A global portfolio Data Book 2014 OUR VISION

BG Group’s vision is to be an internationally diversified exploration and production company with a specialism in gas and LNG.

KEY DATA FOR THE YEAR ENDED 31 DECEMBER

E&P reserves and resources(1) Oil and gas production 2013 E&P production volumes (mmboe) (%) (kboed) 18 511 18 000 17 130 17 721 17 771 700 16 180 644 646 641 657 633 15 000 14 494 600 500 12 000 400 9 000 300 6 000 200

3 000 100

0 0 2009 2010 2011 2012 2013 2013 2009 2010 2011 2012 2013 SECSSEC SEC SEC SEC PE- PRMS Egypt 18% USA 9% Bolivia 6% Gas Proved reserves Discovered resources UK 16% Thailand 6% Australia 4% Oil & liquids Probable reserves Risked exploration Kazakhstan 15% Brazil 6% India 3% Trinidad and Tunisia 6% Norway <1% (1) See page 4 for reserve and resource definitions. Tobago 11% www.bg-group.com 01

CONTENTS

COUNTRIES STATISTICAL SUPPLEMENT 05 Brazil 38 Introduction and legal notices 08 Australia 39 People and communities 11 Egypt 40 Group financial data 13 United Kingdom 42 Exploration and Production 16 Norway 48 Liquefaction 17 Kazakhstan 48 LNG Shipping & Marketing 19 Trinidad and Tobago 49 Oil Marketing 22 United States of America 50 Corporate information 23 Canada 24 Thailand 25 Tunisia MORE ONLINE 26 Bolivia The BG Group Data Book can be found 27 India online at www.bg-group.com/reports 28 Tanzania Other detailed corporate reports, 29 Kenya including the Annual Report and Accounts, 29 Madagascar and the Sustainability Report, 30 Uruguay can be found at the same address. 30 Honduras 31 Colombia Cover image 31 Aruba Survey vessel MV Geo Coral, 32 Myanmar offshore Tanzania The survey vessel MV Geo Coral undertaking 32 Singapore a seismic survey. The seismic survey vessel 33 Areas of Palestinian Authority and the equipment it tows create a footprint 34 Global Energy Marketing 8.5 km long and 1 km wide. Image courtesy and Shipping of CGG.

Inside cover image Workers on the Dolphin platform, Trinidad and Tobago The Dolphin field is part of the BG Group-operated East Coast Marine Area (ECMA), located 83 km off the east coast of Trinidad. Production commenced in 1996.

Upstream total operating profit(2) LNG delivered volumes LNG Shipping & Marketing ($m) (mtpa) total operating profit(2) ($m)

8 000 14 13.1 3 000 12.9 12.8 2 643 12 12.1 2 577 10.9 2 500 2 282 6 000 5 439 5 467 10 2 121 2 135 4 967 2 000 4 092 8 4 000 3 504 1 500 6 1 000 4 2 000 2 500

0 0 0 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013

(2) Business performance (see page 38 for a description). (2) Business performance (see page 38 for a description). 02 Data Book 2014

WHERE WE WORK

BG Group has interests in more than 20 countries on five continents. The Group has two business segments: Upstream and LNG Shipping & Marketing.

Upstream – Exploration and Production

Upstream – Liquefaction

LNG Shipping & Marketing

CANADA

UNITED STATES OF AMERICA

HONDURAS

ARUBA TRINIDAD AND TOBAGO

COLOMBIA BG Group’s strategy is to create value by leveraging its distinctive capabilities in exploration and from its unique LNG business. BRAZIL The Group’s Upstream production is currently sourced from base assets in 10 countries and key growth projects in Brazil and Australia. Wide BOLIVIA geological technical expertise combined with commercial agility enables the Group to access exploration opportunities, targeting low-cost early entry positions. BG Group also explores at existing hubs, aiming to leverage basin knowledge and existing infrastructure. URUGUAY In LNG, the Group’s skills and capabilities span the whole LNG value chain.

* Business performance – see page 38 for description. www.bg-group.com 03

OUR BUSINESS SEGMENTS

UPSTREAM LNG SHIPPING & MARKETING BG Group explores for, develops, produces and markets gas BG Group purchases, ships, markets and sells LNG. The LNG and oil around the world. The Upstream business segment Shipping & Marketing segment covers these activities, covers exploration and production activities plus liquefaction as well as the Group’s interests and capacity in operations associated with integrated LNG projects. regasification facilities.

TOTAL OPERATING PROFIT TOTAL OPERATING PROFIT Business performance* Business performance* $4 967m -9% $2 643m +3% 2012 $5 467m 2012 $2 577m

NORWAY

UNITED KINGDOM

KAZAKHSTAN

TUNISIA AREAS OF PALESTINIAN AUTHORITY

EGYPT

INDIA MYANMAR

THAILAND

SINGAPORE

KENYA

TANZANIA

MADAGASCAR

AUSTRALIA 04 Data Book 2014

DEFINITIONS

For the purpose of this document the following definitions apply:

‘2D’ Two-dimensional seismic ‘HoA’ Heads of Agreement ‘3D’ Three-dimensional seismic ‘HPHT’ High-pressure high-temperature ‘$’ or ‘US$’ US Dollars ‘JV’ Joint venture ‘£’ or ‘UK£’ UK Pounds Sterling ‘kboed’ Thousand barrels of oil equivalent per day ‘bbls’ Barrels ‘kbopd’ Thousand barrels of oil per day ‘bcf’ Billion cubic feet ‘km’ Kilometres ‘bcfd’ Billion cubic feet per day ‘LNG’ Liquefied Natural Gas ‘bcma’ Billion cubic metres per annum ‘LPG’ Liquefied Petroleum Gas ‘BGGM’ BG Gas Marketing Ltd ‘m’ Million ‘BG Group’ BG Group plc and its subsidiary undertakings, ‘mmbbls’ Million barrels of oil or ‘the Group’ joint ventures or associated undertakings ‘mmboe’ Million barrels of oil equivalent ‘billion’ or ‘bn’ One thousand million ‘mmboed’ Million barrels of oil equivalent per day ‘boe’ Barrels of oil equivalent. BG Group uses a conversion ‘mmbtu’ Million British thermal units factor of 1 boe equals 6 000 cubic feet of natural gas ‘mmscfd’ Million standard cubic feet per day ‘boed’ Barrels of oil equivalent per day ‘MoU’ Memorandum of Understanding ‘bopd’ Barrels of oil per day ‘mtpa’ Million tonnes per annum ‘BSR’ Buoyancy supported riser ‘NBP’ National Balancing Point ‘CIF’ Carriage, insurance and freight ‘P10’ At least a 10% probability that the quantities actually ‘cm’ Cubic metre recovered will equal or exceed the high estimate ‘CNG’ Compressed natural gas ‘P90’ At least a 90% probability that the quantities actually ‘CPP’ Central processing plant recovered will equal or exceed the low estimate ‘CSG’ Coal seam gas ‘partner’ An entity with whom BG Group has formed an ‘DCQ’ Daily Contracted Quantity incorporated or unincorporated association or joint venture for the purposes of pursuing its business ‘delivered volumes’ Comprises all LNG volumes discharged in a given activities and the term “partner” in this context is period, excluding LNG utilised by the ships not intended to, nor shall be deemed to, create or ‘DoC’ Declaration of Commerciality constitute a partnership between BG Group and ‘DES’ Delivered ex-ship any such entity for the purposes of the Partnership Act 1890 or any similar law in any jurisdiction in which ‘DST’ Drill stem test such activities may be conducted ‘E&P’ Exploration and Production ‘PDO’ Plan for development and operation ‘EMA’ Energy Marketing Authority ‘PJ’ Petajoules ‘ESMA’ European Securities and Markets Authority ‘PSC’ Production Sharing Contract ‘EWT’ Extended well test ‘SEC’ The United States Securities and Exchange Commission ‘FEED’ Front End Engineering Design ‘SLWR’ Steel lazy wave riser ‘FCS’ Field compression station ‘SPA’ Sale and Purchase Agreement ‘FOB’ Free On Board ‘SPE PRMS’ Petroleum Resources Management System published ‘FPSA’ Final Production Sharing Agreement by the Society of Petroleum Engineers ‘FPSO’ Floating production, storage and offloading vessel ‘TBC’ To be confirmed ‘FSO’ Floating, storage and offloading vessel ‘tcf’ Trillion cubic feet ‘HIIP’ Hydrocarbons initially in place ‘WAG’ Water alternating gas

RESERVES AND RESOURCES Proved reserves Discovered resources From the year ended 31 December 2013 onwards BG Group utilises Discovered resources are defined by BG Group as the best estimate of the Petroleum Resources Management System published by the Society recoverable hydrocarbons where commercial and/or technical maturity of Petroleum Engineers (SPE PRMS) definition of proved reserves. is such that project sanction is not expected within the next three years. Proved reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable Risked exploration certainty to be commercially recoverable, from a given date forward, Risked exploration resources are defined by BG Group as the best from known reservoirs and under defined economic conditions, estimate (mean value) of recoverable hydrocarbons from undiscovered operating methods and government regulations. accumulations multiplied by the chance of success.

Proved developed reserves are those reserves that can be expected Total resources to be recovered through existing wells and with existing equipment Total resources are defined by BG Group as the aggregate of proved and operating methods. Proved undeveloped reserves comprise total and probable reserves plus discovered resources and risked exploration. proved reserves less total proved developed reserves. Total resources may also be referred to as total reserves and resources.

Probable reserves Further information on BG Group’s Reserves and Resources at From the year ended 31 December 2013 onwards BG Group utilises the 31 December 2013 can be found on page 134 of BG Group’s Annual SPE PRMS definition of probable reserves. Probable reserves are those Report and Accounts 2013. additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more US investors should refer to the explanatory note on page 38 certain to be recovered than possible reserves. It is equally likely that of this Data Book. actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. www.bg-group.com 05

BRAZIL

BG Group has significant interests in the Santos Basin, offshore Brazil. To date, the BM-S-9 and BM-S-11 partners have contracted 15 FPSOs to be deployed by the end of 2018. Brazil is a key growth asset for the Group.

AREAS OF OPERATION New information 0 100 km CABIÚNAS 2 ●● Lapa (formerly Carioca) Declaration of Commerciality (DoC) announced ●● First FPSO at Sapinhoá reached oil capacity MARICÁ from four producer wells BRAZIL RIO DE JANEIRO BRAZIL Key dates 1 2000 Acquired pre-salt non-operated acreage in the Santos Basin 2006 Lula (BM-S-11) oil and gas discovery CABIÚNAS

CARAGUATATUBA PIPELINE made in the Santos Basin

MARICÁ MARICÁ PIPELINE PIPELINE SOUTH PIPELINE ATLANTIC 2008 Sapinhoá announced as an oil discovery LULA MEXILHÃO OCEAN Brazil 2 on BM-S-9 Barreirinhas Basin Iara announced as an oil discovery PIPELINE on BM-S-11 BAR-M-215

BAR-M-217 2010 First permanent FPSO on Lula

BAR-M-298 commenced production

BAR-M-300 2013 First FPSO on Sapinhoá commenced production Iara BAR-M-252 Awarded 10 exploration blocks in the BAR-M-254 Barreirinhas Basin BM-S-50 Iracema BAR-M-340 BAR-M-342 BAR-M-388 Lula BAR-M-344 Lapa Sapinhoá Brazil 1 Santos Basin

Key to operations Gas pipeline Oil BG Group operated block Proposed gas pipeline Oil pipeline BG Group non-operated block

date have been exceptional. The first floating for over 95% of BG Group’s mean total reserves BG Group net production production, storage and offloading (FPSO) and resources in the Santos Basin. (kboed) vessels on the Lula and Sapinhoá fields were 40 39 brought into production around four years In 2012, BG Group received independent

32 after exploration success. As at 31 July 2014, expert certification of these resource the BM-S-9 and BM-S-11 partners have three estimates from the oil and gas consulting 25 24 permanent FPSOs from which they are firm Miller and Lents, Ltd (MLL). MLL exporting crude oil, with two more expected was given full access to BG Group’s data to be deployed before the end of 2014. and development models for these fields in 16 13 In total, 15 FPSOs have been contracted order to undertake its probabilistic analysis**. 8 for deployment by the end of 2018 on the Group’s interests in the Santos Basin. The current 15 FPSO programme in the 0 Santos Basin is expected to deliver 2.6 mmboed 2011 2012 2013 Mean total reserves and resources are of gross capacity. Gas estimated to amount to some 6 billion barrels Oil & liquids of oil equivalent (boe) net to BG Group*. The low unit cost of the Santos Basin BG Group has significant interests in three The aggregate range of total reserves and development is a result of the excellent reservoir blocks in the Santos Basin, offshore Brazil. resources net to BG Group is from 4 billion boe characteristics, which deliver high margins and The exploration success, scale of resources (P90) to 8 billion boe (P10)*. The Lula, Sapinhoá, an economic break-even at less than $40/bbl. discovered and production performance to Iracema, Iara and Lapa discoveries account

* Based on BG Group estimates, not the operator or consortium view ** MLL was not asked to differentiate reserves from total discovered resource volumes 06 Data Book 2014

SANTOS BASIN BLOCKS*

Block BG Group (%) Partners (%) Discoveries Exploration well DoC First FPSO production BM-S-9 30 Petrobras 45, Repsol Sinopec Brasil 25 Lapa 2007 2013 Expected 2016 Sapinhoá 2008 2011 2013 BM-S-11 25 Petrobras 65, Petrogal Brasil 10 Lula 2006 2010 2010 Iracema 2009 2010 Expected 2014 Iara 2008 Expected 2014 Expected 2017 BM-S-50 20 Petrobras 60, Repsol Sinopec Brasil 20 Sagitário 2013 *The BM-S-10 block was relinquished and the concession finalisation processes are underway with the ANP Upstream: E&P In December 2013, the consortium announced the by reducing the oil’s viscosity and maintaining BM-S-9 DoC for the Lapa field to the ANP, which included pressure support to aid the flow of oil towards Sapinhoá the relinquishment of the areas of Abaré, Abaré the production well head. The first WAG well In 2008, the Sapinhoá well was announced West, Iguaçu and Iguaçu Mirim. First oil from began injecting water in 2012, switching to as a discovery. In 2011, BG Group and partners a single FPSO development, the Cidade de the gas injection cycle in 2013. The second announced the Declaration of Commerciality Caraguatatuba, is expected in 2016. WAG well began injecting water in 2013. (DoC) with the Brazilian National Agency of Initial pressure support has been positive. The Petroleum, Natural Gas and Biofuels (ANP) BM-S-11 consortium continues to monitor developments for the accumulation of light oil and gas in Lula and Iracema and test elsewhere, with a WAG well expected the Sapinhoá area. The DoC marks the start The Lula discovery well was drilled in 2006 and to be connected on Lula North-East in the first of the commercial production phase for the field the Iracema discovery well, which confirmed half of 2015. and sets the licence period to run to 2038. In the presence of light oil in the north-west January 2013, first production from the Sapinhoá of the evaluation area, was drilled in 2009. Production from the Cidade de Paraty FPSO field commenced through the FPSO Cidade de There has been significant activity on Lula at Lula North-East commenced in June 2013 São Paulo. The installation of the buoyancy and Iracema since the original discoveries and is expected to be operating at around its supported riser (BSR) system was completed were made including appraisal wells, drill stem 120 000 bopd capacity around the end of 2014 in 2014. In May 2014, the second and third wells tests (DSTs) and EWTs, with the information from just five producing wells, following the achieved flow rates of around 34 000 bopd. gathered supporting developments. installation of the BSR system and additional With the connection and start-up of the fourth well connections. well, the FPSO reached its 120 000 bopd capacity. As at 31 July 2014, two permanent FPSOs on Lula are onstream. Production from the first At Iracema, the operator expects to install The second FPSO (Cidade de Ilhabela) at permanent FPSO on the Lula field, the Cidade the Cidade de Mangaratiba in the south of the Sapinhoá North, with capacity of up to de Angra dos Reis, commenced in October 2010. discovery in the fourth quarter of 2014, with 150 000 bopd and 212 million standard cubic The FPSO currently produces close to its a second FPSO, Cidade de Itaguai, expected feet of gas per day (mmscfd), is expected 100 000 bopd capacity from just four producing to be installed in the north in the fourth to be in operation in the second half of 2014. wells, one conventional injector well and two quarter of 2015. Both FPSOs have capacity water alternating gas (WAG) wells. WAG forms for 150 000 bopd and 283 mmscfd. Lapa (formerly Carioca) a key part of the consortium’s efforts in exploring In 2007, the Lapa well was declared a discovery the potential for enhanced oil recovery In 2014, the BM-S-11 consortium began a and in 2011, the results of an extended well test mechanisms to be deployed in the Santos Basin confidential arbitration process in accordance (EWT) on Lapa North-East indicated potential in the future. This process involves injecting with the concession agreement in response to production of approximately 28 000 bopd, water and gas alternately for certain time the ANP’s decision determining the unification above initial expectations. periods. The intention is to improve oil recovery of the Lula and Iracema discoveries. SUBSEA SCHEMATIC WAG SCHEMATIC

FPSO FPSO Cidade de Angra dos Reis Cidade de Angra dos Reis

Gas export line 2 2 O ZONE WATER WATER GAS/CO GAS/C MISCIBLE OIL BANK

Production wells Gas injector wells WAG injector wells www.bg-group.com 07

FPSO SCHEDULE Capacity Capacity Wells drilled – oil – gas – producers/ Main riser Number Name: Cidade de Location Chartered/owned Start-up (kbopd) (mmscfd) injectors* system 1 Angra dos Reis Lula Chartered 2010 (onstream) 100 177 5 / 3 Flexible 2 São Paulo Sapinhoá South Chartered 2013 (onstream) 120 177 7 / 2 BSR 3 Paraty Lula North-East Chartered 2013 (onstream) 120 177 6 / 5 BSR 4 Ilhabela Sapinhoá North Chartered 2014 150 212 6 / 3 SLWR 5 Mangaratiba Iracema South Chartered 2014 150 283 5 / 6 Flexible 6 Itaguai Iracema North Chartered 2015 150 283 3 / 0 Flexible 7 Maricá Lula Alto Chartered 2016 150 212 1 / 1 Flexible** 8 Saquarema Lula Central Chartered 2016 150 212 1 / 0 Flexible** 9 Caraguatatuba Lapa Chartered 2016 100 177 1 / 1 Flexible** 10 P66 Lula South Owned 2016-2018 150 212 1 / 0 Flexible** 11 P67 Lula North Owned 2016-2018 150 212 2 / 1 Flexible** 12 P68 Lula Ext. South Owned 2016-2018 150 212 1 / 1 Flexible** 13 P69 Lula West Owned 2016-2018 150 212 2 / 1 TBC 14 P70 Iara Horst Owned 2016-2018 150 212 0 / 0 TBC 15 P71 Iara North-West Owned 2016-2018 150 212 0 / 0 TBC * As at 30 June 2014 **The consortium intends the main system for FPSOs seven to 12 to be flexible risers, although as at 31 July 2014, these have not yet been contracted

Iara this well revealing carbonate reservoirs of good A second export route, the Cabiúnas pipeline, In 2008, BG Group announced Iara as an oil quality. The consortium continues with the is currently under construction having received discovery and in 2011, drilling on the Iara Horst activities outlined in the approved Discovery the relevant installation licences in 2014. well was successfully completed. The Iara Horst Evaluation Plan. The pipeline will span approximately well encountered good quality oil in a thick 380 kilometres and will connect the Lula field reservoir section with initial results and Oil evacuation to a terminal in Cabiúnas, 180 kilometres subsequent DST demonstrating superior During 2011, BG Group chartered the oil north-east of Rio de Janeiro. The operator reservoir characteristics to the discovery well tanker Windsor Knutsen, a conversion from a expects the pipeline to be installed in 2015, located around eight kilometres away. conventional Suezmax tanker with the capacity and its onshore gas processing plant to be to hold 1.1 million barrels (mmbbls) of crude oil, operational later in 2015. This export route In 2012, the Iara West well was drilled to transport BG Group’s equity oil from Brazil. will provide capacity for further FPSOs. successfully, confirming the westerly extension First crude oil from the Lula FPSO was lifted of the Iara accumulation. In 2013, a fourth in July 2011 and delivered in August 2011. Barreirinhas Basin appraisal well was drilled and tested with In May 2013, BG Group was awarded excellent results. Subsequently, the first The Windsor Knutsen charter has now ended operatorship of 10 offshore blocks covering high-angle well was drilled, finding similar as the Group has chartered four new Suezmax around 7 000 square kilometres in the frontier reservoir characteristics to the original Iara shuttle tankers to manage the increasing oil Barreirinhas Basin, along Brazil’s northern discovery well with the later DST results production, initially for ten years with certain equatorial margin. in line with expectations. extension options. The Samba Spirit, Lambada Spirit and Bossa Nova Spirit arrived in Brazil in In April 2014, BG Group farmed down 25% Appraisal activity continues at Iara, gathering 2013, with the Sertanejo Spirit arriving in early of its interests in the BAR-M-215, 217, 252 and data ahead of the DoC, which is due at the end 2014. All vessels are currently in operation. 254 blocks to PTT Exploration and Production of 2014. In May, a DST was undertaken at a well Oil shipping and marketing activities are Public Company Limited (PTTEP). in the south-west flowing at around 5 000 bopd managed by GEMS (see pages 34 to 36 and a further appraisal well began drilling in for details). In the first five year exploration phase, the north-east with results, including a DST, BG Group’s work programme will incorporate expected in the fourth quarter. In June, an EWT As at 31 July 2014, a total of 31 liftings of a combination of full block seismic acquisition began on the Iara-4 appraisal well in the west. around 1 mmbbls each have been made and processing and a number of wells. Seismic Initial average flow rates of around 29 000 bopd by BG Group from the three producing FPSOs acquisition will begin once the required were in line with expectations, with testing at Lula and Sapinhoá. environmental permitting has been received. to continue into the coming months. Gas evacuation Data from these activities, as well as any While the majority of the gas produced BARREIRINHAS BASIN BLOCKS additional future appraisal work, will help is initially being used for re-injection, BG Group Partners formulate the development plan for the Iara area development plans for the associated Block (%) (%) which will be submitted in 2015 after the DoC. gas resources in the Group’s Santos Basin BAR-M-298 and 340 100 Currently the consortium has allocated two interests have continued to advance. BAR-M-215, 217, 75 PTTEP FPSOs to the Iara development. 252 and 254 Brasil 25 In 2010, a new pipeline was installed BAR-M-300, 342, 50 Petrobras 40, 344 and 388 Petrogal BM-S-50 connecting the Lula field to the Mexilhão gas Brasil 10 Sagitário hub. This pipeline has been used to export In 2013, the Sagitário well, the first to be drilled on gas from the first Lula FPSO since 2011 and has BM-S-50, was declared a discovery. In May 2014, since been connected to the Sapinhoá South the consortium completed a formation test on and Lula North-East FPSOs. 08 Data Book 2014

AUSTRALIA

BG Group is developing a two-train 8.5 mtpa LNG plant supplied by coal seam gas. First LNG is expected in the fourth quarter of 2014. Australia is a key growth asset for the Group.

TOWNSVILLE

AREAS OF OPERATION BOWEN New information COLLINSVILLE Australia 1 ●● Completed 540 kilometre pipeline network ● MACKAY Surat and ● All six Ruby Jo FCSs and CPP operational Bowen Basins Key dates 2008 Alliance with Queensland Gas Company (QGC) established MORANBAH QUEENSLAND 2009 QGC acquisition completed and 1 Pure Energy acquired Queensland Curtis LNG 2010 Queensland Curtis LNG (QCLNG) CLERMONT project sanctioned ROCKHAMPTON Contract signed with CNOOC for sale 2 EMERALD BLACKWATER of 3.6 mtpa of LNG GLADSTONE 2011 Contract signed with Tokyo Gas for sale of 1.2 mtpa of LNG THANGOOL Australia 2 2013 Binding agreements signed for the sale MOURA of certain interests in the QCLNG project Cooper Basin for $1.93 billion QUEENSLAND

Export pipeline

ROMA Gas collection header MILES CHINCHILLA KOGAN Key to operations

SOUTH AUSTRALIA SOUTH SURAT CONDAMINE DALBY BRISBANE Gas pipeline QCLNG Phase 1 TARA TOOWOOMBA Gas export pipeline Bowen CSG NEW SOUTH WALES ST GEORGE 0 120 km Gas collection header Bowen Tight Gas BG Group acreage interests Surat CSG

QCLNG ●● Major shareholdings in the two-train BG Group net production BG Group is developing a two-train 8.5 mtpa liquefaction facility, including 100% (kboed) LNG plant supplied by coal seam gas (CSG). equity in common facilities such as 25 25 25 The Queensland Curtis LNG (QCLNG) plant the LNG storage tanks and jetty; and 21 ●● 20 is being built on a 270 hectare site on Curtis The 140 megawatt Condamine Island, Gladstone, on the Queensland coast. power station. 15 BG Group’s business in Australia comprises: BG Group entered Australia in 2008 via an 10 ●● Licences in four onshore areas of producing alliance with Queensland Gas Company (QGC), and potential gas supply covering a total acquiring a 20% interest in QGC’s CSG assets 5 of around 33 000 square kilometres. in the Surat Basin, southern Queensland, The project’s total reserves and resources and a 9.9% stake in QGC. After a successful 0 at the end of 2013 were around 22 tcf drilling campaign and the decision to develop a 2011 2012 2013 (net BG Group): multi-train LNG project, the Boards of BG Group Gas –– Surat Basin CSG play: producing gas and QGC agreed the terms of a takeover, Oil & liquids for the domestic market and will completed in 2009. To secure additional CSG provide production into the LNG plant; resource BG Group also acquired Pure Energy –– Bowen Basin CSG play: exploration Resources Limited in 2009. and appraisal ongoing; –– Bowen Basin tight gas sand play: Subsequently, BG Group sold certain additional exploration and appraisal ongoing; interests to CNOOC and Tokyo Gas, with CNOOC –– Cooper Basin tight gas sand and shale gas now holding 50% equity in Train 1 and Tokyo Gas plays: exploration and appraisal ongoing; holding 2.5% equity in Train 2. ●● A 540 kilometre pipeline network comprising a 200 kilometre gas collection header and a 340 kilometre export pipeline; www.bg-group.com 09

Upstream: E&P Partners QCLNG Train 1 Partners QCLNG Train 2 Production is currently sold into the domestic (%) (%) market while future production will principally supply the LNG project. On plateau, it is envisaged that gross production to supply the LNG plant and the domestic market will be around 250 000 boed.

The first phase upstream development is expected to comprise approximately 2 000 wells, rising to more than 6 000 wells over the life of the two LNG trains. Drilling is on track, with more than 2 150 wells drilled by the end of June 2014, with around 1 100 wells BG Group 50 CNOOC 50 BG Group 97.5 Tokyo Gas 2.5 available for production or dewatering. BG Group expects to drill on average 50 wells per month and at the end of July 2014 had nine drilling rigs operating in the Surat Basin. SCHEMATIC OF FACILITIES AT QCLNG PROJECT The Ruby Jo, Bellevue, Jordan and Woleebee Creek hubs in the Surat Basin will feed the WATER FOR BENEFICIAL USE QCLNG plant. In the South region, the Ruby Jo CURTIS ISLAND EXPORT MARKETS central processing plant (CPP) commenced LNG PLANT operation in April 2014, being supplied by six field compression stations (FCSs). In the Central CENTRAL PROCESSING GLADSTONE PLANT (CPP) region, three FCSs and the Bellevue CPP are WATER TREATMENT expected to be ready for operations ahead of PLANT Train 1 start-up. The Jordan and Woleebee Creek hubs will provide additional production to assist in meeting the demand from the second train coming online. In total, the Surat Basin will utilise AUSTRALIA four CPPs and 17 FCSs to supply the QCLNG plant’s two trains.

Given the dewatering and ramp up profile TEMPORARY GAS SUPPLY & ELECTRICITY of coal seam gas, BG Group is utilising both WATER STORAGE GENERATION equity gas and third-party gas to ensure the GAS WELLS LNG plant is filled to capacity. During the ramp up of the LNG plant in 2015-16 it is expected FIELD COMPRESSION COAL SEAM that short-term third-party gas will provide STATION (FCS) around 10-20% of throughput in any given year and less than 5% once on plateau. Not to scale SANTA MARTA

In 2010, BG Group and Australia Pacific LNG (APLNG) agreed a framework for the development COLOMBIA of jointly owned CSG tenements ATP 648P and expected to commence drilling in the fourth operation and has a capacity of some 6 million ATP 620P. BG Group also entered into conditional quarter of 2014. In the Bowen CSG play, litres per day. The water treatment facility at gas purchase agreements with APLNG under BG Group will focus on monitoring pilot Kenya, a 92 million litre per day plant, is also in which BG Group expects to buy 145 petajoules (PJ) production from existing well stock; a technical operation with first water exported in 2013. of gas over an initial 15 month period, reducing review is ongoing to assess the potential for The Northern water treatment plant is situated thereafter to an average of 25 PJ per annum. The further drilling. The deepening and logging at Woleebee Creek and will have a capacity start of gas sales is aligned with the start of of the first well in the current campaign in the of 100 million litres per day. commercial operations at the QCLNG project. Cooper tight gas and shale gas plays has been completed. Work is now focusing on deepening Upstream: Liquefaction Additionally, to help manage gas ramp-up, the second well with production testing due Construction of the 8.5 mtpa LNG plant BG Group has entered into an agreement with to commence in the third quarter of 2014. continues on Curtis Island. Both LNG storage AGL Energy Limited (AGL) whereby AGL will use tank roofs were raised in 2013 and hydrotesting a depleted field near Wallumbilla in the Surat Upstream: Infrastructure of the first tank was completed in the first Basin to store QGC gas for a fee for seven years BG Group has constructed a 540 kilometre quarter of 2014. Progress on the plant continues from 2011. pipeline network, comprising a 200 kilometre with the gas turbine generators having begun gas collection header and a 340 kilometre commissioning in the second quarter of 2014. Exploration and appraisal activities continue export pipeline, to link the gas fields in the Commissioning of the refrigeration turbines in order to develop the most economic resource. Surat Basin to the LNG plant on Curtis Island. and compressors is expected in the third quarter of 2014, which are important steps In the Bowen tight gas sand play, four wells BG Group treats produced water for use by prior to cooling Train 1 and producing first have been drilled and preparations are ongoing local landholders, industry and communities. LNG in the fourth quarter. for a further drilling campaign. The next well is The water treatment plant at Windibri is in 10 Data Book 2014

LNG Shipping & Marketing The agreements exclude any interest in the As a key portfolio supply source, QCLNG Train 2 liquefaction facility, pipelines and volumes will be delivered to BG Group’s QCLNG project common facilities. BG Group worldwide customers, including China, retains majority ownership of the QCLNG Japan, Singapore, India and Chile. project. In particular, BG Group has around 74% of its original interest in the upstream In 2010, BG Group signed a LNG sales contract resource and related infrastructure; and 100% with CNOOC. Under the terms of parallel of the project’s common facilities on Curtis agreements between BG Group and CNOOC: Island (including LNG storage tanks and jetty) ●● CNOOC will be supplied with 3.6 mtpa and the 540 kilometre natural gas pipeline of LNG over a 20 year period; network linking the gas fields to Curtis Island. ●● CNOOC acquired a 5% equity interest in the Together, these items represent approximately reserves and resources of certain BG Group 30% of the estimated $20.4 billion 2011-2014 tenements in the Surat Basin in Queensland; project spend. ●● CNOOC became a 10% equity investor in Train 1; and In 2011, BG Group signed a sales agreement ●● BG Group and CNOOC agreed to participate with Tokyo Gas. Under the agreement: jointly in a consortium to construct two ●● Tokyo Gas will buy 1.2 mtpa of LNG for LNG ships in China that will be owned by 20 years from 2015; the consortium. ●● Tokyo Gas acquired a 1.25% interest in the reserves and resources of certain BG Group Further, in May 2013, BG Group announced it tenements in the Walloons Fairway; and had signed a binding agreement with CNOOC ●● Tokyo Gas became a 2.5% equity investor for the sale of certain interests in the QCLNG in the second of the two liquefaction trains. project for $1.93 billion and the sale of an additional 5 mtpa of LNG from BG Group’s BG Group also signed a sales agreement with global portfolio, beginning in 2015. Additionally, Chubu Electric Power Co. Inc, (Chubu Electric) CNOOC reimbursed BG Group for its share for the long-term supply of LNG. Under the of QCLNG project expenditure incurred from agreement, Chubu Electric will purchase up 1 January 2012. In November 2013, transactions to 122 cargoes over 21 years, starting in 2014. were completed with CNOOC. The key terms of the transaction were: Condamine power station ●● BG Group sold certain interests in upstream BG Group also operates Condamine power coal seam gas tenements in Australia and station, which is fuelled by CSG produced a further equity stake in the QCLNG project at QGC’s gasfields in the Surat Basin. Train 1 liquefaction facility; With a potential generating capacity of ●● BG Group will supply CNOOC with a further 140 megawatts, the station provides power 5 mtpa of LNG for 20 years beginning in 2015, to the National Electricity Market. sourced from the Group’s global portfolio; ●● CNOOC acquired a 40% equity interest in QCLNG Train 1, increasing its equity ownership from 10% to 50%; ●● CNOOC acquired a 20% interest in the reserves and resources of certain BG Group tenements in the Walloons Fairway region of the Surat Basin, Queensland, increasing its ownership from 5% to 25%; ●● CNOOC acquired a 25% equity interest in certain other upstream tenements held by BG Group in the Surat and Bowen Basins, Queensland; ●● BG Group and CNOOC will jointly invest in the construction of two LNG ships in China, adding to the two ships already committed under the LNG agreements signed in March 2010; and ●● CNOOC will have the option to participate up to 25% in one of the potential expansion trains at QCLNG. www.bg-group.com 11

EGYPT

BG Group played a leading role in the development of Egypt’s natural gas industry, and is one of the country’s largest gas producers. The Group’s activities in Egypt span the gas chain from exploration, through development and production, to LNG.

AREAS OF OPERATION New information 0 100 km ●● BG Group issued Force Majeure under its SimSat-P2 East El Burullus LNG agreements Solar Simian, Sienna ● Serpent, Sparrow SimSat-P1 ● Notus well completed with evaluation ongoing Scarab, Saffron Silva Key dates Sapphire Mina-1 1995 Rosetta and WDDM Concessions awarded Sapsat-1 2001 Rosetta first production Sapsat-2 Sienna-Up 2003 WDDM first production Saurus MEDITERRANEAN SEA Swan Libra 2004 Additional 40% in Rosetta acquired Sama 2005 Egyptian LNG Trains 1 and 2 exports began Sequoia N. Gamasa 2013 WDDM Phase 9a sanctioned Rashid -1,-2,-3 El Burg Rashid North Harmattan Deep-1 Notus DAMIETTA LNG El Manzala

ALEXANDRIA IDKU Egyptian LNG Trains 1 & 2 PORT SAID

EGYPT

Key to operations Gas BG Group-operated block Gas pipeline BG Group non-operated block CAIRO Oil pipeline

●● Non-operated interest in the East El In January 2014, BG Group issued Force Majeure BG Group net production Burullus Offshore Concession (EEBO); and notices under its LNG agreements in Egypt (kboed) ●● Major shareholdings in the two-train reflecting the ongoing diversions of gas 150 135 132 Egyptian LNG project. volumes to the domestic market in excess of the existing pooling arrangements. Looking 120 112 Upstream development and production activities forward, the strong likelihood of continued 90 in Egypt are undertaken through joint operating diversions to the domestic market, combined companies. In the case of Rosetta, this is through with further reservoir deterioration, means 60 Rashid Petroleum Company (Rashpetco), and that the Group currently expects very limited in the case of WDDM, this is through Burullus cargoes to be lifted from Egyptian LNG for 30 Gas Company (Burullus). These operating the foreseeable future. companies are 50% owned by the Egyptian 0 General Petroleum Corporation (EGPC), the body In the second quarter of 2014, Upstream and 2011 2012 2013 representing the Egyptian government in the LNG activities in Egypt accounted for 10% Gas petroleum sector. BG Group and its partners of BG Group’s production and around 6% of Oil & liquids in each concession hold the remaining 50%. earnings from continuing operations. The book value of BG Group’s investment in Egypt as BG Group’s business in Egypt comprises: The difficult operating environment in Egypt, at 30 June 2014, including receivables, was ●● Operatorship of two gas-producing coupled with lower reserves estimates, has $2.8 billion, of which $0.2 billion relates to areas offshore the Nile Delta: led the Group to revise its expectations of the Egyptian LNG. The receivables balance was –– the Rosetta Concession; and value of its Egyptian operations. Production $1.5 billion with $1.2 billion overdue. Release –– the WDDM Concession; volumes declined throughout 2013 and 2014 as of funds for any further development, including ●● Operatorship of three other concessions a result of deteriorating reservoir performance Phase 9b, remains contingent upon an offshore the Nile Delta: and the continuing high level of diversions improvement in the investment climate –– El Manzala Offshore (EMO); to the domestic market, where the Group is including a significant improvement in the –– El Burg Offshore (EBO); and entitled to a lower share of production. outstanding receivable position. –– North Gamasa Offshore (NGO); Burullus GasCompany WDDM Concession* Rashid PetroleumCompany Rosetta Concession* (%) a shallow onshore The control water platform. the existing WDDM and gas gathering network consist 16 wells sub-sea of into The facilities tied Idku, near120 kilometres Alexandria. offshore Train 2. approximately fields arelocated These LNG to supply Egyptian field contracted is Train LNG supply Egyptian while 1, the Sapphire SimianThe to and Sienna fields arecontracted Sapphire and Sienna Simian, metres. than 700 more of depths the shore from and in kilometres 90 water approximately located terminal.are fields The pipelines by to anconnected onshore processing manifold, to asub-sea in turn connected consist eight wells sub-sea facilities of These 2003 market. and supply gas to the domestic in production started in Egypt, developments water sub-sea deep the first Saffron, Scarab, Saffron Scarab, Idku. at market LNG and Egyptian to the domestic is designed to supply gas WDDM infrastructure Sapsat-1, Sapsat-2 and Swan in production. SimSat-P2, Sequoia, Saurus, Serpent, Sapphire, Simian, Saffron, Sienna, Scarab, with 18 gas fields, haveSince discovered Group BG 1994, and partners Concession WDDM E&P Upstream: 12 Partners UNDERLYING CONTRACT STRUCTURE OF EGYPTIAN LNG

Train 2 (start date 2005) Train 1 (start date 2005) Edison BG Group Upstream BG Gas – WDDM 565 mmscfd BG Gas – WDDM 565 mmscfd supply Gas

Group Group Data Book 2014 Book Data 25 PETRONAS EGPC 40

10 50 25 50% 50% * BGGroupoperator 80 Train equity EGAS EGPC PETRONAS BG Tolling plant Train SUEZ GDF EGAS EGPC PETRONAS BG Tolling plant Train Train equity

Group 35.5% Group

12% 12%

2 –3.6 1 –3.6 50 20 50 50 38% 35.5%

mtpa mtpa

where the Egyptian LNG facilities are facilities located. LNG where the Egyptian the Idku Gas of Hub part processing form facilities oil with the Egyptian Natural Gas the Egyptian oil with Holding and of gas the exploration for agreements (EMO) (EBO) and El Burg concession Offshore Group BG In signed 2005, the El Manzala Offshore Concessions El and Offshore Burg El Manzala Offshore to existing infrastructure. back tied and Rosetta wells:sub-sea three wells WDDM each of on six consists of It in 2008. sanctioned was Concessions, the WDDM of andboundary Rosetta (BG Group 62.99%), which lies across the Phase Phase 4/WDDM 6) field the Sequoia of The unitised development (Rosetta Sequoia of Rosetta. two phases wells to the first back tied consists of five plan. project The development Phasefield 3 gasfrom the Rosetta first delivered BG Group In 2008, in 2001. production started market supplies and gas to the domestic Rosetta Concession Rosetta declines.underlying production offset temporarily only will development well onstream first Thisin July 2014. ninewell in 2013Phase the with 9a wassanctioned pipeline. 68 kilometre,a new 36-inch offshore includinggas gathering and facilities, receiving onshoreseven compressors in total and additional including installationcompression of projects, 53 wells. of sub-sea a total Phases 5and 7were the WDDM Concession has and 8b projects, the Phase2011 of and 8a 2012. the completion With and 8b delivering wells another 17sub-sea between adding three unitised wells, Sequoia and Phases 8a onstream Phase during with 6in 2009 2008, Phase additional 4broughtrecovery. wells seven hydrocarbon maximise to phases development WDDM fields The have a undergone of number phases additional WDDM 38% 12% 12% 5% Downstream BG LNG SUEZ GDF LNG purchase LNG

Group

100% 100%

BG Group farmed in Group toBG the EEBO farmed Concession in Concession ElEast Burullus Offshore hydrocarbons. commercial discover to failed year. well drilled. was well The the Opera In 2014, 3D seismicwith acquisition later that completed formalising the award wassigned in early 2010 in shallow water. concession agreement The the coast from 20 kilometres and is located an area covers 281 square of The block kilometres (NGO) block. Gamasa Offshore North of the in, and is operator Group equity BG holds 60% Concession GamasaNorth Offshore is discoveries ongoing. for both 2013. in December Evaluation the results of encountered gas at horizons anumber target of well,Notus which play, Oligocene is testing anew in 2012. The a discovery declared was Deep-1, well, incommenced 2012.Harmattan The first programme EBO on Atwo-well hydrocarbons. drilled to discover in failed commercial 2011 but in EMO, where the Zonda well equity was 50% BG Groupand EBO holds in commenced 2008. Company drilling (EGAS). Exploration on EMO reduced level. train, which asignificantly at was with one July the plant 2014, only was runningAs of restricted. severely were LNG Egyptian from pooling arrangements. Consequently, volumes market existing in of the excess to the domestic ongoing the gasof volumes diversions reflecting in Egypt agreements LNG under its notices In Group January BG 2014, issued Majeure Force 2005. September in cargo wasLNG lifted operatedissubsidiarywhich by GEMS. The first Marketing (BGGM), Group BG owned awholly under a20 sold year Gas agreement to BG been Train of capacity 2has productive mtpa 3.6 The Mayin 2005. cargowas LNG lifted first The to SUEZ GDF under sold has been a20 year SPA. Train of capacity 1 productive mtpa 3.6 The 7.2 LNG. of of mtpa capacity have aproductive fieldsSequoia in WDDM. Together, trains these the gas Simian, from with Sienna, Sapphire and LNG supply Egyptian GroupBG and partners (Train 2Co.) (BG Group 38%) owns Train 2. Company and Idku1, Natural Gas Liquefaction Company (Train 1Co.) (BG Group 35.5%) owns Train El Beheira Naturalfacilities. Gas Liquefaction all of the operation undertakes trains and common (Opco) (BG Group 35.5%) Projects Liquefaction Company Operating Natural for Gas Egyptian The company, Its sister site and facilities. common LNG the Egyptian Company LNG owns both Egyptian and utilities. loadingtanks, jetty suchinclude as facilities the common storage trains and production LNG comprise the two Idku, at located facilities, LNG Egyptian The LNG Egyptian Liquefaction Upstream: 2013 wasadry hole. in December but completed Kala-1 The 2012, interest. taking well a40% was www.bg-group.com 13

UNITED KINGDOM Faroe Island Licence T NINIA N

BREN

BG Group has a diverse E&P businessSULLOM VOE offshore UK withBedlington interests focused on the central North Sea.

AREAS OF OPERATION

0 100 km

FLOTTA

NORWAY Blake

FLAGS Maria

FRIGG Gaupe

SAGE Armada Buzzard Seymour WAGES Everest BRITANNIA

MEDIAN LINE FORTIES ST. FERGUS

FULMAR

Lomond

ABERDEEN Elgin Erskine NORTH SEA SULLOM VOE Glenelg Franklin Jackdaw FLOTTA Jade

ST.FERGUS Jasmine ABERDEEN UK Judy/Joanne

TEESSIDE NORTH CATS EASINGTON SEA SEAL Dragon LNG IRISH SEA UK BACTON Milford Energy

LANGELED READING LONDON ZEEBRUGGE NORPIPE

Key to operations Gas Gas and Oil/Condensate Gas pipeline BG Group-operated block Oil Oil pipeline BG Group non-operated block

New information Key dates ●● Jasmine first production 1993 Everest and Lomond first production 2009 Asset exchange with BP, concentrating ●● Sold interest in CATS infrastructure 1997 Armada and J-Block first production operations in the central North Sea 2001 Blake and Elgin/Franklin first production Dragon LNG operational 2002 Jade first production 2013 First production from Everest East expansion 2003 Seymour first production 2007 Buzzard, West Franklin and Maria first production 14 Data Book 2014

The Group remains interested in exploration wells, tied back to an existing floating BG Group net production opportunities and is also progressing the production, storage and offloading vessel (kboed) Jackdaw development which is in the concept (FPSO) located over the third-party Ross field 125 select phase. some 9.5 kilometres away. Development of 105 100 96 100 Phase Two, the Blake Flank, was completed and Upstream: E&P production commenced from two wells in 2003. 75 Operated assets This sub-sea development is tied back through Armada Hub Area the existing Blake facilities to the Ross FPSO. 50 The Armada gas condensate fields (Fleming, Drake and Hawkins) achieved first production Everest and Lomond 25 in 1997. The SW Seymour area of the Seymour Everest and Lomond are located in the central field was appraised successfully and drilled North Sea and first production began on each 0 from the Armada platform, with first production in 1993. Gas produced from the two fields is 2011 2012 2013 in 2003. A second well in the NW Seymour area exported via the CATS pipeline and produced Gas was brought into production in 2006 and liquids are exported via FPS to the Kinneil Oil & liquids a replacement well was drilled in 2011. processing plant.

The Maria field was developed via two sub-sea The Lomond platform also provides production BG Group’s position is focused in the central wells tied back to the Armada platform, with facilities for the Erskine field. North Sea where the Group is operator of first production in 2007. three mature platforms and infrastructure Everest field production was enhanced in hubs: Armada, Everest and Lomond. The focus The commingled stream of Armada, Seymour March 2013 with first gas from the Everest East for these assets is on maximising the remaining and Maria gas is exported via the Central Area expansion project, which comprises two value and continuing with a rigorous approach Transmission (CATS) terminal on Teesside. sub-sea wells tied back to the North Everest to maintenance and asset integrity. In parallel, Liquids are transported through the Forties platform and brownfield modifications to BG Group continues to pursue suitable Pipeline System (FPS) to the Kinneil processing the existing production system. Investment opportunities around these infrastructure plant at Grangemouth. in maintenance and asset integrity continues hubs to increase future value. on both facilities with a major flotel campaign The Armada hub also services two fields in due to start in October 2014 and last for around BG Group also has a number of important the Norwegian sector of the North Sea via six months. non-operated interests in the central North tie-backs: the third-party Rev field and the Sea: the Buzzard field operated by Nexen BG Group-operated Gaupe field. Jackdaw (a wholly-owned subsidiary of CNOOC), the The Jackdaw discovery is one of the largest Elgin/Franklin fields operated by Total and Blake undeveloped gas discoveries in the UK the J-Area fields (J-Block, Jade and Jasmine) The Blake field, located in the Outer Moray Continental Shelf. Discovered in 2005, the field operated by ConocoPhillips. Firth, had first production in 2001. The field was was appraised between 2007 and 2012. Results developed in two phases. Phase One was the from the exploration and appraisal programme Blake Channel, which is a sub-sea development are being used to evaluate potential of six producing wells and two water-injection development concepts.

Hub Field/Block BG Group First production 2013 net production Other partners (%) (kboed) (%) Operated Armada Area Armada 76.4 1997 8 Centrica 23.6 Seymour 57.0 2003 2 Centrica 43.0 Maria 36.0 2007 1 Centrica 64.0 Blake Blake 44.0 2001 4 Talisman 53.6, Idemitsu 2.4 Everest and Everest 100.0 1993 16 Lomond Lomond 100.0 1993 6 Jackdaw Jackdaw 40.9 N/A N/A Maersk 29.2, GDF 9.8, OMV 9.7, ConocoPhillips 6.5, JX Nippon 3.9 Non-operated* Buzzard Buzzard 21.7 2007 42 Nexen 43.2, Suncor Energy 29.9, Edinburgh Oil & Gas 5.2 Elgin/Franklin Area Elgin/Franklin 14.1 2001 4 Total 46.2, Eni 21.9, E.ON 5.2, ExxonMobil 4.4, Chevron 3.9, Dyas 2.2, Oranje-Nassau 2.2 Glenelg 14.7 2006 N/A** Total 49.5, E.ON 18.6, GDF SUEZ 9.3, Eni 8.0 Erskine Erskine 32.0 1997 3 Chevron 50.0, BP 18.0 J-Block and J-Block 30.5 1997 8 ConocoPhillips 36.5, Eni 33.0 Jade Area Jade 35.0 2002 5 ConocoPhillips 32.5, Chevron 19.9, Eni 7.0, OMV 5.6 Jasmine 30.5 2013 1 ConocoPhillips 36.5, Eni 33.0 * The first company listed is operator ** Glenelg was shut-in during 2013 www.bg-group.com 15

Non-operated assets The HPHT Glenelg field started production Offshore pipelines Buzzard in 2006. The field has been developed SEAL and SILK The Nexen-operated Buzzard oil field in the through a single well drilled from the BG Group has a 7.86% interest in SEAL, a Outer Moray Firth came onstream in 2007. Elgin wellhead platform. 474 kilometre gas export pipeline to the Bacton The facilities consist of a complex of four terminal. With capacity of around 1 150 mmscfd bridge-linked platforms, with oil export via Elgin/Franklin, West Franklin and Glenelg of dry gas, it has been transporting gas from FPS and gas export via the Frigg System. gas is exported through SEAL to the onshore the Elgin/Franklin and Shearwater fields In 2010, an additional processing platform to gas reception facilities at Bacton in Norfolk. since 2001. remove hydrogen sulphide and extend plateau Liquids are exported through FPS to the production was installed. Commissioning Kinneil processing plant at Grangemouth. BG Group also has a 15.98% interest in and start-up of this platform was completed the 900 metre SILK pipeline that provides in 2011. Erskine direct access from the SEAL pipeline to the Gas and liquids produced from the HPHT UK-Continent Interconnector pipeline. The development drilling programme and Erskine field, located in the central North Sea, field production plateau have continued are processed on the Lomond platform, with CATS significantly beyond initial expectations. gas then transported via the CATS pipeline In July 2014, BG Group sold its 62.78% interest The field partners anticipate sanctioning and liquids via FPS. in the CATS pipeline and terminal system. the Buzzard Phase 2 project in 2015, including The sale does not impact BG Group’s rights the development of the northern area of J-Area to capacity in CATS, as a shipper. the field plus the resumption of infill drilling The Judy/Joanne (J-Block) gas condensate/oil at the existing platform location. Estimated fields and Jade gas condensate field are LNG Shipping & Marketing total recoverable resources from the Buzzard located in the central North Sea. Production BG Group’s UK downstream activities are field are around 800 mmboe. from J-Block commenced in 1997 and from managed by GEMS and encompass LNG Jade in 2002. importation, via Dragon LNG, and energy Elgin/Franklin Area marketing. BG Group sells gas on a wholesale The high-pressure/high-temperature (HPHT) The Joanne field is a sub-sea development basis and exports gas to, and imports from, Elgin/Franklin gas condensate fields are located tied back to the manned Judy platform through mainland Europe via the Interconnector. in the Central Graben area of the central North two 5.5 kilometre pipelines. The Judy/Joanne For details, see GEMS section on pages 34 to 36. Sea and operated by Total. The fields began fields currently produce from 16 wells. production in 2001. Jade was developed using a normally In March 2013, production restarted from unmanned wellhead platform and currently three wells on Elgin/Franklin following a produces from eight wells. Production from year-long shut-in. Production is not expected Jade is exported via a sub-sea pipeline to the to recover to pre shut-down levels until 2016. Judy platform where it is commingled and processed with Judy and Joanne production. West Franklin started production in 2007. Gas processed on the Judy platform is In 2008, the West Franklin B appraisal well transported through the CATS pipeline and identified additional potential reserves liquids are transported to Teesside through and Phase 2 of the development of the the Norpipe system. West Franklin field was sanctioned. It aims to produce estimated reserves of 85 mmboe. Jasmine lies nine kilometres east of the Judy The development involves the drilling of three platform and straddles Blocks 30/6 and 30/7. wells and the installation of a new platform The development started production in tied back to the Elgin/Franklin facilities. November 2013 and comprises a wellhead Production is expected to commence in platform, with a separate bridge-linked the fourth quarter of 2014. accommodation platform, tied back via a multi-phase pipeline and a new riser platform to the existing Judy production facilities. 16 Data Book 2014

NORWAY

BG Group has 10 licences (seven as operator) offshore Norway. The Knarr FPSO is due to come onstream in the fourth quarter of 2014.

PL534

PL393

AREAS OF OPERATION Key dates 0 500 km 2003 First licence awarded BARENTS SEA 2008 Discoveries made at Gaupe and Knarr 2011 PDO for Knarr field approved

PL534 MID-NORWAY 2012 Gaupe field first production PL393 Awarded block PL638 PL522

KRISTIANSUND NYHAMNA PL688 PL638 NORWAY

Knarr SWEDEN PL679S OSLO

NNS HAUGESUND STAVANGER Key to operations CNS Gas Oil pipeline Oil BG Group-operated block Gaupe Gas pipeline BG Group non-operated UK PL143 Pipeline – proposed block or under construction

In 2008, a discovery was declared on Pi North, and operator) and PL688 (BG Group 50%), BG Group net production now renamed Gaupe. Gaupe spans PL292 were awarded in 2013. (kboed) and PL292B (BG Group 60% and operator). 5 The field began production in 2012 through Mid-Norway

4 a two-well sub-sea tie-back to the Group’s (1 licence, 1 operated) Armada infrastructure in the UK. In 2009, BG Group completed a seismic 3 3 survey on PL522 and drilled a commitment Northern North Sea (NNS) well in 2011. BG Group is currently reviewing 2 2 (4 licences, 3 operated) its acreage in mid-Norway. In 2008, a discovery was made with the 1 Jordbær exploration well (PL373S) (BG Group Barents Sea 45% and operator), renamed Knarr. The (2 licences, 1 operated) 0 development of Knarr West was integrated In 2007, the Nucula well in PL393 (BG Group 20%) 2011 2012 2013 into the Knarr project in 2011, raising gross was declared a discovery and was subsequently Gas reserves to around 80 mmboe. The Knarr FPSO appraised in 2008. Oil & liquids is due to come onstream in the fourth quarter of 2014, subject to the receipt of Norwegian The Hegg licence (PL534) (BG Group 40% Upstream: E&P regulatory approvals and favourable weather and operator), was awarded in 2009 and Central North Sea (CNS) conditions during mooring and well connection a 3D seismic survey acquired in 2010. (3 licences, 2 operated) activities. BG Group first entered Norway in the central BG Group is currently participating in the North Sea, applying its UK Central Graben In 2012, BG Group was awarded PL638 in Barents Sea South East seismic campaign expertise and experience across the Norwegian the Knarr area (BG Group 36% and operator). ahead of a possible future licence bid. median line area. Two further licences, PL679S (BG Group 60% www.bg-group.com 17

KAZAKHSTAN

BG Group is joint operator of the giant Karachaganak gas condensate field, where it has a 40 year concession, and is a shareholder in the Caspian Pipeline Consortium.

AREAS OF OPERATION 0 400 km Key dates 1997 40 year Karachaganak FPSA signed ORENBURG 2004 Phase II Karachaganak development completed First exports via CPC pipeline to Karachaganak Novorossiysk on the Black Sea BOLSHOI CHAGAN 2006 Oil exports commenced via the Atyrau-Samara pipeline 2008 Upstream and downstream cooperation KAZAKHSTAN agreements with KazMunaiGas signed 2010 CPC expansion project sanctioned Atyrau-Samara UKRAINE pipeline 2011 Start-up of the fourth liquids stabilisation train Karachaganak 2012 Binding settlement agreement RUSSIA -to-CPC pipeline resulting in KazMunaiGas joining the contractor group CPC ATYRAU

ASTRAKHAN TENGIZ CPC CASPIAN SEA

BLACK SEA NOVOROSSIYSK Key to operations Gas and Oil/Condensate Oil pipeline AKTAU Gas pipeline

Upstream: E&P The FPSA envisaged a phased development BG Group net production Karachaganak programme. Phase 2, which came onstream (kboed) Karachaganak, discovered in 1979, is one of in 2004, involved investment to enhance the 125 the world’s largest gas and condensate fields. existing facilities, construction of new gas and 102 100 98 Located in north-west Kazakhstan, it holds liquids processing and gas injection facilities, 92 estimated hydrocarbons initially in place (HIIP) workover of more than 100 wells, construction 75 totalling 9 billion bbls of condensate and 48 tcf of a 120 megawatt power station and a new of gas, with estimated gross reserves of more 650 kilometre pipeline to connect the field 50 than 2.4 billion bbls of condensate and 16 tcf of to the Caspian Pipeline Consortium (CPC) gas. Only around 10% of the HIIP has been pipeline at Atyrau. 25 recovered to date. Most of the liquids are exported to the west 0 Production from the Karachaganak field (92% in 2013), with some oil and all raw gas sold 2011 2012 2013 began in 1984. Since the signing of the Final locally and into Russia. Since 2004, oil exports Gas Production Sharing Agreement (FPSA) in 1997, have been mainly channelled via the CPC Oil & liquids the Karachaganak partners have made substantial pipeline and, since 2006, additional oil exports investment in wells, facilities and pipelines. In have been routed via the Atyrau-Samara addition to its size, Karachaganak presents the pipeline enabling sales to achieve international operators with formidable challenges because prices. In 2011, a fourth liquids stabilisation train of extreme climate swings (+/- 40 degrees commenced operation. The project increased centigrade) and the requirement to re-inject firm stabilisation capacity up to 10.3 mtpa. high pressure sour gas. 18 Data Book 2014

Karachaganak export routes and capacity Partners Karachaganak Partners Karachaganak Orenburg (%) (%) 8.4 bcma

Atyrau-Samara Orenburg 3.3 mtpa 4 mtpa

Gas re-injection KARACHAGANAK BG Group (joint operator) 29.25 LUKOIL 13.50 FIELD Eni (joint operator) 29.25 KazMunaiGas 10.00 Chevron 18.0 CPC Small refinery 8 to 9 mpta* 0.6 mtpa BG Group (joint operator) 29.25 LUKOIL 13.50 Eni (joint operator) 29.25 KazMunaiGas 10.00 Chevron 18.0

Stabilised oil Gas Capacity 2013 * Firm capacity of 7.0 mtpa plus access

Un-stabilised oil to additional capacity

In 2012, a settlement agreement between Other the Republic of Kazakhstan (the Republic) and Caspian Pipeline Consortium (CPC) Shareholders CPC (%) the Karachaganak partners was completed. BG Group has a 2% equity share in the BG Group 2.00 Under the terms of the agreement, the Republic pipeline but is entitled to 2.75 mtpa Russian government 24.00 acquired a 10% interest in the FPSA from the (55 000 bopd) of capacity (around 10% of Kazakh government 19.00 consortium for $2.0 billion cash and $1.0 billion the total), which is used to transport liquids. Chevron 15.00 non-cash consideration (pre-tax) including BG Group and the Karachaganak partners LUKARCO 12.50 the final and irrevocable settlement of all cost also have the opportunity to capture capacity ExxonMobil 7.50 recovery claims, with each of the contracting unused by other shareholders. Liquids Rosneft-Shell 7.50 companies’ equity shares reducing deliveries into CPC began in 2004 and, CPC Company 7.00 proportionately (BG Group’s share reducing in 2013, 8.3 million tonnes of liquids from Eni 2.00 from 32.5% to 29.25%). The Republic’s interest is Karachaganak were transported via CPC Oryx 1.75 held by a subsidiary of the national oil company, (BG Group 2.1 million tonnes). KPV 1.75 KazMunaiGas (KMG). The consideration under the agreement also includes the allocation In 2010, the CPC shareholders sanctioned of an additional 2 mtpa capacity in the CPC the CPC expansion project, which will more Partners Karachaganak (%) export pipeline over the remaining life of the than double capacity in three phases, with FPSA, bringing total capacity for the use of completion expected in 2016. Total gross the Karachaganak project to 10.4 mtpa on capacity will increase to 67 mtpa. Following completion of the CPC expansion project, expansion, and the allocation of an additional expected in 2016. 2 mtpa capacity to the Karachaganak partners as part of the 2012 settlement agreement, The partners are currently conducting a BG Group’s entitlement will rise to 3 mtpa number of projects aimed at extending the (60 000 bopd) while the total capacity for liquids offtake from the field. This includes BG Group and the Karachaganak partners an ongoing drilling programme comprising will increase to 10.4 mtpa. BG The Group CPC (joint expansion operator) 29.25 LUKOIL 13.50 horizontal development wells into the oil project includes the addition Eni (joint of 10 operator) pump 29.25 KazMunaiGas 10.00 rim and a number of medium-sized projects stations in Russia and Kazakhstan,Chevron 18.0 six crude intended to de-bottleneck the field’s gas oil storage tanks near Novorossiysk and processing and injection facilities. a third single-point mooring at the CPC Marine Terminal. BG Group and its partners are also working to define the next phase of major field development. The Karachaganak Expansion Project is exploring opportunities to identify the optimal method of installing additional gas handling capacity to maximise utilisation of liquid stabilisation trains as the field’s gas-oil ratio increases. Under current plans the gross production of the Karachaganak field will be maintained, although changes in production entitlement under the FPSA will lower BG Group’s net entitlement. www.bg-group.com 19

TRINIDAD AND TOBAGO

BG Group’s integrated gas operations supply the domestic market and Atlantic LNG for export, making Trinidad and Tobago one of the key supply sources for BG Group’s global LNG business.

AREAS OF OPERATION New information 0 100 km ●● Acquired remaining 25% in Block 5(c) North Coast Marine Area (NCMA) ●● Farmed in to Blocks TTDAA 5 and 6

ATLANTIC OCEAN Key dates 1996 Dolphin first production Poinsettia Chaconia TOBAGO TTDAA 5 1999 Atlantic LNG Train 1 start-up 2002 Atlantic LNG Train 2 start-up Hibiscus CARIBBEAN SEA TTDAA 6 2003 Atlantic LNG Train 3 start-up 2005 Manatee-1 discovery and Atlantic LNG Train 4 start-up East Coast Marine Area (ECMA) Petrotrin Refinery Pointe-à-Pierre 2009 New 220 mmscfd contract to supply the National Gas Company commenced Block 5(a) Block 5(c) 2010 Loran-Manatee field treaty ratified PORT OF SPAIN Starfish Endeavour 2012 Production Sharing Contract (PSC) GULF OF TRINIDAD Block E Bounty for Block 5(d) executed PARIA Victory PHOENIX PARK Central Block Block 6(b) Atlantic LNG BEACHFIELD Block 5(d) POINT FORTIN Dolphin Deep Dolphin TRINIDAD AND TOBAGO VENEZUELA Loran-Manatee Block 6(d) Key to operations Gas BG Group-operated block VENEZUELA Oil pipeline BG Group non-operated block Gas pipeline

Upstream: E&P with first gas expected in the fourth quarter BG Group net production East Coast Marine Area (ECMA) of 2014. (kboed) The BG Group-operated ECMA development 80 75 73 70 comprises the Dolphin gas field, located ECMA gas is delivered to NGC via a pipeline 83 kilometres off the east coast of Trinidad to the Poui platform where it connects to the 60 in Block 6(b), which commenced production domestic network. ECMA gas is also delivered in 1996, and the Dolphin Deep gas field in the to Atlantic LNG through a second offshore 40 adjacent Block 5(a), which started up in 2006. pipeline, bringing gas from the Dolphin platform Both Dolphin and Dolphin Deep are contracted to shore at the Beachfield receiving terminal. to supply domestic gas to the National Gas It then connects to NGC’s 76 kilometre onshore 20 Company (NGC) and LNG exports to BG Gas Cross Island Pipeline extending from Beachfield Marketing (BGGM), a wholly owned BG Group to Atlantic LNG at Point Fortin. 0 subsidiary which is operated by GEMS, via 2011 2012 2013 Atlantic LNG Train 3 and Atlantic LNG Train 4. In 2005, BG Group and partner completed Gas the Manatee-1 well in Block 6(d), which Oil & liquids The gas is produced under a Combined indicated gross resources of 1.8 tcf. This Development Plan for the fields in Blocks 5(a), discovery demonstrated the extension of the 6(b) and E. Production is currently delivered Loran field from Venezuela into Block 6(d) in from the Dolphin field through 13 platform Trinidad and Tobago. In 2010, the governments wells, and the Dolphin Deep field from two of Trinidad and Tobago and Venezuela ratified sub-sea wells. The Dolphin Deep sub-sea the field-specific treaty for the cross-border facilities are tied back to facilities on the Dolphin Loran-Manatee field, providing a framework platform. In 2012, the Starfish development for advancing a field development plan by was sanctioned. This will comprise four sub-sea the partners. wells, tied back to the Dolphin platform, 20 Data Book 2014

Partners ECMA Partners NCMA Partners Central Block (%) (%) (%)

BG Group (operator) 50 BG Group (operator) 45.88 Eni 17.31 BG Group (operator) 65 Chevron 50 Petrotrin 19.50 NSGP (Ensign Limited) 17.31 Petrotrin 35

North Coast Marine Area (NCMA) BG Group supplies both gas and condensate in 2009. Declaration of Commerciality was The BG Group-operated NCMA development, to Petrotrin, for use in its refinery at made in 2011. An appraisal drilling programme located 40 kilometres off the north coast Pointe-à-Pierre, Trinidad. Gas is transported is proposed to commence in 2015. of Trinidad, includes the Hibiscus, Poinsettia via a 12 kilometre pipeline that connects to and Chaconia gas fields. There is a Unitisation the NGC network. BG Group also supplies Block 5(d) Agreement with Petrotrin for the development export gas to Atlantic LNG Train 4. The In 2012, BG Group (100% and operator) executed of accumulations within the NCMA Unit Area. development of the Baraka and Baraka East a PSC for Block 5(d), which sits adjacent to These fields are being developed in four phases discoveries and compression (known as the Block 5(c). An extensive seismic survey has to supply gas to Atlantic LNG Trains 2, 3 and 4. BTIC project) was sanctioned in 2009 with been completed with final processed products Phases 1 and 2 comprised the installation of first gas delivered in 2012, allowing for the delivered in the first quarter of 2014. The the Hibiscus platform in 2001, together with extension of the gas supply contracts. exploration potential is currently being a pipeline from NCMA to Atlantic LNG at evaluated utilising this dataset. Point Fortin. Block 5(c) In 2007, BG Group signed a farm-in agreement Trinidad and Tobago Deepwater The development of the Poinsettia field as for Block 5(c), 94 kilometres off the east coast Atlantic Area (TTDAA) part of Phase 3 included accessing the Heliconia of Trinidad. BG Group took a 30% working interest In June 2014, BG Group farmed in to and Bougainvillea accumulations. A pipeline in the PSC and assumed operatorship in 2009. TTDAA Blocks 5 and 6, with 35% equity connects the platform to the existing Hibiscus In 2009, BG Group exercised its pre-emption rights in each block. BHP Billiton retained 65% platform 20 kilometres away. First gas production under the Joint Operating Agreement to increase equity and operatorship from Poinsettia was achieved in 2009. The six its stake in the block to 75%, which became development well drilling programme completed effective later that year. In March 2014, BG Group in 2010, thereby increasing NCMA deliverability purchased the remaining 25% of the block. to Atlantic LNG. Each of the three wells drilled on Block 5(c) The NCMA 4a compression project, which will since 2007 have encountered hydrocarbons sustain existing production from the NCMA and has been successfully tested. The first fields, was sanctioned by BG Group and partners well, Victory-1, was drilled 10 kilometres in 2010. Construction of the compression unit north-east of the Dolphin platform. The second commenced in 2012, with first gas achieved well, Bounty-1, targeted a separate prospect, in June 2014. approximately four kilometres away from the Victory-1 well. Drilling and testing of the third Central Block exploration well, Endeavour-1, was completed BG Group acquired a 65% interest in, and assumed operatorship of, this block in 2004 under an exploration and production licence. Contract Following acreage relinquishment in 2012, this BG Group onshore block now covers 27 square kilometres Concession interest (%) Field Supplying DCQ gross Start End and includes the currently producing Carapal ECMA 50 Dolphin NGC 250 mmscfd 1996 2015 Ridge, Baraka and Baraka East developments. Dolphin Deep Atlantic LNG Train 3 100 mmscfd 2004 2026 Atlantic LNG Train 4 120 mmscfd 2007 2027 A gas plant with a capacity of approximately NGC 220 mmscfd 2009 2023 65 mmscfd was commissioned in 2007, near NCMA 45.88 Hibiscus Atlantic LNG Train 2 240 mmscfd 2004 2023 the existing production site at Carapal Ridge. Poinsettia Atlantic LNG Train 3 45 mmscfd 2004 2023 This was de-bottlenecked to 80 mmscfd Chaconia Atlantic LNG Train 4 80 mmscfd 2007 2017 in 2010. Central Block 65 Carapal Ridge Petrotrin 20 mmscfd 2009 2015 Baraka Petrotrin 1 000 bopd 2012 2016 Baraka East Atlantic LNG Train 4 23 mmscfd 2007 2027 www.bg-group.com UPSTREAM AND DOWNSTREAM CENTRAL ECMA, NCMA, BLOCK AND ATLANTIC LNG: INTEGRATED Train 4 (start date 2005) Train 3 (start date 2003) Train 2 (start date 2002) Train 1 (start date 1999) Upstream upstream partners BG Gas c800 mmscfd upstream partners BG Gas c560 mmscfd upstream partners BG Gas c560 mmscfd Gas supply) (non-BG Group c520 mmscfd supply Gas

Group and and Group and Group and Group

28.9% 25.0% 50.0% NGC Shell BP BG Tolling plant Train Shell BP BG Tolling plant Train Shell BP BG Tolling plant Train NGC Corp. China Investment Shell BP BG Merchant plant Train Train equity Train equity 37.8% 34%

Group Group Group Group 11.1%

3 –3.3 2 –3.3 1 –3.1 4 –5.2 28.9% 26%

mtpa

mtpa mtpa mtpa 25.0% 25.0% 22.2% 32.5% 32.5% 42.5% 42.5% 20% 10% 10% Others BG LNG Natural Gas SUEZ GDF LNG purchase LNG Downstream Others BG LNG Others BG LNG

Group Group Group

28.9%

55.0% 60.0% 71.1% 75.0% 45.0% 25.0% 40.0% Atlantic Trains LNG 3and 2, 4represent to onward BGGM for sale. contract in Traincapacity 4is under also along-term sold Group the BG from liquefaction produced LNG to BGGM saleis sold into for global markets. Trains 2 and Group partners BG 3by and its gas supplied from to produced LNG The is approximately 15 mtpa. Atlantic of LNG capacity LNG production Train mtpa 5.2 of the the total 4in 2005, completion the With mtpa. 6.6 approximately of capacity trains havetwo acombined productive in 2002 and Train additional 3in 2003. These Train3.1 mtpa LNG. production 2commenced of capacity train first hasThe productive a in 1999. Trinidad, south-west operating which began plant Point at LNG Fortin, its constructed Tobago, in Group which BG is ashareholder, AtlanticThe Company Trinidad LNG of and LNG Atlantic Liquefaction Upstream: fully integrated projects for BG Group. BG for projects fully integrated 21 22 Data Book 2014

UNITED STATES OF AMERICA

BG Group owns acreage positions in the Haynesville and Marcellus shale plays.

CANADA

AREAS OF OPERATION Key dates 0 600 km BEAUFORT SEA 2009 Entry into US shale via alliance with PRUDHOE BAY EXCO Resources, Inc. (EXCO) 2010 Acquisition of Common Resources L.L.C. and acreage from Southwestern Energy ALASKA Foothills Area New joint venture with EXCO in the Appalachian Basin Marcellus shale*

WASHINGTON D.C.

ANCHORAGE USA

CANADA Elba Island Haynesville shale*

PACIFIC ATLANTA OCEAN

Prince Rupert

HOUSTON Key to operations

Lake Charles Gas pipeline BG Group jointly operated Potential gas pipeline BG Group non-operated MEXICO GULF OF MEXICO Oil pipeline *Approximate shale area

Upstream: E&P In 2010, BG Group and EXCO jointly purchased BG Group net production BG Group is partnered with EXCO Resources, Common Resources, L.L.C. (Common), which (kboed) Inc. (EXCO) to develop shale gas opportunities owned operations in Texas. Later in 2010, 80 79 73 in the Haynesville Basin (east Texas and north the partners purchased acreage from Louisiana) and in the Appalachian Basin Southwestern Energy. 60 58 (Pennsylvania and West Virginia). In March 2013, BG Group divested all its interests 40 Haynesville shale in the shallow, non-core, conventional producing BG Group acquired its shale gas position assets and acreage in the Cotton Valley formation via an alliance with EXCO in 2009 through in east Texas and north Louisiana. In November 20 which the Group: 2013, BG Group sold its equity holding in TGGT. ●● acquired a 50% interest in EXCO’s acreage 0 in east Texas and north Louisiana, In line with the Group’s strategy of focusing 2011 2012 2013 predominantly in the Haynesville shale gas on value, and the continuing low US natural Gas formation, which is operated by EXCO; gas price, BG Group expects to continue Oil & liquids ●● entered into a joint development agreement to develop its Haynesville position with rig with EXCO to cooperate in the further numbers being optimised based on realised development and production of shale gas gas prices. in east Texas and north Louisiana; and ●● acquired a 50% interest in related and complementary EXCO gas gathering and transport assets, known as TGGT. www.bg-group.com 23

CANADA

Marcellus shale In 2010, BG Group entered into further joint venture (JV) arrangements BG Group is evaluating a potential with EXCO to acquire a 50% interest in companies that hold EXCO’s LNG project at Prince Rupert producing and non-producing assets in the Appalachian Basin, located primarily in Pennsylvania and West Virginia. in British Columbia.

BG Group also acquired 50% of EXCO’s interest in approximately 5 900 shallow producing wells, many of which secure ongoing ownership of deeper Marcellus rights, and approximately 2 100 miles of gathering infrastructure serving the shallow wells. In 2011, BG Group and EXCO jointly purchased further acreage in the Marcellus area.

In line with the Group’s strategy of focusing on value, and the continuing AREAS OF OPERATION low US natural gas price, BG Group is continuing to evaluate its drilling 0 500 km strategy in the Marcellus shale for 2015. BEAUFORT SEA PRUDHOE BAY Alaska In 2006, BG Group signed a Participation Agreement for more than 2 million acres in the Foothills area of the Alaskan North Slope, operated by Anadarko. Drilling, completion and seismic activities were carried ALASKA out in this area between 2007 and 2012. BG Group continues to Foothills Area evaluate its opportunities in the region.

LNG Shipping & Marketing BG Group’s LNG and gas marketing activities include the Lake Charles ANCHORAGE and Elba Island LNG import facilities. BG Group is progressing applications CANADA and development plans for export of LNG from the Lake Charles facility. These activities are managed by GEMS (see pages 34 to 36 for details).

PACIFIC OCEAN Prince Rupert

Key to operations Gas pipeline Oil pipeline Potential gas pipeline BG Group non-operated block USA

LNG Shipping & Marketing BG Group has obtained exclusive rights to a site on Ridley Island near Prince Rupert, British Columbia for the potential location of a LNG terminal. The facility would initially be a two-train development, with the ability to add a third train if market conditions allow. Ridley Island has a natural deep water and ice-free harbour and benefits from its proximity to Asia-Pacific markets. The site is industrially zoned with rail and road access.

BG Group has signed a project development agreement with Spectra Energy to jointly develop a natural gas pipeline from north-east British Columbia to the proposed terminal. In March 2014, Spectra Energy submitted an Environmental Assessment Certificate Application to the British Columbia Environmental Assessment Office for the Westcoast Connector Gas Transmission Project.

In March 2014, BG Group received the final licence it requires from the National Energy Board to allow exports of approximately 25 million tonnes per annum (mtpa) of LNG for 25 years from the date of first export.

BG Group is in discussion with potential partners in the Prince Rupert project and does not plan to take more than 50% interest in the project. 24 Data Book 2014

THAILAND

BG Group’s investment in Thailand includes an interest in the large offshore Bongkot field, which supplies approximately 20% of the country’s gas demand.

AREAS OF OPERATION New information 0 250 km ●● Bongkot North Phase 3L onstream ●● Bongkot South Phase 4B onstream THAILAND Key dates 1990 Entered into Participation and Operating Agreement with partners BANGKOK RATCHABURI 1993 Bongkot North first production CAMBODIA 2001 Memorandum of Understanding RAYONG (MoU) between Thailand and Cambodia MYANMAR for a Joint Development Area 2007 Supplementary Petroleum Concession Agreements signed 2009 Increased equity interest in Blocks 7, 8 and 9 to 66.67% Gas Sales Agreement for Blocks 7, 8, 9 Bongkot South signed ANDAMAN SEA Block 9A 2012 Bongkot South first production

KHANOM GULF OF THAILAND

Key to operations Bongkot Gas Gas and Oil/Condensate Oil BG Group-operated block Gas pipeline BG Group non-operated block Oil pipeline

The Bongkot North development consists Bongkot South is located some 70 kilometres BG Group net production of a central complex for gas gathering, to the south of Bongkot North and involves the (kboed) processing, export and worker accommodation; development of further reserves through new 50 a condensate floating storage and offloading standalone facilities with processing capacity 41 40 (FSO) vessel; 31 remote wellhead platforms; of 350 mmscfd and 15 000 barrels of condensate 36 0 and over 400 development200km wells. Production per day. Production commenced in 2012 and commenced in 1993 and gross daily gas at plateau, Bongkot South delivers some 30 27 production has risen and been sustained 14 000 boed net to BG Group. Phase 4B of 20 at more than 600 mmscfd through a Bongkot South, consisting of four further phased programme of field development. wellhead platforms, came onstream in early 2014. 10 Bongkot South Phase 4C is underway and consists Phase 3K, consisting of two remote wellhead of three wellhead platforms with first gas 0 platforms and 16 wells, came onstream in expected in 2015. Gas from the project is exported 2011 2012 2013 August 2013. Phase 3L, consisting of two remote via a new-build spur line connected to existing Gas wellhead platforms and 18 wells, came onstream gas export infrastructure, while condensate is Oil & liquids in June 2014, while Phase 3M is expected exported to the FSO vessel at Bongkot North. Upstream: E&P onstream in 2015 and Phase 3N is underway. Production is sold to PTT Public Company. Bongkot BG Group has a 22.22% interest in the Bongkot BG Group and its partners continue to explore Blocks 7, 8 and 9 field in the Gulf of Thailand. The field is operated further opportunities to extend the Bongkot BG Group is the operator of Blocks 7, 8 and 9 in by PTT Exploration and Production (PTTEP). North production plateau. Programmes of well the Gulf of Thailand (BG Group 66.67%), in an area In 2012, the Bongkot Concession passed the intervention, infill drilling and booster compression subject to overlapping claims by Thailand and milestone of producing more than 1 bcf of sales are being implemented to improve hydrocarbon Cambodia. Activity in these blocks is suspended gas per day from the Bongkot North and Bongkot recovery and an active programme of exploration until these claims are resolved. BG Group also South fields combined. drilling is underway to discover reserves for further has an Overriding Royalty Agreement covering incremental phases of development. production from Block 9a. www.bg-group.com 25

TUNISIA

BG Group is the country’s largest gas producer, supplying more than 60% of Tunisia’s domestic gas production through the Miskar and Hasdrubal operations.

AREAS OF OPERATION New information 0 200 km ●● Well intervention campaigns on Miskar and Hasdrubal fields SICILY Key dates BIZERTE 1989 Tenneco assets acquired 1996 Miskar field first production TUNIS 2009 Hasdrubal field first production 2011 LPG pipelines start-up

TUNISIA SOUSSE

ALGERIA MEDITERRANEAN SEA

Hannibal plant SFAX Hasdrubal plant BEN SAHLOUN Amilcar Hannibal condensate pipeline Miskar LA SKHIRA GULF OF GABÈS LPG facility GABÈS Hasdrubal Key to operations Gas Oil pipeline Oil BG Group-operated block Gas pipeline

Offshore compression was commissioned in Production is delivered from three gas wells BG Group net production 2005 to maintain the production plateau of the through an unmanned offshore platform to (kboed) field. Six infill wells were drilled between 2007 dedicated offtake facilities. Condensate from 50 and 2010. There is currently an ongoing workover Hasdrubal is transported to La Skhira storage 40 campaign, comprising well re-perforations and terminal through the Hannibal condensate 40 37 38 well re-fracturingLIBYA operations. As a result, pipeline. The condensate is mainly exported 30 there are 18 producing wells. and jointly sold with Miskar condensate to the international market. The LPG storage terminal 20 A 60 kilometre condensate pipeline was has been constructed in Gabès to receive completed in 2007 to transport Miskar and deliver butane for sale locally to Société 10 condensate from Hannibal to La Skhira Tunisienne des Industries de Raffinage (STIR) storage terminal. The condensate is mainly and propane for export to the international 0 exported to the international market. Med LPG market. Two 6-inch, 130 kilometre 2011 2012 2013 parallel pipelines commissioned in 2011 are used Gas Hasdrubal to deliver LPG to the terminal from Hasdrubal. Oil & liquids Hasdrubal came onstream in 2009, with gas being sold to STEG on a long-term contract, Amilcar permit Upstream: E&P while condensate and LPG are sold to both BG Group is operator and joint permit holder Miskar international and local markets. with ETAP, the Tunisian state-owned company, Gas from the Miskar field is processed at the of the 1 016 square kilometre Amilcar exploration BG Group-operated Hannibal plant and sold The Hasdrubal onshore gas processing permit, in the Gulf of Gabès. Approval has into the Tunisian gas system. BG Group has a facility (BG Group 50%, Entreprise Tunisienne been granted in principle for an extension long-term gas sales contract with the Tunisian d’Activités Pétrolières (ETAP) 50%) and LPG to December 2014, pending decree publication. state electricity and gas company, Société production facility (BG Group 100%) have Tunisienne de l’Electricité et du Gaz (STEG). been built adjacent to the Hannibal plant. 26 Data Book 2014

BOLIVIA

BG Group has interests in seven exploration and exploitation licences in Bolivia, including interests in two producing gas condensate fields, Margarita and Itaú.

AREAS OF OPERATION New information 0 100 km ●● First production from Margarita Phase II ●● First production from Itaú Phase II Key dates 1998 Margarita field discovered

Charagua 1999 Itaú field discovered 2004 First production from Margarita Early Production Facility 2006 Supreme Decree on Nationalisation issued New Operations Contracts signed BOLIVIA 2010 Margarita delivery agreement amended to include volumes to Argentina 2011 Itaú Phase I first production Huacareta Caipipendi 2012 Margarita Phase I first production

Margarita 2013 Awarded Huacareta exploration block La Vertiente VILLAMONTES PARAGUAY TARIJA

Tarija XX West Tarija XX East

Itaú Los Suris Key to operations Gas Gas pipeline ARGENTINA Oil Oil pipeline Gas and Oil/ BG Group-operated block Condensate BG Group non-operated block

Upstream: E&P Non-operated licences BG Group net production Operated licences (all 100% BG Group equity) Caipipendi (kboed) La Vertiente BG Group has a 37.5% interest in the Caipipendi 40 36 The La Vertiente licence contains the licence, which contains the large Margarita gas La Vertiente, Escondido and Taiguati gas fields. condensate field. The consortium sanctioned 30 28 Production in these fields is processed at the Phase I in 2010, with first gas produced in 2012. La Vertiente gas plant before delivery to YPFB. In 2011, the consortium sanctioned Margarita 20 19 Phase II, with first gas produced in the third Los Suris quarter of 2013, increasing BG Group net The Los Suris licence contains the Los Suris gas production capacity from the Margarita field 10 field. Production from this field is processed at to around 42 000 boed. the La Vertiente gas plant. 0 Tarija XX West 2011 2012 2013 Tarija XX East BG Group has a 25% interest in the Tarija XX West Gas The Tarija XX East licence contains the licence, which contains the Itaú gas condensate Oil & liquids Palo Marcado gas field where production is field. In 2011, Itaú Phase I came onstream. Phase II processed at the La Vertiente plant. The Ibibobo came onstream in the fourth quarter of 2013, BG Group has both operated and non-operated field is in the process of being relinquished. raising BG Group net production capacity to interests in seven licences. Both gas and 10 000 boed. condensate production in these interests are Huacareta delivered to Yacimientos Petrolíferos Fiscales In 2013, BG Group was awarded the 4 500 square Charagua Bolivianos (YPFB), the national oil company, kilometre Huacareta licence block. The first BG Group has a 20% interest in the Charagua to supply Brazilian, Argentine and domestic five year exploration phase will include a licence, which contains the Itatiqui Retention markets. Exploration activity is focused on combination of seismic acquisition and Area. The partnership is in the process of the 100% owned Huacareta licence block. interpretation, and could include the drilling relinquishing their interests in this licence. of one well. www.bg-group.com 27

INDIA

BG Group has upstream interests in three offshore producing fields, has two exploration licences and has contracted long-term LNG sales into the fast growing Indian gas market.

AHMEDABAD

VADODARA

AREAS OF OPERATION HVJ pipeline Key dates DAHEJ BHARUCH 1995 Mahanagar Gas Ltd (MGL) formed ANKLESHWAR 2002 30% participating interest in the Panna/Mukta and Mid and South Tapti (PMT) fields acquired HAZIRA 1 INDIA 2008 Agreement signed by BG Group with SURAT GAIL (India) Limited to purchase PMT gas 2010 PSC for Block KG-DWN-2009/1 signed Tapti 2 2013 Agreement for initial supply of 1.25 mtpa of LNG to GSPC from 2015 for up to 20 years

GULF OF CAMBAY

Panna

CUTTACK BHUBANESHWAR MUMBAI PURI Mahanagar Gas

India 2 Mukta INDIA

KG-DWN-2009/1 (A) India 1 MB-DWN-2010/1 Key to operations KAKINADA ARABIAN SEA Gas Oil pipeline 0 100 km Oil BG Group-operated block KG-DWN-2009/1 (B) Gas pipeline

Upstream: E&P LNG Shipping & Marketing BG Group net production BG Group has a 30% interest in the Mid and In 2013, BG Group completed an agreement (kboed) South Tapti gas fields and the Panna/Mukta with Gujurat State Petroleum Corporation 40 (PMT) oil and gas fields. Incremental development (GSPC) for the initial supply of 1.25 mtpa of LNG 31 of the existing fields via well intervention and beginning in 2015 for up to 20 years, potentially 30 infill drilling campaigns, as well as evaluating increasing to 2.5 mtpa after two years. 25 new projects and further development 20 20 opportunities, is being planned. Other Mahanagar Gas Ltd (MGL) In 2012, a consortium led by BG Group (50% and MGL, based in Mumbai, is India’s largest 10 operator) was awarded the exploration block gas distribution company in terms of size MB-DWN-2010/1, in the Mumbai Basin, offshore of customer base, serving more than 0 the west coast of India. The block covers an area 690 000 residential, commercial and 2011 2012 2013 of nearly 8 000 square kilometres in water depths industrial customers and fuelling more than Gas of around 3 000 metres. In 2013, a 2D seismic 340 000 vehicles with CNG at the end of Oil & liquids survey was completed. Data is currently being December 2013. BG Group and GAIL (India) interpreted after completion of initial processing. Limited each have a 49.75% stake in MGL, with the residual stake held by the government BG Group (30% and operator) holds exploration of Maharashtra. block KG-DWN-2009/1 (both A and B) in deep water in the Krishna Godavari (KG) Basin. 28 Data Book 2014

TANZANIA

BG Group entered Tanzania in 2010 and is the operator of offshore Blocks 1, 3 and 4 in which it has a 60% interest. Around 15 tcf of total gross resource has been discovered and work is progressing to develop a joint LNG plant in collaboration with the Block 2 partners.

AREAS OF OPERATION New information 0 100 km ●● Mzia confirmed as second giant gas discovery, after Jodari Block 4 ●● Taachui gas discovery in Block 1 Chewa ●● LNG site MoU signed with the government Ngisi ●● HoA signed with Block 2 partners: BG Group Pweza is lead developer for pre-FEED Block 3 ●● Contracts for upstream and LNG plant Papa pre-FEED awarded KILWA KIVINJE Key dates 2010 BG Group farmed into Blocks 1, 3 and 4 Pweza and Chewa gas discoveries INDIAN OCEAN 2011 Chaza gas discovery BG Group became operator TANZANIA of Blocks 1, 3 and 4 Block 1 2012 Jodari, Mzia, and Papa gas discoveries

Taachui 2013 First DST offshore Tanzania conducted at Jodari LINDI Mzia Jodari North Ngisi and Mkizi gas discoveries Jodari MTWARA Chaza Mkizi

MOZAMBIQUE Key to operations Gas BG Group-operated block

Upstream: E&P Block 1 Upstream: Liquefaction In 2010, BG Group farmed in to Blocks 1, 3 and 4 Six discoveries have been made in Block 1 since In April 2014, the partners in Blocks 1, 3 and 4 offshore southern Tanzania taking 60% equity 2010. All are within 100 kilometres of the shore and the partners in Block 2 signed a Heads in each, assuming operatorship in 2011. The blocks and in water depths of 900 to 1 600 metres. of Agreement (HoA) setting out how the cover around 20 850 square kilometres of the Four of these are Tertiary reservoirs (Chaza, companies will collaborate on development Mafia Deep Offshore Basin and the northern Jodari, Jodari North and Mkizi) and two are of a potential joint LNG project. Under the part of the Rovuma Basin. Cretaceous (Mzia and Taachui). Mzia (4.7 tcf agreement, BG Group will be the lead developer total gross resource) and Jodari (4 tcf total during the pre-FEED phase. A contract for Since entering Tanzania, the joint venture has gross resource) are both classified as giant the LNG plant pre-FEED was awarded in acquired over 13 000 square kilometres of 3D discoveries. Four DSTs have been conducted August 2014. seismic data, and has had 15 consecutive drilling on Jodari, Mzia (two DSTs) and Taachui. successes, including 10 gas discoveries and A Memorandum of Understanding (MoU) five appraisal wells. The joint venture has also Block 3 between the government of Tanzania, the conducted five drill stem tests (DSTs). This In 2012, the joint venture successfully drilled partners in Blocks 1, 3 and 4 and the partners in exploration and appraisal activity has led to the Papa discovery well into the deeper Block 2 was signed in April 2014. The MoU covers estimates of total gross resources of around Cretaceous reservoir. The well is around the site selected for the LNG plant, the process 15 tcf, with further exploration upside. 100 kilometres offshore Tanzania in water for acquiring the site, the lease to be negotiated, A contract for the upstream pre-FEED depth of approximately 2 180 metres. and how any resettlement will be managed. was awarded in May 2014. Block 4 In 2010, two gas discoveries were made at Pweza and Chewa. In 2013, another gas discovery was made with the Ngisi well, and a DST on the Pweza well was conducted. www.bg-group.com 29

KENYA MADAGASCAR

BG Group entered Kenya in 2011, BG Group owns a 30% interest acquiring an interest in offshore in the Majunga Offshore Profond blocks L10A and L10B. exploration block in Madagascar.

ETHIOPIA SOMALIA AREAS OF OPERATION AREAS OF OPERATION

0 100 km 0 1 000 km KENYA

TANZANIA

KENYA INDIAN Majunga Offshore Profond OCEAN

L10A

MOMBASA MOZAMBIQUE MADAGASCAR

ANTANANARIVO

TANZANIA L10B SOUTH AFRICA

PEMBA ISLAND

Key to operations Key to operations BG Group-operated block Gas pipeline BG Group non-operated block Oil pipeline

Upstream: E&P Upstream: E&P In 2011, BG Group signed Production Sharing Contracts with the BG Group (30%) partners with ExxonMobil (50% and operator), government of Kenya for two offshore exploration blocks – L10A SK Innovation (10%) and PVEP Corp (10%) in the Majunga Offshore and L10B. BG Group is operator of both blocks and holds a 50% equity Profond exploration block. interest in Block L10A (PTTEP 31.25%, Pancontinental 18.75%) and a 75% interest in Block L10B (Pancontinental 25%). The block covers around 15 840 square kilometres in water depths ranging from around 200 metres to in excess of 3 000 metres, BG Group completed two 3D seismic surveys with approximately offshore the north-west coast of Madagascar. The block is believed 4 700 square kilometres of 3D seismic acquired. In March 2014, the to be oil-prone and it forms part of a largely unexplored frontier basin. Sunbird-1 exploration well, on Block L10A, intersected a gross hydrocarbon column of 44 metres in the Miocene reef, at 1 584 metres subsea, in a water depth of 723 metres. Oil and gas samples were recovered to surface but the discovery is not considered commercial. BG Group plans to continue exploration drilling in 2015.

Potential net unrisked resources are believed to be more than 1 billion boe. 30 Data Book 2014

URUGUAY HONDURAS

BG Group has licences in three BG Group holds an offshore frontier offshore frontier exploration blocks. exploration licence covering approximately Acquisition of over 13 000 square 35 000 square kilometres. kilometres of 3D seismic was completed in 2014.

AREAS OF OPERATION AREAS OF OPERATION

0 150 km 0 200 km

BRAZIL BELIZE Patuca and Mosquitia Basins

LA CEIBA SAN PEDRO SULA

HONDURAS URUGUAY TEGUCIGALPA

BUENOS AIRES MONTEVIDEO

PUNTA LARA

Southern Cross NICARAGUA pipeline

Gas Link pipeline

Block 8 ARGENTINA Block 9

Block 13

Key to operations Key to operations Gas pipeline BG Group-operated block BG Group-operated block

Upstream: E&P Upstream: E&P In 2012, BG Group successfully bid for three offshore blocks (8, 9 and 13) BG Group is the sole licence holder of an approximately 35 000 square in the second licensing round held by the Republic of Uruguay. The PSCs kilometre offshore frontier exploration block covering the Patuca and commit BG Group (100% and operator) to a seismic work programme Mosquitia sedimentary basins. BG Group submitted an Exploration intended to evaluate the blocks in the first three year exploration period. Licence Application in 2012. The Operating Contract was approved by Acquisition of 13 080 square kilometres of 3D seismic was completed legislative decree and commenced in 2013. in February 2014. Sub-surface analysis and prospect mapping is underway. A well commitment is required on each block in order The initial four year exploration period will focus on reviewing existing to enter the second three year exploration phase. exploration data, conducting a gravity gradiometry survey to map the entire block, seabed sampling and seismic surveys. The acquisition Other of data from the gravity gradiometry survey was undertaken between BG Group is operator, with a 40% share, in the Southern Cross pipeline March and May 2014 and will enable targeted seismic surveys, planned linking Punta Lara in Argentina to Montevideo. Through its holding for 2015 and 2016. The seabed coring survey began in July 2014. in Dinarel S.A., BG Group holds a 25.5% interest in Gas Link S.A., a 40 kilometre gas pipeline connecting the Southern Cross pipeline In 2017, BG Group will relinquish 50% of the acreage to the government to the Argentine transportation network. of Honduras. Should the Group elect to proceed to the next two year exploration phase, a commitment to drill at least one exploration well would be required. www.bg-group.com 31

COLOMBIA ARUBA

In 2014, BG Group farmed in to an BG Group entered Aruba in 2014, and holds offshore frontier exploration block. an offshore exploration licence covering approximately 14 000 square kilometres.

AREAS OF OPERATION AREAS OF OPERATION

0 200 km 0 200 km Guajira Offshore 3

ARUBA ARUBA GAP CARIBBEAN SEA CARTAGENA

PANAMA Guajira Offshore 3

VENEZUELA GULF OF VENEZUELA COLOMBIA

PACIFIC OCEAN COLOMBIA VENEZUELA

BOGOTÁ

Key to operations Key to operations BG Group non-operated block BG Group non-operated block

Upstream: E&P Upstream: E&P In January 2014, BG Group signed an agreement to acquire a 30% equity In June 2014, BG Group agreed to acquire a 30% interest in an exploration interest in the Guajira Offshore 3 Block (Shell 70% and operator). The block, offshore Aruba. The block covers 14 356 square kilometres in water agreement is subject to approval from the government’s Agencia depths ranging between 400 metres and 1 800 metres. Nacional de Hidrocarburos (ANH). A Production Sharing Agreement is in place and a 3D seismic programme The block is held under a Technical Evaluation Agreement and is located will be completed in 2014. The Group’s farm-in agreement is subject approximately 70 kilometres offshore in water depths of 1 500 to 4 000 to approval by the Compania Arubano di Petroleo N.V. metres. The 2014 work programme consists of a 3D seismic survey and seabed coring. 32 Data Book 2014

MYANMAR SINGAPORE

In 2014, BG Group was awarded four BG Group’s global centre for LNG and oil blocks of frontier acreage in Myanmar. marketing is located in Singapore. The Group is the supplier of the first 3.0 mtpa of long-term LNG demand in Singapore through its aggregator position.

AREAS OF OPERATION AREAS OF OPERATION

0 200 km 0 250 km MYANMAR

NAYPYIDAW

THAILAND AD-2 MALAYSIA A-4

YANGON SINGAPORE AD-5 A-7

BAY OF INDONESIA BENGAL

ANDAMAN SEA GULF OF Key to operations THAILAND BG Group-operated block BG Group non-operated block

Upstream: E&P LNG Shipping & Marketing In March 2014, BG Group was awarded, subject to finalisation of the In April 2014, BG Group moved the centre of its global LNG and oil Production Sharing Contracts, exploration acreage in the Bay of Bengal, marketing business to Singapore, reflecting the long-term importance offshore western Myanmar, as part of the government’s 2013 offshore of Asian energy markets. This move builds on the Group’s presence in the bid round. Total gross acreage awarded to BG Group and partners country, having been appointed by the Energy Market Authority (EMA) was more than 34 350 square kilometres in water depths of up to in 2008 as the sole aggregator of Singapore’s first 3.0 mtpa of LNG 2 600 metres. demand for up to 20 years, and where the Group’s regional head office for its South and East Asia operations has been for more than 15 years. The Group was awarded four blocks: ●● AD-2 with 55% equity and operatorship (Woodside Energy 45%); The Aggregator Agreement was signed in 2009. Beginning in 2010, ●● A-4 with 45% equity and operatorship (Woodside Energy 45%, BG Group signed gas sales contracts with a variety of customers, Myanmar Petroleum Exploration and Production (MPEP) 10%); including six large scale power generation companies. The total ●● AD-5 with 45% equity (Woodside Energy 55% and operator); and LNG contracted under this agreement by the end of July 2014 was ●● A-7 with 45% equity (Woodside Energy 45% and operator, MPEP 10%). approximately 2.7 mtpa, with the Group having delivered a total of 30 cargoes since the first commercial delivery to the LNG terminal BG Group and its partners have committed to a 3D seismic acquisition on Jurong Island in May 2013. The aggregator is also required to develop programme in each block, which is expected to begin in 2015 following trading activity and market short-term and spot gas sales agreements an Environmental and Social Impact Assessment, with plans beyond to the Singapore market. that for exploration drilling. BG Group sources LNG supply for Singapore from its large, growing and diversified flexible portfolio. It is envisaged that BG Group’s QCLNG project in Australia will serve as one of the sources of supply. www.bg-group.com 33

AREAS OF PALESTINIAN AUTHORITY

BG Group owns a 90% interest in, and is operator of, the offshore Gaza Marine licence.

LEBANON

AREAS OF OPERATION

0 50 km

MEDITERRANEAN SEA

Offshore Gaza Marine licence ISRAEL Gaza Marine

GAZA

EGYPT

Key to operations Gas BG Group-operated block

Upstream: E&P BG Group is operator of an exploration licence, awarded in 1999, covering the entire marine area offshore the Gaza Strip. BG Group drilled two successful wells in 2000 (Gaza Marine-1 and Gaza Marine-2) and resources are estimated to be around 1 tcf. In 2001, a technical review recommended a sub-sea development and pipeline to an onshore processing terminal. In 2002, an outline Development Plan was approved by the Palestinian Authority.

BG Group holds 90% equity in the licence, which would be reduced to 60% if the Consolidated Contractors Company (the current 10% partner in the licence) and the Palestine Investment Fund exercised their options at development sanction.

In 2007, BG Group withdrew from negotiations with the government of Israel for the sale of gas from the Gaza Marine field to Israel. In 2008, BG Group closed its office in Israel but maintains contact with the Palestinian Authority and the government of Israel to investigate options for Gaza Marine development. 34 Data Book 2014

GLOBAL ENERGY MARKETING AND SHIPPING

Global Energy Marketing and Shipping (GEMS) develops and implements BG Group’s strategy for the marketing and optimisation of all commodity streams, connecting diversified and flexible supplies to extensive customer networks.

LNG AREAS OF OPERATION New information ●● Lake Charles FERC application filed for proposed LNG export project Key dates 2001 Agreement signed for Lake Charles import capacity 2003 Access to Elba Island terminal capacity UK* CANADA* 2004 First long-term equity LNG supply purchased from Atlantic LNG JAPAN USA S.KOREA 2006 First long-term third-party supply EGYPT* CHINA purchased from NLNG INDIA 2010 Initial 3.6 mtpa LNG sales contract TRINIDAD signed with CNOOC & TOBAGO* NIGERIA EQUATORIAL GUINEA SINGAPORE 2012 Sabine Pass US LNG exports purchase agreement increased to 5.5 mtpa TANZANIA* 2013 First cargo delivered into Singapore AUSTRALIA* under the LNG Aggregator Agreement with the EMA CHILE Agreement to supply further 5 mtpa of LNG to CNOOC for 20 years Lake Charles LNG exports approved for non-FTA countries

Key to operations Existing long-term supply source Supply source under construction Existing import capacity/Term customer Potential supply source *BG Group equity project

GEMS Train 2, and in 2007, purchases from Atlantic LNG delivered volumes GEMS activities cover global liquefied natural gas LNG Train 4 commenced. (mtpa) (LNG) marketing, gas marketing, oil marketing 15 and shipping. In April 2014, BG Group moved In 2006, BG Group lifted its first third-party 12.8 12.1 the centre of its global LNG and oil marketing cargo from Nigeria LNG (NLNG) Trains 4 and 5. 12 10.9 business to Singapore from its head office in In 2007, the Group lifted its first cargo from the UK, reflecting the long-term importance the Equatorial Guinea LNG (EGLNG) project. 9 of Asian energy markets (see page 32 for more details). BG Group expects first LNG in the fourth 6 quarter of 2014 from its two-train 8.5 million LNG supply tonnes per annum (mtpa) QCLNG project 3 BG Group pursues a number of opportunities currently in development in Australia.

0 to create a diversified supply portfolio. These 2011 2012 2013 include buying LNG from third parties as well In 2011, BG Group signed the first long-term as from BG Group equity LNG projects in LNG purchase agreement from a project on Egypt and Trinidad and Tobago currently, and the US Gulf Coast, agreeing to take 3.5 mtpa Queensland Curtis LNG (QCLNG) in Australia of LNG over a 20 year period from Train 1 of the from the fourth quarter of 2014. Sabine Pass LNG terminal. In 2012, BG Group agreed to purchase an additional 2.0 mtpa In 2004, BG Group purchased its first long-term from Trains 2, 3 and 4 over a 20 year period. LNG cargo of equity gas from Atlantic LNG The operator expects the Sabine Pass project Trains 2 and 3 under a 20 year contract. to commence production of LNG in late 2015. This was followed in 2005 with the first purchases of equity gas from Egyptian LNG www.bg-group.com 35

In 2010, BG Group signed a sales contract BG Group’s LNG strategy with China National Offshore Oil Corporation (CNOOC) which sets out the basis on which CNOOC will purchase 3.6 mtpa of LNG for a period of 20 years from 2014 from the Group’s Diversified and Extensive portfolio, including QCLNG. Deliveries under Flexible flexible LNG customer this contract have commenced. Further, in 2013, portfolio BG Group committed to supply an additional supply network 5 mtpa of LNG to CNOOC beginning in 2015 and sourced from the Group’s global portfolio (see page 10 for more details). BG Group’s total committed LNG sales to CNOOC will BG Group currently expects very limited to an extensive customer network. In addition be 8.6 mtpa, making the Group the largest cargoes to be lifted from Egyptian LNG for the to marketing its own contracted portfolio supplier of LNG to the world’s fastest-growing foreseeable future, with Force Majeure in place of volumes, the Group also buys and sells spot energy market. on the LNG purchase agreements in Egypt LNG cargoes. BG Group has made LNG sales (see page 11 for more details). to more than 60 customers around the globe, In 2011, BG Group contracted to supply in 26 of the current 27 LNG importing countries, Tokyo Gas Co., Ltd. (Tokyo Gas) with 1.2 mtpa BG Group’s LNG supply growth opportunity having also bought LNG from 15 of the 19 LNG of LNG for 20 years from 2015. Tokyo Gas will set includes projects at Lake Charles (USA), producing countries. be supplied with LNG from the Group’s Prince Rupert (Canada) and Tanzania. portfolio, including QCLNG (see page 10 The Group has a long-term contract to supply for more details). In 2011, the US Department of Energy granted the Quintero LNG terminal in Chile with up to authorisation for LNG export from the 3.0 mtpa until 2030. BG Group also signed a sales contract with Lake Charles terminal to free trade agreement Chubu Electric Power Co., Inc. (Chubu Electric) (FTA) countries. In August 2013, authorisation In 2008, BG Group was selected by the Energy for the long-term supply of LNG. Under the for the export of up to 15 mtpa of LNG to Market Authority (EMA) of Singapore to agreement, Chubu Electric will purchase up non-FTA countries was received. source and supply the Singapore market on to 122 cargoes over 21 years, starting in 2014. an exclusive basis with up to 3.0 mtpa of LNG Chubu Electric will be supplied from the In March 2014, subsidiaries of Energy Transfer for up to 20 years from the Group’s portfolio. Group’s portfolio, including QCLNG. filed an application with the Federal Energy The Singapore receiving terminal commenced Regulatory Commission (FERC) seeking commercial operations in May 2013, and In 2013, BG Group signed a sales contract authorisation for the siting, construction, as at 31 July 2014, the Group had delivered for the long-term supply of LNG to Gujarat ownership and operation of the proposed a total of 30 cargoes. State Petroleum Corporation Limited (GSPC) Lake Charles LNG export project. Pending in India. BG Group will initially supply 1.25 mtpa receipt of all necessary approvals and a As the Group’s LNG supply increases with of LNG beginning in 2015 for up to 20 years, final investment decision, expected in 2015, the start-up of the QCLNG and Sabine potentially increasing to 2.5 mtpa after construction could then start shortly Pass projects, the Group has entered into two years. GSPC will be supplied from the afterwards, with first LNG exports anticipated a number of additional long-term sales contracts. Group’s portfolio. in 2019. Energy Transfer will own and finance the proposed facility and BG Group will manage construction and operate the Cargo supply by source Cargo deliveries by geographical region proposed facility, while being responsible for the offtake. 250 250 208 208 200 197 200 197 More information on the Group’s potential 178 178 growth projects in Canada and Tanzania can be found on their country pages, 23 and 150 150 28 respectively. 100 100 Further details of LNG supply can be found 50 50 on page 48 within the Statistical Supplement.

0 0 LNG marketing 2011 2012 2013 2011 2012 2013 GEMS is engaged in marketing LNG to buyers throughout the world, on a long, medium and short-term basis. BG Group’s LNG business has Atlantic LNG Nigeria Asia North America been built around its portfolio of diversified Egyptian LNG Spot purchases South America Europe & Others and flexible LNG supplies that are sold globally Equatorial Guinea 36 Data Book 2014

In addition to these long-term sales contracts, BG Group has regasification capacity at the Capacity rights Net capacity rights Regasification (%) (bcfd) Contract ends Lake Charles and Elba Island terminals in the Lake Charles, USA* 100 1.80** 2030 USA, and the Dragon LNG terminal in the UK. Elba Island, USA 40 0.63** 2027 The Group uses this terminal capacity when prices are attractive. Given the strong demand in Dragon LNG, UK*** 50 0.30 2029 Asia and South America in particular, and the * Energy Transfer and BG Group are progressing the Lake Charles LNG export project which would add liquefaction and associated export infrastructure to the existing facility. impact of increasing US shale gas production, ** Data represents sustainable baseload capacity. GEMS has reduced LNG imports into these *** BG Group has 50% equity in the Dragon LNG terminal (Petronas 50%), including a combined heat and power plant markets freeing valuable cargoes for diversion which uses natural gas boil-off to supply up to an aggregate of 48 megawatt of electricity to Dragon LNG and the grid, to Asia and South America. and 73 megawatt thermal of heat, in the form of hot water for Dragon LNG.

Gas marketing In Singapore, BG Group currently has finalised time charters for four new-build oil shuttle GEMS undertakes gas marketing in North contracts for the supply of around 2.7 mtpa tankers for deployment in the Santos Basin. America, Europe, Australia and Singapore. of LNG out of its franchise 3.0 mtpa agreement. The Samba Spirit, the Lambada Spirit and the Sales are made under various short, medium The Group has signed gas sales contracts with Bossa Nova Spirit arrived in Brazil in 2013, with and long-term arrangements. BG Group’s a variety of customers in Singapore, including the Sertanejo Spirit arriving in early 2014. customers include leading gas and electric six large scale power generation companies. All four vessels are now in operation. utilities, as well as industrial companies and wholesale gas merchants. Oil marketing As production grows, the Group will ensure it GEMS markets oil production from BG Group’s has sufficient shipping capacity to meet lifting In North America, BG Group has a gas assets in the North Sea, Kazakhstan and Brazil. requirements through a variety of sources, marketing business of around 3.4 bcfd and With the planned ramp up in production from which could include additional short, medium controls pipeline capacity of more than 3.9 bcfd. the Group’s interests in the Santos Basin in Brazil, and long-term chartered vessels. It markets the Group’s own shale gas as well more than 300 Suezmax cargoes (or 300 mmbbls) as imported LNG, along with third-party gas of crude oil over the next five years are expected LNG Shipping supplies, to multiple intermediary and end-use to be lifted from these assets alone. BG Group has a long history in LNG shipping, customers via the US and Canadian natural gas having been involved in the development of pipeline infrastructure. In addition to the LNG both the prototype and the industry’s first Oil liftings by source storage facilities at Lake Charles and Elba Island, working LNG carriers. (mmbbls) BG Group will from time to time contract for 60 natural gas storage capacity on a seasonal The Group secures and controls a competitive, 51 and/or medium to long-term basis to facilitate 50 flexible and safe LNG shipping portfolio with 46 its operational and commercial requirements. 41 sufficient capacity to meet expected LNG 40 transportation requirements and capture In the UK, BG Group sells gas on a wholesale 30 business opportunities. The fleet is predominantly basis principally at the UK National Balancing a combination of short, medium and long-term Point (NBP) under contracts with varying 20 charters. This flexible, strategic approach allows durations. This includes the Group’s production 10 BG Group to seize new opportunities by of 0.2 bcfd of gas from the UK and Norwegian managing long-range delivery logistics, with Continental Shelf, which in 2013 was the 0 the Group regularly diverting cargoes from equivalent of approximately 3% of UK gas 2011 2012 2013 the Atlantic Basin to the Pacific Basin. demand. BG Group is an active participant in the capacity auctions held by National Grid In 2010, BG Group took delivery of four new and in the on-the-day commodity market Brazil North Sea** generation, energy-efficient LNG carriers. The and other electronic trading systems that help Kazakhstan* ships have a capacity of 170 000 cubic metres shippers balance their supply and demand. and are among the first carriers in the world * Kazakhstan represents CPC export volumes sold by BG Group owns both import and export capacity BG Group. It excludes volumes sold locally and into Russia. to integrate onboard reliquefaction with the in the Interconnector pipeline (UK to mainland ** North Sea includes Forties, Ekofisk and Ross blend propulsion system, allowing natural gas boil-off Europe), which it uses to ship gas to take crude only from BG Group’s interests in both the UK to be reliquefied and returned to cargo tanks. advantage of market price differentials and and Norwegian Continental Shelf. for sub-lets to third parties. As part of the LNG sales agreements signed In 2011, BG Group took delivery of its first with CNOOC in 2010 and 2013, BG Group and In Australia, BG Group has a gas and power chartered dynamically positioned oil shuttle CNOOC tendered for the design and construction marketing business that includes both domestic tanker, the Windsor Knutsen, to shuttle crude of four LNG vessels. In June 2014, BG Group gas sales and the dispatch of electricity from oil to markets from the floating production, divested its share of the vessels to Teekay Condamine power station into the National storage and offloading (FPSO) units in the LNG Operating LLC. The vessels, which will be Electricity Market. Domestic gas sales range Santos Basin, offshore Brazil. This vessel was constructed at the Hudong-Zhonghua shipyard from short to long-term covering both firm chartered by BG Group until the end of July in China, will be chartered into the Group’s and flexible volumes. 2014. Further in 2011, the Group signed 10 year portfolio for 20 years. www.bg-group.com 37

CONTENTS

Introduction and legal notices 38

People and communities People 39 Safety, health & security 39 Social performance 39

Group financial data Summarised BG Group annual results 40 Summarised BG Group quarterly results 41

Exploration and Production Estimated net reserves of natural gas 42 Estimated net reserves of oil 44 Field interests 45 Drilling activity 45 Licence and block interests 46

Liquefaction Facilities capacity 48

LNG Shipping & Marketing Contracted supply to BG Group 48 Long-term supply contracts 48 Cargoes 49 Ships 49

Oil marketing Ships 49

Corporate information Issued share capital and dividend history 50 Investor calendar 50 Credit ratings (BG Energy Holdings Ltd) 50 38 Data Book 2014

INTRODUCTION AND LEGAL NOTICES

Introduction Legal notices Explanatory note for US investors relating Financial and operating statistics Steps have been taken to verify the information to gas and oil reserves and resources This financial and operating information contained in this Data Book and, unless otherwise On 20 December 2007, BG Group ceased to includes extracts from the BG Group Annual indicated, it is believed to be accurate as at be a United States Securities and Exchange Report and Accounts 2013 (BG Group ARA) 31 July 2014. However, no representation or Commission (SEC) registered company and and quarterly results statements. Reference warranty, express or implied, is or will be made the Group’s SEC reporting obligations also to these reports will assist in the understanding in relation to the accuracy or completeness ceased with effect from that date. BG Group of the figures in this document. The financial of the information in this publication and no continued voluntarily to use the SEC definition information in this document is unaudited and responsibility or liability is or will be accepted by of proved reserves, and from 2009 of probable is not intended to be the statutory accounts BG Group plc or any of its respective subsidiaries, reserves, to report proved gas and oil reserves of BG Group plc. affiliates and associated companies (or by and disclose certain unaudited supplementary any of their respective officers, employees information until 2013. BG Group has decided, Business performance or agents) in relation to it. from the year ended 31 December 2013 onwards, Business performance excludes discontinued to adopt the reserves definitions and guidelines operations and disposals, certain re-measurements Certain statements included in this Data Book consistent with the internationally recognised and impairments*, as exclusion of these items contain forward-looking statements concerning Petroleum Resources Management System provides a clear and consistent presentation BG Group’s strategy, operations, financial published by the Society of Petroleum Engineers, of the underlying operating performance of performance or condition, outlook, growth American Association of Petroleum Geologists, the Group’s ongoing business. opportunities or circumstances in the countries, World Petroleum Council and the Society sectors or markets in which BG Group operates. of Petroleum Evaluation Engineers, known For further explanation of Business performance By their nature, forward-looking statements as the SPE PRMS, in accordance with and the presentation of results from joint involve uncertainty because they depend on recommendations issued by the European ventures and associates, please refer to the future circumstances, and relate to events, Securities and Markets Authority (ESMA) Presentation of non-GAAP measures on not all of which are within BG Group’s control and to achieve greater consistency across page 146 of the BG Group ARA. or can be predicted. Although BG Group its reporting of reserves and resources. believes that the expectations reflected in such Reference conditions (2014) forward-looking statements are reasonable, no BG Group has used gas and crude oil price ●● Brent Oil price real (1/1/2014): $100/bbl assurance can be given that such expectations forecasts that are based on its reference ●● US Henry Hub real (1/1/2014): $4.00/mmbtu will prove to have been correct. Actual results conditions to determine reserves estimates for ●● US/UK exchange rate of $1.55:£1 could differ materially from those set out in the the year ended 31 December 2013. This report ●● US/AUD exchange rate of $1:A$1.05 forward-looking statements in this Data Book also contains additional information about other ●● US/BRL exchange rate of $1:BRL2.10 for a number of reasons. For a detailed analysis BG Group gas and oil reserves and resources ●● Prepared under International Financial of the factors that may affect our business, that would not be permitted in SEC filings. Reporting Standards financial performance or results of operations, ●● All production includes fuel gas we urge you to look at the “Principal risks and Reserves (proved and probable) are measured uncertainties” included on pages 38 to 43 of in accordance with SPE PRMS definitions and the BG Group ARA. Nothing in this Data Book guidelines and, in this transition year, are should be construed as a profit forecast, and no voluntarily shown together with the estimates part of this publication constitutes, or shall be under the SEC definitions, which formed taken to constitute, an invitation or inducement the basis for measurement previously used to invest in BG Group plc or any other entity, by the Group. and must not be relied upon in any way in connection with any investment decision. For further details of BG Group’s proved BG Group undertakes no obligation to update reserves as at 31 December 2013, and related any forward-looking statements. supplemental gas and oil information, see Supplementary information – gas and oil, included on page 134 of the 2013 BG Group ARA. For an explanation of terms used in connection with such additional reserves and resources information, refer to page 4.

* Details of discontinued operations and disposals, certain re-measurements and impairments can be found on the BG Group website, www.bg-group.com www.bg-group.com 39

PEOPLE AND COMMUNITIES

PEOPLE

2013 2012 2011 Employees worldwide (average for year) 5 536 6 569 6 472 – of which employed outside of UK (average for year) 3 758 4 703 4 496 Employees working away from home country 802 775 679 Employee turnover 10% 14% 11% Women in workforce 28% 28% 29% Percentage of women in senior leadership positions(1) 13% 12% 10% Country management teams employed on local terms and conditions from non-OECD countries 43% 32% 32% Speak Up/whistleblowing cases 106 120 134 Number of reported cases with actions against individuals following Speak Up investigations 18 18 28

(1) Prior to 2013, ‘senior leadership’ was defined as two levels below the Group Executive Committee (GEC) (BG Group B grades) and above. However, from 2013 ‘senior leadership’ is now defined internally as one level below the GEC (BG Group A grades) and above.

SAFETY, HEALTH & SECURITY

2013 2012 2011 Fatalities – employees – – – Fatalities – contractors 1 2 3 Total recordable case frequency – employees (per million work hours) 0.48 0.53 0.67 Total recordable case frequency – contractors (per million work hours) 1.95 2.73 2.35 Total recordable case frequency – total workforce (per million work hours) 1.64 2.26 1.92 Reported occupational-related illness frequency 0.17 0.21 0.49

SOCIAL PERFORMANCE Social investment ($000) 2013 2012(3) 2011(3) STEM education 3 857 N/A N/A Vocational training 2 165 N/A N/A Livelihoods and enterprise development 1 895 N/A N/A Other 8 172 N/A N/A Total voluntary(1) 16 089 25 432 11 484 Total mandatory(2) 1 800 1 800 1 819 Total social investment 17 889 27 232 13 303

(1) Social investment spend that BG Group makes on a voluntary basis (2) Social investment spend that is a requirement or obligation under a licence, production sharing contract or other commercial agreement with a host government (3) Voluntary investment spend by theme not previously disclosed 40 Data Book 2014

SUMMARISED BG GROUP ANNUAL RESULTS

BUSINESS PERFORMANCE(1)

2013 2012 Restated(2) Dated Brent assumption ($/bbl) 108.66 111.58 Henry Hub (US$/mmbtu) 3.65 2.79 FX rate (US$/UK£) 1.56 1.58

BG Group E&P production (mmboe) 230.9 240.5 oil volume (mmboe) 35.8 29.4 liquids volume (mmboe) 33.9 33.9 gas volume (mmboe) 161.2 177.2 BG Group E&P production (‘000 boepd) 633 657 Delivered LNG volumes (‘000 tonnes) 10 878 12 063

Realised avg UK gas (pence per produced therm) 53.67 45.91 Realised avg UK gas (cents per produced therm) 84.07 72.80 Realised avg Int’l gas price (cents per produced therm) 42.73 42.05 Overall avg gas price (cents per produced therm) 46.59 44.84 Realised avg oil price ($/bbl) 108.61 110.86 Realised avg liquids price ($/bbl) 92.50 94.98

Lifting costs ($/boe) 7.07 6.06 Royalties and other operating costs ($/boe) 5.10 4.19 Opex ($/boe) 12.17 10.25 Other E&P costs ($/boe) 4.01 4.23 DD&A ($/boe) 11.29 9.05

Total operating profit including share of pre-tax operating results from joint ventures and associates ($ million) E&P Operating profit before exploration charge 5 431 5 830 Exploration charge (711) (684) E&P Operating profit 4 720 5 146 Liquefaction 360 351 Upstream business development (113) (30) Upstream 4 967 5 467 LNG Shipping and Marketing 2 643 2 577 Other activities 6 6 Total operating profit 7 616 8 050 Net finance costs(3) (203) (152) Profit before tax 7 413 7 898 Tax on profit on ordinary activities(4) (3 039) (3 519) Earnings 4 374 4 379 Earnings per ordinary share (cents) 128.6 128.9 Dividends per ordinary share (cents) 28.75 26.14

Capital investment on a cash basis(5) 11 215 10 407 Free cash flow(6) (3 626) (2 380)

Net borrowings (10 610) (10 624) Gearing %(7) 24.8 24.3

ADDITIONAL INFORMATION: EXPLORATION AND PRODUCTION

Development expenditure ($ million) 8 210 6 796 Gross exploration expenditure ($ million) 1 658 1 220 – capitalised 1 341 855 – other expenditure 317 365

(1) ‘Business performance’ excludes disposals, certain re-measurements and impairments as exclusion of these items provides a clear and consistent presentation of the underlying operating performance of the Group’s ongoing business (2) 2012 results have been restated to reflect the adoption of the amended IAS 19 in respect of defined benefit pension obligations (3) Includes share of joint ventures and associates net finance costs (4) Includes share of joint ventures and associates tax (5) 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. Includes capital investment relating to discontinued operations for the full year of $10 million (2012 $281 million) (6) Net cash flow from operating activities, less net interest paid and capital investment on a cash basis, plus dividends received and loan repayments (7) Net borrowings as a percentage of total shareholders’ funds (excluding balances associated with commodity financial instruments and related deferred tax) plus net borrowings www.bg-group.com 41

SUMMARISED BG GROUP QUARTERLY RESULTS

BUSINESS PERFORMANCE(1)

Q2 Q1 Q4 Q3 Q2 Q1 2014 2014 2013 2013 2013 2013 Dated Brent assumption ($/bbl) 109.38 108.31 109.27 110.36 102.44 112.55 Henry Hub (US$/mmbtu) 4.67 4.94 3.61 3.58 4.09 3.34 FX rate (US$/UK£) 1.68 1.66 1.62 1.53 1.53 1.58

BG Group E&P production (mmboe) 53.8 57.0 58.4 53.4 59.8 59.3 oil volume (mmboe) 12.3 11.6 10.2 8.9 8.8 8.0 liquids volume (mmboe) 7.8 8.8 8.7 8.2 8.2 8.7 gas volume (mmboe) 33.7 36.6 39.5 36.3 42.8 42.6 BG Group E&P production (‘000 boepd) 591 633 635 580 657 659 Delivered LNG volumes (‘000 tonnes) 3 102 2 447 2 816 2 683 2 399 2 980

Realised avg UK gas price (pence per produced therm) 38.01 50.37 53.05 44.61 54.48 58.40 Realised avg UK gas (price cents per produced therm) 63.74 83.47 86.21 68.17 83.49 91.75 Realised avg Int’l gas price (cents per produced therm) 43.58 45.04 42.99 43.87 42.98 41.23 Overall avg gas price (cents per produced therm) 45.90 50.00 47.14 45.42 47.55 46.10 Realised avg oil price ($/bbl) 110.21 108.95 109.60 111.72 102.11 110.47 Realised avg liquids price ($/bbl) 91.33 88.60 95.28 96.42 82.88 95.10

Lifting costs ($/boe) $8.39 $7.88 $7.47 $7.49 $7.05 $6.31 Royalties and other operating costs ($/boe) $7.03 $6.84 $5.55 $5.87 $4.32 $4.77 Opex ($/boe) $15.42 $14.72 $13.02 $13.36 $11.37 $11.08 Other E&P costs ($/boe) $6.84 $4.51 $6.65 $3.18 $2.02 $3.59 DD&A ($/boe) $11.06 $11.52 $11.95 $10.91 $11.22 $11.08

Total operating profit including share of pre-tax operating results from joint ventures and associates ($ million) E&P Operating profit before exploration charge 1 296 1 364 1 483 1 217 1 295 1 436 Exploration charge (117) (161) (369) (103) (133) (106) E&P Operating profit 1 179 1 203 1 114 1 114 1 162 1 330 Liquefaction 71 94 58 84 112 106 Upstream business development (19) 28 (56) (29) (23) (5) Upstream 1 231 1 325 1 116 1 169 1 251 1 431 LNG Shipping and Marketing 749 692 778 602 521 742 Other activities 12 (8) 14 2 16 (26) Total operating profit 1 992 2 009 1 908 1 773 1 788 2 147 Net finance costs(2) (10) (56) (79) (63) (26) (35) Profit before tax 1 982 1 953 1 829 1 710 1 762 2 112 Tax on profit on ordinary activities(3) (773) (801) (694) (640) (776) (929) Earnings 1 209 1 152 1 135 1 070 986 1 183 Earnings per ordinary share (cents) 35.5 33.8 33.3 31.5 29.0 34.8 Dividends per ordinary share (cents) 14.4 – 15.7 – 13.1 –

Capital investment on a cash basis(4) 2 476 2 283 3 183 2 792 2 604 2 636 Free cash flow(5) (507) 153 (1 292) (1 391) (602) (341)

Net borrowings (10 377) (10 410) (10 610) (13 001) (11 198) (10 609) Gearing %(6) 23.0 23.6 24.8 27.6 25.2 23.5

ADDITIONAL INFORMATION: EXPLORATION AND PRODUCTION

Development expenditure ($ million) 1 720 1 500 1 995 2 234 2 069 1 912 Gross exploration expenditure ($ million) 325 285 403 586 334 335 – capitalised 228 181 326 514 267 234 – other expenditure 97 104 77 72 67 101

(1) ‘Business performance’ excludes disposals, certain re-measurements and impairments as exclusion of these items provides a clear and consistent presentation of the underlying operating performance of the Group’s ongoing business (2) Includes share of joint ventures and associates net finance costs (3) Includes share of joint ventures and associates tax (4) 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 (5) Net cash flow from operating activities, less net interest paid and capital investment on a cash basis, plus dividends received and loan repayments (6) Net borrowings as a percentage of total shareholders’ funds (excluding balances associated with commodity financial instruments and related deferred tax) plus net borrowings 42 Data Book 2014

EXPLORATION AND PRODUCTION: ESTIMATED NET RESERVES OF NATURAL GAS

All information for periods up to 31 December 2012 is presented under SEC methodology. Information for 31 December 2013 is presented under both SEC and SPE PRMS methodology.

The allocation of the countries within these areas is: UK Atlantic Basin – Canada, Egypt, Nigeria, Trinidad and Tobago and the USA Asia and the Middle East – Areas of Palestinian Authority, Australia, China, India, Kazakhstan and Thailand Rest of the World – Algeria, Bolivia, Brazil, Colombia, Honduras, Kenya, Madagascar, Norway, Tanzania, Tunisia and Uruguay

ESTIMATED NET PROVED RESERVES OF NATURAL GAS

Atlantic Asia and Rest of UK Basin Middle East World Total bcf bcf bcf bcf bcf As at 31 December 2010 862 4 237 4 354 2 232 11 685(1) Movement during the year: Revisions of previous estimates(2) 100 486 (77) 339 848 Extensions, discoveries and reclassifications 3 256 731 300 1 290 Production (99) (610) (225) (107) (1 041) Acquisitions of reserves-in-place 70 33 – – 103 Disposals of reserves-in-place – – (31) – (31) 74 165 398 532 1 169 As at 31 December 2011 936 4 402 4 752 2 764 12 854(1) Movement during the year: Revisions of previous estimates(2) (22) (516) 87 (93) (544) Extensions, discoveries and reclassifications (1) 79 821 59 958 Production (87) (612) (240) (124) (1 063) Disposals of reserves-in-place – – (22) – (22) (110) (1 049) 646 (158) (671) As at 31 December 2012 826 3 353 5 398 2 606 12 183(1) Movement during the year: Revisions of previous estimates(2) (35) (108) 553 129 539 Extensions, discoveries and reclassifications (13) (116) 27 – (102) Production (82) (510) (238) (137) (967) Disposals of reserves-in-place – (65) (791) – (856) (130) (799) (449) (8) (1 386) As at 31 December 2013 (SEC) 696 2 554 4 949 2 598 10 797(1) Revisions of previous estimates(3) – 92 55 6 153 Extensions, discoveries and reclassifications(4) – – 1 091 – 1 091 As at 31 December 2013 (SPE PRMS) 696 2 646 6 095 2 604 12 041(5)

Note: Conversion factor of 6 bcf of gas to 1 mmboe. (1) Estimates of proved natural gas reserves at 31 December 2013 include fuel gas of 978 bcf (2011: 1 013 bcf; 2010: 829 bcf; 2009: 702 bcf). (2) Includes effect of oil and gas price changes on PSCs. (3) Includes the effect of changing from SEC price assumptions to SPE PRMS reference prices, including impact on PSCs. (4) The increase in net proved reserves of natural gas compared with SEC estimates is mainly due to reserves maturation from probable into proved reserves. (5) Estimates of proved natural gas reserves at 31 December 2013 under SPE PRMS methodology include fuel gas of 1 031 bcf.

ESTIMATED NET PROVED DEVELOPED RESERVES OF NATURAL GAS

Atlantic Asia and Rest of UK Basin Middle East World Total bcf bcf bcf bcf bcf As at 31 December 2010 640 2 099 2 469 776 5 984 As at 31 December 2011 728 2 103 2 426 892 6 149 As at 31 December 2012 680 2 088 2 360 1 194 6 322 As at 31 December 2013 (SEC) 572 1 414 2 249 1 192 5 427 As at 31 December 2013 (SPE PRMS) 572 1 407 2 300 1 195 5 474 www.bg-group.com 43

ESTIMATED NET PROBABLE RESERVES OF NATURAL GAS Atlantic Asia and Rest of UK Basin Middle East World Total bcf bcf bcf bcf bcf Probable developed reserves of natural gas As at 31 December 2010 264 881 21 296 1 462 As at 31 December 2011 203 873 7 239 1 322 As at 31 December 2012 171 545 256 272 1 244 As at 31 December 2013 (SEC) 324 570 300 100 1 294 As at 31 December 2013 (SPE PRMS) 324 570 300 100 1 294 Probable undeveloped reserves of natural gas As at 31 December 2010 71 1 002 6 717 2 630 10 420 As at 31 December 2011 97 1 280 7 479 1 586 10 442 As at 31 December 2012 270 1 436 6 668 1 895 10 269 As at 31 December 2013 (SEC)(1) 67 1 228 4 333 4 756 10 384 As at 31 December 2013 (SPE PRMS)(1) 66 1 143 3 267 4 869 9 345 Total estimated net probable reserves of natural gas(2) As at 31 December 2010 335 1 883 6 738 2 926 11 882 As at 31 December 2011 300 2 153 7 486 1 825 11 764 As at 31 December 2012 441 1 981 6 924 2 167 11 513 As at 31 December 2013 (SEC)(1) 391 1 798 4 633 4 856 11 678 As at 31 December 2013 (SPE PRMS)(1)(3) 390 1 713 3 567 4 969 10 639

(1) On 26 January 2014, the Algerian government issued a decree which confirmed the relinquishment of reserves in Algeria (381 bcf of estimated net probable reserves of natural gas). (2) Estimates of probable natural gas reserves at 31 December 2013 include fuel gas of 660 bcf (2011: 470 bcf; 2010: 693 bcf; 2009: 934 bcf). (3) The reduction in net probable reserves of natural gas compared with SEC estimates is mainly due to reserve maturation from probable to proved reserves. Estimates of probable natural gas reserves under SPE PRMS methodology at 31 December 2013 include fuel gas of 607 bcf. 44 Data Book 2014

EXPLORATION AND PRODUCTION: ESTIMATED NET RESERVES OF OIL

ESTIMATED NET PROVED RESERVES OF OIL ‘OIL’ INCLUDES CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS.

Atlantic Asia and Rest of UK Basin Middle East World Total mmbbl mmbbl mmbbl mmbbl mmbbl As at 31 December 2010 151.4 9.8 322.9 461.7 945.8 Movement during the year: Revisions of previous estimates(1) 31.9 0.9 (35.2) 198.2 195.8 Extensions, discoveries and reclassifications 0.3 (0.4) 0.5 21.1 21.5 Production (21.8) (1.8) (28.5) (8.4) (60.5) Acquisitions of reserves-in-place 2.8 – – – 2.8 13.2 (1.3) (63.2) 210.9 159.6 As at 31 December 2011 164.6 8.5 259.7 672.6 1 105.4 Movement during the year: Revisions of previous estimates(1) 7.5 (0.5) 17.1 96.3 120.4 Extensions, discoveries and reclassifications 1.4 – 0.2 235.6 237.2 Production (20.8) (1.7) (27.5) (13.3) (63.3) Disposals of reserves-in-place(2) – – 0.8 – 0.8 (11.9) (2.2) (9.4) 318.6 295.1 As at 31 December 2012 152.7 6.3 250.3 991.2 1 400.5 Movement during the year: Revisions of previous estimates(1) 9.3 4.1 2.6 145.7 161.7 Extensions, discoveries and reclassifications (2.9) 0.1 0.4 33.9 31.5 Production (22.9) (2.4) (25.4) (19.0) (69.7) Disposals of reserves-in-place – (0.6) – – (0.6) (16.5) 1.2 (22.4) 160.6 122.9 As at 31 December 2013 (SEC) 136.2 7.5 227.9 1 151.8 1 523.4 Revisions of previous estimates(3) (2.2) 0.1 9.2 1.5 8.6 As at 31 December 2013 (SPE PRMS) 134.0 7.6 237.1 1 153.3 1 532.0

(1) Includes effect of oil and gas price changes on PSCs. (2) Karachaganak Settlement Agreement (disposal) resulted in minor addition to liquids. (3) Includes the effect of changing from SEC price assumptions to SPE PRMS reference prices, including impact on PSCs.

ESTIMATED NET PROVED DEVELOPED RESERVES OF OIL

Atlantic Asia and Rest of UK Basin Middle East World Total mmbbl mmbbl mmbbl mmbbl mmbbl As at 31 December 2010 113.6 5.7 277.5 27.8 424.6 As at 31 December 2011 136.8 4.1 238.1 62.5 441.5 As at 31 December 2012 126.1 6.2 230.5 95.0 457.8 As at 31 December 2013 (SEC) 120.5 4.9 212.8 132.2 470.4 As at 31 December 2013 (SPE PRMS) 119.1 4.9 221.4 132.4 477.8

ESTIMATED NET PROBABLE RESERVES OF OIL Atlantic Asia and Rest of UK Basin Middle East World Total mmbbl mmbbl mmbbl mmbbl mmbbl Probable developed reserves of oil As at 31 December 2010 49.3 2.9 4.3 14.1 70.6 As at 31 December 2011 41.2 3.2 0.2 30.9 75.5 As at 31 December 2012 36.6 1.8 2.6 22.3 63.3 As at 31 December 2013 (SEC) 26.5 2.2 2.8 47.6 79.1 As at 31 December 2013 (SPE PRMS) 26.5 2.2 2.8 47.6 79.1 Probable undeveloped reserves of oil As at 31 December 2010 20.6 1.0 99.6 1 650.4 1 771.6 As at 31 December 2011 18.5 1.4 137.0 1 745.9 1 902.8 As at 31 December 2012 27.0 8.3 75.0 1 666.1 1 776.4 As at 31 December 2013 (SEC) 27.5 3.3 110.6 1 450.9 1 592.3 As at 31 December 2013 (SPE PRMS) 28.7 3.2 118.4 1 449.7 1 600.0 Total estimated net probable reserves of oil As at 31 December 2010 69.9 3.9 103.9 1 664.5 1 842.2 As at 31 December 2011 59.7 4.6 137.2 1 776.8 1 978.3 As at 31 December 2012 63.6 10.1 77.6 1 688.4 1 839.7 As at 31 December 2013 (SEC) 54.0 5.5 113.4 1 498.5 1 671.4 As at 31 December 2013 (SPE PRMS) 55.2 5.4 121.2 1 497.3 1 679.1 www.bg-group.com 45

EXPLORATION AND PRODUCTION: FIELD INTERESTS

PRODUCING FIELDS

Gas production Oil and liquids production Total production kboed kboed kboed 2013 2012 2011 2013 2012 2011 2013 2012 2011 Australia 25 25 21 – – – 25 25 21 Bolivia 29 23 16 7 5 3 36 28 19 Brazil 4 3 1 35 22 12 39 25 13 Egypt 107 129 132 5 3 3 112 132 135 India 14 17 21 6 8 10 20 25 31 Kazakhstan 36 36 39 56 62 63 92 98 102 Norway 1 2 – 1 1 – 2 3 – Thailand 34 30 22 7 6 5 41 36 27 Trinidad and Tobago 68 72 74 2 1 1 70 73 75 Tunisia 29 28 32 9 9 8 38 37 40 UK 37 40 45 63 56 60 100 96 105 USA 58 79 73 – – – 58 79 73 Total production of gas, oil and liquids (kboed) 442 484 476 191 173 165 633 657 641

Total production of gas, oil and liquids (mmboe) 230.9 240.5 234.1

Production volume includes fuel gas.

OTHER FIELDS AND DISCOVERIES WITH PROVED OR PROBABLE RESERVES: BG GROUP WORKING INTEREST (%) AS AT 31 DECEMBER 2013

Brazil Iara 25.00 Lapa* 30.00 Egypt WDDM near field satellites, e.g. Mina, Silva, Sapphire Deep 50.00 Norway Knarr 45.00 Tanzania Jodari 60.00 Pweza 60.00 Chewa 60.00 Trinidad and Tobago Starfish 50.00 Endeavour 100.00 UK Jackdaw 40.94

*Formerly named Carioca prior to Declaration of Commerciality.

EXPLORATION AND PRODUCTION: DRILLING ACTIVITY

WELL OPERATIONS(1)

Number of exploration and appraisal wells 2013 2012 2011 Total 24 19 16 Percentage successful 79 95 63

WELLS DRILLED IN 2013 ANALYSIS BY COUNTRY(1)

Exploration Appraisal Bolivia 1 – Brazil 2 3 Egypt 2 – Tanzania 2 4 Thailand 8 – UK 2 – Total 17 7

(1) Excludes unconventional coal seam gas and shale gas wells. 46 Data Book 2014

EXPLORATION AND PRODUCTION: LICENCE AND BLOCK INTERESTS Held at 31 July 2014

Number BG Group- BG Group Country Interest details of blocks Type of fields(1) operated interest (%) Areas of Palestinian Authority Gaza Marine 1 Gas 1 90 Aruba Aruba Block(2) 1 Unknown 0 30 Australia Walloons Fairway 45 Gas (CSG) 45 Various Other Surat Basin 5 Unknown 4 Various Bowen Basin 13 Unknown 10 Various Cooper Basin 1 Unknown 1 Various Bolivia La Vertiente 1 Gas 1 100 Caipipendi 1 Gas & condensate 0 37.5 Block Tarija XX West 1 Gas & condensate 0 25 Block Tarija XX East 1 Gas & oil 1 100 Charagua(3) 1 Unknown 0 20 Los Suris 1 Gas 1 100 Huacareta 1 Unknown 1 100 Brazil(4) BM-S-9 1 Oil & gas 0 30 BM-S-11 1 Oil & gas 0 25 BM-S-50 1 Oil & gas 0 20 BAR-M-215 1 Unknown 1 75 BAR-M-217 1 Unknown 1 75 BAR-M-252 1 Unknown 1 75 BAR-M-254 1 Unknown 1 75 BAR-M-298 1 Unknown 1 100 BAR-M-300 1 Unknown 1 50 BAR-M-340 1 Unknown 1 100 BAR-M-342 1 Unknown 1 50 BAR-M-344 1 Unknown 1 50 BAR-M-388 1 Unknown 1 50 Colombia Guajira Offshore 3(5) 1 Unknown 0 30 Egypt Rosetta 4 Gas 4 80 West Delta Deep Marine 8 Gas 8 50 El Manzala Offshore 1 Unknown 1 50 El Burg Offshore 1 Gas 1 60 North Gamasa Offshore 1 Unknown 1 60 East El Burullus Offshore 1 Unknown 0 40 Honduras Mosquitia and Patuca Basins 1 Unknown 1 100 India Mid and South Tapti 1 Gas & condensate 1(6) 30 Panna/Mukta 2 Oil & gas 2(6) 30 KG-DWN-2009/1 1 Unknown 1 30 MB-DWN-2010/1 1 Unknown 1 50 Italy Po Valley Permit (Vigevano) 1 Unknown 0 40 Kazakhstan Karachaganak 1 Various 1(7) 29.25 Kenya L10A 1 Unknown 1 50 L10B 1 Unknown 1 75 Madagascar Majunga Offshore Profond 1 Unknown 0 30 Myanmar(8) Block A-4 1 Unknown 1 45 Block A-7 1 Unknown 0 45 Block AD-2 1 Unknown 1 55 Block AD-5 1 Unknown 0 45 Nigeria(3) OPL 286-DO 1 Oil & gas 1 66 OPL 284-DO 1 Oil & gas 0 45 Norway(9) Central North Sea 5 Various 4 Various Northern North Sea 18 Oil & unknown 16 Various Mid-Norway 5 Unknown 5 40 Barents Sea 6 Various 3 Various

www.bg-group.com 47

Number BG Group- BG Group Country Interest details of blocks Type of fields(1) operated interest (%) Tanzania Block 1 1 Gas 1 60 Block 3 1 Gas 1 60 Block 4 1 Gas 1 60 Thailand 3/2515/7 2 Various 0 22.22 3/2549/71 1 Various 0 22.22 4/2515/8(10) 3 Unknown 3 66.67 5/2515/9 1 Various 0 22.22 Trinidad and Tobago Block 5(a) 1 Various 1 50 Block 5(c) 1 Various 1 100 Block 5(d) 1 Unknown 1 100 Block 6(b) 1 Various 1 50 Block 6(d) 1 Various 1(11) 50 Block E 1 Gas 1 50 Central Block 1 Various 1 65 TTDAA 5 1 Unknown 0 35 TTDAA 6 1 Unknown 0 35 NCMA 1 Gas 1 45.88 Tunisia Amilcar 1 Unknown 1 50 Miskar 1 Gas & condensate 1 100 Hasdrubal 1 Various 1 50 United Kingdom(9) Central North Sea c.70 Various & unknown 43 Various United States Alaska Foothills 329 Gas 0 33.33 Penn. & W. Virginia Marcellus Shale – Gas 0(12) Various Texas & Louisiana Haynesville Shale – Gas 0 Various Uruguay Block 8 1 Unknown 1 100 Block 9 1 Unknown 1 100 Block 13 1 Unknown 1 100

(1) The type of field is given as Various where it relates to oil and/or gas and/or condensate, or Unknown where the interest is an exploration interest with no discovery (2) BG Group’s farm-in agreement is subject to approval by the Compania Arubano di Petroleo N.V. (3) Blocks under relinquishment (4) The BM-S-10 block was relinquished and the concession finalisation processes are underway with the ANP (5) BG Group’s farm-in agreement is subject to approval by the Colombian government’s Agencia Nacional de Hidrocarburos (6) Mid and South Tapti and Panna/Mukta are jointly operated by BG Group with ONGC and Reliance Industries Limited (7) Joint operator with Eni (8) Blocks awarded in March 2014. PSCs expected to be finalised in due course (9) Includes part blocks and sub-areas (10) Area is subject to international boundary dispute – obligations under suspension pending resolution (11) Block 6(d), Manatee, operated by Chevron Trinidad and Tobago Resources SRL (12) Portions of interests in the Marcellus Shale are operated by an entity that is jointly held with EXCO Resources 48 Data Book 2014

LIQUEFACTION: FACILITIES CAPACITY As at 31 July 2014

EXPORT TERMINALS

Total capacity Total capacity BG Group (mtpa) (mtpa) Train equity (%) Gross Net Status Atlantic LNG 1 26.00 3.1 0.81 Since April 1999 Atlantic LNG 2 32.50 3.3 1.07 Since April 2002 Atlantic LNG 3 32.50 3.3 1.07 Since April 2003 Atlantic LNG 4 28.89 5.2 1.50 Since December 2005 Egyptian LNG 1 35.50 3.6 1.28 Since May 2005 Egyptian LNG 2 38.00 3.6 1.37 Since September 2005 Total 7.10

IMPORT TERMINALS

Total capacity Total capacity Total capacity (mtpa) (mtpa) (bcfd) Gross(1) Net(1) Net Status 100% since 1 January 2004 Phase 2 expansion completed July 2006 Lake Charles, USA 13.1 13.1 1.8(2) Infrastructure enhancement project completed March 2010 Elba Island, USA 11.5(3) 4.6(3) 0.63(2) 40% since March 2010 Dragon LNG, UK 4.4 2.2 0.30 Operational since July 2009 Total 29.0 19.9 2.73

(1) Mtpa equivalent is based on a conversion factor of 1 mtpa : 7.3 bcfd (2) Data represents terminal base load capacity. Lake Charles peak capacity is 2.35 bcfd, 17.3 mtpa; Elba Island net peak capacity is 0.71 bcfd, 5.2 mtpa (3) Of which 1.2 mtpa may be supplied by Marathon

LNG SHIPPING & MARKETING: CONTRACTED SUPPLY TO BG GROUP As at 31 July 2014

Total supply (mtpa) Start Duration End Shipping Atlantic LNG Trains 2/3 PFLE(1) 1.7 Q1 2004 20 Q3 2023 FOB Trinling(1) 0.4 Q1 2004 22 Q1 2026 DES(2) Nigeria LNG Trains 4/5 2.3 Q3 2006 20 Q3 2026 CIF Egyptian LNG Train 2 3.6 Q2 2006(3) 20 Q2 2026 FOB Atlantic LNG Train 4 1.5 Q2 2007 20 Q2 2027 FOB Equatorial Guinea 3.3 Q4 2006(3) 17 Q4 2023 FOB Queensland Curtis LNG 8.5 2014 20 2034 FOB Sabine Pass 5.5 2016(4) 20 2036 FOB Nigeria LNG Train 7 2.3 20 CIF Total contracted supply 29.1

(1) LNG is sold to Point Fortin LNG Exports Limited (PFLE) and Trinling Limited (both incorporated in Trinidad and Tobago) from Atlantic LNG for onward sale to BGGM. PFLE and Trinling are owned in proportional equity by the NCMA and ECMA partners respectively (2) BG Group has diversion rights under the contract (3) Contract start date. May differ from date of first cargo lifted (4) Contract start date. Not indicative of terminal start date

LNG SHIPPING & MARKETING: LONG-TERM SUPPLY CONTRACTS As at 31 July 2014

Supply (mtpa) Years Start-up Quintero LNG, Chile Up to 3.0 21 2009 Singapore Up to 3.0 20 2013 China National Offshore Oil Corporation 3.6 20 2014 Chubu Electric Power Co., Inc. Up to 0.4 21 2014 China National Offshore Oil Corporation 5.0 20 2015 Gujarat State Petroleum Corporation Up to 2.5 20 2015 Tokyo Gas Co., Ltd. 1.2 20 2015 Total Up to 18.7 www.bg-group.com 49

LNG SHIPPING & MARKETING: CARGOES

Q2 Q1 Q4 Q3 Q2 Q1 2014 2014 2013 2013 2013 2013 LNG cargo deliveries by geographical region Asia 32 26 37 32 25 33 Europe – 1 – – – 2 South America 15 11 9 10 12 10 USA 2 1 – 1 1 4 Other 1 1 – 1 1 – Total 50 40 46 44 39 49

LNG delivered volumes (mtpa) 3.10 2.45 2.82 2.68 2.40 2.98

LNG SHIPPING & MARKETING: SHIPS As at 31 July 2014

Name Year built Capacity (cm)(1) Propulsion Containment Contract Core fleet Methane Kari Elin 2004 138 267 ST(2) Mk.III BB(3) (10+ years) Methane Princess 2004 138 158 ST No.96 TC(4) Methane Nile Eagle 2007 145 598 ST Mk.III TC Methane Julia Louise 2010 170 723 TFDE(5) Mk.III Owned Methane Becki Anne 2010 170 678 TFDE Mk.III Owned Methane Patricia Camilla 2010 170 600 TFDE Mk.III Owned Methane Mickie Harper 2010 170 600 TFDE Mk.III Owned Total 7 1 104 624 Flexible fleet Various 2005-2010 < 165 936 – – TC

(1) Capacity – gross 100% (2) ST – steam turbine (3) BB – bareboat charter (4) TC – time charter (5) TFDE – tri-fuel diesel-electric

OIL MARKETING: SHIPS As at 31 July 2014

Name Year built Capacity (boe)(1) Propulsion Containment Contract Core fleet Samba Spirit 2013 1 000 000 MF(2) OCT(3) TC(4) (10+ years) Lambada Spirit 2013 1 000 000 MF OCT TC Bossa Nova Spirit 2013 1 000 000 MF OCT TC Sertanejo Spirit 2013 1 000 000 MF OCT TC Total 4 4 000 000 1 000 000- Flexible fleet Various/Spot market 2005-2012 2 000 000 – – VC(5)

(1) Capacity – gross 100% (2) MF – marine fuel (3) OCT – oil cargo tanks (4) TC – time charter (5) VC – voyage charter 50 Data Book 2014

ISSUED SHARE CAPITAL AND DIVIDEND HISTORY

TOTAL ISSUED ORDINARY SHARE CAPITAL

2013 2012 2011 Shares in issue at year end (millions) 3 619 3 614 3 611

DIVIDEND DATA

Payment Value Announcement date Ex-dividend date Record date Payment date Final 11.78c/7.31p 8 February 2011 13 April 2011 15 April 2011 20 May 2011 Interim 10.80c/6.63p 26 July 2011 3 August 2011 5 August 2011 8 September 2011 Final 12.96c/8.19p 9 February 2012 11 April 2012 13 April 2012 25 May 2012 Interim 11.88c/7.64p 26 July 2012 1 August 2012 3 August 2012 7 September 2012 Final 14.26c/9.03p 5 February 2013 17 April 2013 19 April 2013 31 May 2013 Interim 13.07c/8.51p 26 July 2013 7 August 2013 9 August 2013 6 September 2013 Final 15.68c/9.51p 4 Feb 2014 23 Apr 2014 25 Apr 2014 30 May 2014 Interim 14.38c/8.47p 31 Jul 2014 13 Aug 2014 15 Aug 2014 12 Sep 2014

INVESTOR CALENDAR

Type Date 2014 Third quarter 2014 results Announcement 28 October 2014 2015 Fourth quarter and full year 2014 results Announcement 3 February 2015(1) 2014 final dividend Ex-dividend April 2015(1) 2015 Annual General Meeting Meeting 5 May 2015(1) First quarter 2015 results Announcement 8 May 2015(1) 2015 final dividend Dividend paid (UK and US ADR) May 2015(1)

(1) Provisional dates.

CREDIT RATINGS (BG ENERGY HOLDINGS LTD)

BG Energy Holdings Ltd (BGEH) is rated by three major credit rating agencies, with the following long-term ratings as at 31 July 2014:

Long-term Date rating Date outlook Rating agency rating assigned Outlook assigned Fitch A- July 2013 Negative July 2014 Moody’s A2 August 2005 Negative November 2012 Standard & Poor’s A- May 2013 Negative May 2014

BGEH’s objective is to maintain long-term credit ratings equivalent to mid-single A from all the above agencies.

Registrar and Transfer Office Stock Exchange Information Deutsche Bank Trust Company Americas Equiniti Limited London Stock Exchange c/o American Stock Transfer & Trust Company Aspect House, Spencer Road Ticker symbol: BG.L 6201 15th Avenue, Brooklyn NY 11219, USA Lancing, West Sussex SEDOL number: 0876289 Tel: +1 800 937 5449 (toll free for US residents) BN99 6DA Tel: +1 718 921 8124 (outside USA) Tel: 0871 384 2064 One ADR: one ordinary share www.adr.db.com +44 121 415 7029 (outside UK) Pink OTC Markets symbol: BRGYY Email: [email protected] www.shareview.co.uk American Depositary Receipts Email via https://help.shareview.co.uk More online The BG Group Data Book can be found online at www.bg-group.com/reports Other detailed corporate reports, including the Annual Report and Accounts, and the Sustainability Report, can be found at the same address.

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This Data Book has been printed on UPM Fine, a paper produced using wood fibre from fully sustainable forests with FSC® certification. All pulps used are Elemental Chlorine Free and the manufacturing mill holds the ISO14001 and the EMAS accreditations for environmental management. BG Group plc 100 Thames Valley Park Drive Reading, Berkshire RG6 1PT United Kingdom www.bg-group.com

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