the amount of interest on borrowings that can be capitalised against assets under construction following the start-up of QCLNG. Total net finance costs, including re-measurements, amounted to $202 million (2014: $753 million).

TAXATIONThe tax charge for the year reduced to $472 million (2014: $2 233 million) and reflects the lower profit before tax and a reduction in the Group’s effective tax rate (excluding BG Group’s share of joint ventures and associates’ results and tax) to 24.0% (2014: 36.9%). The lower tax rate includes the impact of changes in the Group’s mix of profits and revisions to certain tax positions.

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Re-measurements included within revenue and other operating income amount to a charge of $117 million (2014: $403 million credit), of which a charge of $4 million (2014: $280 million credit) represents non-cash mark-to-market movements on certain gas contracts. While the activity surrounding these contracts involves the physical delivery of gas, the contracts fall within the scope of IAS 39 and meet the definition of a derivative instrument. In addition, re-measurements include a net $113 million charge (2014: $17 million credit) representing unrealised mark-to-market movements associated with economic hedges. Other operating income in 2014 also included a $106 million credit in respect of final settlement of a legacy treaty dispute relating to investments formerly held by the Group.

Operating costs include a $50 million pre- and post-tax charge relating to the downward re-measurement of trade receivables in Egypt to reflect the time value of money associated with the outstanding debt based on a revised assumed repayment profile. This increases the total discount recognised to $150 million following the $100 million pre-tax charge ($79 million post-tax) recorded in 2014.

Disposals include a pre-tax gain of $2 538 million (post-tax $1 663 million) following the disposal of the QCLNG pipeline and a pre-tax loss of $15 million (post-tax $14 million) in respect of the sale of two LNG vessels. Disposals in 2014 included a pre- and post-tax gain of $782 million in respect of the disposal of the Central Area Transmission System (CATS) gas pipeline and associated infrastructure in the UK and a pre-tax gain of $216 million (post-tax $170 million) in respect of the sale of six LNG vessels, which were previously held as finance leases and have subsequently been leased back under operating leases. Other disposals in 2015 resulted in a pre-tax gain of $30 million (2014: $31 million charge) for the year (post-tax $23 million, 2014 $18 million charge).

In 2015, non-cash pre-tax impairment charges of $1 452 million (post-tax $691 million) primarily reflected the impact of further falls in commodity prices and reserves revisions on certain of BG Group’s E&P assets, mainly in the North Sea and Tunisia.

In the North Sea, the non-cash pre-tax impairment charge was $787 million (post-tax $307 million), driven by lower commodity prices, a reserves downgrade reflecting underlying reservoir performance, and higher decommissioning costs on certain fields.

In Tunisia, the pre-tax impairment charge was $534 million (post-tax $307 million) driven by lower commodity prices and a reserves downgrade reflecting reservoir performance.

Elsewhere in 2015, reduction in the Group’s assumptions of future commodity prices resulted in pre-tax impairment charges of $131 million (post-tax $77 million) in relation to certain other E&P assets.

In 2014, a non-cash pre-tax impairment charge of $8 956 million (post-tax $5 928 million) related to Upstream activities in Australia, Egypt and certain other assets. This was driven mainly by the significant fall in global commodity prices.

In Australia, the total pre-tax impairment charge was $6 824 million ($4 540 million post-tax). With the agreement to sell the wholly owned subsidiary QCLNG Pipeline Pty Ltd in 2014, the remaining QCLNG assets were impaired by $2 747 million pre-tax ($1 828 million post-tax). A further $4 077 million pre-tax ($2 712 million post-tax) impairment charge in Australia was driven mainly by a reduction in the Group’s assumptions for future commodity prices.

In Egypt, the total pre-tax impairment charge was $790 million ($737 million post-tax), principally driven by further reserves downgrades reflecting underlying reservoir performance, and a write-down of the Group’s investment in Egyptian LNG reflecting the Group’s expectation of limited LNG exports for the foreseeable future.

Elsewhere in 2014, the reduction in the Group’s assumptions for future commodity prices resulted in a $1 342 million pre-tax ($651 million post-tax) impairment charge of which the most significant charges were in the North Sea $566 million pre-tax ($172 million post-tax), Tunisia $450 million pre-tax ($255 million post-tax) and the USA $227 million pre-tax ($148 million post-tax).

Other items in 2015 resulted in a pre-tax charge of $142 million (2014: $131 million), post-tax $109 million (2014: $95 million). There was a further pre- and post-tax charge of $40 million (2014: $nil), being the Group’s share of an impairment charge recognised by a joint venture, along with a pre- and post-tax charge of $5 million (2014: $56 million) relating to the Group’s share of a write-off of assets under construction in Brazil following the bankruptcy of a contractor.

CAPITAL AND LIQUIDITYTotal equity as at 31 December 2015 of $29 757 million was $617 million higher than 2014. Details of the maturity, currency and interest rate profile of BG Group’s borrowings as at 31 December 2015, and details of movements in the Group’s net borrowings during 2015, are shown in note 16, page 58. Details of the Group’s cash and cash equivalents as at 31 December 2015 are shown in note 15, page 58.

The Group’s principal borrowing entities are BG Energy Holdings Limited and certain wholly owned subsidiary undertakings, the majority of whose borrowings are guaranteed by BG Energy Holdings Limited (collectively BGEH).

BG Energy Holdings Limited is the Group’s principal credit-rated entity. As at 31 December 2015, it had long-term credit ratings of A-, rating watch positive from Fitch; A2, rating under review for upgrade from Moody’s; and A-, credit watch with developing implications from Standard & Poor’s; and short-term credit ratings of F-2, rating watch positive from Fitch; P-1 from Moody’s; and A-2 from Standard & Poor’s.

As at 31 December 2015, BGEH had a $4.0 billion US Commercial Paper Programme and a $2.0 billion Euro Commercial Paper Programme, both of which were unutilised, and a $15.0 billion Euro Medium Term Note Programme, of which $7.0 billion was unutilised.

BGEH also had aggregate undrawn committed revolving bank borrowing facilities of $7.25 billion, of which $5.04 billion expires in 2017 and $2.21 billion expires in 2019. During 2015, BGEH drew down the remaining $1.6 billion available under a credit facility provided by an export credit agency.

Furthermore, BGEH had uncommitted borrowing facilities including multicurrency lines, overdraft facilities of £45 million and credit facilities of $20 million, all of which were unutilised.

Unutilised committed borrowing facilities of $7.25 billion were canceled in February 2016.

COMMITMENTSBG Group has commitments in respect of LNG ships in support of its expanding LNG portfolio, and oil tankers and FPSO vessels required for marketing and production operations primarily in Brazil. For further information on the Group’s commitments, see note 21, page 68.

DISPOSALS, RE-MEASUREMENTS AND IMPAIRMENTSThe following items, described as ‘disposals, re-measurements and impairments’ are excluded from Business Performance as exclusion of these items provides a clearer presentation of the underlying performance of the Group’s ongoing business. For a full reconciliation between BG Group’s Total Results and Business Performance, see note 1, page 42. For further details of amounts comprising disposals, re-measurements and impairments, see note 4, page 49.

Disposals, re-measurements and impairments in respect of continuing operations in 2015 amounted, in aggregate, to a profit of $744 million before tax and interest (2014: $7 954 million loss), see note 1, page 42.


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PROJECT DECISION AND DELIVERYDescription

● Poor decision making regarding project selection and development leading to inadequate returns on capital employed.

Controls ● Investment decisions were made through

the Group’s Capital Investment Process. ● Strategic resourcing and strategic alliances.

Commentary ● Project execution risk has fallen in 2015

following the completion of QCLNG and the sixth Brazilian FPSO.

● Other risks remain, primarily on future developments in Brazil.

COMMODITY PRICES Description

● Commodity prices have fallen sharply since mid-2014; risk is that they remain low, affecting earnings, cash flows and balance sheet.

Controls ● Key mitigation focused on capital rationing and

cost control through developing business plans at lower commodity prices.

Commentary ● Continued downward pressure on oil price during

the year has affected financial results; although volatile, forward curve prices remain low in 2016.

SHELL ACQUISITIONDescription

● Shell acquisition proposal fails to complete due to either shareholder or regulatory issues.

Controls ● Measures were in place to focus and motivate

the organisation. ● Standalone BG Group strategy was developed

in case of deal failure.

Commentary ● All of the five pre-conditions were fulfilled. ● Shareholder approvals received and Combination

became effective on 15 February 2016.

The ERM Framework was the process by which BG Group:

● Defined risk appetite: the Board and CET determine the extent to which the Group was willing to accept and manage risks and uncertainties in the pursuit of its strategic objectives;

● Identified and assessed risks: the nature and extent of the Group’s principal risks and uncertainties were identified, analysed and assessed;

● Designed and executed controls: the Group put in place appropriate control systems directed at mitigating those risks and uncertainties;

● Monitored risks and assured controls: the management and mitigation of risks and uncertainties were monitored and associated internal controls were assured in the short and longer term through ongoing Board and management oversight and performance review processes. The effect of uncertainty on the Group’s cash flow and earnings profiles was modelled and used as an input to decision-making; and

● Took and tracked actions: ensured appropriate actions were taken to strengthen controls and reduce risk.

The Risk Management EnvironmentThe principal change in risk since late 2014 was the substantial fall in commodity prices, which materially affected the oil and gas industry as a whole. These lower prices added pressure on the Group’s revenues, cash flows and balance sheet and demonstrated the need for a robust ERM Framework to identify and manage the associated risks. Prior to completion of the Shell transaction, the Board and CET had considered the ongoing viability of the Group and the associated draft viability statement disclosures.

Successful start-up of the QCLNG project in Australia and further FPSOs on production in Brazil have meant that capital expenditure could be reduced without risk to project delivery and a number of the Group’s project-related risks and uncertainties were reduced in 2015.

The financial situation and corruption allegations affecting the Group’s Brazilian partner, Petrobras, may lead to impacts on the cost and schedule of further developments in the Santos Basin due to either supply chain disruption or capital and liquidity constraints on Petrobras.

FISCAL RISK AND GOVERNMENT TAKEDescription

● Governments and their agencies act in a way that extracts greater value from BG Group than assumed in the Business Plan.

Controls ● Risks managed through government and

stakeholder influence. ● Creation and maintenance of a strong Licence

to Operate.

Commentary ● Fiscal risk may increase with falling commodity

prices as governments look to maintain tax revenues.

● This is partly mitigated as other tax regimes have lower taxes in a low price environment.

RESERVES AND RECOVERABILITYDescription

● Reservoir potential may not match planned levels.

● Adverse outcome of field unitisation decisions. ● Impact of rules and guidelines.

Controls ● Reserves Committee deliver an independent

review including the impact of rules and guidelines.

● Data acquisition and reservoir modelling to forecast and manage future performance, and including history matching.

Commentary ● Poor reservoir performance leads to reserve

downgrades. ● Lower commodity prices reduce the economic

potential and therefore lower reserves.

The principal risks and uncertainties upon which the Board and Corporate Executive Team (CET) were focused in 2015 and up to the date of completion of the Shell transaction (‘Completion’) are described below. For forward-looking risks applicable to the BG Group as part of the Shell Group following Completion, please refer to Shell’s latest regulatory filings, in particular, Shell’s Annual Report on Form 20-F for the year ended 31 December 2015.

Effective identification, assessment and management of BG Group’s principal risks and uncertainties, the implementation of associated controls and the monitoring of sources of assurance, was integral to how the Group ran its business.

The Board considered carefully the nature and extent of the risks and uncertainties it was willing to take in achieving the Group’s strategic objectives and a summary is set out here, although it should not be considered as being exhaustive. Please refer to the Important Notes on page 16.

BG Group’s approach to the system of risk management and internal control was articulated and managed through the Group’s Enterprise Risk Management (ERM) Framework.

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Strategic report Principal risks and uncertainties

HEALTH, SAFETY, SECURITY AND ASSET INTEGRITY (HSSAI)DescriptionIn a BG Group venture, any of the following:

● Major accident hazard event, including process safety or asset integrity;

● Occupational safety or health event; ● Being subject to violent attack,

demonstrations; or ● Inability to operate due to major in-country

disruption (war, disorder, revolution).

Controls ● Regular training for all staff. ● Developed an HSSE Management System

Framework and Safety Case process. ● The Group tests controls regularly, including

Emergency response planning.

Commentary ● Risk of fatalities, litigation, environmental or

reputational damage all affect the Group’s Licence to Operate.

● In 2015, focus has been on the safe start-up of the QCLNG and Brazilian projects and on the security situation in North Africa, particularly Tunisia.

INSUFFICIENT EXPLORATION SUCCESSDescription

● Insufficient addition of resources to develop new projects and deliver future production growth.

Controls ● Robust opportunity screening to manage

a balanced portfolio. ● Well planning and risk assessment. ● Global New Ventures team to acquire acreage

via farm-ins and licence rounds.

Commentary ● Low commodity price environment in 2015

has been challenging, but allows a reduction in exploration and new venture entry costs.

REGULATION, LEGISLATION, LITIGATION AND COMPLIANCEDescription

● Contractual disputes and litigation or breach of applicable laws and regulations.

Controls ● Increased involvement from Group Legal. ● Continued application of legal and regulatory

compliance systems. ● Independent Speak Up reporting system.

Commentary ● Volatile commodity prices increase counterparty

and litigation risk. ● Risk that BG Group is affected by the corruption

allegations in Brazil.

ENVIRONMENT AND CLIMATE CHANGEDescription

● Release, emission or discharge beyond agreed or acceptable limits.

● The impact of climate change on demand for hydrocarbons.

● Risk of reputational damage.

Controls ● HSSE Management System Framework in place. ● Environmental management systems certified

to ISO 14001. ● Emergency and crisis response plans in place.

Commentary ● No significant environmental breaches in 2015. ● BG Group was active in industry coalitions

on climate change and the COP21 discussions in Paris.

PARTNER RELATIONSHIPSDescription

● Dependence on, inability to influence or misalignment with partners.

Controls ● Due diligence and strategic view taken in new

partner selection. ● Robust JOA process, from drafting to execution. ● Close monitoring of partner activities, backed

up by joint venture audits.

Commentary ● Petrobras, BG Group’s Brazilian partner,

has faced corruption allegations throughout the year; BG Group is not implicated.

● Lower prices increased the partner risk, but this has not had a major impact on the Group in 2015.

MACRO-ECONOMIC AND GEO-POLITICAL DEVELOPMENTSDescription

● The Group may not foresee or adapt to changes in the external environment.

Controls ● Strategic planning from top down to

take into account external environment. ● Maintaining a balanced portfolio across

the Group. ● Analysis of political and Licence to

Operate risks.

Commentary ● The global slowdown in 2015, particularly

in China and deteriorating Brazilian stability has been a focus.

ACCESS TO CAPITAL AND LIQUIDITYDescription

● Inability to meet the Group’s funding requirements or manage liquidity and solvency risks.

Controls ● The Group’s planning process assists in judging

the amount of capital and liquidity required. ● Minimum levels of committed facilities

maintained and limits are placed on the amount of borrowings maturing in a specific period.

Commentary ● Risk has increased due to a ‘lower for longer’

price environment, weakening sector credit metrics and a difficult M&A environment for divestments.

CREDITDescription

● BG Group’s counterparties may be unable to meet their financial or performance obligations.

Controls ● Credit policies in place; credit support required

when considered necessary. ● Credit limits applied to counterparties. ● Monitoring of exposures and overdue balances.

Commentary ● Credit risk, including suppliers, producers,

governments and trading companies, is increasing due to lower prices.


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HUMAN RESOURCES CAPACITY AND CAPABILITYDescription

● Insufficient people with the right behaviours, skills, experience in the right places to deliver the Group’s business plan.

Controls ● Resourcing model aligned with business plans. ● Strategic alliances. ● Competitive reward and incentive packages.

Commentary ● Lower than expected impact of the Shell

takeover on staff turnover in 2015, although the risk increases again as the deal has completed and integration activities begin.

IT, CYBERSECURITY AND RESILIENCEDescription

● Failure of business or production-critical IT systems.

● A successful attack on Group computer networks.

● Loss of, or unauthorised access to, sensitive information held electronically.

Controls ● Security awareness campaigns increased

following Shell offer. ● Enhanced technical security monitoring. ● Critical infrastructure designed to be resilient.

Commentary ● Risk range could be from the loss of sensitive

information to unauthorised access and damage to production control systems.

PORTFOLIO CONCENTRATIONDescription

● Over-concentration in a particular country or revenue stream.

Controls ● Value Assurance Framework with stage-gates. ● Executive management and Board review

Group strategy. ● Portfolio management.

Commentary ● The 2015 strategy and portfolio review confirmed

concentration in the Group’s Australian, Brazilian and GEMS business, but this was believed to be manageable.

IMPORTANT NOTES

Risk Identification and AssuranceWhile BG Group developed processes for identifying and managing risk, these processes provided reasonable, rather than absolute, assurance and were designed to help manage, rather than eliminate, risk. It is not possible to be certain that such processes will be successful in managing or mitigating these risks effectively or at all, not least because not all of these risks and uncertainties are within BG Group’s control. In particular, BG Group was limited in its ability to impose risk management systems and processes (and associated controls) in non-operated ventures. Systems of risk management and internal control were therefore no guarantee that all risks have been identified, or will not materialise, or that associated damage or losses will not occur.

In addition to the principal risks and uncertainties listed in this report, BG Group’s activities may also be affected adversely by other risks as yet unforeseen or currently considered not to be material. For the year 2015, the principal risks and uncertainties described in this section should be read in conjunction with the Legal notice on the inside front cover.

Insurance Some of the major risks involved in BG Group activities cannot reasonably and economically be insured. The transfer of risks to the insurance market may be affected and influenced by constraints on the availability of cover, market appetite and capacity, pricing, and the decisions of regulatory authorities.

BG Group may incur significant losses from different types of risks that are not covered by insurance. The Group maintains an insurance programme to provide some mitigation against significant losses, which, as is consistent with general industry practice, includes limited cover for physical damage, removal of debris, control of wells, re-drill, sudden and accidental pollution, and employer’s and third-party liabilities.

Policies purchased are subject to limits, deductibles and specific terms and conditions. In addition, premium costs are subject to changes based on a company’s loss experience, the overall loss experience of the insurance markets accessed and capacity constraints. Insurance is, by its nature, contingent. As such, any particular insurance claim made might not result in a full recovery from insurers.

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The Company was a listed public limited company throughout the financial year ended 31 December 2015. At the date of this report, the Company was no longer listed, having re-registered as a private limited company on 30 March 2016. As such, this report has been prepared in accordance with the reporting requirements set out in the Companies Act 2006 (the Act) of an unlisted, public limited company. The relevant provisions of the UK Listing Authority Listing Rules, Disclosure and Transparency Rules, and the provisions of the UK Corporate Governance Code are no longer applicable to the Company.

BOARD OF DIRECTORSThe following served as Directors during the year, and up to the effective date of the Combination, 15 February 2016:

Andrew Gould (Chairman)

Helge Lund (Chief Executive)(appointed 9 February 2015)Simon Lowth (Chief Financial Officer)Sir John Hood (Senior Independent Director, Non-Executive Director)Vivienne Cox (Non-Executive Director)Pam Daley (Non-Executive Director)Martin Ferguson (Non-Executive Director)Caio Koch-Weser (Non-Executive Director)Lim Haw-Kuang (Non-Executive Director)Sir David Manning (Non-Executive Director)

Patrick Thomas (Non-Executive Director)

Baroness Hogg (Non-Executive Director)

The following Directors were appointed after the year end, and from the effective date of the Combination, 15 February 2016:

Simon HenryDonny ChingGerard PaulidesHuibert VigevenoJoanne WilsonErik BoninoRussell O’Brien

COMPANY SECRETARY The following served as Company Secretary during the year and up to the date of this report, unless otherwise shown:

Steve Allen (resigned 14 March 2016)Shell Corporate Secretary Limited (appointed 14 March 2016)

GENDER DIVERSITY In accordance with reporting requirements set out in the Act, disclosure is provided in respect of gender diversity at Board level, senior management (including directors of subsidiary companies) and in the organisation as a whole, in each case as at 31 December 2015.

Male (%) Female (%)

Board(a) 77 23

Senior Management 73 27(b)

Other 74 26

(a) Following the changes to the Board, from the effective date of the Combination, 15 February 2016, 14% of the Board were female.

(b) The Board considers that a more meaningful measure of senior management than that defined by the Act is employees in leadership positions, in line with the definition used within the Group Diversity Statement. At 31 December 2015, 13% of employees in leadership positions were female.


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Corporate governance

The Remuneration Committee met on many occasions during 2015. During the early part of the year, the Committee’s major decisions were focused on revisions to the Company’s Long-Term Incentive Plan (LTIP) and, for the remainder of the year, a significant part of the Committee’s focus was on considering and discussing remuneration matters in the context of the proposed Combination with Shell.Through consultation with a number of the Group’s shareholders during 2014, it was evident that certain shareholders favoured a basket of Company performance metrics applying to the LTIP Performance Share Awards, rather than a single metric dependent solely on relative total shareholder return (TSR). The single TSR metric was well-suited to the first phase of BG Group’s development, during which the Company was judged principally on its ability to add value through discovering resource. However, as the Company’s focus shifted to improving return on capital and delivering earnings and cash flow growth, the Board believed it appropriate for the Company performance metrics for the BG Group LTIP to reflect this.

Following an extensive consultation exercise with major shareholders during February 2015, the Committee revised the LTIP performance conditions for 2015 awards so that they were based on a basket of metrics comprising 50% relative TSR, 25% cash flow (earnings before interest, tax, depreciation and amortisation (EBITDA)) and 25% return on capital (return on average capital employed (ROACE)). The expected value of the BG Group LTIP awards remained broadly unchanged. The changes were all within the Directors’ Remuneration Policy approved by shareholders in May 2014. Further details are set out in the following report.

In considering remuneration matters in the context of the proposed Combination with Shell, the Committee took into account a number of factors, including the importance of retaining and motivating BG Group’s management and employees during the unusually long period between the announcement of the Combination in April 2015 and the Effective Date (15 February 2016). Retention was seen as critical both in order to facilitate the continued delivery of high standards of safety and operational performance during the offer period. Full details of the decisions on remuneration matters, including those relating to the Company’s share plans and the arrangements for the Executive Directors, are set out in the Scheme Document that was published on 22 December 2015.

2015 was Helge Lund’s first year as Chief Executive and, during a period of prolonged uncertainty for BG and its employees, Mr Lund continued to lead high standards of safety, project delivery and operational performance, while also maintaining staff morale. Despite the very challenging external environment, BG Group delivered strongly in all of these areas. Over successive quarters in 2015, the BG Group Directors believed that BG Group had met or exceeded market expectations. Under Mr Lund’s leadership, BG Group grew production by 16% on 2014, increasing the Group’s guidance for production in 2015 during the year to 680–700 kboed and achieving actual production of 704 kboed. BG Group brought core major projects in Australia and Brazil onstream and introduced a more streamlined operating model, achieving cost and efficiency savings of more than $300 million and reducing capital expenditure by 32%.

The Committee reviewed the outcome of the 2015 annual bonus scorecard for the Executive Directors in this context. Before considering individual performance, the bonus scorecard outcome was 80% (compared to 42.5% target and 85% stretch). After careful consideration, the Committee determined that the business performance scorecard outcome should apply.

As a result of the Committee’s annual review of Executive Directors’ salaries in March 2015, no increase was made to the salary of the Chief Executive, consistent with the determination that this should remain unchanged for five years. The Chief Financial Officer’s salary was increased by 2%, which was in line with the general increases for UK employees.

I should like to take this opportunity to thank my fellow Committee members for their contributions and constructive support during the period of my chairmanship, particularly over the past 18 months, which were by any standards exceptionally busy for the Committee. Their commitment and professionalism helped the Committee through this challenging period and were of considerable assistance to me in chairing it. I thank them all for their service.

SIR JOHN HOOD CHAIRMAN OF THE REMUNERATION COMMITTEE15 February 2016

REMUNERATION REPORT – GLOSSARY OF TERMSThese terms or acronyms are used in the following report:

Acronyms

AGM Annual General Meeting

AIS Annual Incentive Scheme, the Group’s annual bonus plan

CET Corporate Executive Team

CSOS Company Share Option Scheme, a legacy plan under which share options were previously granted

DBP Deferred Bonus Plan

EBITDA Earnings before interest, tax, depreciation and amortisation

EPS Earnings per share

EPV Estimated present value, a measure of the economic or fair value of a share award

HMRC HM Revenue & Customs

HSSE Health, safety, security and environment

LTIP Long-Term Incentive Plan

PSA Performance Share Award, an award granted under the LTIP which is subject to performance conditions other than in exceptional circumstances

ROACE Return on average capital employed

SIP Share Incentive Plan, an HMRC approved plan for UK employees

TRCF Total recordable case frequency

TSR Total shareholder return

VBDP Voluntary Bonus Deferral Plan

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Corporate governance Remuneration report

The following section of this report provides details of the implementation of the Directors’ Remuneration Policy for the year ended 31 December 2015.

The Directors’ Remuneration Policy, as approved by shareholders at the AGM in May 2014, can be found in the 2013 Remuneration report and is available upon request at the Company’s registered office.EXECUTIVE DIRECTORS’ TOTAL REMUNERATION

Executive Directors YearSalary£’000

Benefits£’000

Pension£’000

Bonus£’000

LTIP – annual award

£’000

LTIP – on-hire award

£’000

Total remuneration

£’000

Helge Lund, appointed Chief Executive from 9 February 2015

2015 1 339 948 402 2 546 – 295 5 529

2014 n/a n/a n/a n/a n/a n/a n/a

Simon Lowth, appointed Chief Financial Officer from 2 December 2013

2015 736 61 221 1 004 – – 2 022

2014 725 33 218 877 – – 1 853

SALARYWhen awarding salary increases, the Committee considered, among other factors, the salary increases applied elsewhere in the Group and, for UK-based Executive Directors, the increases applied for UK employees.

Executive Directors

Increase in year

%Salary£’000

Pro-rated%

Salary received

in year£’000

Helge Lund nil 1 500 89% 1 339

Simon Lowth 2 740 100% 736

BENEFITSBenefits included life assurance, income protection, personal accident insurance, company car or cash in lieu of company car, chauffeur services, spousal travel, relocation, financial counselling, medical insurance and any taxable business expenses, including the applicable tax.

Executive Directors

SIP Flex Share

allocations£’000

Relocation allowance

£’000

Other benefits

£’000

Total benefits

£’000

Helge Lund 4 906 38 948

Simon Lowth 4 n/a 57 61

PENSIONSThe Executive Directors were able to choose a defined contribution pension contribution or receive cash in lieu, or a combination thereof, at a rate of up to 30% of salary.

Executive Directors

Pensionable salary

received in year£’000

Cash in lieu%

Cash in lieu of pension

£’000

Helge Lund 1 339 30 402

Simon Lowth 736 30 221

BONUSFor an individual’s AIS award, the Committee’s determination of the business performance outcome was added to the individual’s performance outcome and the resulting percentage figure was applied to their bonus opportunity range, with a 50% outcome resulting in a target award and increasing on a linear basis with a 100% outcome resulting in a maximum award.

Bonus potential as % of salary Actual

bonus awarded as a % of

salary

Bonus

Executive Directors Target MaximumCash

£’000Deferred

£’000

Total bonus£’000

Helge Lund 100 200 190 2 546 n/a(a) 2 546

Simon Lowth 60 150 135.6 1 004 n/a(a) 1 004

(a) No portion was deferred as the Executive Directors were no longer in employment at the time of the granting of awards under the Deferred Bonus Plan.

PROCESS FOR DETERMINING BONUSThe following business performance metrics operated for the 2015 financial year:

● Group EPS – Actual Business Performance results were adjusted to exclude the effects of changes in upstream prices, material exchange rates and contracted LNG prices.

● Group ROACE – Actual post-tax Business Performance results (adjusted as for Group EPS above but excluding net finance income/costs on net borrowings/funds) are expressed as a percentage of average Group capital employed. Average Group capital employed was calculated by averaging the positions at the start and end of the year, excluding the impact of any material impairments. Group capital employed is the aggregate of total equity (excluding commodity financial instruments and associated deferred tax) and net borrowings/funds (in both cases adjusted to exclude the effects of changes in upstream prices, material exchange rates and contracted LNG prices).

● Project performance – In-year performance on all Board-sanctioned projects, both operated and non-operated, was assessed against a range of indicators, including in-year cost and on-schedule performance relative to plan.

● Group HSSE – Performance was assessed against a balanced scorecard of measures and targets across a broad range of leading and lagging indicators, including, for example, TRCF and the actioning of audit findings.

Individual performance was assessed against individual objectives for the year.

For the 2015 incentive year, the Committee followed the two-stage review process outlined in the Directors’ Remuneration Policy. This involved, for each metric, a review of performance against targets and, secondly, consideration of the outcomes of the first stage in the context of the underlying performance of the business.


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Corporate governance Remuneration reportAnnual remuneration report

Metric Performance outcome

Target outcome

(%)

Weighting and maximum outcome

(%)

Helge LundPerformance

assessment(%)

Simon Lowth Performance

assessment(%)

1. Group EPS Normalised EPS was 128c, which was ahead of a target of 95c and a maximum of 111c. 19 38 38 38

2. Group ROACE Normalised ROACE was 10.5%, which was ahead of a target of 8% and a maximum of 9.4%. 6 12 12 12

3. Project performance Good progress was made during the year on Board-sanctioned projects, particularly in Australia and Brazil, and performance was assessed as between target and maximum. 10 20 16 16

4. Group HSSE Performance was assessed against the HSSE balanced scorecard set at the start of the year as between target and maximum, with all the scorecard indicators at or ahead of target. 7.5 15 14 14

5. Individual performance

Individual performance was assessed against the objectives set for the year. 7.5 15 15 12

Total 50 100

Overall assessment 95 92

For the 2015 financial year, the Annual Incentive Scheme performance metric outcomes in determining the Executive Directors’ bonuses were as follows (all Company performance measures are Group-wide):

AWARDS UNDER THE DEFERRED BONUS PLAN GRANTED DURING 2015For bonus awards for the 2014 financial year in excess of 100% of salary, the excess was automatically deferred for three years in accordance with the Directors’ Remuneration Policy. Awards under the DBP are not subject to Company performance conditions, but vest at the end of the deferral period subject to continued employment.

Awards under the Deferred Bonus Plan granted during 2015

Executive DirectorsBonus

yearDate of

grant

End of deferral

period

Share priceat grant(a)

£

Face value (at date

of grant) £’000

Simon Lowth 2014 12 May 2015 17 Mar 2017 11.89 152

(a) Granted in the form of nil-cost options based on the average share price over the five dealing days preceding the date of grant.

LONG-TERM INCENTIVE PLAN

LTIP PERFORMANCE SHARES VESTING IN 2015Performance Share Awards vesting

during 2015

Executive Directors%

vestingNumber

of shares

Market value£’000

Dividend equivalent

£’000

Total award£’000

Helge Lund(a) 100 31 735 295 – 295

(a) Helge Lund received an award of vested shares, not subject to performance conditions, on account of 2014 bonus entitlements foregone on leaving his former employer.

As Helge Lund and Simon Lowth did not join the Group until February 2015 and December 2013, respectively, they did not receive a 2012 PSA grant. For other participants, the performance period for the 2012 PSAs ended on 31 August 2015. None of the shares awarded vested, and the awards lapsed in full on 4 September 2015. BG Group’s TSR performance relative to the weighted index was measured by the independent TSR monitoring service of Alithos Limited and reviewed by Kepler Associates. This analysis indicated that BG Group had underperformed the index. The Committee considered the underlying financial performance of the Group, and concluded that none of the PSAs granted in September 2012 should vest.

LTIP PERFORMANCE SHARES GRANTED IN 2015

Executive DirectorsDate of

grant

End of performance

period

Face value of shares awarded

as a % of salary

EPV of awards

£’000

Share price at grant

£(a)

Maximum shares

awarded

Face value (at date

of grant) £’000

Number of shares received

if threshold performance

achieved(15%)(b)

Helge Lund 9 Mar 2015 9 Mar 2017 30 455 9.29 48 976 455 48 976(c)

9 Mar 2015 9 Mar 2018 707 4 558 9.29 1 141 011 10 600 171 151

12 May 2015 12 May 2018 600 3 870 11.89 756 938 9 000 113 540

Simon Lowth 12 May 2015 12 May 2018 465 1 480 11.89 289 475 3 442 43 421

(a) PSAs granted on 9 March 2015 were in the form of conditional share awards based on the average share price over the three dealing days preceding the date of grant. PSAs granted on 12 May 2015 were in the form of nil-cost options based on the average share price over the five dealing days preceding the date of grant.

(b) Assuming continuing employment until the normal vesting date and excluding any dividend equivalents.(c) The vesting of this buy out award, 75% on 9 March 2016 and the remainder on 9 March 2017, is not subject to Company performance conditions, consistent with the share awards foregone by Mr Lund on leaving

his former employer.

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2015 LTIP Performance Metrics KPI Weighting Link to strategy

● Prioritising safety and asset integrity ● Disciplined financial approach ● World-class exploration ● Excellence in project development and execution ● Maximising value through supply and market positions

TSR 50%

EBITDA 25%

ROACE 25%

Performance Metric Measurement of performance Performance targetsDetermination of vesting outcome

TSR Measured on a relative basis compared to a sector peer group.

Threshold performance is performance at the median of the peer group.

Maximum performance is performance that exceeds the median of the peer group by 7% on a compounded annual basis.

The peer group for the 2015 award comprised: Anadarko Petroleum Corp.; Apache Corporation; BHP Billiton Plc; BP plc; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; Eni S.p.A.; EOG Resources Inc; Exxon Mobil Corporation; Hess Corporation; Marathon Oil; Novatek; Occidental Petroleum Corp.; Repsol S.A.; Royal Dutch Shell plc; Statoil ASA; Total S.A.; Tullow Oil plc; and Woodside Petroleum Ltd.

For each metric, 15% of the portion of the award vests for threshold performance, increasing on a linear basis to 100% for maximum performance.

EBITDA Measured by the cumulative performance of the Company over the three-year period on an absolute basis, normalising for commodity prices and material exchange rate movements.

The targets for threshold vesting for EBITDA set by the Committee were informed by the forecast level of performance of the Company and the targets for maximum vesting were set at a level that the Committee considered represented a significant challenge for the Company to achieve.

ROACE Measured by the average annual performance of the Company over the three-year period on an absolute basis, normalising for commodity prices and material exchange rate movements.

The targets for threshold vesting for ROACE set by the Committee are informed by the forecast level of performance of the Company and the targets for maximum vesting are set at a level that the Committee considers represents a significant challenge for the Company to achieve.

2015 LTIP PERFORMANCE METRICSThrough consultation with a number of the Group’s shareholders during 2014, it was evident that certain shareholders favoured that a basket of Company performance metrics apply to the LTIP PSAs, rather than a single metric dependent solely on relative TSR. The single TSR metric was well-suited to the first phase of BG Group’s development, during which the Company was judged principally on its ability to add value through discovering resource. However, with the shift in the Company’s focus to improving return on capital and delivering earnings and cash-flow growth, the Board believed it was appropriate that the Company performance metrics for the LTIP reflect this.

Following consultation with major shareholders during February 2015, the Committee revised the LTIP performance conditions for future awards

so that they were based on a basket of metrics. The Committee considered that the structure for future LTIP awards, using a basket of metrics that were clearly linked to the evolving strategic priorities of the Group, would serve to incentivise the senior management of the Company to achieve exceptional financial and business performance, and would thereby promote the long-term success of the Company. Further details of the metrics, the structure of the awards and the targets are set out below. As the LTIP outcome would be derived, in part, from reported financial metrics (EBITDA and ROACE) that were based on completed financial years (1 January to 31 December), the awards moved from a September to a May grant date, to allow the vesting period to align more closely with the relevant period of Company performance.

ADDITIONAL INFORMATION ON 2015 LTIP PERFORMANCE METRICS

TSRThe TSR peer group was reviewed and updated to include the most relevant comparator companies. Seventeen of the 20 companies in the 2015 peer group were also included in the 2014 peer group for assessing TSR performance. For a listing of peer group companies for prior years see page 22.

EBITDA AND ROACEThe Committee considered that it would be detrimental to disclose the performance targets for EBITDA and ROACE before the completion of the financial years to which they applied, as such disclosure would provide the Company’s competitors with confidential information on the timing of key projects and might adversely impact the Group’s ability to optimise its marketing activities. It might also require the Company to provide earlier disclosure of material events that may or may not impact on the EBITDA and ROACE forecasts informing the LTIP targets. In accordance with the approved remuneration policy, the targets would be disclosed following completion of the financial years to which they applied, when they would no longer be commercially sensitive.

PRIOR YEARS’ LTIP PERFORMANCE METRICSFor PSAs granted during 2014 and prior years and subject to performance conditions, TSR performance was the only performance measure, with performance measured over a three-year performance period commencing on the first day of the calendar month in which the award was made and with no retest provision. Subject to the review of the Committee, the level of PSAs vesting would depend on BG Group’s TSR performance over the performance period relative to the TSR performance of a weighted index of a selection of oil and gas industry peers.


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The constituents of the index for 2014 and for the two prior years are shown in the table below.

TSR CONSTITUENTS – INDEX FOR PERFORMANCE SHARE AWARDS

SHAREHOLDINGSDILUTIONIn the event that all options and awards outstanding as at 31 December 2015 under BG Group’s LTIP vested (such awards to be satisfied by the re-issue of treasury shares or by the issue of new shares), and all CSOS options (a legacy plan under which options are currently satisfied by the issue of new shares) were exercised, the resulting issue of new shares and re-issue of treasury shares would amount to 0.55% of the issued ordinary share capital (excluding treasury shares) at that date.

The exercise of options under BG Group’s Sharesave Plan 2008 was satisfied by the issue of new shares. If the total number of options outstanding under these plans as at 31 December 2015 had been exercised on that date, the resultant issue of shares would have represented 0.07% of the total ordinary share capital (excluding treasury shares) then in issue.

Partnership and Flex Share awards made under the SIP during 2015 were satisfied by the re-issue of treasury shares. These awards represented 0.01% of the issued ordinary share capital (excluding treasury shares) as at 31 December 2015.

BG Group’s intention was to continue to satisfy the future exercise of options and vesting of awards under the above share plans by the issue of new shares and re-issue of treasury shares as described above.

As at 31 December 2015, the BG Group Employee Share Trust held 2 264 578 shares.

EXECUTIVE DIRECTORS’ INTERESTS IN SHARES AT 31 DECEMBER 2015The table below shows the Executive Directors’ (and their connected persons’) interests in ordinary shares, which included all shares held beneficially, together with those interests in shares that have vested, and that are no longer subject to deferral or performance conditions, and that were able to be included as an interest in shares under BG Group’s shareholding guidelines.

Interests in ordinary shares(a)

Executive DirectorsAs at

1 Jan 2015As at

31 Dec 2015Value£’000(b)

Salary£’000(c)

Helge Lund – 17 077 168 1 500

Simon Lowth 29 177 29 488 290 740

(a) Interests in ordinary shares included ordinary shares acquired pursuant to the BG Group SIP (vested and unvested).

(b) The value of shareholdings was based on the closing price of a BG Group ordinary share on 31 December 2015.

(c) Salary is annual salary as at 31 December 2015.

SUMMARY OF EXECUTIVE DIRECTORS’ OVERALL INTERESTS IN BG GROUP SHARES

Executive Directors Type

Lapsed during

2015

Exercised during

2015

Outright or vested

as at31 Dec 2015

Unvestedas at

31 Dec 2015

Unvested and subject to performance conditions as at

31 Dec 2015

Total as at

31 Dec 2015

Helge Lund Shares – – 16 771 – – 16 771

Conditional Share Awards(a) – – – – 1 189 987 1 189 987

Nil-cost options(a) – – – – 756 938 756 938

Share Incentive Plan – – 5 301 – 306

Simon Lowth Shares n/a n/a 28 913 – – 28 913

Nil-cost options(a) – – – – 1 655 194 1 655 194

Share Incentive Plan – – 10 565 – 575

(a) The Executive Directors’ interests in shares under awards made in the form of conditional share awards and nil-cost options are stated before the operation of any applicable withholdings for tax and social security, which would typically arise when a vested award is exercised.

OTHER OUTSTANDING LTIP AWARDS

Executive DirectorsDate of

grant

End of performance

period

Face value of shares awarded as a % of salary

EPV of awards

£’000

Share price at grant

£(a)

Maximum shares

awarded

Face value (at date

of grant) £’000

Number of shares received if threshold

performance achieved(25%)(b)

Simon Lowth 11 Dec 2013 30 Nov 2016 454 1 448 12.27 268 255 3 291 67 063

11 Dec 2013 30 Nov 2016 700 2 234 12.27 413 854 5 078 103 463

18 Mar 2014 30 Nov 2016 590 508 10.74 398 701 4 282 99 675(c)

4 Sept 2014 31 Aug 2017 454 1 450 12.11 272 126 3 295 40 818

(a) Based on the average share price over the five dealing days preceding the date of grant. (b) Assuming continuing employment until the normal vesting date and excluding any dividend equivalents.(c) The vesting outcome will be reduced by the proportion of the awards granted on 11 December 2013 that vest.

Company 2014 2013 2012

Anadarko Petroleum Corp.

Apache Corporation

BP plc

Canadian Natural Resources Limited

Cenovus Energy Inc.

Chevron Corporation

ConocoPhillips

Devon Energy Corporation

Eni S.p.A.

EOG Resources Inc.

Exxon Mobil Corporation

Company 2014 2013 2012

Hess Corporation

Marathon Oil

Occidental Petroleum Corp.

Repsol S.A.

Royal Dutch Shell plc

Statoil ASA

Suncor Energy Inc.

Total S.A.

Tullow Oil plc

Woodside Petroleum Ltd.

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SHAREHOLDING GUIDELINESThe Committee adopted guidelines for Executive Directors and CET members and certain other senior employees to encourage substantial long-term share ownership. These specified that Executive Directors should build up, and then retain, a holding of shares with a value equivalent to 300% of salary. The required holding for other members of the CET was 100% of salary and for certain other senior employees was 50% of salary. The guidelines required that, in relation to LTIP and DBP awards, vested shares (net of tax) should be retained by the individual until the required shareholding level was reached.

The chart sets out the percentage of salary held in shares by the Executive Directors as compared with the guidelines. The chart also shows for other members of the CET and senior employees the average actual shareholding as a percentage of salary.

Under the shareholding guidelines, vested nil-cost option awards under the LTIP, VBDP and DBP was included. They were included net of the withholding for tax and social security which would have been made had they been exercised at the year end. For UK employees, the withholding applied was the current UK maximum of 47%.

SHAREHOLDINGS AT 31 DECEMBER 2015 AGAINST GUIDELINES(% of salary)

Shareholding guideline

Actual holding

Average holding

50

77

Other senior employees(b)

100

130

HelgeLund(a)

300

39

(a) In post for less than five years.(b) Some in post for less than five years.

CET(b)

Simon Lowth(a)

300

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EXTERNAL APPOINTMENTSTo broaden the experience of Executive Directors, they were able to accept one external appointment as a non-executive director of another company provided that permission was sought from the Board in advance. Any external appointment was not permitted to conflict with the Director’s duties and commitments to BG Group. Any fees from such appointments could be retained by the individual Executive Director.

The Chief Financial Officer, Simon Lowth, served as a non-executive director of Standard Chartered plc throughout 2015, and received annual fees of £160 000 during 2015 in connection with this appointment.

No other non-executive director appointments were held by the Chief Executive or Chief Financial Officer.

PAYMENTS FOR LOSS OF OFFICE AND PAYMENTS TO FORMER DIRECTORSDuring 2015, the total of payments made to former Directors in respect of or as a result of their employment as a Director did not exceed £10 000 per individual, the de minimis level set by BG Group for disclosure purposes.

HISTORICAL TSR PERFORMANCEThe graph shows the growth in value of a hypothetical £100 holding invested over seven years in each of BG Group shares, the FTSE 100 index and the 2015 LTIP index of oil and gas industry peers.

The FTSE 100 was chosen as this is a recognised broad equity market index of which BG Group is a member. The calculations were in accordance with the Large and Medium-Sized Companies and Groups (Accounts and Reports) (Amendment) Regulations 2013 (the Regulations).

HISTORICAL TSR PERFORMANCE FOR THE YEAR ENDED 31 DECEMBER

201520132008 2012201120102009

200

180

140

120

160

100

80

BG Group return index FTSE 100 indexPeer return index

2014

CHANGE IN CHIEF EXECUTIVE’S REMUNERATIONThe table shows the Chief Executive’s remuneration over the same seven-year period as the TSR graph above.

The remuneration of the interim Executive Chairman is included for the period from 28 April 2014, following the resignation of Chris Finlayson, until 9 February 2015 when Helge Lund joined as Chief Executive. Andrew Gould did not receive any additional remuneration as interim Executive Chairman.

Year – Chief Executive

CEO total remuneration

£’000

Annual variable element award rates

against maximum opportunity

LTIP vesting rates against maximum

opportunity

2015 – Helge Lund 5 529 95% –

2015 – Andrew Gould (interim Executive Chairman) 78 – –

2014 – Chris Finlayson 467 0% 0%

2014 – Andrew Gould (interim Executive Chairman) 487 – –

2013 – Chris Finlayson 2 518 59% 0%

2012 – Sir Frank Chapman 5 411 0%(a) 44%

2011 – Sir Frank Chapman 7 912 69% 62%



(a) At the request of the Executive Directors, they received no bonuses for 2012.

The table below provides a comparison of the percentage year-on-year change from 2014 to 2015 in elements of the Chief Executive’s reward package relative to the Group’s general UK employee population, which represented a sizeable portion of the Group’s global employee population and the most relevant employee comparator group for the UK-based Chief Executive.

Chief Executive Salary Benefits Bonus

Chief Executive(a) 75% 1 877%(b) n/a(c)

UK employees of the Group 4% 7% 10%

(a) Comparing figures for Andrew Gould as interim Executive Chairman until 8 February 2015 and Helge Lund as Chief Executive from 9 February 2015 with those for Chris Finlayson as Chief Executive until 27 April 2014 and Andrew Gould as interim Executive Chairman from 28 April 2014.

(b) 2015 benefits include the relocation allowance paid to Helge Lund.(c) Neither Chris Finlayson nor Andrew Gould was awarded a 2014 bonus.


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RELATIVE IMPORTANCE OF SPEND ON PAYThe chart details BG Group’s Business Performance earnings as a measure of the Group’s operating performance, distributions to shareholders and total Group-wide expenditure on pay for all employees (including benefits, pension, variable pay, termination payments and social security), for the last two financial years. The average number of employees in 2015 was 4 717 (2014: 5 143).

5 000

2 000

3 000

4 000

1 000

1 697

982

RELATIVE IMPORTANCE OF SPEND ON PAY

($m)

2015 2015

1 022

–42% –4% –19%

2014 2014 2014 2015

Business Performanceearnings

Distributions to shareholders

Total spend on pay

4 035

1 0271 259

CHAIRMAN AND NON-EXECUTIVE DIRECTORSThe Chairman’s remuneration was last reviewed during 2014 and the other Non-Executive Directors’ fees were last reviewed in 2012. The Non-Executive Directors’ fees, effective since 1 June 2012 following the last change, and Chairman’s annual fee, effective since 16 May 2012 following the last change, are summarised below.

Chairman’s fee £725 000

Non-Executive Directors’ basic fee £82 000

Committee membership fee (excluding Nominations Committee) £8 000

Chairman – Audit Committee £28 000

Chairman – Remuneration Committee £25 000

Chairman – Sustainability Committee £20 000

Senior Independent Director £30 000

CHAIRMAN AND NON-EXECUTIVE DIRECTORS’ TOTAL REMUNERATIONIndividual remuneration for the year to 31 December

Salary/fees £ Taxable benefits £(a) Total £

Non-Executive Directors 2015 2014 2015 2014 2015 2014

Andrew Gould (Chairman) 725 000 725 000 5 075 5 592 730 076 730 592

Vivienne Cox 98 000 98 000 2 551 6 261 100 551 104 261

Pamela Daley 94 667 85 333 34 003 44 111 128 670 129 444

Martin Ferguson 90 000 90 000 14 568 24 291 104 568 114 291

Baroness Hogg 90 000 90 000 373 4 921 90 373 94 921

Sir John Hood 153 000 153 000 7 776 13 015 160 776 166 015

Caio Koch-Weser 98 000 98 000 5 764 11 079 103 764 109 079

Lim Haw-Kuang 90 000 90 000 27 936 22 033 117 936 112 033

Sir David Manning 102 000 102 000 2 389 4 675 104 389 106 675

Mark Seligman 118 000 118 000 4 482 4 700 122 482 122 700

Patrick Thomas 98 000 98 000 10 594 25 567 108 594 123 567

(a) Taxable benefits include reasonable travel, accommodation and subsistence expenses, including any applicable tax, incurred when undertaking their duties as a BG Group Director, and may on occasion have included necessary spousal travel in support of the business.

CHAIRMAN AND NON-EXECUTIVE DIRECTORS’ INTERESTS IN ORDINARY SHARESThe Chairman and Non-Executive Directors’ interests in ordinary shares of BG Group plc (Shares) at the start and at the end of the financial year are set out below.

Interests in ordinary shares

As at 1 Jan 2015

As at 31 Dec 2015

Andrew Gould (Chairman) 65 000 65 000

Vivienne Cox 3 818 6 370

Pamela Daley 14 200 32 000(a)

Martin Ferguson – 650

Baroness Hogg 17 976 19 788

Sir John Hood 8 795 8 795

Caio Koch-Weser 3 600 3 600

Lim Haw-Kuang 3 751 8 367

Sir David Manning 3 108(b) 3 679

Mark Seligman 21 076 24 705

Patrick Thomas 7 302 12 410

(a) Pam Daley purchased Shares jointly with her husband on 12 February 2015.(b) Notification was provided on 19 January 2016 in respect of historic acquisitions and disposals of beneficial holdings of Sir David Manning, between 17 February 2009 and 3 September 2010, resulting in a net disposal of 139

shares, reflected as an adjustment to interest in ordinary shares as at 1 January 2015.

24



STATEMENT OF IMPLEMENTATION OF REMUNERATION POLICY IN 2016Full details of the decisions on remuneration matters relating to the recommended cash and share offer by Shell for the entire issued and to be issued ordinary share capital of BG Group plc, including those relating to the Company’s share plans and the arrangements for the Executive Directors, are set out in the Scheme Document that was published on 22 December 2015.

Following the shareholder meetings and prior to the date of the Court Order implementing the Combination, the Committee determined in accordance with the Scheme Document the extent to which the performance conditions applicable to PSAs vesting at the time of the Court Order had been satisfied.

2013 LTIP PSAsFor the PSAs granted in 2013, BG Group’s TSR performance relative to the weighted index was measured by the independent TSR monitoring service of Alithos Limited and reviewed by Kepler Associates. This analysis indicated that BG Group had underperformed the index. The Committee concluded that none of the shares awarded would vest and the awards lapsed in full on 11 February 2016. Accordingly, the ‘parallel award’ granted to Simon Lowth on 18 March 2014 was not reduced and the award vested in full on 11 February 2016.

2014 LTIP PSAsFor the PSAs granted in September 2014, BG Group’s TSR performance relative to the weighted index was measured by the independent TSR monitoring service of Alithos Limited and reviewed by Kepler Associates. This analysis indicated that BG Group had outperformed the index by 2.25% per annum

on average, and as a result 42.3% of the shares awarded should vest. The Committee concluded that 42.3% of the shares awarded would vest and accordingly the corresponding portion of the awards vested on 11 February 2016 and the balance lapsed.

2015 LTIP PSAsFor the PSAs granted in 2015, BG Group’s TSR performance relative to the weighted index was measured by the independent TSR monitoring service of Alithos Limited and reviewed by Kepler Associates. This analysis indicated that BG Group had outperformed the index by significantly in excess of 7% per annum on average, and as a result the portion of shares awarded and dependent on the Company’s TSR performance should vest in full. Normalised EBITDA was $10 billion, which was ahead of a target of $8.5 billion and a maximum of $8.8 billion. Reported Group EBITDA was $5.6 billion. Normalised ROACE was in excess of 10.5%, which was ahead of a target of 7.9% and a maximum of 8.5%. Reported Group ROACE was 4.6%. The Committee concluded that 100% of the shares eligible to vest should vest and accordingly the corresponding portion of the awards vested on 11 February 2016.

As explained in the Scheme Document, the Executive Directors’ employments with BG Group plc terminated on 16 February 2016, on the day following the Effective Date, and on 15 March 2016 each Executive Director was paid a lump sum change of control payment and their AIS award for the 2015 financial year, the determination of which is described on page 19.

EXTERNAL ADVISERS AND FEES

Kepler Associates* During the year, Kepler Associates provided the Committee with advice on market trends, incentive schemes and other remuneration matters.

Kepler Associates was formally re-appointed by the Committee in 2012 as adviser to the Committee, following a competitive selection process. Kepler, a brand of Mercer and part of the MMC group of companies, did not provide any other services to the Group, and the Committee was satisfied that the advice it received was objective and independent.

£133 543 on the basis of time incurred, and expenses.

Towers Watson* During the year, the Committee received market information from Towers Watson.

Towers Watson also provided general compensation and benefits information, general consultancy services to the Group and actuarial advice to the Trustees of the BG Pension Scheme. Towers Watson was selected by the Company and the Committee was satisfied that the market information it received was objective and independent.

£19 000 on the basis of time incurred, and expenses.

Alithos Limited* During the year, Alithos Limited, an independent TSR monitoring service, provided the Committee with reports on the Company’s TSR performance relative to the relevant indices.

Alithos also provided reports to the Group on BG Group’s TSR performance and on its sector peers. Alithos was selected by the Company and the Committee was satisfied that the information it received was independent and objective.

£31 750 on the basis of a fixed fee for the requested reports.

* Kepler Associates, Towers Watson and Alithos Limited have given, and not withdrawn, their consent to the issue of this document with the inclusion of the reference to their respective names in the form and context in which they appear.

GOVERNANCE AND ADVISERS TO THE REMUNERATION COMMITTEEREMUNERATION COMMITTEE’S RESPONSIBILITIESThe Committee’s principal responsibilities were:

● Setting, reviewing and recommending to the Board for approval the Group’s overall remuneration policy and strategy;

● Setting, reviewing and approving the remuneration arrangements (including any bonuses, incentive payments, share awards, pension and benefit arrangements, and termination payments) of the Chairman, Chief Executive and Executive Directors;

● Reviewing and approving the remuneration arrangements (including any bonuses, incentive payments, share awards, pension and benefit arrangements, and termination payments) of members of the CET who are not Executive Directors, and the Company Secretary; and

● Reviewing and approving the rules of (and any significant amendment to) any LTIP (whether cash or share-based), DBP, cash-based incentive plan, or share plan, subject to final approval by the Board and/or shareholders, where necessary.

During 2015, the following Non-Executive Directors were members of the Committee and attended Committee meetings as shown:

DirectorCommittee meeting

attendance

Sir John Hood (Committee Chairman) 17/17

Vivienne Cox 16/17

Pamela Daley (appointed to the Committee with effect from 1 June 2015) 9/9

Mark Seligman 17/17

Patrick Thomas 14/17

During the year, the Committee also invited the following individuals to attend on certain occasions to provide advice to the Committee to enable it to make informed decisions:

● Chairman;

● Chief Executive;

● Executive Vice President, Human Resources, or People; and

● Head of Reward.

The Company Secretary attended meetings as secretary to the Committee.

No individual was present when their own remuneration was being discussed.

The Committee also met without management present and received independent executive remuneration advice and information from external advisers (see table below).


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AUDIT NOTESIn accordance with Section 421 of the Companies Act 2006 and the Regulations, the following sections of the report have been audited: Executive Directors’ total remuneration; scheme interests awarded during the year; payments to former Directors; Executive Directors’ interests in shares; Non-Executive Directors’ remuneration; Non-Executive Directors’ interests in ordinary shares; and the table and notes in the Pensions section of the report. The remaining sections are not subject to audit.

By order of the Board

SIMON HENRY DIRECTOR 1 June 2016

Registered office: 100 Thames Valley Park Drive, Reading, Berkshire RG6 1PT

Registered in England & Wales No. 3690065

SHAREHOLDER VOTINGThe table sets out actual voting in respect of the Group’s previous Remuneration report.

For Against Abstain(a)

2014 Annual Statement and Annual Report on Remuneration

1 773m 388m 43m

(2015 AGM) (82%) (18%)

(a) A vote abstained is not a vote in law and is not counted in the calculation of the proportion of votes ‘For’ or ‘Against’ a resolution.

26



There are a number of legal requirements set out in the Companies Act 2006 (the Act) with which BG Group must comply, which are addressed in this section.

INCORPORATION AND CONSTITUTIONBG Group Limited is domiciled in England and incorporated in England and Wales under Company Number 3690065. The Company was a listed public limited company throughout the financial year ended 31 December 2015. The Company’s shares were de-listed on completion of the Combination on 15 February 2016 and the Company was re-registered as a private limited company on 30 March 2016.

The Company adopted new Articles of Association (the New Articles) on re-registration. Such New Articles may only be amended by a special resolution of the shareholders.

Unless specifically referenced, the disclosures set out on pages 27 to 31 refer to the provisions contained in the articles of association which were in place ahead of re-registration, and throughout the financial year ended 31 December 2015 (the Articles).

SHARE CAPITALThe Company’s share capital consists of ordinary shares with a nominal value of 10p each, and a single, redeemable Dividend Access Share with a nominal value of 10p. Under the Scheme, the creation of a new class of shares, the Dividend Access Shares, was approved by Shareholders at a General Meeting of the Company held on 28 January 2016, and such share was allotted and issued to the Dividend Access Trustee (as defined in the Scheme Document published on 22 December 2015). The rights attaching to the Dividend Access Share are set out in the New Articles. Details of the Company’s share capital, together with details of the movements in the share capital during the year, and up to the date of this report, are set out in note 20 on page 68.

SHAREHOLDERS’ RIGHTS AND OBLIGATIONSRights and restrictions that applied to the Company’s shares during the financial year are as follows:

● Restrictions on shareholders’ rights – Subject to the Articles, and unless the Directors decided otherwise, if a shareholder had failed to supply information about interests in shares after receiving a notice properly issued by the Company, the shareholder would not have been entitled to attend or vote at a shareholders’ meeting for as long as the default continued. Any person who acquired these shares was subject to the same restrictions. In addition, if the shareholder’s interest represented 0.25% or more of the existing shares further restrictions applied.

● Restrictions on holding securities – There were no restrictions under the Articles or under UK law that either restricted the rights of UK resident shareholders to hold, or limited the rights of non-resident or foreign shareholders to hold, or vote, the Company’s ordinary shares.

● Transfer – There were no restrictions on the transfer of shares beyond those required by applicable law, under the Articles or under any applicable share dealing code.

● Voting – Subject to any special rights or restrictions, at any general meeting on a poll, every shareholder on the Register not less than 48 hours (excluding non-working days) before the time fixed for a general meeting, had one vote for every share that they held. Shareholders were permitted to cast votes either personally or by proxy and a proxy need not be a shareholder. Under the Articles, only shareholders who had paid the Company all calls, and all other sums, relating to their shares that were due at the time of the meeting, were permitted to attend and vote.

● Alteration of share capital and variation of rights – The shareholders could by ordinary resolution: (a) consolidate, or consolidate and then divide, all or any of the Company’s share capital into new shares of a larger nominal amount than the existing shares; and (b) divide some or all of the Company’s share capital into shares that are of a smaller nominal value than the existing shares. The Company could reduce or vary the rights that attached to its share capital by special resolution. However, such matters are subject to the relevant provisions of the Articles, or New Articles and applicable law and regulations. Further details in relation to rights and restrictions applying to the Company’s shares are set out in the New Articles.

PROFIT AND DIVIDENDSThe shareholders can declare final dividends by ordinary resolution. No dividend can exceed the amount recommended by the Directors. Dividends are paid based on the amounts that have been paid up on the shares in the relevant period.

The Directors can recommend that the shareholders pass an ordinary

resolution to direct all or part of a dividend to be paid by distributing specific assets. The Directors must give effect to such a resolution. The Company may invest unclaimed dividends, or these may be forfeited, subject to the relevant provisions of the Articles, or New Articles.

For the year ended 31 December 2015, the total profit for the Group before tax was $2 971 million (2014: $2 330 million loss). The results are dealt with more fully in the Financial statements on pages 31 to 78.

An interim dividend in respect of the six-month period up to 30 June 2015 of 14.38 cents (9.22 pence) per share was paid on 11 September 2015. The effective date of the Combination, 15 February 2016, was prior to the record date for Shell’s 2015 fourth quarter dividend (being 19 February 2016). As such, BG Group plc shareholders would be entitled to receive that Shell dividend and would not receive a further BG Group plc dividend for 2015. On 4 February 2016, Shell announced a fourth quarter dividend of 47.00 cents per Shell share (equivalent to 20.93 cents per BG Group share, based on the default consideration of 383 pence in cash and 0.4454 Shell B shares for each BG Group plc share held).

SUBSTANTIAL SHAREHOLDERSAs at 31 December 2015, the following voting interests in the ordinary share capital of the Company, which were disclosable under DTR 5, had been notified to the Directors:

BlackRock Inc 231 289 616 6.77%

Norges Bank 127 624 204 3.73%

On 15 February 2016, the effective date of the Combination and the date on which the shares of the Company were de-listed, the following voting interests in the ordinary share capital of the Company, which were disclosable under DTR 5, had been notified to the Directors:

BlackRock Inc 205 566 688 6.01%

JPMorgan Chase & Co. 195 919 807 5.72%

Norges Bank 125 705 776 3.67%

UBS Investment Bank 231 778 826 6.77%

SIGNIFICANT CONTRACTS – CHANGE OF CONTROLAs at 31 December 2015, there were a number of agreements that would take effect, alter or terminate upon a change of control of BG Group following a takeover bid.

BG Energy Holdings Limited had committed borrowing facilities with a number of financial institutions in aggregate amounts of (i) $7.3 billion, which were undrawn and (ii) $2.7 billion, which were drawn. Under the terms of these facilities, the lenders had an option to demand repayment or cancellation of any or all of them upon a change of control of BG Group. When taken together, these facilities were significant to the ongoing liquidity of the BG Group.

No other agreements that take effect, alter or terminate upon a change of control of the Group following a takeover bid were considered to be significant in terms of their potential impact on the business of the Group as a whole as at 31 December 2015 and none are considered to be significant in the context of the combined Shell-BG Group.

RESEARCH AND DEVELOPMENTIn 2015, BG Group invested approximately $33 million in research and development (R&D) of which $19 million was with Brazilian third parties. The investments support the Group’s technology programme which is focused on five priority areas: Sustainable Gas, Carbonate Improved Oil Recovery, Subsea, Geoscience and Coal Seam Gas, and is based in Rio de Janeiro, Brazil.

Under the Sustainable Gas technology programme, 2015 saw the launch of the Gas Innovation Centre, in partnership with the São Paulo Research Foundation and the University of São Paulo, and the first White Paper published by the Sustainable Gas Institute under the Sustainable Gas Technology programme on the theme of fugitive gas emissions. In addition, the Blue Amazon project developed a new hull design for LNG ships in order to improve ship propulsion efficiency and reduce both costs and emissions.

2015 also saw the inauguration and commissioning of the supercomputer, Remoja, at SENAI – The Integrated Campus of Manufacturing and Technology (SENAI CEMATEC), to support the International Inversion Initiative to develop Fullwave Form Inversion research, a partnership between BG Group, SENAI CEMATEC, University of Rio Grande do Norte, Imperial College London and University of British Colombia. A new innovative geomechanics software called TATU was also developed with the start-up Alis Solutions, which allows


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Corporate governance Other disclosures

the fast evaluation of displacements caused by hydrocarbon production and associated stress changes in and outside the reservoir.

Under the Subsea technology programme, a prototype for the Autonomous Underwater Vehicle ‘Flatfish’ was built and tested in ocean conditions in Brazil, with field trials planned in 2017. This project is a partnership between BG Group, SENAI CEMATEC and the German Research Centre for Artificial Intelligence (DFKI) with the intention to raise integrity assurance of subsea pipelines and equipment and contribute to improve the availability of BG Group’s Assets. Other projects under the Subsea programme are focused on research into reducing costs and improving asset integrity of deepwater risers.

During 2015, significant investments were also made in the field of Carbonate Improved Oil Recovery (IOR), focused on the Brazilian pre-salt. In particular, the first equipment was installed at the new cutting-edge laboratory in Enhanced Oil Recovery at the Federal University of Rio de Janeiro and research undertaken on pre-salt reservoir characterisation and fluid modelling with multiple international academic and industry partners and student exchange programmes.

Construction of the Global Technology Centre in Rio de Janeiro was completed in November 2015, with occupation planned for mid-2016.

BRANCHESThe Group, through various subsidiaries, has established branches in a number of different countries in which the business operates.

EMPLOYEES ● Engagement – Employees are informed about significant business issues,

the Group’s performance, and other matters of concern to them, using webcasts, the Group’s intranet and in-house publications, as well as at face-to-face briefing meetings at each business location. When appropriate, consultation with employee and union representatives also takes place. Employees are given an opportunity to become shareholders in the Company and many participate in the Group’s share plans.

● Disabilities – BG Group takes a positive approach to equality and diversity. The Group remains committed to the full and fair treatment of people with disabilities in relation to job applications, training, promotion and career development. Where existing employees become disabled, the Group’s policy is to provide continuing employment and training wherever practicable. The Group encourages its partners to take a similar approach to these issues where Group Policies or Standards are not able to be implemented directly.

APPOINTMENT AND REMOVAL OF DIRECTORSThe Board may appoint any person to be a Director of the Company and such Director would only hold office until the next AGM, when he or she would be eligible for re-appointment by the shareholders. The Articles provided that, at each AGM, all these Directors who were elected, or last re-elected a Director at or before the AGM held in the third calendar year before the current year, shall automatically retire from office.

POLITICAL DONATIONSThe Group’s policy is not to make donations for political purposes. In 2015, no donations were made to any EU member state for political purposes, nor contributions made to any non-EU political parties.

DIRECTORS’ POWERSThe Directors are empowered to exercise all the powers of the Company subject to any restrictions in the Articles, or New Articles, the Act and any special resolution.

● Repurchase of shares – The Company did not repurchase shares during the year or make any shares the subject of a charge. At the 2015 AGM, the Company was given authority to make market purchases of up to 341 441 611 of its own issued share capital at a maximum price per share of the higher of: (i) 105% of the average middle market closing price of the shares for the five business days prior to the relevant purchase; and (ii) an amount equal to the higher of the price of the last independent trade and the highest independent bid for an ordinary share. This authority will expire on 1 June 2016 and the Company will not seek to renew it.

● Pre-emptive rights and new issues – At the 2015 AGM, the Directors were given the power to allot shares up to a maximum nominal amount of £113 813 870, representing approximately 1/3 of the Company’s issued share capital (excluding treasury shares) as at 17 March 2015, together with ordinary shares outstanding under BG Group’s share option schemes. This authority will expire on 1 June 2016 and the Company will not seek to renew it.

● Borrowing powers – So far as the Act allows, the Directors can exercise all the powers of the Company to: (a) borrow money; (b) issue debentures and other securities; and (c) give any form of guarantee or security for any debt, liability or obligation of the Company or of any third party, subject to the limits (as and where defined in the Articles, or New Articles). Such limits may be exceeded if the Company’s consent has been given in advance by an ordinary resolution passed at a general meeting.

DIRECTORS’ INDEMNITIES AND INSURANCEDuring the financial year BG Group maintained liability insurance for its Directors and officers. The Directors, Company Secretary and some senior management were also granted a qualifying third-party indemnity, under the Act. On the Combination, the Directors who had served during the year resigned and new Directors were appointed. Prior to the Effective Date, the Company entered into a deed of indemnity with each new Director under identical terms. The deeds indemnify the Directors to the widest extent permitted by the applicable laws of England against all liability incurred as a Director or employee of the Company or of certain other entities.

Neither the BG Group nor the Shell company indemnity and insurance would provide cover in the event that the indemnified individual was proved to have acted fraudulently or dishonestly.

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Corporate governance Other disclosures > continued

DIRECTORS’ REPORT – PRINCIPAL DISCLOSURESThe Directors’ report comprises pages 2 to 30. The following information, which forms part of the Directors’ report, can be found on the pages detailed:

Amendments to Articles

2, 27 Greenhouse gas emissions

3

Appointment and removal of Directors

28 Important events since end of financial year

2, 25, 73

Branches 28 Incorporation and constitution

27

Corporate Governance report

17 Payments to Directors/employees on a takeover

19, 25

Directors’ details 17 Political donations 28

Directors’ indemnities and insurance

28 Profit and dividends 2, 27

Directors’ interests 19–24 Repurchase of shares

28

Directors’ powers 28 Research and development

27

Directors’ responsibilities

30 Restrictions on the transfer of shares

27

Disclosure of information to auditors

30 Restrictions on voting rights

27

Employee engagement

28 Risk management 14

Employees with disabilities

28 Securities carrying special rights

27

Employee equal opportunities

28 Share capital 27, 68

Employees’ gender disclosure

17 Shareholders’ rights and obligations

27

Employee share schemes

19 Significant contracts – change of control

27

Financial instruments

33, 60 Strategic report and principal activities

2

Future developments

7–10 Substantial shareholders

27

Going concern 30


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STATEMENT OF DIRECTORS’ RESPONSIBILITIESFINANCIAL STATEMENTS AND ACCOUNTING RECORDSThe Directors are responsible for preparing the Annual Report, the Directors’ Remuneration report and the Financial statements in accordance with applicable law and regulations.

The Companies Act 2006 (the Act) requires the Directors to prepare Financial statements for each financial year. Under the Act, the Directors have prepared the Group and the parent Company Financial statements in accordance with IFRS as adopted by the European Union and as applied in accordance with the provisions of the Act. The Financial statements are required by law to give a true and fair view of the state of affairs of the Group and the Company and of the profit or loss of the Group for that period.

The Directors consider that, in preparing the Financial statements on pages 31 to 78, the Company has used appropriate accounting policies consistently applied and supported by reasonable and prudent judgements and estimates, and all applicable accounting standards have been followed. The Company has complied with UK disclosure requirements in this report, in order to present a consistent picture to all shareholders.

The Directors have responsibility for ensuring that the Company keeps accounting records that disclose with reasonable accuracy the financial position of the Company and of the Group and that enable them to ensure that the Financial statements and the Directors’ Remuneration report comply with the Act and, as regards the Group Financial statements, Article 4 of the International Accounting Standard Regulation.

The Directors have general responsibility for taking such steps as are reasonably open to them to safeguard the assets of BG Group and to prevent and detect fraud and other irregularities, and have adopted a control framework for application across the Group.

The Directors, having prepared the Financial statements, have asked the auditor to take whatever steps, and to undertake whatever inspections, they consider to be appropriate for the purposes of enabling them to give their audit report.

A copy of the Financial statements of the Company is placed on the Shell website. The work carried out by the auditor does not involve consideration of the maintenance of the Shell website and, accordingly, the auditor accepts no responsibility for any changes that may have occurred to the Financial statements since they were initially presented on the website.

Legislation in the UK governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

STATEMENT OF DISCLOSURE OF INFORMATION TO AUDITORSAs required by Sections 418 and 419 of the Act, each of the Directors has approved this report and confirmed that, so far as they are aware, there is no relevant audit information (being information needed by the auditor in connection with preparing their audit report) of which the Company’s auditor is unaware, and they have taken all the steps that they ought to have taken as a Director in order to make themselves aware of any relevant audit information and to establish that the Company’s auditor is aware of that information.

GOING CONCERNBG Group’s business activities, together with factors likely to affect its future development, performance and position, are set out in the Strategic report on pages 2 to 16. The financial position of the Group, its cash flows, liquidity position and borrowing facilities, as well as the Group’s objectives, policies and processes for managing capital, are described on pages 11 to 13. Financial risk management objectives, details of financial instruments and hedging activities, and exposures to credit risk and liquidity risk are described in note 17, pages 60 to 66. The Directors consider that the Group’s business activities and financial resources ensure that it is well placed to manage its business risks successfully.

The Directors are satisfied that it is appropriate to continue to adopt a going concern basis in the preparation of the Financial statements.

By order of the Board

SIMON HENRY DIRECTOR 1 June 2016

Registered office: 100 Thames Valley Park Drive, Reading, Berkshire RG6 1PT, United Kingdom

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Corporate governance Disclosure statement

We have audited the Financial statements of BG Group Limited for the year ended 31 December 2015 which comprise the Consolidated income statement, the Consolidated statement of comprehensive income, the Consolidated and parent Company balance sheets, the Consolidated and parent Company statements of changes in equity, the Consolidated and parent Company cash flow statements and the Principal accounting policies and the related notes 1 to 26. The financial reporting framework that has been applied in their preparation is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union and, as regards the parent Company Financial statements, as applied in accordance with the provisions of the Companies Act 2006.

This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company’s members as a body, for our audit work, for this report, or for the opinions we have formed.

RESPECTIVE RESPONSIBILITIES OF DIRECTORS AND AUDITORAs explained more fully in the Directors’ Responsibilities Statement set out on page 30, the directors are responsible for the preparation of the Financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the Financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.

SCOPE OF THE AUDIT OF THE FINANCIAL STATEMENTSAn audit involves obtaining evidence about the amounts and disclosures in the Financial statements sufficient to give reasonable assurance that the Financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the Group’s and the parent Company’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the directors; and the overall presentation of the Financial statements. In addition, we read all the financial and non-financial information in the Annual Report to identify material inconsistencies with the audited Financial statements and to identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.

OPINION ON FINANCIAL STATEMENTSIn our opinion:

● the Financial statements give a true and fair view of the state of the Group’s and of the parent Company’s affairs as at 31 December 2015 and of the Group’s profit for the year then ended;

● the Group Financial statements have been properly prepared in accordance with IFRSs as adopted by the European Union;

● the parent Company Financial statements have been properly prepared in accordance with IFRSs as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006; and

● the Financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and as regards the Group Financial statements, Article 4 of the IAS Regulation.

OPINION ON OTHER MATTER PRESCRIBED BY THE COMPANIES ACT 2006In our opinion:

● the information given in the Strategic report and the Directors’ report for the financial year for which the Financial statements are prepared is consistent with the financial statements; and

● the part of the Directors’ Remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006.

MATTERS ON WHICH WE ARE REQUIRED TO REPORT BY EXCEPTIONWe have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:

● adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not been received from branches not visited by us; or

● the parent Company Financial statements and the part of the Directors’ Remuneration report to be audited are not in agreement with the accounting records and returns; or

● certain disclosures of directors’ remuneration specified by law are not made; or

● we have not received all the information and explanations we require for our audit.

GARY DONALD (SENIOR STATUTORY AUDITOR)for and on behalf of Ernst & Young LLP, Statutory Auditor

London

1 June 2016

Notes:

(a) The maintenance and integrity of the Royal Dutch Shell plc web site is the responsibility of the directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site.

(b) Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

Financial statementsIndependent auditor’s report to the member of BG Group Limited

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Financial statementsPrincipal accounting policies

Reserves, commodity prices, impairment and depreciationOne factor that affects the calculation of depreciation and impairment in particular is the estimation of hydrocarbon reserves and resources. BG Group’s estimates of reserves and resources of gas and oil are reviewed and, where appropriate, updated quarterly. They are also subject to periodic review by external petroleum engineers. A number of factors impact on the amount of gas and oil reserves and resources, including the available reservoir data, commodity prices and future costs, and the amount is subject to periodic revision as these factors change.

BG Group estimates that a 1% change throughout 2015 in the estimation of proved, proved developed and proved plus probable reserves associated with producing fields would have changed the 2015 depreciation charge by $25 million.

In 2015, the Group recognised a non-cash pre-tax impairment charge of $1 452 million (post-tax $691 million) primarily reflecting the impact of further falls in commodity prices and reserves revisions on certain of the Group’s E&P assets, mainly in the North Sea and Tunisia. In the North Sea, the pre-tax impairment charge was $787 million (post-tax $307 million), driven by lower commodity prices, a reserves downgrade reflecting underlying reservoir performance, and higher decommissioning costs on certain fields. In Tunisia, the pre-tax impairment charge was $534 million (post-tax $307 million), driven by lower commodity prices and a reserves downgrade reflecting reservoir performance. Elsewhere, the reduction in the Group’s assumptions of future commodity prices resulted in pre-tax impairment charges of $131 million (post-tax $77 million) in relation to certain other E&P assets.

Egypt receivablesAs at 31 December 2015, the amount owed by Egypt General Petroleum Corporation (EGPC) in respect of domestic gas sales was $1.1 billion (2014: $0.9 billion), of which $0.9 billion (2014: $0.7 billion) was overdue. The Group considers that the current receivable balance remains fully recoverable as cash payments from EGPC continue to be received, however, in 2015, a $50 million pre- and post-tax charge was recognised relating to the downward re-measurement of the receivable balance to reflect the time value of money associated with the outstanding debt based on a revised assumed repayment profile. This increases the total discount recognised to $150 million following the $100 million pre-tax charge ($79 million post-tax) recorded in 2014. The net amount after this remeasurement is $0.9 billion (2014: $0.8 billion). Discussions continue with the Egyptian government regarding potential future gas development programmes, subject to the negotiation of a higher domestic gas price and resolution of the outstanding receivables.

Exploration expenditureExpenditure on unproved gas and oil reserves within intangible assets is reviewed at least annually to confirm the Group’s continued right and intent to explore, develop or otherwise realise value from these assets. As at 31 December 2015 BG Group held a balance of $3 141 million (2014: $3 014 million) relating to expenditure on unproved gas and oil reserves within intangible assets. Capitalised exploratory well costs included within this total amounted to $2 570 million (2014: $2 525 million). Unsuccessful exploration expenditure written off to the income statement in 2015 was $363 million (2014: $237 million). Capitalised exploratory well costs relate to areas where further work is being undertaken on geological and geophysical assessment, development design and commercial arrangements.

Decommissioning costsThe recognition and measurement of decommissioning provisions involves the use of estimates and assumptions. These include: the existence of a legal or constructive obligation to decommission, based on current legislation, contractual or regulatory requirements or best practice; the risk-free discount rate used to determine the net present value of the liability; the estimated cost of decommissioning based on internal and external engineering estimates and reports; and the payment dates of expected decommissioning costs which are uncertain and are based on economic assumptions surrounding the useful economic lives of the fields concerned. Actual costs could differ from estimated costs due to changes in legislation, regulations, technology, price levels and the expected date of decommissioning.

On the basis that all other assumptions in the calculation remain the same as at 31 December 2015, a 10% increase in the cost estimates used to assess the final decommissioning obligations would result in an increase to the decommissioning provision of circa $450 million, and a 1% increase in the discount rate would result in a decrease to the decommissioning provision of circa $800 million. These changes would be principally offset by a change in the value of the associated asset, resulting in no material change to the consolidated net assets.

BASIS OF PREPARATIONThe Financial statements for the year ended 31 December 2015 have been prepared in accordance with International Financial Reporting Standards (IFRS), and IFRS Interpretations Committee (IFRIC) interpretations as adopted by the European Union. In addition, the Financial statements have been prepared in accordance with those parts of the Companies Act 2006 applicable to companies reporting under IFRS. The Financial statements have been prepared primarily using historical cost principles except that, as disclosed in the accounting policies below, certain items, including derivatives, are measured at fair value.

BASIS OF CONSOLIDATIONThe Financial statements comprise a consolidation of the accounts of the Company and its subsidiary undertakings and incorporate the results of its share of joint ventures and associates using the equity method of accounting. All inter-company transactions are eliminated on consolidation. Consistent accounting policies have been used to prepare the consolidated Financial statements.

Most of BG Group’s exploration and production (E&P) activity is conducted through joint operations. The Group recognises its own share of the assets, liabilities, revenues, expenses and cash flows associated with these joint operations.

The results of undertakings acquired or disposed of are consolidated from or to the date when control passes to or from the Company.

PRESENTATION OF RESULTSBG Group presents its results in the income statement to separately identify the contribution of disposals, certain re-measurements, impairments and certain other exceptional items in order to provide readers with a clear and consistent presentation of the underlying operating performance of the Group’s ongoing business; see note 1, page 42 and note 8, page 53.

SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATESThe preparation of Financial statements in conformity with IFRS requires management to make judgements and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the Financial statements and the reported revenues and expenses during the reporting period. Actual results could differ from these estimates. BG Group believes that the accounting policies associated with reserves, impairment, depreciation, exploration expenditure, decommissioning costs and tax are the policies where changes in estimates and assumptions could have a significant impact on the Financial statements.

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Financial statementsPrincipal accounting policies > continued

Depreciation and amortisationFreehold land is not depreciated. Other property, plant and equipment, except exploration and production assets, is depreciated on a straight-line basis at rates sufficient to write off the historical cost less residual value of individual assets over their estimated useful economic lives. Asset lives and residual values are reassessed annually.

The depreciation periods for the principal categories of assets are as follows:

Freehold and leasehold buildings up to 50 years

Plant and machinery 5 to 40 years

Motor vehicles and office equipment up to 10 years

Exploration and production assets associated with conventional activities are depreciated from the commencement of commercial production in the fields concerned, using the unit of production method based on the proved developed reserves of those fields, except that a basis of total proved reserves is used for acquired interests and for facilities.

Exploration and production assets associated with unconventional activities, including coal seam and shale gas, are depreciated from the commencement of commercial production in the fields concerned, using the unit of production method based on proved plus probable reserves, together with the estimated future development expenditure required to develop those reserves.

Intangible assets in respect of contractual rights are recognised at cost less amortisation. They are amortised on a straight-line basis over the term of the related contract.

Changes in depreciation and amortisation estimates are dealt with prospectively.

Decommissioning costsWhere a legal or constructive obligation has been incurred, provision is made for the net present value of the estimated cost of decommissioning at the end of the producing lives of assets.

When this provision gives access to future economic benefits, an asset is recognised and then subsequently depreciated in line with the life of the underlying producing asset, otherwise the costs are charged to the income statement. The unwinding of the discount on the provision is included in the income statement within finance costs. Any changes to estimated costs or discount rates are dealt with prospectively.

Impairment of non-current assetsNon-current assets subject to depreciation or amortisation are reviewed for impairments whenever events or other changes in circumstances indicate that the carrying amount may not be recoverable. Expenditure on unproved gas and oil reserves is assessed for impairment when facts and circumstances suggest that its carrying amount exceeds its recoverable amount.

Any impairment of non-current assets (excluding financial assets) is calculated as the difference between the carrying values of cash-generating units (including associated goodwill) and their recoverable amount, being the higher of the estimated value in use or fair value less costs of disposal at the date the impairment charge is recognised. Value in use represents the net present value of expected future cash flows discounted on a pre-tax basis. Fair value less costs of disposal is

based on the best evidence available to the Group, and may include appropriate valuation techniques, market data or sales of comparable assets.

For the purposes of impairment testing, exploration and production assets may be aggregated into appropriate cash-generating units based on considerations including geographical location, the use of common facilities and marketing arrangements.

Financial instrumentsDerivative financial instruments are initially recognised and subsequently re-measured at fair value.

Derivative financial instruments utilised by BG Group’s treasury operations include interest rate swaps, foreign currency swaps, cross-currency interest rate swaps, forward rate agreements and forward exchange contracts.

Certain derivative financial instruments are designated as hedges in line with the Group’s risk management policies. Gains and losses arising from the re-measurement of these financial instruments are either recognised in the income statement or deferred in other comprehensive income depending on the type of hedging relationship. When a hedging instrument is sold or expires, any cumulative gain or loss previously recognised in other comprehensive income remains in other comprehensive income until the hedged transaction is recognised in the income statement or is no longer expected to occur. Movements in the fair value of derivative financial instruments not included in hedging relationships are recognised in the income statement.

Loans held by the Group are initially measured at fair value and subsequently carried at amortised cost, except where they form the underlying transaction in an effective fair value hedge relationship when the carrying value is adjusted to reflect fair value movements associated with the hedged risks. Such adjustments are reported in the income statement.

Other financial instruments such as receivable balances are measured at amortised cost less impairments.

Commodity instrumentsWithin the ordinary course of business BG Group routinely enters into sale and purchase transactions for commodities. The majority of these transactions take the form of contracts that were entered into and continue to be held for the purpose of receipt or delivery of the commodity in accordance with the Group’s expected sale, purchase or usage requirements. Such contracts are not within the scope of IAS 39.

Certain commodity contracts have pricing terms that bring them into the scope of IAS 39. In addition, commodity instruments are used to manage certain price exposures in respect of optimising the timing and location of physical gas, LNG and oil commitments. These contracts are recognised on the balance sheet at fair value with movements in fair value recognised in the income statement.

The Group uses various commodity-based derivative instruments to manage some of the risks arising from fluctuations in commodity prices. Such contracts include physical and net-settled forwards, futures, swaps and options. Where these derivatives have been designated as cash flow hedges of underlying commodity price exposures, certain

Current and deferred taxBG Group is subject to income taxes in numerous jurisdictions. There are transactions and calculations for which the ultimate tax determination is uncertain. The Group periodically evaluates situations in which applicable tax regulation is subject to interpretation and establishes provisions where appropriate based on amounts expected to be paid to the tax authorities. In estimating these provisions, consideration is taken of the strength of the technical arguments, the local statute of limitations, likely scope for double tax relief, and whether penalties and interest could apply.

Deferred tax assets are recognised for deductible temporary differences, unutilised tax losses and unused tax credits to the extent that realisation of the related tax benefit through future taxable income is probable. To determine the future taxable income, reference is made to the latest available profit forecasts. This requires assumptions regarding future profitability and is therefore inherently uncertain. Significant items where the Group has relied on estimates of future taxable income include a deferred tax asset in respect of the US tax group amounting to $1 266 million (2014: $1 298 million) and a deferred tax asset relating to the Australian tax group amounting to $698 million (2014: $2 167 million).

SIGNIFICANT ACCOUNTING POLICIESExploration expenditureBG Group uses the ‘successful efforts’ method of accounting for exploration expenditure.

Exploration expenditure, including licence acquisition costs, is capitalised as an intangible asset when incurred and certain expenditure, such as geological and geophysical exploration costs, is expensed. A review of each licence or field is carried out, at least annually, to ascertain whether commercial reserves have been discovered.

For conventional E&P activities, intangible exploration and appraisal expenditure is reclassified to property, plant and equipment on the determination of proved reserves. This is the point when exploration and appraisal activities become a development project and reflects the importance of individual well performance and reserves to conventional E&P projects. By comparison, unconventional coal seam and shale gas activities have a relatively short exploration and appraisal phase and are more focused on the average deliverability of a large number of wells over an entire licence area rather than the performance and reserves associated with individual wells. Accordingly, BG Group uses the determination of proved plus probable reserves as the point at which exploration and appraisal expenditure on unconventional E&P activities is reclassified to property, plant and equipment. This approach is consistent with the methodology used to depreciate assets associated with these activities.

Exploration expenditure transferred to property, plant and equipment is subsequently depreciated on a unit of production basis. Exploration expenditure deemed to be unsuccessful is written off to the income statement.

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OTHER ACCOUNTING POLICIESProperty, plant and equipment excluding decommissioning assetsAll property, plant and equipment is carried at depreciated historical cost. Additions represent new, or replacements of specific components of property, plant and equipment. Finance costs associated with borrowings used to finance major capital projects are capitalised up to the point at which the asset is ready for its intended use.

InventoriesInventories, including inventories of gas, LNG and oil held for sale in the ordinary course of business, are stated at weighted average historical cost less provision for deterioration and obsolescence or, if lower, net realisable value.

Foreign currenciesThe currency in which the Group presents its consolidated and parent Company Financial statements is US Dollars. The functional currency of the Company is Pounds Sterling. The exchange rates of US Dollar to Pound Sterling over the periods included in this Annual Report and Accounts are as follows:

US$/UK£ exchange rate 2015 2014 2013 2012 2011

Closing rate 1.4739 1.5593 1.6563 1.6255 1.5541

Average rate 1.5322 1.6545 1.5640 1.5848 1.6079

On consolidation, assets and liabilities denominated in currencies other than US Dollars are translated into US Dollars at closing rates of exchange. Non-US Dollar trading results of the parent Company, subsidiary undertakings, jointly controlled entities and associates are translated into US Dollars at average rates of exchange. Differences resulting from the retranslation of the opening net assets and the results for the year are recognised in other comprehensive income.

Any differences arising from 1 January 2003, the date of transition to IFRS, are presented as a separate component of equity.

Share capital, share premium and other reserves are translated into US Dollars at the historical rates prevailing at the date of the transaction.

Exchange differences on monetary assets and liabilities arising in individual entities are taken to the income statement, including those in respect of inter-company balances unless related to exchange differences on items that form part of a net investment in a foreign operation. These differences are taken to reserves until the related investment is disposed of. All other exchange movements are dealt with through the income statement.

LeasesAssets held under finance leases are capitalised and included in property, plant and equipment at the lower of fair value and the present value of the minimum lease payments as determined at the inception of the lease. The obligations relating to finance leases, net of finance charges in respect of future periods, are determined at the inception of the lease and included within borrowings. The interest element of the rental obligation is allocated to accounting periods during the lease term to reflect the constant rate of interest on the remaining balance of the obligation for each accounting period.

BG Group has certain long-term arrangements under which it has acquired all of the capacity of certain property, plant and equipment. In circumstances where it is considered that the Group has the majority of the risks and rewards of ownership of the plant, the arrangement is considered to contain a finance lease.

Rentals under operating leases are charged to the income statement on a straight-line basis over the lease term.

PensionsThe amount recognised on the balance sheet in respect of liabilities for defined benefit pension and post-retirement benefit plans represents the present value of the obligations offset by the fair value of plan assets.

The cost of providing retirement pensions and related benefits is charged to the income statement over the periods benefiting from the employees’ services. Current service costs are reflected in operating profit and net interest costs are reflected in finance costs in the period in which they arise. Actuarial gains and losses are recognised in full as they occur in other comprehensive income.

Contributions made to defined contribution pension plans are charged to the income statement when payable.

A surplus in a plan is recognised as an asset to the extent that it is considered recoverable.

Share-based paymentsThe cost of providing share-based payments to employees is charged to the income statement over the vesting period of the related share options or share allocations. The cost is based on the fair value of the options or shares allocated and the number of awards expected to vest. The fair value of each option or share is determined using either the share price on the date of the grant or a Monte Carlo projection model, depending on the type of award. Market-related performance conditions are reflected in the fair value of the share. Non-market-related performance conditions are allowed for using a separate assumption about the number of awards expected to vest; the final charge made reflects the number actually vesting.

gains and losses attributable to these instruments are deferred in other comprehensive income and recognised in the income statement when the underlying hedged transaction crystallises or is no longer expected to occur.

All other commodity contracts within the scope of IAS 39 are measured at fair value with gains and losses taken to the income statement. Gas and oil contracts and related derivative instruments associated with the physical purchase and re-sale of third-party gas and oil are presented on a net basis within other operating income.

Revenue recognitionRevenue associated with E&P sales (of natural gas, crude oil and petroleum products) is recorded when title passes to the customer. Revenue from the production of natural gas and oil in which BG Group has an interest with other producers is recognised based on the Group’s working interest and the terms of the relevant production sharing contracts (entitlement method).

Sales of LNG and associated products are recognised when title passes to the customer. LNG shipping revenue is recognised over the period of the relevant contract.

All other revenue is recognised when title passes to the customer.

Current and deferred income taxThe tax expense for the period comprises current and deferred tax, determined using currently enacted or substantively enacted tax laws.

Deferred income tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Financial statements. Deferred tax assets are recognised to the extent that it is probable that future taxable profit will be available, against which the temporary differences can be utilised.

Deferred income tax is provided on temporary differences arising on investments in subsidiaries, joint ventures and associates, except where the timing of the reversal of the temporary difference can be controlled and it is probable that the temporary difference will not reverse in the foreseeable future.

34


ACCOUNTING DEVELOPMENTS DURING 2015A number of amendments to accounting standards issued by the IASB are applicable from 1 January 2015. They have not had a material impact on the Group’s Financial statements for the year ended 31 December 2015.

ACCOUNTING DEVELOPMENTS NOT YET ADOPTEDThe following standards and amendments have been issued by the IASB up to the date of this report and in some cases have not yet been endorsed by the European Union.

IFRS 9 ‘Financial Instruments’The IASB issued the final version of IFRS 9 in July 2014, which reflects all phases of the financial instruments project. IFRS 9 introduces new requirements for the classification, measurement and impairment of financial instruments and hedge accounting, and is required to be adopted by 2018. BG Group is reviewing the standard to determine the likely impact.

IFRS 15 ‘Revenue from Contracts with Customers’The IASB issued IFRS 15 in May 2014. The standard establishes a five-step model that will apply to revenue arising from contracts with customers. Revenue is recognised when a customer obtains control of a good or service and thus has the ability to direct the use and obtain the benefits from the good or service. Revenue is recognised based on the consideration to which the Group expects to be entitled. IFRS 15 is required to be adopted by 2018. BG Group is reviewing the standard to determine the likely impact.

IFRS 16 ‘Leases’The IASB issued IFRS 16 in January 2016. The standard requires lessees to recognise a lease liability and a right of use asset for all leases unless the lease term is 12 months or less or the underlying asset has a low value. Interest expense on the lease liability and depreciation on the right of use asset will be recognised in the income statement, resulting in a higher total charge to profit or loss in the initial years of a lease. IFRS 16 is required to be adopted by 2019. BG Group is reviewing the standard to determine the likely impact.

Amendment to IFRS 11 ‘Joint Arrangements’The IASB issued an amended IFRS 11 in May 2014. The amendment requires an acquisition of an interest in a joint operation that is a business as defined in IFRS 3, ‘Business Combinations’, to apply the relevant IFRS 3 principles for business combinations accounting, and applies to both the acquisition of an initial interest in a joint operation and the acquisition of any additional interest. The amendment is required to be applied prospectively from 2016.

Other revisions and amendmentsOther revisions and amendments are not expected to have a material impact.


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Financial statementsConsolidated income statement

for the year ended 31 December

Note

2015 2014

Business Performance

$m

Disposals, re-measurements and impairments

$mTotal

$m

Business Performance

$m

Disposals, re-measurements and impairments

$mTotal

$m

Group revenue 1 16 148 – 16 148 19 289 – 19 289

Other operating income 1, 4 271 (117) 154 257 403 660

Group revenue and other operating income 1 16 419 (117) 16 302 19 546 403 19 949

Operating costs 2, 4 (14 196) (53) (14 249) (13 391) (181) (13 572)

Profits and losses on disposal of non-current assets and impairments 4 – 959 959 – (8 120) (8 120)

Share of post-tax results from joint ventures and associates 1 206 (45) 161 222 (56) 166

Operating profit/(loss) before interest and tax (EBIT) 1 2 429 744 3 173 6 377 (7 954) (1 577)

Finance income 4, 5 107 278 385 153 – 153

Finance costs 4, 5 (367) (220) (587) (262) (644) (906)

Profit/(loss) before taxation 2 169 802 2 971 6 268 (8 598) (2 330)

Taxation 4, 6 (472) (171) (643) (2 233) 3 512 1 279

Profit/(loss) for the year from continuing operations 1, 4 1 697 631 2 328 4 035 (5 086) (1 051)

Profit/(loss) for the year from discontinued operations – 6 6 – 7 7

Profit/(loss) for the year attributable to Shareholders (earnings) 1 697 637 2 334 4 035 (5 079) (1 044)

Earnings per ordinary share continuing operations (cents)

Basic 8 49.7 18.5 68.2 118.4 (149.2) (30.8)

Diluted 8 49.5 18.4 67.9 118.4 (149.2) (30.8)

Earnings per ordinary share discontinued operations (cents)

Basic – 0.2 0.2 – 0.2 0.2

Diluted – 0.2 0.2 – 0.2 0.2

Total earnings per ordinary share (cents)

Basic 49.7 18.7 68.4 118.4 (149.0) (30.6)

Diluted 49.5 18.6 68.1 118.4 (149.0) (30.6)

For information on dividends paid and proposed in the year see note 7, page 53.

The accounting policies on pages 32 to 35 together with the notes on pages 42 to 78 form part of these accounts.

36


Financial statementsConsolidated statement of comprehensive income

for the year ended 31 December 2015$m

2014$m

Profit/(loss) for the year 2 334 (1 044)

Items that may be reclassified to the income statement:

Fair value losses on cash flow hedges – (71)

Transfers to income statement on cash flow hedges (2) 33

Fair value losses on net investment hedges (867) (574)

Fair value movements on available-for-sale assets (4) (17)

Tax on cash flow and net investment hedges(a) 156 125

Currency translation adjustments(b) (127) (223)

Other items:

Re-measurement of defined benefit pension obligation 21 (163)

Tax on re-measurement of defined benefit pension obligation (6) 45

Other comprehensive income/(charge) for the year, net of tax(c) (829) (845)

Total comprehensive income/(charge) for the year attributable to Shareholders 1 505 (1 889)

(a) Includes tax relating to cash flow hedges of $nil (2014: $9m credit) and a tax credit relating to net investment hedges of $156m (2014: $116m).(b) In 2015, $405m charge (2014: $nil) was transferred to the income statement as part of the profit on disposal of non-US Dollar denominated operations.(c) Includes a charge in other comprehensive income in respect of joint ventures and associates of $28m (2014: $29m).

The result for the financial year for the Company was $nil (2014: $(6)m loss). Total comprehensive charge for the Company was $292m (2014: $361m). As permitted by section 408 of the Companies Act 2006, no income statement or statement of comprehensive income is presented for the Company.


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Financial statementsBalance sheets

Note

The Group The Company

as at 31 December 2015$m

2014$m

2015$m

2014$m

Assets

Non-current assets

Intangible assets 10 3 253 3 135 – –

Property, plant and equipment 11 35 256 35 855 – –

Investments in subsidiary undertakings 12 – – 3 940 4 104

Investments 12 4 308 3 547 – –

Deferred tax assets 6 2 844 3 949 5 2

Trade and other receivables 14 1 282 1 068 – –

Retirement benefit surplus 23 205 – –

Commodity contracts and other derivative financial instruments 17 164 287 – –

47 312 47 841 3 945 4 106

Current assets

Inventories 13 1 117 1 194 – –

Trade and other receivables 14 3 667 5 042 784 1 786

Current tax receivable 213 151 8 35

Commodity contracts and other derivative financial instruments 17 167 235 – –

Cash and cash equivalents 15 7 200 5 295 – –

12 364 11 917 792 1 821

Assets classified as held for sale 24 – 2 088 – –

Total assets 59 676 61 846 4 737 5 927

Liabilities

Current liabilities

Borrowings 16 (1 268) (1 586) – –

Trade and other payables 18 (3 775) (4 768) (34) (48)

Current tax liabilities (832) (1 412) – –

Commodity contracts and other derivative financial instruments 17 (141) (128) – –

(6 016) (7 894) (34) (48)

Non-current liabilities

Borrowings 16 (15 473) (15 921) – –

Trade and other payables 18 (184) (136) – –

Commodity contracts and other derivative financial instruments 17 (846) (253) – –

Deferred tax liabilities 6 (2 111) (2 946) – –

Retirement benefit obligations 23 (69) (258) – –

Provisions for other liabilities and charges 19 (5 220) (5 235) – –

(23 903) (24 749) – –

Liabilities associated with assets classified as held for sale 24 – (63) – –

Total liabilities (29 919) (32 706) (34) (48)

Net assets 29 757 29 140 4 703 5 879


38


Financial statementsBalance sheets > continued

Note



2014$m

2015$m

2014$m

EquityOrdinary shares 20 580 579 580 579Share premium 707 691 707 691Hedging reserve (9) (7) – –Translation reserve (2 305) (1 467) (515) (223)Other reserves 2 710 2 710 1 203 1 203Retained earnings 28 074 26 634 2 728 3 629

Total equity 29 757 29 140 4 703 5 879

The accounts on pages 32 to 78 were approved by the Board and signed on its behalf on 1 June 2016 by:

SIMON HENRYDIRECTOR


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Financial statementsStatements of changes in equity

The GroupCalled up

share capital$m

Share premium

account$m

Hedging reserve

$m

Translationreserve(a)

$m

Otherreserves(b)

$m

Retainedearnings(c)

$mTotal

$m

As at 1 January 2014 579 663 22 (786) 2 710 28 772 31 960

Total comprehensive income for the year – – (29) (681) – (1 179) (1 889)

Loss for the year – – – – – (1 044) (1 044)

Hedges, net of tax – – (29) (458) – – (487)

Available-for-sale assets, net of tax – – – – – (17) (17)

Defined benefit pension obligation, net of tax – – – – – (118) (118)

Currency translation adjustments, net of tax – – – (223) – – (223)

Adjustment for share schemes – – – – – 71 71

Tax in respect of share schemes(d) – – – – – (3) (3)

Dividends – – – – – (1 027) (1 027)

Issue of shares(e) – 28 – – – – 28

As at 31 December 2014 579 691 (7) (1 467) 2 710 26 634 29 140

Total comprehensive income for the year – – (2) (838) – 2 345 1 505

Profit for the year – – – – – 2 334 2 334

Hedges, net of tax – – (2) (711) – – (713)

Available-for-sale assets, net of tax – – – – – (4) (4)

Defined benefit pension obligation, net of tax – – – – – 15 15

Currency translation adjustments – – – (127) – – (127)


Tax in respect of share schemes(d) – – – – – 1 1

Dividends – – – – – (982) (982)

Issue of shares(e) 1 16 – – – – 17

As at 31 December 2015 580 707 (9) (2 305) 2 710 28 074 29 757

The CompanyCalled up

share capital$m

Share premium

account$m

Hedging reserve

$m

Translation reserve

$m

Otherreserves(b)

$m

Retainedearnings

$mTotal

$m

As at 1 January 2014 579 663 – 132 1 203 4 598 7 175

Total comprehensive income for the year(f) – – – (355) – (6) (361)


Tax in respect of share schemes(d) – – – – – (7) (7)

Dividends – – – – – (1 027) (1 027)

Issue of shares(e) – 28 – – – – 28

As at 31 December 2014 579 691 – (223) 1 203 3 629 5 879

Total comprehensive income for the year(f) – – – (292) – – (292)


Tax in respect of share schemes(d) – – – – – 5 5

Dividends – – – – – (982) (982)

Issue of shares(e) 1 16 – – – – 17

As at 31 December 2015 580 707 – (515) 1 203 2 728 4 703

(a) As at 31 December 2015, includes currency translation losses of $37m (2014: $9m losses) relating to joint ventures and associates.(b) Other reserves, which are not distributable, represent the difference between the carrying value of subsidiary undertaking investments and their respective capital structures following

the restructuring and refinancing in 1999.(c) As at 31 December 2015, includes retained earnings in respect of joint ventures and associates of $704m (2014: $660m).(d) This consists of current tax of $1m (2014: $5m) and deferred tax of $nil (2014: $(8)m) in the Group and deferred tax of $5m (2014: $(7)m) in the Company.(e) The issue of shares relates to amounts issued to employees under employee share option schemes for a cash consideration of $17m (2014: $28m).(f) Comprises result for the year of $nil (2014: $(6)m loss) and currency translation adjustments of $(292)m (2014: $(355)m).


40


Financial statementsCash flow statements

Note



2014$m

2015$m

2014$m

Profit/(loss) before taxation(a) 2 977 (2 321) 1 (1)

Finance income (386) (153) (8) (13)

Finance costs 587 906 – –

Operating profit/(loss) before interest and tax 3 178 (1 568) (7) (14)

Share of post-tax results from joint ventures and associates (161) (166) – –

Depreciation of property, plant and equipment 3 194 2 788 – –

Amortisation of other intangible assets 10 11 – –

Share-based payments 69 62 12 3

Fair value movements in commodity-based contracts 22 (354) – –

Profits and losses on disposal of non-current assets and impairments(b) (955) 8 120 (6) –

Unsuccessful exploration expenditure written off 363 237 – –

Decrease in provisions for liabilities and retirement benefit obligations (568) (94) – –

Movements in working capital:

Decrease/(increase) in inventories 53 (272) – –

Decrease in trade and other receivables 472 993 – –

(Decrease)/increase in trade and other payables (355) 258 – –

Cash generated/(used) by operations 5 322 10 015 (1) (11)

Income taxes (paid)/received (1 019) (2 616) 28 8

Net cash inflow/(outflow) from operating activities 4 303 7 399 27 (3)

Cash flows from investing activities

Dividends received 131 179 – –

Proceeds from disposal of subsidiary undertakings and investments(c) 4 606 800 – –

Proceeds from disposal of property, plant and equipment and intangible assets(d) 580 55 – –

Purchase of property, plant and equipment and intangible assets (5 596) (8 510) – –

Repayments from joint ventures and associates – 41 – –

Interests in subsidiaries, joint ventures and associates, and other investments (791) (892) – –

Other loan repayments 130 111 – –

Net cash outflow from investing activities (940) (8 216) – –

Cash flows from financing activities

Interest paid (655) (620) – –

Interest received 70 64 – –

Dividends paid (980) (1 024) (980) (1 024)

Net proceeds from issue of new borrowings 1 614 2 086 – –

Repayment of borrowings (1 559) (625) – –

Issue of shares 17 28 17 28

Funding movements with subsidiary – – 936 999

Net cash (outflow)/inflow from financing activities (1 493) (91) (27) 3

Net increase/(decrease) in cash and cash equivalents 1 870 (908) – –

Cash and cash equivalents at 1 January 15 5 295 6 208 – –

Effect of foreign exchange rate changes 35 (5) – –

Cash and cash equivalents at 31 December 15 7 200 5 295 – –

(a) Profit before taxation from discontinued operations was $6m (2014: $9m).(b) Excludes $4m cash receipts recognised in profits and losses on disposal of non-current assets and impairments in the Income Statement.(c) 2015 includes proceeds from the disposal of the QCLNG pipeline of $4 597m. 2014 includes proceeds from the sale of the Central Area Transmission System pipeline and associated infrastructure in the

UK North Sea of $797m.(d) 2015 includes proceeds of $460m from the sale and lease back of LNG ships (2014: $53m).

The cash flows above are inclusive of discontinued operations.


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41


Financial statementsNotes to the accounts

1 SEGMENTAL ANALYSIS AND RESULTS PRESENTATIONBG Group’s reportable segments are those used by the Group’s Board and management (the ‘Chief Operating Decision Maker’ as defined in IFRS 8 ‘Operating Segments’) to run the business and are based on differences in the Group’s products and services. Segment information is presented on the same basis as that used for internal reporting purposes. BG Group has two principal operating and reporting segments; Upstream and LNG Shipping & Marketing.

Upstream comprises exploration, development, production, liquefaction and marketing of hydrocarbons. LNG Shipping & Marketing combines the development and use of LNG import facilities with the purchase, shipping and sale of LNG and regasified natural gas. The Group’s transmission and distribution businesses and certain corporate activities are included in the Other activities segment.

In order to simplify disclosures and improve transparency, the Group’s share of joint ventures and associates’ results are now reported separately on a post-tax basis within each segment as part of EBITDA.

Intra-Group sales are settled at market prices and are generally based on the same prices as those charged to third parties (arm’s length principle). Group revenue, profit for the year and capital investment attributable to BG Group activities are shown within this note, analysed by operating segment.

The presentation of BG Group’s results under IFRS separately identifies the effect of the re-measurement of certain financial instruments, profits and losses on the disposal and impairment of non-current assets and certain other exceptional items. Results excluding discontinued operations and disposals, certain re-measurements and impairments and certain other exceptional items (‘Business Performance’) are used by management and are presented in order to provide readers with a clear and consistent presentation of the underlying operating performance of the Group’s ongoing business. Further information on Business Performance is given on page 79.

The disposals, re-measurements and impairments column includes unrealised gains and losses in respect of certain gas sales contracts classified as derivatives under IAS 39, commodity instruments that represent economic hedges but do not qualify for hedge accounting, and financial instruments used to manage foreign exchange and interest rate exposure. Where these instruments represent economic hedges but cannot be designated as hedges under IAS 39, unrealised movements in fair value, together with foreign exchange movements associated with the underlying borrowings and foreign exchange movements in respect of certain inter-company balances, are recorded in the income statement and disclosed separately as ‘disposals, re-measurements and impairments’. The separate presentation of these items best reflects the underlying performance of the business since it distinguishes between the temporary timing differences associated with re-measurements under IAS 39 rules and actual realised gains and losses.

Reconciliations between the Total Results and Business Performance are provided on page 43. The geographical information provided for external revenue is based on country of production.

GROUP REVENUEAnalysed by operating segment

External revenue Intra-Group revenue Total Group revenue


2014$m

2015$m

2014$m

2015$m

2014$m

Group revenue(a)

Upstream 8 012 11 161 1 713 701 9 725 11 862

LNG Shipping & Marketing 8 132 8 121 3 3 8 135 8 124

Other activities 4 7 – – 4 7

Segmental revenue 16 148 19 289 1 716 704 17 864 19 993

Less: Intra-Group revenue – – (1 716) (704) (1 716) (704)

Group revenue 16 148 19 289 – – 16 148 19 289

(a) External revenue attributable to the UK is $1 725m (2014: $3 168m). External revenue attributable to non-UK countries is $14 423m (2014: $16 121m). Included in the Upstream segment is external revenue of $2 454m attributable to Brazil representing 15% of Group external revenue (2014: $2 441m, 13%). LNG Shipping & Marketing revenues are not considered reliant on individual countries since they are associated with the global deployment of the Group’s portfolio of flexible LNG supplies. External revenue from the largest single customer amounted to $2 177m representing 13% of Group revenue and is included within both LNG and Upstream segments. In 2014 no single customer had external revenue exceeding 10% of Group revenue.

42


43Financial statementsNotes to the accounts > continued

1 SEGMENTAL ANALYSIS AND RESULTS PRESENTATION CONTINUEDPROFIT FOR THE YEARAnalysed by operating segment

Business PerformanceDisposals, re-measurements

and impairments Total


2014$m

2015$m

2014$m

2015$m

2014$m

Group revenue 16 148 19 289 – – 16 148 19 289

Other operating income(a)(b) 271 257 (117) 403 154 660

Group revenue and other operating income 16 419 19 546 (117) 403 16 302 19 949

EBITDA

Upstream 4 167 6 453 906 (8 238) 5 073 (1 785)

LNG Shipping & Marketing 1 456 2 683 (177) 205 1 279 2 888

Other activities 10 40 15 79 25 119

5 633 9 176 744 (7 954) 6 377 1 222

DD&A

Upstream (3 092) (2 652) – – (3 092) (2 652)

LNG Shipping & Marketing (108) (143) – – (108) (143)

Other activities (4) (4) – – (4) (4)

(3 204) (2 799) – – (3 204) (2 799)

Operating profit/(loss) before interest and tax (EBIT)

Upstream 1 075 3 801 906 (8 238) 1 981 (4 437)

LNG Shipping & Marketing 1 348 2 540 (177) 205 1 171 2 745

Other activities 6 36 15 79 21 115

2 429 6 377 744 (7 954) 3 173 (1 577)

Net finance (costs)/income

Finance income 107 153 278 – 385 153

Finance costs (367) (262) (220) (644) (587) (906)

(260) (109) 58 (644) (202) (753)

Taxation

Taxation (472) (2 233) (171) 3 512 (643) 1 279

Profit/(loss) for the year from continuing operations 1 697 4 035 631 (5 086) 2 328 (1 051)

Profit for the year from discontinued operations – – 6 7 6 7

Profit/(loss) for the year attributable to Shareholders 1 697 4 035 637 (5 079) 2 334 (1 044)

(a) Business Performance Other operating income includes gains on the Group’s 2014 oil hedging programme, the results of the purchase and re-sale of third-party gas and income arising from optimisation activities undertaken by the Group’s LNG Shipping & Marketing operations. Information on Disposals, re-measurements and impairments Other operating income is given in note 4, page 49.

(b) Business Performance Other operating income is attributable to segments as follows: Upstream $67m (2014: $164m) and LNG Shipping & Marketing $204m (2014: $93m).

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Financial statementsNotes to the accounts > continued

1 SEGMENTAL ANALYSIS AND RESULTS PRESENTATION CONTINUEDJOINT VENTURES AND ASSOCIATESAnalysed by operating segment

Share of post-tax results from joint ventures and associates


2014$m

Upstream 167 130

LNG Shipping & Marketing (30) 14

Other activities 24 22

161 166

CAPITAL INVESTMENTAnalysed by operating segment

Capital expenditure(a) Capital investment(b)


2014$m

2015$m

2014$m

Upstream 5 894 8 867 6 687 9 759

LNG Shipping & Marketing 10 6 10 6

Other activities – 4 – 4

5 904 8 877 6 697 9 769

(a) Comprises expenditure on property, plant and equipment and other intangible assets.(b) Comprises expenditure on property, plant and equipment, other intangible assets and investments.

At 31 December 2015, the Group’s non-current assets (excluding derivative financial instruments, deferred tax assets, retirement benefit surplus and finance lease receivable) of $43 927m (2014: $43 433m) included an amount attributable to the UK of $4 226m (2014: $5 798m). The amount attributable to non-UK countries was $39 701m (2014: $37 635m) including $16 468m (2014: $16 148m) attributable to Australia representing 37% (2014: 37%) of the Group total and $10 875m (2014: $8 022m) attributable to Brazil representing 25% of the Group total (2014: 18%).

44



2 OPERATING COSTSIncluded within the Group’s operating costs charged to the income statement were the following items:

2015$m

2014$m

Raw materials, consumables and finished goods 3 839 3 552

Employee costs (see note 3(C), page 47) 1 022 1 259

Less: Own work capitalised (169) (340)

Employee costs included within other operating charges below (81) (140)

Employee costs included within net finance costs 1 (7)

773 772

Depreciation and amortisation

Depreciation of Property, plant and equipment 3 194 2 788

Amortisation of Other intangible assets 10 11

3 204 2 799

Other operating charges:

Unsuccessful exploration expenditure written off 363 237

Other exploration expenditure(a) 313 514

Total exploration expenditure 676 751

Operating lease rentals 1 047 701

Research and development 33 90

Net foreign exchange (gains)/losses on operating activities 79 (8)

Other costs(b) 4 598 4 915

Continuing operations total 14 249 13 572

(a) Broadly equivalent to cash flows attributable to operating activities arising from exploration and evaluation.(b) Includes certain E&P lifting, storage, marketing, royalty, tariff and general administration costs.

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2 OPERATING COSTS CONTINUEDAUDITOR’S FEES AND SERVICESErnst & Young LLP has served as BG Group’s independent external auditor for the two-year period ended 31 December 2015.

The following table presents the aggregate fees for professional services and other services rendered by the external auditor to BG Group:

2015$m

2014$m

Fees payable to the Group’s auditor for the audit of both the parent Company and the Group’s Annual Report and Accounts 3.0 2.5

Fees payable to the Group’s auditor and its associates for other services:

The audit of the parent’s subsidiaries 1.9 2.2

Audit related assurance services(a) 1.1 1.1

3.0 3.3

Total fees payable for audit and audit related services 6.0 5.8

Services relating to corporate finance transactions(b) 3.0 –

All other services(c) 0.4 0.4

9.4 6.2

(a) Audit related assurance services includes costs relating to the interim review and regulatory reporting.(b) Services in relation to the Combination with Shell.(c) All other services includes fees billed for attestation services, consultations concerning financial accounting and reporting standards, and other advice.

3 DIRECTORS AND EMPLOYEESA) DIRECTORS’ REMUNERATION

2015$’000

2014$’000

Fees to Non-Executive Directors and Chairman 2 679 2 947

Salaries(a) 3 165 3 834

Benefits(b) 1 704 423

Bonuses(c) 5 413 1 200

Share-based payments(d) 9 603 3 444

Fees and benefits in respect of former Directors – 7

22 564 11 855

(a) Salaries for 2015 include termination payments of $nil (2014: $2 097 000).(b) In addition, in 2015, two Directors (2014: two) received cash in lieu of their pension totalling $950 000 (2014: $521 000).(c) Bonus figures for 2015 represent payments under the Annual Incentive Scheme (AIS) in respect of the 2015 incentive year which will be made in 2016. Bonus figures for 2014 represent payments

under the AIS in respect of the 2014 incentive year which were made in 2015. Bonuses exclude remuneration in the form of mandatorily deferred shares under the Deferred Bonus Plan (DBP) (2015: $nil; 2014: $251 000).

(d) Share-based payments include a charge for mandatorily deferred shares awarded to the Directors under the DBP in respect of the previous incentive years.

For further information please see the Remuneration report on page 18.

B) KEY MANAGEMENT COMPENSATIONDuring 2015, the Group’s governance arrangements were revised and a new Corporate Executive Team (CET) was established, replacing the Executive Management Committee (EMC) and the Group Leadership Team (GLT).

The key management compensation analysed below for 2015 represents amounts in respect of the Directors and the executive officers, defined as members of the EMC and GLT, and subsequently the CET, and the Company Secretary. For 2014, the analysis reflects the Group’s previous governance structure.

2015$’000

2014$’000

Fees to Non-Executive Directors and Chairman 2 679 2 947

Salaries(a) 12 344 11 078

Benefits 2 283 817

Bonuses(b) 11 885 6 952

Pension charge(c) 2 211 2 158

Share-based payments(d) 17 989 14 746

49 391 38 698

(a) Salaries for 2015 include termination payments of $1 670 000 (2014: $3 021 000).(b) Bonus figures for 2015 include payments under the AIS in respect of the 2015 incentive year which will be made in 2016. Bonus figures for 2014 represent payments under the AIS in respect of the

2014 incentive year which were made in 2015. Bonuses for 2014 include remuneration in the form of awards under the VBDP. Bonuses exclude remuneration in the form of mandatorily deferred shares under the DBP (2015: $746 000; 2014: $746 000).

(c) Includes benefits accruing under defined benefit schemes and cash in lieu of pensions.(d) Share-based payments include a charge for mandatorily deferred shares awarded to key management under the DBP in respect of the previous incentive years.

46



3 DIRECTORS AND EMPLOYEES CONTINUEDC) EMPLOYEE COSTS

The Group

2015$m

2014$m

Wages and salaries(a) 678 896

Social security costs 47 69

Pension charge(b) 58 65

Share-based payments (see note 3(E) below) 81 56

Other including incentive schemes(c) 158 173

1 022 1 259

(a) Includes termination payments.(b) The pension charge for the year ended 31 December 2015 includes a $1m credit (2014: $7m charge) which is presented within finance costs (see note 23, page 70).(c) Includes payments under the AIS and remuneration in the form of awards under the VBDP.

In 2015, employee costs of $853m (2014: $919m) were charged to the income statement and $169m (2014: $340m) were capitalised.

D) AVERAGE NUMBER OF EMPLOYEES DURING THE YEAR2015

Number 2014

Number

Upstream 4 419 4 779

LNG Shipping & Marketing 298 364

4 717 5 143

E) SHARE-BASED PAYMENTSThe Group

2015$m

2014$m

Equity-settled share-based payments:

Group Share Awards 44 40

Performance Share Awards 18 15

Other share awards(a) 8 10

70 65

Cash-settled share-based payments 11 (9)

81 56

(a) The charge for other share awards excludes an amount of $6m (2014: $6m) relating to shares and nil-cost options awarded under the VBDP, which was transferred to equity during 2015. This expense was recognised in the income statement during 2014 as part of the AIS charge. The number of awards made was 0.4m (2014: 0.3m).

The 2015 share-based payment charge excludes the effect of accelerated vesting on certain schemes as a consequence of the Combination with Shell, see note 25, page 73.

Group Share AwardsGroup Share Awards under the Group’s Long-Term Incentive Plan (LTIP) will normally vest three years after the date of grant, subject to continued employment and the individual employee’s performance. Awards are in the form of shares (2015: 1.6m shares; 2014: 1.6m shares) or nil-cost options (2015: 1.5m options; 2014: 1.5m options). The costs in respect of these awards are charged to the income statement over the vesting period, based on the fair value of the shares and options at the award date. Dividend equivalents accrue on the award during the vesting period. Accordingly, the fair value of the shares and options awarded is based on the market value of BG Group plc shares on the award date, which was £11.89 per share in 2015 (2014: £12.09 per share).

Performance Share AwardsDetails of Performance Share Awards under the Group’s LTIP are given on pages 21 and 22. Awards are in the form of shares (2015: 1.5m shares; 2014: 0.3m shares) or nil-cost options (2015: 2.3m options; 2014: 2.0m options). The costs in respect of these awards are charged to the income statement over the vesting period, based on the fair value of the shares and options at the award date, adjusted for the probability of market-related performance conditions being achieved. Generally, the fair value of options awarded during the year is estimated using a Monte Carlo projection model with the following assumptions: share price on date of issue of £11.89 (2014: £12.11), exercise price of £nil (2014: £nil), a risk-free rate of 1.30% (2014: 1.20%) and a vesting period of three years (2014: three years). The model also contains assumptions for both the Group and each member of the industry peer group (set out on pages 21 and 22) in respect of volatility, average share price growth and share price correlation. Expected volatility was determined by calculating the historical volatility of the share price over the previous three-year period. Share price correlation was determined by calculating the historical correlation of the share price over the previous three-year period. Average share price growth was determined from historical growth over the previous year. Dividend equivalents accrue on the award during the vesting period. The fair value of the most significant options awarded during the year was £6.66 per share (2014: £4.73 per share).

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3 DIRECTORS AND EMPLOYEES CONTINUEDE) SHARE-BASED PAYMENTS CONTINUEDOther share awardsThe charge for Other share awards includes awards made under the DBP, the Sharesave Plan, the Share Incentive Plan and the Share Award Plan.

The DBP operates in conjunction with the AIS and is described in the Directors’ Remuneration Policy, which can be found in the 2013 Remuneration report and is available upon request at the Company’s registered office. Awards are in the form of nil-cost options (2015: 0.1m options; 2014: 0.3m options). The charge to the income statement in respect of these awards was $1m in 2015 (2014: $3m) and is based on the market value of BG Group plc shares at the award date, which was £8.86 in 2015 (2014: £10.74).

The charge to the income statement in respect of the Sharesave Plan is based on the fair value of the share options at the grant date and the likelihood of allocations vesting under the scheme. The charge was $2m in 2015 (2014: $1m). The fair value of the share options granted is determined using a Black-Scholes option pricing model and was £3.24 in 2015 (2014: £2.10).

In 2015, awards of 0.2m shares (2014: 0.3m shares) were made in conjunction with the Group’s UK Flexible Benefits Plan, an element of the Share Incentive Plan. The charge to the income statement in respect of these awards was $4m in 2015 (2014: $4m) and is based on the market value of BG Group plc shares at the grant date, which was £11.80 in 2015 (2014: £11.34).

The Share Award Plan was an award in 2013 in the form of shares or nil-cost options with a three-year vesting period. In 2015 and 2014, no awards were made under this plan. The charge to the income statement in respect of these awards was $1m in 2015 (2014: $2m). The fair value of the shares and options awarded is based on the market value of BG Group plc shares at the grant date, which was £12.19 in 2013.

Cash-settled share-based paymentsCash-settled share-based payments arise when the Group incurs a liability to transfer cash amounts that are based on the price (or value) of the Company’s shares. Most of the charge in respect of cash-settled share-based payments relates to social security costs on share awards which have not vested or, in the case of share options, have not been exercised. The charge to the income statement is based on the fair value of the awards outstanding at the balance sheet date, multiplied by the current employer’s social security rate.

F) SUMMARY OF MOVEMENTS IN SHARE AWARDS AND SHARE OPTIONS

Share awards under the LTIP

m

Nil-cost options under

the LTIPm

Sharesave Plan options

mCSOS options

m

Other nil-costoptions(a)

m

2014

Outstanding as at 1 January 2014 5.3 12.4 1.4 6.0 1.5

Granted 1.9 3.5 1.0 – 0.5

Vested (1.0) n/a n/a n/a n/a

Exercised n/a (0.9) (0.2) (2.3) (0.2)

Forfeited (1.9) (3.6) (0.3) (0.1) (0.1)

Outstanding as at 31 December 2014 4.3 11.4 1.9 3.6 1.7

Exercisable as at 31 December 2014 n/a 2.2 – 3.6 1.2

Option price range as at 31 December 2014 (£) n/a n/a 8.30–11.10 4.99–7.92 n/a

Weighted average remaining contractual life n/a 8yrs 2mths 2yrs 7mths 1yr 9mths 4yrs 5mths

Option price range for exercised options (£) n/a n/a 8.74–11.10 3.47–7.92 n/a

Weighted average share price at the date of exercise for options exercised in the year (£) n/a 11.82 11.63 11.52 11.89

2015

Outstanding as at 1 January 2015 4.3 11.4 1.9 3.6 1.7

Granted 3.1 3.8 0.6 – 0.5

Vested (1.1) n/a n/a n/a n/a

Exercised n/a (1.0) – (1.4) (0.2)

Forfeited (0.8) (2.9) (0.3) (0.1) –

Outstanding as at 31 December 2015 5.5 11.3 2.2 2.1 2.0

Exercisable as at 31 December 2015 n/a 2.3 – 2.1 0.5

Option price range as at 31 December 2015 (£) n/a n/a 8.30–11.10 6.90–7.92 n/a

Weighted average remaining contractual life n/a 8yrs 11mths 2yrs 3mths 1yr 2mths 4yrs 8mths

Option price range for exercised options (£) n/a n/a 8.30–11.10 4.99–7.92 n/a

Weighted average share price at the date of exercise for options exercised in the year (£) n/a 10.23 10.90 10.28 10.42

(a) Comprises nil-cost options awarded under the DBP, Share Award Plan and VBDP.

G) WEIGHTED AVERAGE EXERCISE PRICE OF SHARE OPTIONS 2015 Sharesave Plan options

£

2015 CSOS options

£

2014 Sharesave Plan options

£

2014 CSOS options

£

Outstanding as at 1 January 8.72 6.82 9.43 6.38

Granted 8.30 – 8.30 –

Exercised 10.25 5.96 10.00 5.69

Forfeited 9.42 6.26 9.64 6.71

Outstanding as at 31 December 8.50 7.43 8.72 6.82

Exercisable as at 31 December n/a 7.43 n/a 6.82

48



4 DISPOSALS, RE-MEASUREMENTS AND IMPAIRMENTSBG Group has separately identified profits and losses related to disposals of non-current assets, certain re-measurements of financial instruments, impairments of non-current assets and certain other exceptional items. A reconciliation of results before and after disposals, re-measurements and impairments is given in note 1, page 42.

2015$m

2014$m

Other operating income:

Re-measurements of commodity-based contracts (117) 297

Other – 106

(117) 403

Operating costs (53) (181)

Profits and losses on disposal of non-current assets and impairments:

Disposals of non-current assets 2 553 967

Impairments (1 452) (8 956)

Other (142) (131)

959 (8 120)

Share of post-tax results from joint ventures and associates (45) (56)

Finance income 278 –

Finance costs (220) (644)

802 (8 598)

Taxation (171) 3 512

Profit/(loss) for the year from continuing operations 631 (5 086)

OTHER OPERATING INCOMERe-measurements included within Other operating income amount to a charge of $117m (2014: $297m credit), of which a charge of $4m (2014: $280m credit) represents non-cash mark-to-market movements on certain gas contracts. While the activity surrounding these contracts involves the physical delivery of gas, the contracts fall within the scope of IAS 39 and meet the definition of a derivative instrument. In addition, re-measurements include a net $113m charge (2014: $17m credit) representing unrealised mark-to-market movements associated with economic hedges. Further information on commodity instruments is given in note 17, page 60. Other operating income in 2014 included a credit of $106m in respect of final settlement of a legacy treaty dispute relating to investments formerly held by the Group.

OPERATING COSTSOperating costs in 2015 include a pre- and post-tax charge of $50m relating to the downward re-measurement of trade receivables in Egypt to reflect the time value of money associated with the outstanding debt based on a revised assumed repayment profile. This increases the total discount recognised to $150m following the pre-tax charge of $100m (post-tax $79m) recognised in 2014.

DISPOSAL OF NON-CURRENT ASSETS AND IMPAIRMENTS2015Disposal of non-current assetsBG Group completed the sale of the Queensland Curtis Liquefied Natural Gas (QCLNG) pipeline for gross proceeds of $4 597m, resulting in a pre-tax profit on disposal of $2 538m (post-tax $1 663m) in the Upstream segment. The Group completed the sale of two LNG vessels, for total gross consideration of $460m, resulting in a pre-tax loss on disposal of $15m (post-tax $14m) in the LNG Shipping & Marketing segment. Other disposals resulted in a pre-tax gain of $30m (post-tax $23m).

ImpairmentsThere was a pre-tax impairment charge of $1 452m (post-tax $691m) relating to Upstream activities in the North Sea, Tunisia and certain other assets. This was driven by the impact of further falls in commodity prices and reserves revisions and reflected a forward Brent price curve for five years, reverting to the Group’s long-term price assumption for impairment testing of $75 real from 1 January 2015.

The Group used the fair value less costs of disposal method to calculate the recoverable amount of the cash-generating units (CGU) consistent with a Level 3 fair value measurement as defined in note 17, page 60. In determining the fair value, the Group used a post-tax discount rate of 8% based on the Group weighted average cost of capital. Where appropriate, cash flows were adjusted to take into account any specific country risks.

In the North Sea, the total pre-tax non-cash impairment charge was $787m (post-tax $307m) and the related recoverable amount was $806m. This was driven by lower commodity prices, a reserves downgrade reflecting underlying reservoir performance, and higher decommissioning costs on certain fields.

In Tunisia, the total pre-tax non-cash impairment charge was $534m (post-tax $307m) and the related recoverable amount was $569m. This was driven by lower commodity prices and a reserves downgrade reflecting reservoir performance.

Elsewhere, reduction in the Group’s assumptions of future commodity prices resulted in pre-tax impairment charges of $131m (post-tax $77m) in relation to certain other E&P assets.

OtherOther write-offs and provisions for certain other exceptional items resulted in a pre-tax charge to the income statement of $142m (post-tax $109m).

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4 DISPOSALS, RE-MEASUREMENTS AND IMPAIRMENTS CONTINUED2014Disposal of non-current assetsBG Group completed the sale of its 62.78% equity interest in the Central Area Transmission System (CATS) gas pipeline and associated infrastructure in the UK North Sea for total consideration of $797m, resulting in a pre- and post-tax profit on disposal of $782m in the Upstream segment.

The Group completed the sale of six LNG steam vessels, which were previously held as finance leases and have subsequently been leased back under operating leases, for total gross consideration of $930m (net cash proceeds were $53m after repayment of the finance lease liabilities and settlement of associated cross-currency interest rate swaps and interest rate swaps). This resulted in a pre-tax profit on disposal of $216m (post-tax $170m) in the LNG Shipping & Marketing segment.

Other disposals resulted in a pre-tax charge of $31m (post-tax $18m) in the Upstream segment.

ImpairmentsThere was a pre-tax impairment charge of $8 956m (post-tax $5 928m) relating to Upstream activities in Australia, Egypt and certain other assets. This was driven mainly by the significant fall in global commodity prices.

The Group used the fair value less costs of disposal method to calculate the recoverable amount of the cash-generating units consistent with a Level 3 fair value measurement as defined in note 17, page 60. In determining the fair value, the Group used a post-tax discount rate of 8% based on the Group weighted average cost of capital. Where appropriate, cash flows were adjusted to take into account any specific country risks.

In Australia, the total pre-tax non-cash impairment charge was $6 824m (post-tax $4 540m). The Group entered into an agreement to sell its wholly owned subsidiary QCLNG Pipeline Pty Limited and, as a result, the remaining QCLNG assets were subject to a pre-tax impairment charge of $2 747m (post-tax $1 828m) principally reflecting the increase in tariffs payable to third parties post-completion. The remaining pre-tax impairment charge of $4 077m (post-tax $2 712m) in Australia was driven primarily by a reduction in the Group’s assumptions of future commodity prices. The recoverable amount of the CGU, excluding QCLNG Pipeline Pty Limited, which was classified as held for sale, was $15.0bn.

In Egypt, there was a pre-tax impairment charge of $790m (post-tax $737m), principally driven by further reserve downgrades reflecting underlying reservoir performance and the Group’s expectation of limited LNG exports from Egyptian LNG for the foreseeable future. The recoverable amount of the CGU was $0.8bn.

Elsewhere, the reduction in the Group’s assumptions of future commodity prices resulted in pre-tax impairment charges of $1 342m (post-tax $651m). The most significant impairment charges were in the North Sea $566m pre-tax (post-tax $172m), Tunisia $450m pre-tax (post-tax $255m) and the USA $227m pre-tax (post-tax $148m). Other impairments in 2014 resulted in pre-tax impairment charges of $99m (post-tax $76m).

OtherOther write-offs and provisions for certain other exceptional items resulted in a pre-tax charge to the income statement of $131m (post-tax $95m).

SHARE OF POST-TAX RESULTS FROM JOINT VENTURES AND ASSOCIATESIn 2015, a pre- and post-tax charge of $40m was recognised, being the Group’s share of an impairment charge recognised by a joint venture. In addition, a pre- and post-tax charge of $5m (2014: $56m) was recognised in respect of the Group’s share of a write-off of assets under construction in Brazil following the bankruptcy of a contractor.

FINANCE INCOME AND COSTSRe-measurements presented in finance income and costs include mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk and foreign exchange movements on borrowings and certain intercompany balances. In addition, re-measurements in 2015 include a pre-tax credit of $76m (post-tax $61m) in relation to interest recognised on a consortium loan.

TAXATIONIn 2015, taxation included a net charge of $204m relating to disposals, re-measurements and impairments, a net charge of $659m reflecting the impact of foreign exchange movements on deferred and current tax balances, especially in Australia and Brazil, a $388m credit relating to changes in deferred tax balances due to changes in UK taxation rates and a net $304m credit resulting from a number of exceptional one-off and prior period taxation items.

In 2014, taxation included a credit of $3 028m as a result of the impairment charges, and a net credit of $449m resulting from a number of exceptional one-off and prior period taxation items. These items included the full recognition of taxable losses in Australia following first LNG production at QCLNG and exceptional prior period adjustments and one-off changes to tax positions in a number of jurisdictions.

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5 FINANCE INCOME AND COSTS2015

$m2014

$m

Interest receivable(a) 153 153

Net fair value gains and losses on derivatives and fair value hedge adjustments(b) 232 –

Finance income 385 153

Interest payable (543) (548)

Finance lease charges (89) (92)

Interest capitalised(c) 397 532

Unwinding of discount on provisions and pension assets and liabilities(d) (132) (154)

Net fair value gains and losses on derivatives and fair value hedge adjustments(b) (220) (644)

Finance costs (587) (906)

Net finance costs – continuing operations (202) (753)

(a) Interest receivable includes net exchange gains of $nil (2014: $49m).(b) Comprises $73m gain (2014: $26m loss) associated with fair value hedge adjustments, $293m loss (2014: $238m loss) in respect of mark-to-market movements on derivatives, $223m gain

(2014: $236m gain) on foreign exchange movements on borrowings, and $9m gain (2014: $616m loss) on foreign exchange movements on certain inter-company balances. (c) Finance costs associated with the Group’s central borrowings used to finance major capital projects are capitalised up to the point that the project is ready for its intended use. The weighted

average interest cost applicable to these borrowings is 3.2% per annum (2014: 3.4%). Tax relief for capitalised interest is approximately $126m (2014: $162m).(d) Relates to the unwinding of the discount on provisions and retirement benefit schemes.

6 TAXATION2015

$m2014

$m

Current tax

UK corporation tax and petroleum revenue tax 332 869

Overseas tax 55 1 321

Total current tax 387 2 190

Deferred tax 256 (3 469)

Total tax charge/(credit) – continuing operations 643 (1 279)

Factors affecting the tax charge for the yearThe total tax charge/(credit) reconciles with that calculated using the statutory UK corporate tax rate of 20.25% (2014: 21.49%):

2015$m

2014$m

Profit/(loss)before taxation 2 971 (2 330)

Tax on profit/(loss) before taxation at UK statutory corporation tax rate 602 (501)

Effect on tax charge of:

Non tax-deductible or non-taxable items 221 (145)

Overseas taxes at different rates to UK statutory rate (63) (478)

North Sea taxes at different rates to UK statutory rate (84) 380

Petroleum revenue tax (31) 2

Effect of changes in tax rate on deferred tax balances (388) –

Adjustment recognised for current tax of prior periods (467) (194)

Adjustment recognised for deferred tax of prior periods 282 (35)

Recognition of deferred tax (74) (183)

Foreign exchange movements on current and deferred tax balances 659 354

Other items (14) (479)

Tax charge/(credit) – continuing operations 643 (1 279)

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6 TAXATION CONTINUEDThe net movement in deferred tax assets and liabilities is shown below:

Accelerated tax depreciation

$m

Decommi-ssioning

$m

Unused tax losses

$m

Other temporary

differences(a)

$mTotal

$m

As at 1 January 2014 (5 986) 548 2 433 282 (2 723)

Credit/(charge) for the year 2 130 189 1 510 (360) 3 469

Charge to equity and other comprehensive income – – – 163 163

Currency translation adjustments 400 (42) (306) 13 65

Disposals 60 (31) – – 29

As at 31 December 2014 (3 396) 664 3 637 98 1 003

Credit/(charge) for the year 726 177 (1 164) 5 (256)

Charge to equity and other comprehensive income – – – 142 142

Currency translation adjustments 83 (39) (219) 12 (163)

Disposals 6 1 – – 7

As at 31 December 2015 (2 581) 803 2 254 257 733

2015$m

2014$m

Deferred tax liabilities (2 111) (2 946)

Deferred tax assets 2 844 3 949

Net deferred tax asset as at 31 December 733 1 003

(a) Other temporary differences include deferred petroleum revenue tax, retirement benefit obligations and certain provisions.

Deferred tax assets are recognised for deductible temporary differences, unutilised tax losses and unused tax credits to the extent that realisation of the related tax benefit through future taxable income is probable. To determine the future taxable income, reference is made to the latest available profit forecast which takes into account production volumes, LNG Shipping & Marketing supply volumes and commodity prices in the relevant jurisdictions. This requires assumptions regarding future profitability and is therefore inherently uncertain.

2015$m

2014$m

Temporary differences for which no deferred tax asset has been recognised

Deductible temporary differences 1 462 2 211

Tax losses 2 941 2 192

Tax credits 531 554

Total deferred tax assets not recognised 4 934 4 957

To the extent unutilised, $252m of the unused tax losses will expire within five years (2014: $166m) and $1 214m of the unused tax losses will expire between six and 20 years (2014: $849m).

The aggregate amount of taxable temporary differences associated with undistributed earnings of subsidiaries, joint ventures and associates, for which deferred tax liabilities have not been recognised, is approximately $2m (2014: $5m). No liability has been recognised in respect of these differences either because no liability is expected to arise on distribution under applicable tax legislation or because the Group is in a position to control the timing of the reversal of the temporary differences and it is probable that such differences will not reverse in the foreseeable future.

As at 31 December 2015, the Company had a deferred tax asset of $5m (2014: $2m).

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7 DIVIDENDS2015 2014

$mCents per

ordinary sharePence per

ordinary share $mCents per

ordinary sharePence per

ordinary share

Prior year final dividend, paid in the year 499 14.37 9.52 547 15.68 9.51

Interim dividend, paid in the year 483 14.38 9.22 480 14.38 8.47

Total dividend, paid in the year 982 28.75 18.74 1 027 30.06 17.98

The final dividend of 14.37 cents per ordinary share ($499m) in respect of the year ended 31 December 2014 was paid on 22 May 2015 to shareholders on the register at the close of business on 24 April 2015. The interim dividend of 14.38 cents per ordinary share ($483m) in respect of the year ending 31 December 2015 was paid on 11 September 2015 to shareholders on the register as at 14 August 2015.

Following the Combination with Shell on 15 February 2016, BG Group shareholders will not receive a further BG Group dividend for 2015. However, as the effective date of the Combination** with Shell occurred prior to the record date for Shell’s fourth quarter dividend (being 19 February 2016), BG Group shareholders were entitled to receive that Shell dividend. On 4 February 2016 Shell announced a fourth quarter 2015 dividend of 47 cents per Shell share (equivalent to 20.93 cents per BG share based on the default consideration of 383 pence in cash and 0.4454 Shell B shares for each BG share held). On 23 March 2016, BG Group plc paid an interim ordinary dividend to the holder of the Shell Dividend Access Share of $401m.

8 EARNINGS PER ORDINARY SHARE – CONTINUING OPERATIONSEarnings per ordinary share has been calculated by dividing the earnings for the year for the continuing operations of the Group of $2 328m (2014: $(1 051)m) by 3 413m (2014: 3 408m), being the weighted average number of ordinary shares outstanding during the year. The average number of shares outstanding excludes treasury shares and shares held by employee share plans. Earnings per ordinary share excluding disposals, re-measurements and impairments has been presented in order to reflect the underlying performance of the Group.

2015 2014

$m

Basic earnings per ordinary share

cents $m

Basic earnings per ordinary share

cents

Earnings excluding disposals, re-measurements and impairments 1 697 49.7 4 035 118.4

Disposals, re-measurements and impairments (see note 4, page 49) 631 18.5 (5 086) (149.2)

Earnings including disposals, re-measurements and impairments 2 328 68.2 (1 051) (30.8)

The earnings figure used to calculate diluted earnings per ordinary share is the same as that used to calculate earnings per ordinary share given above, divided by 3 429m, being the weighted average number of ordinary shares in issue during the year as adjusted for dilutive equity instruments relating to the employee share schemes. A reconciliation of the weighted average number of ordinary shares used as the denominator in calculating the basic and diluted earnings per ordinary share is given below. In 2014, potentially issuable ordinary shares were excluded from the diluted earnings per ordinary share calculation, as their inclusion would have decreased the loss per ordinary share.

2015 Sharesm

2014 Sharesm

Basic 3 413 3 408

Dilutive potential ordinary shares:

Equity instruments outstanding during the year(a) 16 –

Diluted basis 3 429 3 408

Diluted earnings per ordinary share (excluding disposals, re-measurements and impairments) (cents) 49.5 118.4

Diluted earnings per ordinary share (including disposals, re-measurements and impairments) (cents) 67.9 (30.8)

(a) The weighted average number of anti-dilutive equity instruments excluded from the calculation of diluted earnings per ordinary share was 15m at 31 December 2014.

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9 GOODWILL

The Group 2015$m

2014$m

Cost and net book value as at 1 January – 25

Currency translation adjustments – (2)

Charge for impairment (see note 4, page 49) – (23)

Cost and net book value as at 31 December – –

For the purpose of impairment testing, goodwill is allocated to cash-generating units; these represent the lowest level at which goodwill is monitored. During 2014, there was a goodwill impairment charge of $23m recognised as a consequence of the significant fall in global commodity prices.

10 INTANGIBLE ASSETS

The Group Expenditure on unproved gas and oil reserves Other(a) Total

2015$m

2014$m

2015$m

2014$m

2015$m

2014$m

Cost as at 1 January 5 023 4 800 393 373 5 416 5 173

Additions 629(b) 746(b) – 24 629 770

Disposals and unsuccessful exploration expenditure(c) (394) (256) – – (394) (256)

Transfers from/(to) property, plant and equipment 14 (100) – – 14 (100)

Other movements (7) 8 3 (3) (4) 5

Currency translation adjustments (115) (175) (2) (1) (117) (176)

Cost as at 31 December 5 150 5 023 394 393 5 544 5 416

Amortisation as at 1 January (2 009) (1 048) (272) (261) (2 281) (1 309)

Charge for the year – – (10) (11) (10) (11)

Charge for impairment (see note 4, page 49) – (961) – – – (961)

Amortisation as at 31 December (2 009) (2 009) (282) (272) (2 291) (2 281)

Net book value as at 31 December 3 141 3 014 112 121 3 253 3 135

(a) Other includes capacity rights in the Caspian Pipeline Consortium export pipeline which are amortised on a straight-line basis over the term of the contract and have an average remaining useful life of 22 years (2014: 23 years). Other also includes the contractual rights in respect of the purchase of LNG regasification services and related gas sales. These rights are amortised on a straight-line basis over the term of the contract.

(b) Broadly equivalent to cash flows attributable to investing activities arising from exploration and evaluation. The Group’s net book value includes capitalised interest of $20m (2014: $nil).(c) Disposals and unsuccessful exploration expenditure includes $363m of intangible assets written off (2014: $232m).

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11 PROPERTY, PLANT AND EQUIPMENT

The GroupLand and buildings

$m

Plant and machinery

$m

Motor vehicles and office

equipment$m

Exploration and production

$mTotal

$m


Additions – 973 94 4 204 5 271

Disposals, transfers and other movements(a) – (224) (36) 108 (152)

Currency translation adjustments (9) (67) (98) (1 957) (2 131)


Accumulated depreciation as at 1 January 2015 (58) (1 949) (1 189) (29 855) (33 051)

Charge for the year – (104) (194) (2 894) (3 192)

Charge for impairment (see note 4, page 49) – (1) – (1 451) (1 452)

Disposals, transfers and other movements – 208 40 2 250

Currency translation adjustments 2 27 64 714 807

Accumulated depreciation as at 31 December 2015 (56) (1 819) (1 279) (33 484) (36 638)

Net book value as at 31 December 2015 (b)(c)(d) 64 8 697 642 25 853 35 256

The GroupLand and buildings

$m

Plant and machinery

$m

Motor vehicles and office

equipment$m

Exploration and production

$mTotal

$m


Additions – 994 213 6 900 8 107

Disposals, transfers and other movements(a) – (650) (22) 49 (623)

Currency translation adjustments (9) (88) (99) (2 084) (2 280)

Reclassified as held for sale – (2 157) – – (2 157)


Accumulated depreciation as at 1 January 2014 (49) (938) (1 035) (21 612) (23 634)

Charge for the year – (145) (213) (2 436) (2 794)

Charge for impairment (see note 4, page 49) (12) (1 228) (25) (6 792) (8 057)

Disposals, transfers and other movements – 252 24 569 845

Currency translation adjustments 3 31 60 416 510

Reclassified as held for sale – 79 – – 79

Accumulated depreciation as at 31 December 2014 (58) (1 949) (1 189) (29 855) (33 051)

Net book value as at 31 December 2014(b)(c)(d) 71 7 885 772 27 127 35 855

(a) Includes, within Exploration and production, a net transfer (to)/from Intangible assets of $(14)m (2014: $100m).(b) The Group’s net book value includes capitalised interest of $1 559m (2014: $1 398m) comprising Exploration and production $890m (2014: $873m) and Plant and machinery $669m (2014: $525m).

A deferred tax liability is recognised in respect of this taxable temporary difference at current enacted rates.(c) Includes the net book value of decommissioning assets of $2 406m (2014: $2 908m) and expenditure on Plant and machinery and Exploration and production assets under construction of

$5 743m (2014: $10 739m).(d) The net book value of assets capitalised and held under finance leases is shown below and comprises $992m (2014: $1 073m) included in Plant and machinery and $196m (2014: $228m) included

in Exploration and production:


2014$m

Cost 1 929 1 963

Accumulated depreciation (741) (662)

Net book value 1 188 1 301

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12 INVESTMENTS

The Groupas at 31 December 2015

$m2014

$m

Joint ventures 729 796

Associates 3 546 2 709

Other investments(a) 33 42

4 308 3 547

(a) Includes an investment in Drillsearch Energy Limited and Azure Midstream Energy, LP (Azure).

During 2014, a charge for impairment of $168m was recorded against the carrying value of associates.

JOINT VENTURES AND ASSOCIATES INFORMATIONThe Group does not have any individually material joint ventures or associates. Analysis of BG Group’s share of profit after tax and comprehensive income from individually immaterial joint ventures and associates in aggregate is shown below:

Joint ventures Associates


2014$m

2015$m

2014$m

Share of profit after tax from continuing operations 23 80 138 86

Share of total comprehensive income 23 80 138 86

As at 31 December 2015, the Group’s joint ventures had placed contracts for capital expenditure, the Group’s share of which amounted to $32m (2014: $23m). As at 31 December 2015, the Group had no contingent liabilities in respect of its joint ventures or associates (2014: $nil).

A list of all joint ventures and associates is given in note 26, page 74.

The Company Subsidiary undertakings

2015$m

2014$m

As at 1 January 4 104 4 288

Capital contribution(a) 64 70

Currency translation adjustments (228) (254)

As at 31 December 3 940 4 104

(a) Represents the fair value of equity instruments granted to subsidiaries’ employees arising from equity-settled employee share schemes.

MATERIAL JOINT OPERATIONSThe following joint operations are considered individually material to the Group.

as at 31 December 2015 Principal place of business Activity

West Delta Deep Marine(a) Egypt Exploration and production

Karachaganak(b) Kazakhstan Exploration and production

(a) West Delta Deep Marine concession is operated by Burullus Gas Company S.A.E. in which the Group has a 25% interest. (b) Karachaganak concession is operated by Karachaganak Petroleum Operating B.V. in which the Group has a 29.25% interest.

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13 INVENTORIES


$m2014

$m

Raw materials and consumables 636 613

Finished goods for resale 481 581

1 117 1 194

14 TRADE AND OTHER RECEIVABLES



2014$m

2015$m

2014$m

Amounts falling due within one year

Trade receivables 946 1 228 – –

Amounts owed by Group undertakings (see note 22, page 69) – – 784 1 786

Amounts owed by joint ventures and associates (see note 22, page 69) 18 42 – –

Other receivables 780 1 225 – –

Prepayments 619 387 – –

Accrued income 1 304 2 160 – –

3 667 5 042 784 1 786

Amounts falling due after more than one year

Trade receivables 515 460 – –

Other receivables 767 608 – –

1 282 1 068 – –

4 949 6 110 784 1 786

Trade receivables are stated net of provisions. When management considers the recovery of a receivable to be improbable, a provision is made against the carrying value of the receivable. The movement in this provision is as follows:

The Group 2015$m

2014$m

Provision as at 1 January 58 41

Charge to the income statement 98 17

Provision as at 31 December 156 58

As at 31 December 2015, $1 050m (2014: $928m) of trade and other receivables were past due but not provided for; an analysis of these receivables is as follows:

The Group 2015$m

2014$m

Less than three months past due 168 134

Between three and six months past due 88 196

Between six and 12 months past due 190 42

More than 12 months past due 604 556

1 050 928

Included within past due but not impaired receivables is a balance of $919m (2014: $729m) with Egypt General Petroleum Corporation (EGPC), none of which has been received post year end. This balance does not include a $150m downward re-measurement of the carrying amount, to reflect the time value of money associated with the outstanding debt based on the latest assumed repayment profile. The net amount of trade and other receivables with EGPC past due but not provided for after this re-measurement is $769m. $3m has been received post year end.

The remaining balance of $131m relates to a diversified number of independent customers. Of this, $34m has been received post year end.

For further information on the credit risk associated with trade receivables, including the EGPC balance, see note 17, page 60.

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15 CASH AND CASH EQUIVALENTS

The Group


2014$m

Cash at bank and in hand 415 371

Cash equivalent investments 6 785 4 924

7 200 5 295

Cash and cash equivalents comprise cash in hand, deposits with a maturity of three months or less and other short-term money market deposit accounts that are readily convertible into known amounts of cash.

Included within cash and cash equivalent investments in the current year is an amount equivalent to $279m (2014: $390m), which is not immediately available to the Group other than for funding local cash expenditure. This includes 2.1bn (2014: 2.8bn) Egyptian Pounds (equivalent to $267m (2014: $390m)), which is subject to foreign exchange restrictions.

For information on the interest rate composition of the Group’s financial assets see note 17, page 60.

16 BORROWINGSGROSS BORROWINGS


$m2014

$m


Bonds

2.5% US Dollar 350m bond due December 2015 – 349

2.875% US Dollar 750m bond due October 2016 750 –

Fair value hedge adjustments – 1

750 350

Loans from financial institutions 451 1 169

Obligations under finance leases 67 67

1 268 1 586


Bonds and other loans

2.875% US Dollar 750m bond due October 2016 – 749

5.125% Pound Sterling 500m bond due December 2017 737 779

Floating rate US Dollar 300m bond due September 2018 300 300

3.0% Euro 1 000m bond due November 2018 1 085 1 209

3.625% Euro 500m bond due July 2019 542 603

3.625% Euro 250m bond due July 2019 275 308

3.94% Hong Kong Dollar 370m bond due October 2019 48 48

4.0% US Dollar 650m bond due December 2020 645 644

4.0% US Dollar 1 350m bond due October 2021 1 341 1 339

1.25% Euro 775m bond due November 2022 840 935

5.125% Pound Sterling 750m bond due December 2025 1 095 1 157

2.25% Euro 800m bond due November 2029 866 964

3.5% Euro 100m bond due October 2033 106 118

5.0% Pound Sterling 750m bond due November 2036 1 082 1 144

5.125% US Dollar 900m bond due October 2041 881 881

6.5% Pound Sterling 600m bond due November 2072(a) 881 932

6.5% US Dollar 500m bond due November 2072(a) 497 497

6.5% Euro 500m bond due November 2072(a) 541 603

Fair value hedge adjustments 83 175

11 845 13 385

Loans from financial institutions 2 250 1 076

Obligations under finance leases 1 378 1 460

15 473 15 921

Gross borrowings 16 741 17 507

(a) These bonds are long-dated, subordinated securities, which, although accounted for as debt, incorporate some features typical of equity, such as potential coupon deferral. The Group may, at its sole discretion, redeem all, but not part, of the securities at their principal amount on 30 November 2017, 30 November 2022 or any subsequent coupon date thereafter to maturity.

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16 BORROWINGS CONTINUEDNET BORROWINGS(a)


$m2014

$m


Cash and cash equivalents 7 200 5 295

Borrowings (1 268) (1 586)

Commodity contracts and other derivative financial instruments(b) (5) 6

5 927 3 715


Borrowings (15 473) (15 921)

Trade and other receivables(c) 172 172

Commodity contracts and other derivative financial instruments(b) (694) 36

(15 995) (15 713)

Net borrowings (10 068) (11 998)

(a) Net borrowings are defined on page 80.(b) Commodity contracts and other derivative financial instruments comprise treasury financial derivatives of $(699)m (2014: $42m).(c) Trade and other receivables comprise a finance lease receivable of $172m (2014: $172m). See note 17, page 60.

The following table shows a reconciliation of net borrowings:

The Group 2015$m

2014$m

Net borrowings as at 1 January (11 998) (10 610)

Net increase/(decrease) in cash and cash equivalents 1 870 (908)

Cash inflow from changes in borrowings (55) (1 461)

Inception of finance leases – (247)

Disposal of finance leases – 923

Currency translation and other re-measurements 115 305

Net borrowings as at 31 December (10 068) (11 998)

As at 31 December 2015, BG Group’s share of the net borrowings in joint ventures and associates amounted to approximately $0.3bn (2014: $0.3bn), including BG Group shareholder loans of approximately $0.3bn (2014: $0.4bn). These net borrowings are included in BG Group’s share of the net assets in joint ventures and associates.

MATURITY AND INTEREST RATE PROFILE OF THE GROUP’S BORROWINGSThe following tables analyse the Group’s gross borrowings. These are repayable as follows:

Gross borrowings (including obligations under finance leases) Fixed rate borrowings Total gross borrowings

2015$m

2014$m

2015$m

2014$m

Within one year 1 017 417 1 268 1 586

Between one and two years 266 827 1 552 1 078

Between two and three years 271 73 1 901 1 424

Between three and four years 458 78 1 137 1 833

Between four and five years 284 1 009 950 1 058

After five years 7 135 7 816 9 933 10 528

9 431 10 220 16 741 17 507

For the purpose of the table above, borrowings with an initial maturity within one year are treated as floating rate.

As part of its interest rate risk strategy, the Group has entered into swaps. The disclosure above is presented after the effect of these swaps. Further information on the fair value of the swaps is included in note 17, page 60.

The weighted average post-swap interest rate of borrowings as at 31 December 2015 was 3.5% (2014: 3.7%). Post-swap fixed-rate borrowings mature between 2016 and 2072 (2014: mature between 2015 and 2072).

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16 BORROWINGS CONTINUED

Obligations under finance leases pre-swap

Amounts due:

Minimum lease paymentsObligations under finance

leases

2015$m

2014$m

2015$m

2014$m

Within one year 161 162 67 67

Between one and five years 643 654 295 275

After five years 1 667 1 904 1 083 1 185

Less: future finance charges (1 026) (1 193) – –

1 445 1 527 1 445 1 527

The Group has finance lease obligations in respect of infrastructure and LNG ships. These lease obligations expire between 2024 and 2039 (2014: expire between 2024 and 2039).

CURRENCY COMPOSITION OF THE GROUP’S BORROWINGSThe following table analyses the currency composition of the Group’s borrowings:

2015$m

2014$m

Currency:

Pound Sterling 3 881 5 296

US Dollar 8 422 7 205

Euro 4 230 4 778

Other 208 228

16 741 17 507

The disclosure above does not include the impact of certain currency swaps as these are separately recognised under IAS 39 and presented in note 17, page 60. As at 31 December 2015, the Group had swapped $2 164m (2014: $2 291m) of Pound Sterling borrowings into US Dollars, $4 230m (2014: $4 778m) of Euro borrowings into US Dollars and $51m (2014: $50m) of other currencies into US Dollars.

COMPOSITION OF THE GROUP’S UNDRAWN COMMITTED FACILITIESThe Group has undrawn committed borrowing facilities, in respect of which all conditions have been met, as follows:

Expiring:2015

$m2014

$m

Within one year – 2 102

Between one and two years 5 040 2 180

Between two and three years – 3 040

Between three and four years 2 210 –

7 250 7 322

Unutilised committed borrowing facilities of $7 250m were canceled in February 2016.

17 FINANCIAL INSTRUMENTSTREASURY INSTRUMENTSThe Group is exposed to credit risk, interest rate risk, exchange rate risk and liquidity risk. As part of its business operations, the Group uses derivative financial instruments (derivatives) in order to manage exposure to fluctuations in interest rates and exchange rates. The Group enters into interest rate derivatives to manage the fixed and floating composition of its debt. The Group enters into currency exchange rate derivatives to hedge certain currency cash flows and to adjust the currency composition of its assets and liabilities. Certain agreements are combined currency and interest swap transactions, described as cross-currency interest rate derivatives. The Group’s policy is to enter into interest or currency exchange rate derivatives only where these are matched by an underlying asset, liability or transaction.

Further information on treasury risks is contained in the Principal risks and uncertainties section, pages 14 to 16.

COMMODITY INSTRUMENTSWithin the ordinary course of business the Group routinely enters into sale and purchase transactions for commodities. The majority of these transactions take the form of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of the commodity in accordance with the Group’s expected sale, purchase or usage requirements. Such contracts are not within the scope of IAS 39.

Certain gas sales contracts fall within the scope of IAS 39. These contracts include pricing terms that are based on a variety of commodities and indices. They are recognised in the balance sheet at fair value with movements in fair value recognised in the income statement.

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17 FINANCIAL INSTRUMENTS CONTINUEDCOMMODITY INSTRUMENTS CONTINUEDCertain short-term market traded contracts for the purchase and subsequent resale of third-party commodities are within the scope of IAS 39 and are recognised in the balance sheet at fair value with movements in fair value recognised in the income statement. The Group uses various commodity-based derivative instruments to manage some of the risks arising from fluctuations in commodity prices. Such contracts include physical and net-settled forwards, futures, swaps and options. Where these derivatives have been designated as cash flow hedges of underlying commodity price exposures, certain gains and losses attributable to these instruments are deferred in other comprehensive income and subsequently recognised in the income statement when the underlying hedged transaction crystallises. Commodity derivatives that are not part of a hedging relationship are recognised in the balance sheet within Other commodity derivatives at fair value, with movements in fair value recognised in the income statement.

Further information on commodity price exposure is contained in the Principal risks and uncertainties section, pages 14 to 16.

AMOUNTS RECOGNISED IN RESPECT OF FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE

The Groupas at 31 December

Included in the balance sheet:

2015 2014

Assets$m

Liabilities$m

Assets$m

Liabilities$m

Interest rate derivatives 87 (77) 102 (61)

Currency exchange rate derivatives – – – (3)

Cross-currency interest rate derivatives 61 (770) 183 (179)

Gas contracts 55 – 82 (14)

Other commodity derivatives 128 (140) 155 (124)

331 (987) 522 (381)

As at 31 December 2015, the Group also held non-derivative available-for-sale financial assets of $33m (2014: $42m) which are recognised in the balance sheet at fair value.

As at 31 December 2015, the Group had deposited cash of $166m (2014: $119m) and received cash of $16m (2014: $16m) in respect of collateral and margin payments associated with the use of commodity derivatives.

Derivative financial instruments expected to be realised within one year are presented within current assets and current liabilities. All other derivative financial instruments are classified as non-current. The maturity profile of derivative financial instruments is as follows:

2015 2014

Assets$m

Liabilities$m

Assets$m

Liabilities$m

Within one year 167 (141) 235 (128)

Between one and five years 106 (567) 103 (163)

After five years 58 (279) 184 (90)

331 (987) 522 (381)

The notional principal amounts of derivative financial instruments are as follows:

2015 2014

Within one year

$m

Between one and five years

$mAfter five years

$mTotal

$m

Within one year$m

Between one and five years

$mAfter five years

$mTotal

$m

Interest rate derivatives – 2 687 1 240 3 927 1 300 780 2 200 4 280

Currency exchange rate derivatives 482 – – 482 599 – – 599

Cross-currency interest rate derivatives – 4 121 3 285 7 406 – 4 121 3 285 7 406

Other commodity derivatives 8 428 3 651 80 12 159 10 394 5 723 – 16 117

The notional principal amounts of gas contracts are $96m (2014: $293m).

The amounts in respect of derivatives represent the gross combination of notional principals and accordingly do not show the extent to which these may offset. These notional principal amounts give an indication of the scale of derivatives held, but do not reflect the risks that the Group is exposed to from their use.

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17 FINANCIAL INSTRUMENTS CONTINUEDVALUATIONAll financial instruments that are initially recognised and subsequently re-measured at fair value have been classified in accordance with the hierarchy described in IFRS 13 ‘Fair Value Measurement’.

Fair value measurement hierarchyThe fair value hierarchy, described below, reflects the significance of the inputs used to determine the valuation of financial assets and liabilities measured at fair value.

Level 1 fair value measurements are those derived directly from quoted prices (unadjusted) in active markets for identical assets and liabilities.

Level 2 fair value measurements are those including inputs other than quoted prices included within Level 1 that are observable for the asset or liability directly or indirectly. The fair value of the Group’s interest rate and currency exchange rate derivatives and the majority of the Group’s commodity derivatives are calculated from relevant market prices and yield curves at the balance sheet date and are therefore based solely on observable price information. These instruments are not directly quoted in active markets and are accordingly classified as Level 2 in the fair value hierarchy.

Level 3 fair value measurements are those derived from valuation techniques that include significant inputs for the asset or liability that are not based on observable market data. Where observable market valuations of commodity contracts are unavailable, the fair value on initial recognition is the transaction price and is subsequently determined using the Group’s forward planning assumptions for the price of gas, other commodities and indices. Due to the assumptions underlying their fair value, certain gas contracts are categorised as Level 3 in the fair value hierarchy. These contracts contain an underlying linkage to oil prices, and one of the assumptions used for their valuation is that observable commodity prices are liquid for four years (2014: four years). The fair values of the commodity contracts are calculated using the market yield curve at the balance sheet date.

The Group Financial assets Financial liabilities

as at 31 December 2015 Level 1$m

Level 2$m

Level 3$m

Total$m

Level 1$m

Level 2$m

Level 3$m

Total$m

Interest rate derivatives – 87 – 87 – (77) – (77)

Cross-currency interest rate derivatives – 61 – 61 – (770) – (770)

Gas contracts – 5 50 55 – – – –

Other commodity derivatives 3 89 36 128 (88) (21) (31) (140)

3 242 86 331 (88) (868) (31) (987)

Financial assets Financial liabilities

as at 31 December 2014 Level 1$m

Level 2$m

Level 3$m

Total$m

Level 1$m

Level 2$m

Level 3$m

Total$m

Interest rate derivatives – 102 – 102 – (61) – (61)

Currency exchange rate derivatives – – – – – (3) – (3)

Cross-currency interest rate derivatives – 183 – 183 – (179) – (179)

Gas contracts – – 82 82 – (14) – (14)

Other commodity derivatives 43 73 39 155 (69) (9) (46) (124)

43 358 121 522 (69) (266) (46) (381)

As at 31 December 2015, the Group also held available-for-sale financial assets of $33m (2014: $42m), the fair value of which is determined using Level 1 fair value measurements.

Level 3 fair value measurementsThe movements in the year associated with financial assets and liabilities, measured at fair value and determined in accordance with Level 3, are shown below:

Total

2015$m

2014$m

Fair value as at 1 January 75 (87)

Total gains or losses recognised in the income statement 59 139

Reclassification to Level 2 – 8

Settlements (69) 19

Currency translation adjustments (10) (4)

Fair value as at 31 December 55 75

Total gains or losses recognised in the income statement are presented in Revenue and other operating income.

As at 31 December 2015, the potential pre-tax change in the fair value of gas contracts, assuming a $20 per barrel change (2014: $20 per barrel) in the Brent price assumption, was $32m (2014: $79m).

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17 FINANCIAL INSTRUMENTS CONTINUEDFAIR VALUE ADJUSTMENTS ON FINANCIAL INSTRUMENTS

The GroupIncluded in the income statement:

2015$m

2014$m

Interest rate and currency exchange rate derivatives not in a designated hedge relationship(a) (92) (176)

Interest rate derivatives designated as fair value hedges (18) –

Cross-currency interest rate derivatives designated as fair value hedges(a) (188) (71)

Ineffectiveness on net investment hedges 4 10

Gas contracts (4) 280

Other commodity derivatives not in a designated hedge relationship (28) 73

Continuing operations (326) 116

(a) These amounts are offset by foreign exchange gains or losses on the underlying borrowings.

Fair value losses of $4m (2014: $17m) on available-for-sale financial assets are included within other comprehensive income.

HEDGE ACCOUNTINGIn line with the Group’s risk management policies, certain derivative and non-derivative instruments are designated as hedges of currency, interest rate and commodity price exposures in accordance with IAS 39.

Fair value hedgesAs at 31 December 2015, the Group held a number of interest rate derivatives and cross-currency interest rate derivatives designated as hedges of the fair value risk associated with the Group’s fixed rate debt. The hedged items and the related derivatives have the same critical terms to ensure that they are an effective hedge under IAS 39. The fair value of derivative instruments designated as fair value hedges outstanding as at 31 December 2015 is $(235)m (2014: $(8)m). During 2015, adjustments of $73m (2014: $(26)m) have been made to hedged items in respect of the risks being hedged.

Cash flow hedgesThe Group has forward commodity contracts, currency exchange rate derivatives, interest rate derivatives and cross-currency interest rate derivatives designated as hedges of highly probable forecast purchases and sales, and of interest flows and currency exposure on Group debt. As at 31 December 2015, an unrealised pre-tax loss of $44m (2014: $42m) was deferred in other comprehensive income in respect of effective cash flow hedges. The hedged transactions are expected to occur within 18 years (2014: 19 years) and the associated gains and losses deferred in other comprehensive income will be released to the income statement as the underlying transaction crystallises. As at 31 December 2015, deferred pre-tax losses of $6m (2014: $13m) are expected to be released to the income statement within one year. The fair value of derivative instruments designated as cash flow hedges outstanding as at 31 December 2015 is $(70)m (2014: $(30)m).

The Consolidated statement of comprehensive income, page 37, identifies the amounts that have been transferred from other comprehensive income in respect of transactions completed during the year. These items are reported within the income statement to match against the underlying transaction.

Hedges of net investments in foreign operationsAs at 31 December 2015, certain borrowings and currency derivatives have been designated as hedges of the currency risk associated with net investments in foreign operations. The portion of gains or losses on the hedging instruments determined to be an effective hedge are transferred to other comprehensive income to offset the gains or losses arising on the retranslation of net investments in foreign subsidiaries. The pre-tax loss on effective hedging instruments deferred within other comprehensive income as at 31 December 2015 is $912m (2014: $45m). The fair value of financial instruments designated as hedges of net investments in foreign operations outstanding as at 31 December 2015 is $(7 457)m (2014: $(5 682)m).

FINANCIAL ASSETS (EXCLUDING NON-INTEREST BEARING SHORT-TERM RECEIVABLES)The Group’s financial assets consist of cash and cash equivalents of $7 200m (2014: $5 295m), loans made to joint ventures and associates of $348m (2014: $353m), a finance lease receivable of $172m (2014: $172m), available-for-sale assets of $33m (2014: $42m), receivables due within one year of $450m (2014: $520m) and receivables due after more than one year of $616m (2014: $519m).

The currency and interest rate profile of financial assets is as follows:

The Group 2015 2014

Fixed rate financial assets

$m

Floating rate financial assets

$m

Non-interest bearing assets

$mTotal

$m

Fixed rate financial assets

$m

Floating rate financial assets

$m

Non-interest bearing assets

$mTotal

$m

Currency:

US Dollar 303 7 910 17 8 230 231 6 295 22 6 548

Other – 573 16 589 – 328 25 353

303 8 483 33 8 819 231 6 623 47 6 901

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17 FINANCIAL INSTRUMENTS CONTINUEDFINANCIAL ASSETS (EXCLUDING NON-INTEREST BEARING SHORT-TERM RECEIVABLES) CONTINUEDWithin floating rate financial assets, cash and cash equivalents earn interest at the relevant market rates. Periodic interest rate determinations in respect of floating rate loans to joint ventures and associates generally comprise London Interbank Offered Rate (LIBOR) plus or minus an agreed margin. As at 31 December 2015, floating rate receivables and loans to joint ventures and associates had an effective interest rate of between 1.52% and 4.07% (2014: between 1.27% and 4.52%) and are expected to expire between 2018 and 2022 (2014: between 2015 and 2022). The maturity profile of non-interest bearing loans to joint ventures and associates cannot be practicably estimated as repayments are based on the performance of the individual joint venture or associate.

As at 31 December 2015, fixed rate assets expire between 2016 and 2020 (2014: 2016 and 2024) and have effective interest rates of between 6% and 13% (2014: 6% and 15%).

OFFSETTING FINANCIAL ASSETS AND FINANCIAL LIABILITIESThe following financial assets and financial liabilities are subject to offsetting, enforceable master netting arrangements or similar agreements:

The GroupFinancial assets as at 31 December 2015

Amounts offset Amounts not offset Net

Gross assets$m

Gross liabilities offset

$m

Net presented in the balance

sheet$m


$m

Cash collateral received

$m $m

Derivative financial assets 935 (654) 281 (146) (4) 131

Trade and other receivables 1 286 (290) 996 – (1) 995

2 221 (944) 1 277 (146) (5) 1 126

The GroupFinancial liabilities as at 31 December 2015


Gross liabilities$m

Gross assets offset

$m


sheet$m


$m

Cash collateral paid

$m $m

Derivative financial liabilities (1 710) 723 (987) 146 79 (762)

Trade and other payables (902) 221 (681) – – (681)

(2 612) 944 (1 668) 146 79 (1 443)

The GroupFinancial assets as at 31 December 2014


Gross assets$m

Gross liabilities offset

$m


sheet$m


$m

Cash collateral received

$m $m

Derivative financial assets 1 098 (658) 440 (123) (16) 301

Trade and other receivables 988 (248) 740 – (4) 736

2 086 (906) 1 180 (123) (20) 1 037

The GroupFinancial liabilities as at 31 December 2014


Gross liabilities$m

Gross assets offset

$m


sheet$m


$m

Cash collateral paid

$m $m

Derivative financial liabilities (1 121) 740 (381) 123 5 (253)

Trade and other payables (718) 166 (552) – 9 (543)

(1 839) 906 (933) 123 14 (796)

For the financial assets and liabilities subject to enforceable master netting arrangements or similar arrangements above, each agreement between the Group and the counterparty typically requires net settlement of the relevant financial assets and liabilities. In the absence of such a requirement, financial assets and liabilities will be settled on a gross basis, however, each party to the master netting agreement or similar agreement will be required or have the option to settle all such amounts on a net basis in the event of default of the other party. Per the terms of each agreement, an event of default includes: failure by a party to make payment when due; failure by a party to perform any obligation required by the agreement (other than payment) if such failure is not remedied within a specified cure period after notice of such failure is given to the party; or bankruptcy.

FAIR VALUES OF OTHER FINANCIAL INSTRUMENTSThe following financial instruments are measured at historical or amortised cost and have fair values that differ from their book values:

The Group 2015 2014

Book value$m

Fair value$m

Book value$m

Fair value$m

Financial instruments held or issued to finance the Group’s operations:

Long-term borrowings (15 674) (17 222) (15 921) (17 770)

The fair values of long-term borrowings are within Level 1 ($12 511m) and Level 2 ($4 711m) of the fair value hierarchy and have been estimated based on quoted market prices where available, or by discounting all future cash flows by the relevant market yield curve at the balance sheet date.

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17 FINANCIAL INSTRUMENTS CONTINUEDTHE COMPANYThe Company’s financial instruments are all denominated in Pounds Sterling and consist of short-term receivables of $784m (2014: $1 786m) and short-term payables of $34m (2014: $48m). Short-term receivables comprise amounts owed by Group undertakings, of which $771m (2014: $1 768m) earns interest at LIBOR minus an agreed margin. The remaining short-term receivables of $13m (2014: $18m) were non-interest bearing. Short-term payables are due within one year and are non-interest bearing. The fair value of the financial instruments approximates book value.

FINANCIAL RISK FACTORSThe principal financial risks arising from financial instruments are commodity price risk, exchange rate risk, interest rate risk and credit and liquidity risk. Additional quantitative information and market sensitivities in relation to certain principal market risks are included in the following sections.

Liquidity riskThe Group limits the amount of borrowings maturing within any specific period and the Group’s financial assets are primarily held as short-term, liquid investments that are readily convertible into known amounts of cash. These measures reduce liquidity risk.

The undiscounted contractual cash flows receivable/(payable) under financial instruments as at the balance sheet date are as follows:


Within one year$m

Between one and two years

$m

Between two and five years

$mAfter five years

$mTotal

$m

Non-derivative financial liabilities

Borrowings (1 840) (2 063) (5 412) (21 195) (30 510)

Short-term payables (1 064) – – – (1 064)

(2 904) (2 063) (5 412) (21 195) (31 574)

Outflows from derivative financial instruments

Currency and interest rate derivatives (819) (2 073) (3 056) (4 079) (10 027)

Gross-settled commodity derivatives (884) (253) (225) – (1 362)

Net-settled commodity derivatives (3) – (1) – (4)

(1 706) (2 326) (3 282) (4 079) (11 393)

Non-derivative financial assets and inflows from derivative financial instruments 10 673 2 841 3 531 3 669 20 714

Total as at 31 December 2015 6 063 (1 548) (5 163) (21 605) (22 253)


Within one year$m

Between one and two years

$m

Between two and five years

$mAfter five years

$mTotal

$m

Non-derivative financial liabilities

Borrowings (2 251) (1 737) (6 083) (24 231) (34 302)

Short-term payables (1 509) – – – (1 509)

(3 760) (1 737) (6 083) (24 231) (35 811)

Outflows from derivative financial instruments

Currency and interest rate derivatives (310) (327) (4 963) (4 254) (9 854)

Gross-settled commodity derivatives (1 213) (291) (559) (234) (2 297)

Net-settled commodity derivatives (5) – – – (5)

(1 528) (618) (5 522) (4 488) (12 156)

Non-derivative financial assets and inflows from derivative financial instruments 9 197 1 438 5 560 4 490 20 685

Total as at 31 December 2014 3 909 (917) (6 045) (24 229) (27 282)

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17 FINANCIAL INSTRUMENTS CONTINUEDFINANCIAL RISK FACTORS CONTINUEDCredit riskCredit risk is managed on a Group basis. Credit risk in financial instruments arises from cash and cash equivalents and derivative financial instruments, as well as credit exposures of commercial counterparties including exposures in respect of outstanding receivables and committed transactions. For banks and financial institutions, only independently rated parties with a minimum long-term credit rating of ‘A’ are normally accepted as a counterparty and credit limits are established based primarily on the credit ratings, although other credit assessment factors that determine credit quality, including the external environment, are taken into account when considering the awarding of or maintenance of a limit. Similarly, if a commercial counterparty is independently credit rated, the rating is primarily used to determine credit quality and limits, with other relevant assessment factors also considered. If there is no independent credit rating, credit quality is assessed in accordance with credit policies that take account of the counterparty’s financial position and other similar factors. Exposures are monitored by the relevant Group businesses and at a Group level.

As at 31 December 2015, the Group’s maximum credit risk exposure (after the impact of any netting arrangements) under currency and interest rate related derivatives was $13m (2014: $167m) and commodity related derivatives $79m (2014: $79m). The Group’s credit risk exposure under receivables and other financial assets is represented by the book values. The Group considers its portfolio for credit related concentration risks where risks may result from strategic investments, commercial relationships or sales of product in a variety of locations. Mitigation may be considered where appropriate to diversify or reduce risk profile.

As at 31 December 2015, the amount owed by Egypt General Petroleum Corporation (EGPC) in respect of domestic gas sales was $1.1bn (2014: $0.9bn), of which $0.9bn (2014: $0.7bn) was overdue. The Group considers that the current receivable balance remains fully recoverable as cash payments from EGPC continue to be received, however, in 2015, a $50m pre- and post-tax charge was recognised relating to the downward re-measurement of the receivable balance to reflect the time value of money associated with the outstanding debt based on a revised assumed repayment profile. This increases the total discount recognised to $150m following the $100m pre-tax charge ($79m post-tax) recorded in 2014. Discussions continue with the Egyptian government regarding potential future gas development programmes, subject to the negotiation of a higher domestic gas price and resolution of the outstanding receivables.

Market riskFinancial instruments used by the Group that are affected by market risks primarily comprise cash and cash equivalents, borrowings and derivative contracts. The principal market variables that affect the value of these financial instruments are UK and US interest rates, US Dollar to Pound Sterling exchange rates, UK and US gas prices, and Japan Custom-cleared Crude (JCC) and Brent oil prices. The table below illustrates the indicative post-tax effects on the income statement and other comprehensive income of applying reasonably foreseeable market movements to the Group’s financial instruments at the balance sheet date.

The Group Market movementIncome statement

income/(charge)Other comprehensive

income/(charge)

2015 2014 2015$m

2014$m

2015$m

2014$m

UK interest rates + 100 basis points + 100 basis points – (7) (125) (142)

US interest rates + 100 basis points + 100 basis points 50 49 138 140

US$/UK£ exchange rates + 20 cents + 20 cents (325) (366) 1 738 1 506

UK gas prices + 20 pence/therm + 20 pence/therm (35) (48) – –

US gas prices + 1 $/mmbtu + 1 $/mmbtu 83 86 – –

JCC/Brent prices + 20 $/bbl + 20 $/bbl (58) (62) – –

The Company

UK interest rates + 100 basis points + 100 basis points 6 14 – –

The above sensitivity analysis is based on the Group’s financial assets, liabilities and hedge designations as at the balance sheet date and indicates the effect of a reasonable increase in each market variable. The effect of a corresponding decrease in these variables is approximately equal and opposite. The following assumptions have been made:

(i) the sensitivity includes a full year’s change in interest payable and receivable from floating rate borrowings and investments based on the post-swap amounts and composition as at the balance sheet date;

(ii) fair value changes from derivative instruments designated as cash flow or net investment hedges are considered fully effective and are recorded in other comprehensive income;

(iii) fair value changes from derivative instruments designated as fair value hedges are considered fully effective and entirely offset by adjustments to the underlying hedged item; and

(iv) fair value changes from derivatives not in a hedge relationship are recorded in the income statement.

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18 TRADE AND OTHER PAYABLES



2014$m

2015$m

2014$m


Trade payables 555 894 – –

Amounts owed to Group undertakings (see note 22, page 69) – – 9 23

Amounts owed to joint ventures and associates (see note 22, page 69) 139 258 – –

Other payables(a) 370 357 25 25

Accruals and deferred income 2 711 3 259 – –

3 775 4 768 34 48


Accruals and deferred income 184 136 – –

184 136 – –

3 959 4 904 34 48

(a) As at 31 December 2015, Group other payables include $19m (2014: $16m) relating to share-based payment transactions, of which $12m (2014: $10m) relates to awards that have already vested, and $172m (2014: $165m) relating to amounts provided in 2015 for payments to eligible employees under bonus schemes, including the BG Group Annual Incentive Scheme (AIS).

19 PROVISIONS FOR OTHER LIABILITIES AND CHARGES

The Group Decommissioning Other Total

2015$m

2014$m

2015$m

2014$m

2015$m

2014$m

As at 1 January 4 605 3 662 630 453 5 235 4 115

Charge for the year 26 17 278 172 304 189

Unwinding of discount 131 146 1 2 132 148

Additions 241 714 18 56 259 770

Change in discount rate – 808 – – – 808

Disposals (66) (119) – – (66) (119)

Currency translation and other adjustments (300)(a) (504)(a) (24) 110(b) (324) (394)

Amounts used (30) (83) (133) (139) (163) (222)

Unused provisions credited to the income statement – – (157) (24) (157) (24)

Reclassified as assets held for sale – (36) – – – (36)

As at 31 December 4 607 4 605 613 630 5 220 5 235

(a) Includes a movement of $37m due to a change in inflation assumptions (2014: $(272)m).(b) 2014 includes $138m reclassified from elsewhere on the balance sheet.

A brief description of each provision together with estimates of the timing of expenditure is given below:

DECOMMISSIONING COSTSThe estimated cost of decommissioning at the end of the producing lives of fields is reviewed at least annually and engineering estimates and reports are updated periodically. Provision is made for the estimated cost of decommissioning at the balance sheet date, to the extent that current circumstances indicate BG Group will ultimately bear this cost. The payment dates of expected decommissioning costs are uncertain and are based on economic assumptions surrounding the useful economic lives of the fields concerned. Useful economic lives of fields are affected by the estimation of hydrocarbon reserves and resources, which is in turn impacted by available reservoir data, commodity prices and future costs. Payments (on a discounted basis) of $973m (2014: $705m) are currently anticipated within one to five years; $813m (2014: $1 093m) within six to 10 years; and $2 821m (2014: $2 807m) over 10 years.

OTHERThe balance as at 31 December 2015, includes provisions for onerous contracts of $174m (2014: $111m), field-related payments of $31m (2014: $124m), insurance costs of $73m (2014: $107m) and costs associated with disposals and restructuring of $113m (2014: $119m). The payment dates are uncertain, but are expected to be between 2016 and 2019 (2014: 2015 and 2018).

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20 CALLED UP SHARE CAPITAL

Number of shares

as at 31 December 2015m

2014m

2015$m

2014$m

Issued and fully paid up

Equity:

Ordinary shares of 10p each 3 622 3 621 580 579

For information on the rights and restrictions applying to the Company’s shares see Other disclosures section on page 27.

During the year, the Company allotted 1.45m ordinary shares of 10p each (2014: 2.51m ordinary shares) with an aggregate nominal value of $223 245 (2014: $416 703) in connection with exercises of share options issued under the Company Share Option Scheme (CSOS) and the Sharesave Plan. The consideration received on these allotments amounted to $17m (2014: $28m).

At 31 December 2015, the Company held 207.0m (2014: 209.9m) of its own shares. The market value of these shares as at 31 December 2015 was $3 005m (2014: $2 831m). The Company made the following transactions in respect of its own shares:

(i) During 2015, the Company transferred 2.9m (2014: 2.8m) of its ordinary shares to eligible employees in accordance with the terms of the Share Incentive Plan, the Long-Term Incentive Plan (LTIP) and Global Partnership Plan. The shares transferred had a nominal value of $441 446 (2014: $469 193) and represented approximately 0.1% (2014: 0.1%) of the called up share capital at 31 December 2015. The cost of shares transferred was $10m (2014: $22m).

(ii) The maximum number of shares held during the year was 209.9m ordinary shares (2014: 212.7m), representing approximately 5.8% (2014: 5.9%) of the called up share capital at 31 December 2015, and having a nominal value of $32 729 650 (2014: $35 233 224).

21 COMMITMENTS AND CONTINGENCIESA) CAPITAL EXPENDITUREAs at 31 December 2015, the Group had contractual commitments for future capital expenditure amounting to $2 920m (2014: $4 195m) of which $2 899m related to acquisition of property, plant and equipment (2014: $3 998m) and $21m related to intangible exploration assets (2014: $197m).

Included in the amount for contractual commitments for future capital expenditure is $729m (2014: $1 388m) relating to commitments under operating leases split between amounts due within one year $412m (2014: $723m), and amounts due between one and five years $317m (2014: $665m).

B) DECOMMISSIONING COSTS ON DISPOSED ASSETSBG Group has contingent liabilities in respect of the future decommissioning costs of gas and oil assets disposed of to third parties should they fail to meet their remediation obligations. The amounts of future costs associated with these contingent liabilities could be significant. The Group has obtained indemnities and/or letters of credit against the estimated amount of certain of these potential liabilities.

C) FUTURE EXPLORATION WELL COSTSAs at 31 December 2015, certain petroleum licences in which BG Group has an interest contained outstanding uncontracted obligations to drill exploration and appraisal wells. The uncontracted cost attributable to the Group in respect of these capital commitments is estimated to be $278m (2014: $384m).

D) LEASE COMMITMENTSCommitments under operating leases to be expensed to the income statement as at 31 December were as follows:

The Group Land and buildings Vessels and other FPSOs Total

2015$m

2014$m

2015$m

Restated(a)

2014$m

2015$m

2014$m

2015$m

Restated(a)

2014$m

Amounts due:

Within one year 64 70 836 614 393 282 1 293 966

Between one and five years 171 203 3 361 2 658 1 830 1 579 5 362 4 440

After five years 121 152 3 503 2 120 2 623 2 695 6 247 4 967

356 425 7 700 5 392 4 846 4 556 12 902 10 373

(a) The Group has amended the comparative lease commitment disclosure for ‘Vessels and other’ to include subsea equipment leased from an associate company. The impact of including these amounts on the previously disclosed 2014 comparatives was to increase operating lease commitments for ‘Vessels and other’ from $4 629m to $5 392m.

Certain expenditure under operating leases is recovered from third parties under partnership agreements and is excluded from the table above.

The longest dated lease, in respect of an FPSO, expires in 2029 (2014: expires in 2029).

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21 COMMITMENTS AND CONTINGENCIES CONTINUEDE) LEGAL PROCEEDINGSIn August 2009, two separate tax deficiency notices were issued against Petrobras by the São Paulo State Tax Authority based on alleged irregularities in connection with the import of a rig on behalf of the BM-S-9 Consortium (Petrobras (45% – Operator), BG E&P Brasil (30%) and Repsol Sinopec Brasil (25%)). BG Group’s potential liability arises from indemnity provisions in favour of Petrobras, as set out in the Joint Operating Agreement.

The first tax deficiency notice was issued due to the São Paulo State Tax Authority’s contention that Petrobras should not benefit from lower tax rates on the importation of a rig. Petrobras’ initial appeal of this decision was rejected by the administrative courts. However, Petrobras’ challenges at the judicial courts level have been successful with first instance and second instance decisions confirming that the São Paulo State Tax Authority was not competent to decide unilaterally where customs clearance takes place or to consider if the Consortium would be entitled to the special tax treatment. These rulings are positive decisions for the Consortium. The São Paulo State Tax Authority has filed an appeal against the second instance judicial decision to the Brazilian Superior Court of Justice and a final decision is expected in 2016.

The second tax deficiency notice issued by the São Paulo Tax Authority reflects the view that Petrobras should have recorded transfers of goods to and from a rig as if the offshore rig and the onshore base were two distinct branches of Petrobras. As such, the authorities are charging a penalty. Petrobras’ appeal at the administrative courts was rejected and it is anticipated that judicial proceedings will be brought in a manner similar to the first tax deficiency notice referred to above. This process may take up to four years to be resolved.

In 2014, the Brazilian Federal Tax Authority issued tax assessments against Petrobras in respect of the treatment of cost allocation for FPSOs, offshore service vessels and rig hire for the years 2008 to 2011 (inclusive). Some of these FPSOs, vessels and rigs were allocated to the BM-S-9 and BM-S-11 consortia. Defences and administrative appeals have been submitted by Petrobras and are pending.

BG Group’s Australian subsidiary is defending claims brought by McConnell Dowell Constructors (Aust) Pty Limited and Consolidated Contracting Company Australia Pty Limited (together, ‘MCJV’). MCJV is the main contractor for the Export and Narrows pipelines project. In March 2014, MCJV initiated ICC arbitration proceedings relating to project variations, delay and completion of milestones. The claim has been retained by BG Group in the sales process of QCLNG Pipeline Pty Limited. The arbitration hearings are ongoing and an award is not expected before mid-2016.

Various issues have been in dispute for a number of years with the Government of India in relation to the interpretation of the production sharing contracts for the Panna/Mukta and Tapti fields and related matters. An arbitral award on the merits of the issues in dispute is expected in 2016.

Where practicable to estimate the financial effects in relation to the outstanding legal proceedings detailed above, amounts have either been provided for (see note 19, page 67), or been included within the other contingency liabilities amount in subsection (F) below.

The Company and its subsidiaries are, or may from time to time be, in connection with current or past operations, involved in a number of legal or arbitration proceedings, including, for example, claims, suits, actions, investigations and/or inquiries relating to commercial, tax, environmental or other matters, with third parties or governmental or regulatory authorities. While the outcome of some of these matters cannot readily be foreseen, it is currently considered that they will be resolved without material effect on the net asset position as set out in these Financial statements.

F) CONTINGENT LIABILITIESThe amount of contingent liabilities as at 31 December 2015 (mainly the provision of guarantees, indemnities, contingent decommissioning obligations or warranties to third parties and various legal or arbitration proceedings in connection with the current and prior operations of the Group) amounted to $3 577m (2014: $7 188m), of which $142m (2014: $224m) related to the Company.

22 RELATED PARTY TRANSACTIONSIn the normal course of business BG Group provides goods and services to, and receives goods and services from, its joint ventures and associates.

The Group received and incurred the following income and charges from its joint ventures and associates:

for the year ended 31 December 2015 2014

Income$m

Charges$m

Income$m

Charges$m

LNG cargo purchases, sales and other related costs 61 (463) 118 (720)

Shipping, transportation costs and other related costs 3 (12) 2 (23)

E&P operating costs – (377) – (298)

64 (852) 120 (1 041)

BG Group provides certain guarantees in respect of its obligations to its joint ventures and associates, and its share of obligations undertaken by its joint ventures and associates, in the normal course of business.

As at 31 December 2015, a debtor balance of $18m (2014: $42m) (see note 14, page 57) and a creditor balance of $139m (2014: $258m) (see note 18, page 67) were outstanding with these parties.

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22 RELATED PARTY TRANSACTIONS CONTINUEDIn addition, BG Group provides financing to some of these parties by way of loans. As at 31 December 2015, loans of $348m (2014: $353m) were due from joint ventures and associates. These loans are accounted for as part of BG Group’s investment in joint ventures and associates and disclosed in note 12, page 56. Interest of $10m (2014: $9m) was charged on these loans during the year at interest rates of between 1.27% and 4.08% (2014: 1.25% and 3.99%). The maximum debt outstanding during the year was $353m (2014: $714m).

BG Group has a finance lease arrangement with a joint venture company. As at 31 December 2015, the obligation was $124m (2014: $130m). The lease expires in 2027.

BG Group has operating lease arrangements with associate companies in respect of FPSOs and subsea equipment. As at 31 December 2015, the obligation was $5 560m (2014: $4 609m). Charges paid during the year in respect of these leases are presented as E&P operating costs in the table. The last of these leases expires in 2029 (2014: 2029).

William Backhouse, the son of Peter Backhouse, a former Non-Executive Director who resigned during 2014, was employed by BG International Limited, a wholly owned subsidiary of BG Group plc. Peter Backhouse is regarded as interested in the contract of employment by virtue of his relationship with William Backhouse. The terms and conditions of William Backhouse’s employment are consistent with others employed in a similar role.

As at 31 December 2015, a debtor balance of $784m (2014: $1 786m) (see note 14, page 57) and a creditor balance of $9m (2014: $23m) (see note 18, page 67) were outstanding between BG Group plc and other Group undertakings.

BG Group plc grants equity instruments to subsidiaries’ employees in respect of equity-settled employee share schemes. In 2015, the fair value of equity instruments charged to the income statement was $58m (2014: $70m).

23 PENSIONS AND POST-RETIREMENT BENEFITSDuring the year ended 31 December 2015, a number of the Group’s UK employees were members of the BG Pension Scheme (BGPS), a defined benefit registered pension plan established under trust. The Trustee is BG Group Pension Trustees Limited. The BGPS is funded to cover future pension liabilities in respect of service up to the closure of the scheme. It is subject to an independent valuation at least every three years, on the basis of which the independent qualified actuary certifies the rate of employers’ contributions that, together with the returns on the BGPS’s assets, are expected to be sufficient to fund the benefits payable.

In common with all workplace pension schemes in the UK, the BGPS is subject to regulation by The Pensions Regulator. The Trustee is responsible for overall management and governance of the BGPS, including compliance with all applicable legislation and regulations. The Trustee also has responsibility for investment of the BGPS’s assets, following consultation with the Group.

The BGPS closed to future accrual of benefits on 31 December 2013 and all active members became deferred pensioners with pensions calculated based on salaries up until the point of closure for such active members. These deferred pensions are generally revalued in line with movements in the Retail Prices Index. Certain benefits relating to individual transfers-in and purchases of additional pensionable service by employees retain a link to pensionable salary post-closure.

The last full independent actuarial valuation of the BGPS for funding purposes showed that the aggregate market value of the plan assets at 31 March 2014 was £1 540m, representing 97% of the accrued liabilities. The next full funding valuation is expected to be performed with an effective date of 31 March 2017. As part of the funding agreement in respect of the 2011 actuarial valuation and the closure of the BGPS to future accrual of benefits, the Group and the Trustee established a Pension Funding Partnership (PFP) to address the deficit and to provide greater security to the Trustee.

In December 2013, the Group acquired an interest in the PFP for £110m. It also contributed £350m to the BGPS and the Trustee used this to purchase its interest in the PFP. The PFP had an interest in loans secured on four of the Group’s LNG ships, the proceeds from which the PFP were to use to make annual distributions of £33m to the BGPS for 15 years and to pay a capital sum in 2028 of £172m which would have been used, if necessary, to fund any deficit in the BGPS at that time, measured on a ‘self-sufficiency’ funding basis. In December 2014, BG Group entered into an agreement for the sale of two of these LNG ships for proceeds of $460m, which completed in March 2015. The majority of the proceeds from this sale were utilised to support the funding of the BGPS and as such the amount of ongoing annual contributions will reduce to £16.5m and the capital sum due in 2028 was revised to £86m.

The Group has taken advantage of the exemption conferred by Regulation 7 of the Partnerships (Accounts) Regulations 2008 and has, therefore, not appended the accounts of this qualifying partnership to these financial statements. Separate accounts for the PFP are not required to be, and have not been, filed at Companies House.

For scheme funding purposes, the Trustee’s interest in the PFP is treated as an asset which reduces the BGPS actuarial funding deficit. However, the PFP is not a plan asset under IAS 19 for the purposes of the Group’s consolidated financial statements and therefore does not reduce the deficit/increase the surplus on an IAS 19 accounting basis.

The Group is exposed to a number of risks relating to the BGPS. For example, additional contributions may be required if the life expectancy of the members increases or if investments underperform, compared with the assumptions adopted at the last valuation of the BGPS.

The BG Supplementary Benefits Scheme (BGSBS) provides benefits broadly in excess of the ‘lifetime allowance’. This defined benefit plan is an unfunded, non-registered arrangement. The BGSBS was closed to future accrual of benefits on 31 December 2013, the same date as benefit accrual ceased in the BGPS.

The Group has a small number of defined benefit plans outside the UK, that are not material in Group terms.

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23 PENSIONS AND POST-RETIREMENT BENEFITS CONTINUEDWith effect from 2 April 2007, new UK employees have been offered membership of a defined contribution stakeholder pension plan, the BG Group Retirement Benefits Plan (BGGRBP). With effect from 1 April 2013, the Company enhanced the BGGRBP by increasing employer’s pension contributions to 20% of salary, irrespective of the contribution rate chosen by employees. Under the BG Group Flexible Benefits system, BGGRBP members can choose to increase this percentage via salary sacrifice or to receive a proportion of the 20% contribution as cash (subject to statutory tax and National Insurance deductions). With effect from 1 December 2013, existing BGPS employee members transferred to the BGGRBP for future service. A wide range of funds is available from which members may choose how the contributions will be invested.

Independent actuaries reported on the financial position of the BGPS and the BGSBS as at 31 December 2015 in accordance with the requirements of IAS 19. The fair value of plan assets, the present value of plan liabilities and the net balance sheet surplus/(liability) were as follows:


2014$m

Fair value of plan assets 2 212 2 004

Present value of liabilities (2 076) (2 262)

Net balance sheet surplus/ (liability)(a) 136 (258)

(a) As a result of the special contribution associated with the sale of two LNG ships, the funded BGPS is in a surplus position of $205m (2014: $183m deficit). The unfunded BGSBS is in a deficit position of $69m (2014: $75m deficit). The BGPS surplus and the BGSBS deficit are separately disclosed on the face of the balance sheet in the current year. The surplus of BGPS is considered recoverable as the Group would be entitled to a refund of any surplus in the event that the BGPS were wound-up.

The following table shows the movements in the defined benefit obligation (DBO), the fair values of plan assets and the net defined benefit obligation in the period, separately identifying the impact on the income statement and other comprehensive income:

2015$m

2014$m

Defined benefit

obligation

Fair values of plan assets

Net surplus/

(liability)

Defined benefit

obligation

Fair values of plan assets

Net surplus/

(liability)

At 1 January (2 262) 2 004 (258) (2 095) 1 927 (168)

Pension (cost)/ credit to income statement:

Past service cost – – – 15 – 15

Net interest (80) 81 1 (92) 85 (7)

Subtotal recognised in the income statement: (80) 81 1 (77) 85 8

Remeasurement gains/(losses) in other comprehensive income:

Return on plan assets (excluding amounts included in net interest) – (52) (52) – 119 119

Actuarial changes arising from changes in financial assumptions 20 – 20 (225) – (225)

Actuarial changes arising from changes in demographic assumptions – – – (75) – (75)

Experience adjustments 53 – 53 18 – 18

Currency translation adjustments 119 (122) (3) 124 (116) 8

Subtotal recognised in other comprehensive income: 192 (174) 18 (158) 3 (155)

Benefits paid 74 (74) – 68 (68) –

Contributions by employer – 375 375 – 57 57

At 31 December (2 076) 2 212 136 (2 262) 2 004 (258)

Also recognised in the consolidated income statement was a $59m charge (2014: $73m) in relation to defined contribution schemes within continuing operations.

As at 31 December 2015, $2 007m of the DBO relates to the funded BGPS (2014: $2 187m) and $69m relates to the unfunded BGSBS (2014: $75m).

The weighted average duration of the DBO as at 31 December 2015 is 22 years. As at 31 December 2015, $1 377m of the DBO relates to deferred pensioners and $699m relates to pensions in payment.

The valuations as at 31 December were based on the following significant assumptions:

2015 %

2014 %

Rate of price inflation and benefit increases(a) 3.1 3.1

Discount rate 3.8 3.7

(a) Rate of increase of the majority of deferred pensions and pensions in payment in excess of any Guaranteed Minimum Pension element.

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23 PENSIONS AND POST-RETIREMENT BENEFITS CONTINUEDThe assumptions set out in the table above are those applicable to Pounds Sterling, being the currency in which the plans are denominated.

If the discount rate used for the valuation of the BGPS and BGSBS was reduced by 0.1% to 3.7%, the DBO would increase by $44m. A 0.1% increase in the inflation rate would have a similar impact on the DBO.

In determining the DBO as at 31 December 2015, mortality assumptions are based on the ‘Self Administered Pension Schemes’ (SAPS) S2 series (light) tables issued by the Institute and Faculty of Actuaries with a 98% multiplier for males and a 91% multiplier for females, appropriate to each member’s year of birth, together with an allowance for projected longevity improvements in line with the CMI’s ‘core projection’ model (2013 version), with a long-term rate of improvement of the projected mortality rates of 1.5% per annum. Based on these assumptions, the life expectancies of pensioners on the measurement date and also of pensioners in 10 years time are as follows:

Life expectancy of pensioners (years)

as at 31 December 2015 2014

2015 2025 2014 2024

Male age 60 28.9 30.1 28.8 30.0

Male age 65 24.0 25.1 23.9 24.9

Female age 60 30.7 31.9 30.6 31.8

Female age 65 25.7 26.9 25.6 26.8

If the life expectancy of a member currently age 60 was increased by one year, with consistent changes for members at other ages, the DBO in respect of the BGPS and BGSBS would increase by $54m.

While the BGPS portfolio remains weighted towards growth assets, following the closure to future accrual at the end of 2013, the Trustees, assisted by their Investment Consultant (Hymans Robertson) have developed a de-risking strategy. This strategy led to the implementation of a Liability Driven Investment (LDI) mandate in 2014 and, in 2015, to the appointment of a further three new managers to increase the diversification of the BGPS portfolio. As a result, the BGPS’s diversified investment portfolio is spread across eight (2014: five) investment managers.

Under the LDI mandate, the LDI manager (Insight Investment Management) received the BGPS’s index-linked gilt portfolio, which they use, along with a combination of conventional investments and derivative instruments, to seek to hedge a proportion of the interest rate and inflation exposure associated with the BGPS’s liabilities. As at 31 December 2015, approximately 40% of both the interest rate risk and inflation risk associated with the BGPS’s liabilities was hedged.

As at 31 December 2015, the BGPS held unquoted assets valued at $7m (2014: $4m) through its absolute return investment in the Lansdowne Developed Markets Fund and unquoted assets valued at $166m (2014: $nil) through the alternative credit investments in the M&G Illiquid Credit Opportunity Fund and the Henderson Multi-Asset Credit Fund.

As at 31 December, the fair value of plan assets was as follows:

2015 2014

Percentage of plan assets

%Value

$m

Percentage of plan assets

%Value

$m

Absolute return strategies 25 549 15 305

Liability driven investments and index-linked gilts 25 546 30 590

Alternative credit 21 457 – –

Equities(a) 20 446 38 753

Corporate bonds – – 10 204

Property funds 9 205 7 146

Money market funds and cash – 9 – 6

Fair value of plan assets 2 212 2 004

(a) Equities are invested across a globally diversified range of funds, which track benchmark general industry indices in each market.

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24 ASSETS HELD FOR SALE

The Group as at 31 December 2015

$m2014

$m

Property, plant and equipment – 2 078

Trade and other receivables – 10

Assets classified as held for sale – 2 088

Trade and other payables – (27)

Provisions for other liabilities and charges – (36)

Liabilities associated with assets classified as held for sale – (63)

Net assets classified as held for sale – 2 025

There were no assets held for sale as at 31 December 2015.

Assets held for sale as at 31 December 2014 comprised QCLNG Pipeline Pty Limited in the Upstream segment and two LNG vessels in the LNG Shipping & Marketing segment, the disposals of which completed in 2015.

25 POST BALANCE SHEET EVENTSOn 8 April 2015, the Boards of Royal Dutch Shell plc (Shell) and BG Group plc announced that they had reached agreement on the terms of a recommended cash and share offer to be made by Shell for the entire issued and to be issued share capital of BG Group plc to be effected by way of a Scheme of Arrangement under Part 26 of the Companies Act 2006 (the Scheme). On 27 January 2016, Shell shareholders voted to approve the Combination and, on 28 January 2016, BG Group plc shareholders voted to approve the Scheme at a court-convened meeting and to approve a special resolution to implement the Scheme, including amendments to the BG Group plc articles, at a general meeting of BG Group plc. Following a court hearing on 11 February 2016, the Scheme became effective on 15 February 2016.

On 15 February 2016, the Company’s shares were delisted on completion of the Combination and the Company was re-registered as a private limited company on 30 March 2016, with its immediate parent undertaking being Royal Dutch Shell plc.

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26 SUBSIDIARY AND OTHER RELATED UNDERTAKINGSSubsidiary and other related undertakings are set out below in accordance with the Companies Act 2006. Unless otherwise stated, all Group owned shares are ordinary shares. The Group does not have any individually material joint ventures or associates requiring disclosure under IFRS 12. For further details concerning the Group’s joint ventures, associates and material joint operations, see also Note 12 – Investments.

as at 31 December 2015 Country of incorporation Group holding %

A.C.N. 081 118 292 Pty Limited Australia 100.00%

Alie Investments Limited United Kingdom 100.00%

Atlantic 1 Holdings, LLC United States 26.00%

Atlantic 2/3 Holdings, LLC United States 32.50%

Atlantic 4 Holdings, LLC United States 28.89%

Atlantic LNG 2/3 Company of Trinidad and Tobago Unlimited Trinidad and Tobago 32.50%

Atlantic LNG 4 Company of Trinidad and Tobago Unlimited Trinidad and Tobago 28.89%

Atlantic LNG Company of Trinidad and Tobago Trinidad and Tobago 26.00%

Australian Oil & Gas Corporation Pty Limited Australia 100.00%

BC 789 Holdings Pty Limited Australia 100.00%

Berkshire Global Limited (In Liquidation) British Virgin Islands 100.00%

Berkshire International Investments Limited (In Liquidation) British Virgin Islands 100.00%

BG (Uruguay) S.A.(b) Uruguay 100.00%

BG 123 Limited United Kingdom 100.00%

BG 2/3 Investments Limited Trinidad and Tobago 100.00%

BG 456 Limited(c) United Kingdom 100.00%

BG 789 Limited(c) United Kingdom 100.00%

BG ABC Limited United Kingdom 100.00%

BG Alaska E&P, Inc. United States 100.00%

BG Alpha LLP(a) (Strike off in progress) United Kingdom 100.00%

BG Aruba Limited United Kingdom 100.00%

BG Asia Pacific Holdings Pte Limited Singapore 100.00%

BG Asia Pacific Pte Limited Singapore 100.00%

BG Asia Pacific Services Pte Limited(d) Singapore 100.00%

BG Asia, Inc. United States 100.00%

BG Atlantic 1 Holdings Limited Saint Lucia 100.00%

BG Atlantic 2/3 Holdings Limited Saint Lucia 100.00%

BG Atlantic 4 Holdings Limited Saint Lucia 100.00%

BG Atlantic Finance Limited United Kingdom 100.00%

BG Bolivia Corporation Cayman Islands 100.00%

BG Brasilia, LLC(a) United States 100.00%

BG Canada Limited (d) Canada 100.00%

BG Central Holdings Limited United Kingdom 100.00%

BG Central Holdings Limited Saint Lucia 100.00%

BG Central Investments Limited United Kingdom 100.00%

BG Chile S.A. Chile 100.00%

BG Comercio E Importacao Ltda. Brazil 100.00%

BG CPS Pty Limited Australia 100.00%

BG Cyprus Limited United Kingdom 100.00%

BG Delta Limited United Kingdom 100.00%

BG do Brasil Ltda. Brazil 100.00%

BG E&P Brasil Ltda. Brazil 100.00%

BG Egypt S.A. Cayman Islands 100.00%

BG Employee Shares Trustees Limited United Kingdom 100.00%

BG Energy Capital Plc United Kingdom 100.00%

BG Energy Finance, Inc. United States 100.00%

BG Energy Holdings Limited(e) United Kingdom 100.00%

BG Energy Iberian Holdings S.L. Spain 100.00%

BG Energy Marketing Limited United Kingdom 100.00%

BG Energy Merchants Canada Limited Canada 100.00%

BG Energy Merchants, LLC United States 100.00%

BG Energy Trading Limited United Kingdom 100.00%

BG Energy US Finance Limited (Strike off in progress) United Kingdom 100.00%

BG Equatorial Guinea Limited United Kingdom 100.00%

BG Exploration & Production Myanmar Pte Limited Singapore 100.00%

(a) Partnership interest(b) Bearer shares only(c) Ordinary shares and redeemable preference shares(d) Ordinary shares and preference shares(e) Ordinary shares held directly by BG Group Limited

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BG Exploration America, Inc. United States 100.00%

BG Exploration and Production India Limited Cayman Islands 100.00%

BG Exploration and Production Limited United Kingdom 100.00%

BG Exploration and Production Nigeria Limited Nigeria 100.00%

BG Finance Investments Limited United Kingdom 100.00%

BG Finance LLP(a) (Strike off in progress) United Kingdom 100.00%

BG Gas Atlantic Holdings B.V. Netherlands 100.00%

BG Gas Brazil E&P 12 B.V.(d) Netherlands 100.00%

BG Gas Brazil Holdings B.V.(d) Netherlands 100.00%

BG Gas Brazilian Investment B.V. Netherlands 100.00%

BG Gas Global Holdings B.V. Netherlands 100.00%

BG Gas International B.V. Netherlands 100.00%

BG Gas International Holdings B.V. Netherlands 100.00%

BG Gas Marketing Limited United Kingdom 100.00%

BG Gas Netherlands Holdings B.V. Netherlands 100.00%

BG Gas São Paulo Investments B.V. Netherlands 100.00%

BG Gas Services Limited United Kingdom 100.00%

BG Gas Supply (UK) Limited United Kingdom 100.00%

BG Gas Supply Trinidad Limited Trinidad and Tobago 100.00%

BG General Holdings Limited United Kingdom 100.00%

BG General Investments United Kingdom 100.00%

BG General Partner Limited United Kingdom 100.00%

BG Global Employee Resources Limited United Kingdom 100.00%

BG Global Energy Limited United Kingdom 100.00%

BG Great Britain Limited United Kingdom 100.00%

BG Group Company Secretaries Limited United Kingdom 100.00%

BG Group Employee Benefit Trust Limited United Kingdom 100.00%

BG Group Employee Shares Trustees Limited United Kingdom 100.00%

BG Group Healthcare Trustee Limited United Kingdom 100.00%

BG Group Mexico Exploration, S.A. de C.V Mexico 100.00%

BG Group Mexico Services, S.A. de C.V Mexico 100.00%

BG Group Pension Trustees Limited United Kingdom 100.00%

BG Group Trustees Limited United Kingdom 100.00%

BG Gulf Coast LNG, LLC(a) United States 100.00%

BG Hasdrubal Limited United Kingdom 100.00%

BG India Energy Private Limited India 100.00%

BG India Energy Services Private Limited India 100.00%

BG India Energy Solutions Private Limited India 100.00%

BG Insurance Company (Singapore) Pte Limited Singapore 100.00%

BG Intellectual Property Limited United Kingdom 100.00%

BG International (AUS) 1 Pty Limited Australia 100.00%









BG International (AUS) Alternate Limited Partnership Australia 100.00%

BG International (AUS) Finance Pty Limited Australia 100.00%

BG International (AUS) Investments Pty Limited Australia 100.00%

BG International (AUS) Limited Partnership Australia 100.00%

BG International (AUS) Pty Limited Australia 100.00%

BG International (CNS) Limited United Kingdom 100.00%

BG International Limited United Kingdom 100.00%

BG International Services AB Sweden 100.00%

BG Inversiones Argentinas S.A. (In Liquidation) Argentina 100.00%

BG Iran Limited United Kingdom 100.00%

26 SUBSIDIARY AND OTHER RELATED UNDERTAKINGS CONTINUED


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BG Italia Power S.p.A. Italy 100.00%

BG Karachaganak Limited United Kingdom 100.00%

BG Karachaganak Trading Limited United Kingdom 100.00%

BG Kenya L10A Limited United Kingdom 100.00%

BG Kenya L10B Limited United Kingdom 100.00%

BG Lake Charles Operations, LLC(a) United States 100.00%

BG LNG Investments Limited United Kingdom 100.00%

BG LNG Regas India Private Limited India 100.00%

BG LNG Services, LLC(a) United States 100.00%

BG LNG Trading, LLC United States 100.00%

BG LNG Transport No.3 Limited United Kingdom 100.00%

BG LNG Transport No.5 Limited United Kingdom 100.00%

BG Manatee Limited Trinidad and Tobago 100.00%

BG Mauritius LNG Holdings Limited Mauritius 100.00%

BG Mongolia Holdings Limited United Kingdom 100.00%

BG Mumbai Holdings Limited Mauritius 100.00%

BG Myanmar Pte Limited Singapore 100.00%

BG Netherlands Financing United Kingdom 100.00%

BG Netherlands United Kingdom 100.00%

BG Norge AS Norway 100.00%

BG Norge Exploration Limited United Kingdom 100.00%

BG Norge Limited United Kingdom 100.00%

BG North America, LLC United States 100.00%

BG North Investments Limited United Kingdom 100.00%

BG North Sea Holdings Limited United Kingdom 100.00%

BG Oil Marketing Pte Limited Singapore 100.00%

BG OKLNG Limited United Kingdom 100.00%

BG Omikron Limited United Kingdom 100.00%

BG Overseas Holdings Limited United Kingdom 100.00%

BG Overseas Investments Limited United Kingdom 100.00%

BG Overseas Limited United Kingdom 100.00%

BG Pacific Holdings Pty Limited Australia 100.00%

BG Pacific Investments Limited (In Liquidation) British Virgin Islands 100.00%

BG Pension Funding Scottish Limited Partnership(a) United Kingdom 100.00%

BG Petroleo & Gas Brasil Ltda Brazil 100.00%

BG Production Company (PA), LLC(a) United States 100.00%

BG Production Company (WV), LLC(a) United States 100.00%

BG Puerto Rico, Corp. Puerto Rico 100.00%

BG Rosetta Limited United Kingdom 100.00%

BG Singapore Gas Marketing Pte Limited Singapore 100.00%

BG Singapore Gas Supply Pte Limited Singapore 100.00%

BG Singapore Limited United Kingdom 100.00%

BG South Asia LNG Limited United Kingdom 100.00%

BG South East Asia Limited United Kingdom 100.00%

BG Subsea Well Project Limited United Kingdom 100.00%

BG Tanzania Holdings Limited United Kingdom 100.00%

BG Tanzania Limited United Kingdom 100.00%

BG Thailand Limited United Kingdom 100.00%

BG Thailand Pte. Limited Singapore 100.00%

BG Trinidad 5(A) Limited United Kingdom 100.00%

BG Trinidad and Tobago Limited United Kingdom 100.00%

BG Trinidad Block E Limited United Kingdom 100.00%

BG Trinidad Central Block Limited Trinidad and Tobago 100.00%

BG Trinidad LNG Limited United Kingdom 100.00%

BG Tunisia Limited United Kingdom 100.00%

BG Tunisia LPG S.A. Tunisia 100.00%

BG UK Capital II Limited(d) United Kingdom 100.00%

BG UK Capital Limited(d) United Kingdom 100.00%

BG UK Holdings Limited United Kingdom 100.00%



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BG Upstream A Nigeria Limited Nigeria 100.00%

BG US Gathering Company, LLC(a) United States 100.00%

BG US Production Company, LLC(a) United States 100.00%

BG US Services, Inc. United States 100.00%

BG West Indies No. 2 Limited Saint Lucia 100.00%

BG XYZ Limited United Kingdom 100.00%

BGMEP, LLC Mongolia 100.00%

BNG (Surat) Pty Limited Australia 100.00%

Brazil Crude Services, LLC(a) United States 100.00%

Brazil Shipping I Limited United Kingdom 100.00%

Brazil Shipping II Limited United Kingdom 100.00%

Brindisi LNG S.p.A. Italy 100.00%

British Gas (Malaysia) S.A. Cayman Islands 100.00%

British Gas Corporation Limited United Kingdom 100.00%

British Gas International Limited United Kingdom 100.00%

Burullus Gas Company S.A.E. Egypt 25.00%

Condamine 1 Pty Limited Australia 100.00%




Condamine Power Station Pty Limited Australia 100.00%

Dinarel S.A. Uruguay 50.00%

Dragon LNG Group Limited United Kingdom 50.00%

Dragon LNG Limited United Kingdom 100.00%

Egypt LNG Shipping Limited Bermuda 25.00%

El Behera Natural Gas Liquefaction Company S.A.E. Egypt 35.50%

Exco Appalachia Midstream, LLC(a) United States 50.00%

Exco Resources (PA), LLC(a) United States 50.00%

Fahari Gas Marketing Company Limited United Republic of Tanzania 52.80%

Gas Link S.A. Argentina 51.00%

Gas Resources Limited Cayman Islands 100.00%

Gasoducto Cruz Del Sur S.A Uruguay 40.00%

Guara B.V. Netherlands 30.00%

Hamilbent Pty Limited Australia 100.00%

Hydrocarbons Offshore Services Limited (Strike off in progress) United Kingdom 100.00%

Idku Natural Gas Liquefaction Company S.A.E. Egypt 38.00%

Interstate Pipelines Pty Limited Australia 100.00%

Iqara Holdings Limited (Strike off in progress) United Kingdom 100.00%

Iqara Limited (Strike off in progress) United Kingdom 100.00%

Karachaganak Petroleum Operating B.V. Netherlands 29.25%

Karachaganak Project Development Limited United Kingdom 38.00%

Lake Charles Exports, LLC United States 80.00%

Laurentide E&P, LLC(a) United States 100.00%

Mahanagar Gas Limited India 49.75%

Methane Services Limited(d) United Kingdom 100.00%

Mzalendo Gas Processing Company Limited United Republic of Tanzania 52.80%

New South Oil Pty Limited Australia 100.00%

Ome Resources Australia Pty Limited Australia 100.00%

Petroleum Exploration Australia Pty Limited Australia 100.00%

Petroleum Resources (Thailand) Pty Limited Australia 100.00%

Point Fortin LNG Exports Limited Trinidad and Tobago 45.89%

Prince Rupert LNG Exports Limited Canada 100.00%

Prince Rupert LNG Limited Canada 100.00%

Pure Energy Resources Pty Limited Australia 100.00%

QCLNG Common Facilities Company Pty Limited Australia 100.00%

QCLNG Land Pty Limited Australia 100.00%

QCLNG Operating Company Pty Limited(f) Australia 75.00%

QCLNG Train 1 UJV Manager Pty Limited Australia 100.00%

QCLNG Train 2 Pty Limited Australia 100.00%



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QCLNG Train 2 UJV Manager Pty Limited Australia 100.00%

QGC (B7) Pty Limited Australia 100.00%

QGC (Berwyndale South) Pty Limited Australia 100.00%

QGC (Exploration) Pty Limited Australia 100.00%

QGC (Infrastructure) Pty Limited Australia 100.00%

QGC Northern Forestry Pty Limited Australia 100.00%

QGC Pty Limited Australia 100.00%

QGC Sales Qld Pty Limited Australia 100.00%

QGC Train 1 Pty Limited Australia 100.00%

QGC Train 1 Tolling Pty Limited Australia 100.00%

QGC Train 2 Tolling No.2 Pty Limited Australia 100.00%

QGC Train 2 Tolling Pty Limited Australia 100.00%

Queensland Curtis LNG Pty Limited Australia 100.00%

Queensland Gas Company Pty Limited Australia 100.00%

Rashid Petroleum Company S.A.E. Egypt 40.00%

Roma Petroleum Pty Limited Australia 100.00%

Ruvuma Pipeline Company Limited United Republic of Tanzania 52.80%

Schooner Trustees Limited United Kingdom 100.00%

Sga (Queensland) Pty Limited Australia 82.14%

Sgai Pty Limited Australia 82.16%

Starzap Pty Limited Australia 100.00%

Sunshine 685 Pty Limited Australia 100.00%

Sunshine Gas Pty Limited Australia 100.00%

Tanzania LNG Limited United Republic of Tanzania 100.00%

Thai Energy Company Limited Thailand 100.00%

The Egyptian LNG Company S.A.E. Egypt 35.50%

The Egyptian Operating Company for Natural Gas Liquefaction Projects S.A.E. Egypt 35.50%

The International School of Port of Spain Limited Trinidad and Tobago 25.00%

TRINLING Limited Trinidad and Tobago 50.00%

Tunisian Processing S.A. Tunisia 100.00%

Tupi B.V. Netherlands 25.00%

Walloons Coal Seam Gas Company Pty Limited(f) Australia 75.00%

Walloons Electricity Co. Pty Limited Australia 100.00%

Westcoast Connector Gas Transmission Limited Canada 50.00%


(a) Partnership interest(b) Bearer shares only(c) Ordinary shares and redeemable preference shares(d) Ordinary shares and preference shares(e) Ordinary shares held directly by BG Group Limited(f) 100% of ordinary shares are Group owned, 100% of redeemable preference shares are held by CNOOC Gas and Power (AUS) Investment Pty Limited.

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BG Group publishes certain additional information in a non-statutory format in order to provide readers with an increased insight into the underlying performance of the business. The measures the Group uses are explained below.BUSINESS PERFORMANCEBusiness Performance excludes discontinued operations and disposals, certain re-measurements and impairments and certain other exceptional items (see below) as exclusion of these items provides a clear and consistent presentation of the underlying operating performance of the Group’s ongoing business.

BG Group uses commodity instruments to manage price exposures associated with its marketing and optimisation activity. This activity enables the Group to take advantage of commodity price movements. It is considered more appropriate to include both unrealised and realised gains and losses arising from the mark-to-market of derivatives associated with this activity in Business Performance.

DISPOSALS, CERTAIN RE-MEASUREMENTS AND IMPAIRMENTSBG Group’s commercial arrangements for marketing gas include the use of gas sales contracts. While the activity surrounding these contracts involves the physical delivery of gas, certain gas sales contracts are classified as derivatives under the rules of IAS 39, ‘Financial Instruments: Recognition and Measurement’, and are required to be measured at fair value at the balance sheet date. Unrealised gains and losses on these contracts reflect the comparison between current market gas prices and the actual prices to be realised under the gas sales contracts, and are disclosed separately as disposals, re-measurements and impairments.

BG Group also uses commodity instruments to manage certain price exposures in respect of optimising the timing and location of its physical gas, LNG and oil sales commitments. These instruments are also required to be measured at fair value at the balance sheet date under IAS 39 and, where practical, have been designated as formal hedges. However, IAS 39 does not always allow the matching of fair values to the economically hedged value of the related commodity, resulting in unrealised movements in fair value being recorded in the income statement. These movements in fair value, together with any unrealised gains and losses associated with discontinued hedge-accounting relationships that continue to represent economic hedges, are disclosed separately as disposals, re-measurements and impairments.

BG Group also uses financial instruments, including derivatives, to manage foreign exchange and interest rate exposure. These instruments are required to be recognised at fair value or amortised cost on the balance sheet in accordance with IAS 39. Most of these instruments have been designated either as hedges of foreign exchange movements associated with the Group’s net investments in foreign operations, or as hedges of interest rate risk. Where these instruments represent economic hedges but cannot be designated as hedges under IAS 39, unrealised movements in fair value, together with foreign exchange movements associated with the underlying borrowings and certain inter-company balances, are recorded in the income statement and disclosed separately as disposals, re-measurements and impairments.

Realised gains and losses relating to the instruments referred to above are included in Business Performance. This presentation best reflects the underlying performance of the business since it distinguishes between the temporary timing differences associated with re-measurements under IAS 39 rules and actual realised gains and losses.

BG Group has also separately identified profits and losses associated with the disposal of non-current assets, impairments of non-current assets and certain other exceptional items, including taxation, as they require separate disclosure in order to provide a clearer understanding of the results for the period.

For a reconciliation between Total Results and Business Performance, and details of disposals, re-measurements and impairments, see note 1, page 42, note 4, page 49 and note 8, page 53.

NET BORROWINGS AND RETURN ON AVERAGE CAPITAL EMPLOYEDBG Group provides a reconciliation of net borrowings and an analysis of the amounts included within net borrowings as this is an important liquidity measure for the Group.

Return on average capital employed represents Business Performance profit (excluding disposals, re-measurements and impairments) excluding net finance costs/(income) on net borrowings, as a percentage of average capital employed.

FREE CASH FLOWFree cash flow is defined in the Glossary, page 80.

Additional informationPresentation of non-GAAP measures

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FOR THE PURPOSE OF THIS REPORT THE FOLLOWING DEFINITIONS APPLY:

API American Petroleum Institute

CATS Central area transmission system

CNOOC China National Offshore Oil Corporation

DD&A Depreciation, depletion and amortisation

E&P Exploration and production

EBIT Earnings before interest and tax

EBITDA Earnings before interest, tax, depreciation and amortisation, including post-tax results of joint ventures and associates

EY Ernst & Young LLP

EU European Union

FPSO Floating production, storage and offloading (vessel)

GAAP Generally accepted accounting principles

GHG Greenhouse gas

IAS International Accounting Standard

IEA International Energy Agency

IFRS International Financial Reporting Standards

IPIECA The global oil and gas industry association for environmental and social issues

LNG Liquefied natural gas

BG Group or the Group

BG Group plc and its subsidiary undertakings, joint ventures and associated undertakings

Capital investment

Expenditure on property, plant and equipment, other intangible assets and investments, including business combinations

Capital investment on a cash basis

Cash flows on purchase of property, plant and equipment and intangible assets, loans to joint ventures and associates, and investments in subsidiaries, joint ventures and associates

Coal seam gas

Gas trapped in underground coal seams by water and ground pressure

Combination The acquisition of the entire issued and to be issued share capital of BG Group plc by Royal Dutch Shell plc announced 8 April 2015, and effective on 15 February 2016.

the Company BG Group plc

Delivered volumes

Comprise all LNG volumes discharged in a given period, excluding LNG utilised by the ships

Discovered resources

Defined by BG Group as being the best estimate of discovered recoverable hydrocarbons where commercial and/or technical maturity is such that the initiation of development is subject to certain conditions and therefore sanction is not expected within the next few years

E&P EBIT/EBITDA margin

E&P EBIT/EBITDA before exploration charge divided by net production for the period

Extended well test

A test to evaluate production and characteristics of a reservoir

Forward curve

A series of current market prices or rates applicable to commodities or financial instruments for specific dates in the future

Free cash flow

Net cash flow from operating and investing activities after tax and interest but before disposals

Frontier acreage

Areas where little or no exploration activity has taken place

bbl Barrel

billion or bn One thousand million

boe Barrels of oil equivalent. BG Group uses a conversion factor of 1 boe equals 6 000 cubic feet of natural gas

boed Barrels of oil equivalent per day

bopd Barrels of oil per day

CO2e Carbon dioxide equivalent

kboed Thousand barrels of oil equivalent per day

kbopd Thousand barrels of oil per day

kt Thousand tonnes

m Million

mmboe Million barrels of oil equivalent

mmbtu Million British thermal units

mt Million tonnes

mtpa Million tonnes per annum

therm Approximate energy equivalent of burning 100 cubic feet of natural gas

OGP International Association of Oil and Gas Producers

OPEC The Organization of the Petroleum Exporting Countries

QCLNG Queensland Curtis LNG

QGC QGC Pty Limited, Australia

ROACE Return on average capital employed. Represents Business Performance earnings over the past 12 months, excluding net finance costs / income on net borrowings, as a percentage of average capital employed over the past 12 months

SEC The United States Securities and Exchange Commission

SPE-PRMS Petroleum Resources Management System published by the Society of Petroleum Engineers, American Association of Petroleum Geologists, World Petroleum Council and the Society of Petroleum Evaluation Engineers

TRCF Total recordable case frequency – total recorded incidents per million work hours

WDDM West Delta Deep Marine

Further acronyms are also defined in the Remuneration report on page 18.

Fugitive Fugitive gas emissions refers to gases that escape from the production, transportation or storage of oil and gas

Gearing Ratio of net borrowings to total shareholders’ funds (excluding balances associated with commodity financial instruments and related deferred tax) plus net borrowings

Lifting costs Costs of producing oil and gas after drilling is completed

LNG Shipping & Marketing

LNG shipping, marketing and interests in regasification businesses

Net debt/net borrowings

Comprise cash, current asset investments, finance lease liabilities/assets, currency and interest rate derivative financial instruments and short and long-term borrowings. Excludes net borrowings in respect of assets classified as held for sale

Probable reserves

Those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves

Proved reserves

Those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated within reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods and government regulations. Proved developed reserves are those reserves that can be expected to be recovered through existing wells and with existing equipment and operating methods. Proved undeveloped reserves comprise total proved reserves less total proved developed reserves

Risked exploration

Risked exploration resources are defined by BG Group as the best estimate (mean value) of recoverable hydrocarbons from undiscovered accumulations multiplied by the chance of success

Spot A charter for a particular vessel to move a single cargo between specified ports in the immediate future. The contract rate (‘spot’ rate) covers total operating expenses

Spud(ded) To start the well drilling process

Tight Relatively impermeable reservoir rock. Stimulation of tight formations can result in increased production from formations that previously might have been abandoned or been produced uneconomically

Total capital investment

Expenditure on property, plant and equipment, other intangible assets and investments, including business combinations

Total operating profit

Operating profit plus share of pre-tax operating results from joint ventures and associates

Total resources

Defined by BG Group as being the aggregate of proved and probable reserves plus discovered resources and risked exploration. Total resources may also be referred to as total reserves and resources

Unit operating costs/ expenditure per boe

Calculated by dividing production and other operating costs (royalties) by the net production for the period. This measure does not include the impact of depreciation and amortisation costs and exploration costs as they are not considered to be costs associated with the operation of producing assets

Upstream Exploration & Production and LNG liquefaction businesses

Acronyms

Terms – explained

Unit of measurement

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BG Group Limited 100 Thames Valley Park Drive Reading, Berkshire RG6 1PT United Kingdom

www.shell.com/investor

Registered in England & Wales No. 3690065

Designed and produced by Addison Group www.addison-group.net

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