A global portfolio Data Book 2014 - Shell Global | Shell ...

A global portfolioData Book 2014

Oil and gas production 2013(%)

Egypt 18%UK 16%Kazakhstan 15%Trinidad and Tobago 11%

USA 9%Thailand 6%

Bolivia 6%

Brazil 6%Tunisia 6%

Australia 4%India 3%Norway <1%

600

700

500

400

300

200

100

0

644 646 641 657

2013

633

20102009 2011 2012

E&P production volumes(kboed)

Gas

Oil & liquids

15 000

18 000

12 000

9 000

6 000

3 000

0

14 49416 180

17 13018 511

2013

SECSECSECSECSEC SPE-PRMS

2013

17 721 17 771

20102009 2011 2012

E&P reserves and resources(1)

(mmboe)

(1) See page 4 for reserve and resource definitions.

Proved reserves

Probable reserves

Discovered resources

Risked exploration

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

OUR VISION

KEY DATA FOR THE YEAR ENDED 31 DECEMBER

12

14

10

8

6

4

2

0

13.1 12.9 12.812.1

2013

10.9

20102009 2011 2012

LNG delivered volumes(mtpa)

LNG Shipping & Marketing total operating profit(2) ($m)

2 500

3 000

2 000

1 500

1 000

500

0

2 121 2 1352 282

2 577

2013

2 643

20102009 2011 2012

(2) Business performance (see page 38 for a description).

6 000

8 000

4 000

2 000

0

3 5044 092

5 439 5 467

2013

4 967

20102009 2011 2012

Upstream total operating profit(2) ($m)

(2) Business performance (see page 38 for a description).

Cover imageSurvey vessel MV Geo Coral, offshore TanzaniaThe survey vessel MV Geo Coral undertaking a seismic survey. The seismic survey vessel and the equipment it tows create a footprint 8.5 km long and 1 km wide. Image courtesy of CGG. Inside cover imageWorkers on the Dolphin platform, Trinidad and TobagoThe 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.

CONTENTS

COUNTRIES

05 Brazil08 Australia 11 Egypt13 United Kingdom16 Norway17 Kazakhstan19 Trinidad and Tobago22 United States of America23 Canada24 Thailand25 Tunisia26 Bolivia27 India28 Tanzania29 Kenya29 Madagascar30 Uruguay30 Honduras31 Colombia31 Aruba32 Myanmar32 Singapore33 Areas of Palestinian Authority34 Global Energy Marketing

and Shipping

STATISTICAL SUPPLEMENT

38 Introduction and legal notices39 People and communities

40 Group financial data42 Exploration and Production

48 Liquefaction48 LNG Shipping & Marketing49 Oil Marketing50 Corporate information

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.

01www.bg-group.com

CANADA

ARUBA

UNITED STATES OF AMERICA

HONDURAS

TRINIDAD AND TOBAGO

BOLIVIA

URUGUAY

BRAZIL

COLOMBIA

WHERE WE WORK

BG Group’s strategy is to create value by leveraging its distinctive capabilities in exploration and from its unique LNG business. The Group’s Upstream production is currently sourced from base assets in 10 countries and key growth projects in Brazil and Australia. Wide 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. In LNG, the Group’s skills and capabilities span the whole LNG value chain.

* Business performance – see page 38 for description.

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

Data Book 201402

MADAGASCAR

KENYA

AREAS OF PALESTINIAN AUTHORITY

TUNISIA

UNITED KINGDOM

NORWAY

MYANMAR

THAILAND

SINGAPORE

KAZAKHSTAN

EGYPT

INDIA

AUSTRALIA

TANZANIA

OUR BUSINESS SEGMENTS

UPSTREAMBG Group explores for, develops, produces and markets gas and oil around the world. The Upstream business segment covers exploration and production activities plus liquefaction operations associated with integrated LNG projects.

LNG SHIPPING & MARKETINGBG Group purchases, ships, markets and sells LNG. The LNG Shipping & Marketing segment covers these activities, as well as the Group’s interests and capacity in regasification facilities.

TOTAL OPERATING PROFITBusiness performance*

$4 967m2012 $5 467m

-9% +3%

TOTAL OPERATING PROFITBusiness performance*

$2 643m2012 $2 577m

www.bg-group.com 03

‘HoA’ Heads of Agreement

‘HPHT’ High-pressure high-temperature

‘JV’ Joint venture

‘kboed’ Thousand barrels of oil equivalent per day

‘kbopd’ Thousand barrels of oil per day

‘km’ Kilometres

‘LNG’ Liquefied Natural Gas

‘LPG’ Liquefied Petroleum Gas

‘m’ Million

‘mmbbls’ Million barrels of oil

‘mmboe’ Million barrels of oil equivalent

‘mmboed’ Million barrels of oil equivalent per day

‘mmbtu’ Million British thermal units

‘mmscfd’ Million standard cubic feet per day

‘MoU’ Memorandum of Understanding

‘mtpa’ Million tonnes per annum

‘NBP’ National Balancing Point

‘P10’ At least a 10% probability that the quantities actually recovered will equal or exceed the high estimate

‘P90’ At least a 90% probability that the quantities actually recovered will equal or exceed the low estimate

‘partner’ An entity with whom BG Group has formed an incorporated or unincorporated association or joint venture for the purposes of pursuing its business activities and the term “partner” in this context is not intended to, nor shall be deemed to, create or constitute a partnership between BG Group and any such entity for the purposes of the Partnership Act 1890 or any similar law in any jurisdiction in which such activities may be conducted

‘PDO’ Plan for development and operation

‘PJ’ Petajoules

‘PSC’ Production Sharing Contract

‘SEC’ The United States Securities and Exchange Commission

‘SLWR’ Steel lazy wave riser

‘SPA’ Sale and Purchase Agreement

‘SPE PRMS’ Petroleum Resources Management System published by the Society of Petroleum Engineers

‘TBC’ To be confirmed

‘tcf’ Trillion cubic feet

‘WAG’ Water alternating gas

RESERVES AND RESOURCESProved reservesFrom the year ended 31 December 2013 onwards BG Group utilises the Petroleum Resources Management System published by the Society of Petroleum Engineers (SPE PRMS) definition of proved reserves. Proved reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods and government regulations.

Proved developed reserves are those reserves that can be expected to be recovered through existing wells and with existing equipment and operating methods. Proved undeveloped reserves comprise total proved reserves less total proved developed reserves.

Probable reservesFrom the year ended 31 December 2013 onwards BG Group utilises the SPE PRMS definition of probable reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves.

Discovered resourcesDiscovered resources are defined by BG Group as the best estimate of recoverable hydrocarbons where commercial and/or technical maturity is such that project sanction is not expected within the next three years.

Risked explorationRisked exploration resources are defined by BG Group as the best estimate (mean value) of recoverable hydrocarbons from undiscovered accumulations multiplied by the chance of success.

Total resourcesTotal resources are defined by BG Group as the aggregate of proved and probable reserves plus discovered resources and risked exploration. Total resources may also be referred to as total reserves and resources.

Further information on BG Group’s Reserves and Resources at 31 December 2013 can be found on page 134 of BG Group’s Annual Report and Accounts 2013.

US investors should refer to the explanatory note on page 38 of this Data Book.

For the purpose of this document the following definitions apply:

‘2D’ Two-dimensional seismic

‘3D’ Three-dimensional seismic

‘$’ or ‘US$’ US Dollars

‘£’ or ‘UK£’ UK Pounds Sterling

‘bbls’ Barrels

‘bcf’ Billion cubic feet

‘bcfd’ Billion cubic feet per day

‘bcma’ Billion cubic metres per annum

‘BGGM’ BG Gas Marketing Ltd

‘ BG Group’ or ‘the Group’

BG Group plc and its subsidiary undertakings, joint ventures or associated undertakings

‘billion’ or ‘bn’ One thousand million

‘boe’ Barrels of oil equivalent. BG Group uses a conversion factor of 1 boe equals 6 000 cubic feet of natural gas

‘boed’ Barrels of oil equivalent per day

‘bopd’ Barrels of oil per day

‘BSR’ Buoyancy supported riser

‘CIF’ Carriage, insurance and freight

‘cm’ Cubic metre

‘CNG’ Compressed natural gas

‘CPP’ Central processing plant

‘CSG’ Coal seam gas

‘DCQ’ Daily Contracted Quantity

‘delivered volumes’ Comprises all LNG volumes discharged in a given period, excluding LNG utilised by the ships

‘DoC’ Declaration of Commerciality

‘DES’ Delivered ex-ship

‘DST’ Drill stem test

‘E&P’ Exploration and Production

‘EMA’ Energy Marketing Authority

‘ESMA’ European Securities and Markets Authority

‘EWT’ Extended well test

‘FEED’ Front End Engineering Design

‘FCS’ Field compression station

‘FOB’ Free On Board

‘FPSA’ Final Production Sharing Agreement

‘FPSO’ Floating production, storage and offloading vessel

‘FSO’ Floating, storage and offloading vessel

‘HIIP’ Hydrocarbons initially in place

04 Data Book 2014

DEFINITIONS

CABIÚNAS

SOUTHATLANTIC

OCEANLULA MEXILHÃO

PIPELINE

CABIÚN

AS

PIPEL

INE

MA

RIC

Á

PIP

ELIN

E

RIO DE JANEIRO

CARAGUATATUBA

BRAZILBRAZIL BRAZIL

BAR-M-215

BAR-M-217

BAR-M-298

BAR-M-300

BAR-M-252

BAR-M-254

BAR-M-340

BAR-M-342

BAR-M-388

BAR-M-344

Lapa

MARICÁ

LULA MEXILHÃO

PIPELINE

CABIÚN

AS

PIPEL

INE

MA

RIC

Á

PIP

ELIN

E

BM-S-50 Iracema

Iara

Lula

Sapinhoá

0 100 km

40

32

24

16

8

0

BG Group net production

Gas

Oil & liquids

2011 2012

(kboed)

2013

25

13

39

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.

New information ● Lapa (formerly Carioca) Declaration of Commerciality (DoC) announced

● First FPSO at Sapinhoá reached oil capacity from four producer wells

Key dates2000 Acquired pre-salt non-operated acreage

in the Santos Basin2006 Lula (BM-S-11) oil and gas discovery

made in the Santos Basin2008 Sapinhoá announced as an oil discovery

on BM-S-9Iara announced as an oil discovery on BM-S-11

2010 First permanent FPSO on Lula commenced production

2013 First FPSO on Sapinhoá commenced production

Awarded 10 exploration blocks in the Barreirinhas Basin

BG Group has significant interests in three blocks in the Santos Basin, offshore Brazil. The exploration success, scale of resources discovered and production performance to

date have been exceptional. The first floating production, storage and offloading (FPSO) vessels on the Lula and Sapinhoá fields were brought into production around four years after exploration success. As at 31 July 2014, the BM-S-9 and BM-S-11 partners have three permanent FPSOs from which they are exporting crude oil, with two more expected to be deployed before the end of 2014. In total, 15 FPSOs have been contracted for deployment by the end of 2018 on the Group’s interests in the Santos Basin.

Mean total reserves and resources are estimated to amount to some 6 billion barrels of oil equivalent (boe) net to BG Group*. The aggregate range of total reserves and resources net to BG Group is from 4 billion boe (P90) to 8 billion boe (P10)*. The Lula, Sapinhoá, Iracema, Iara and Lapa discoveries account

for over 95% of BG Group’s mean total reserves and resources in the Santos Basin.

In 2012, BG Group received independent expert certification of these resource estimates from the oil and gas consulting firm Miller and Lents, Ltd (MLL). MLL was given full access to BG Group’s data and development models for these fields in order to undertake its probabilistic analysis**.

The current 15 FPSO programme in the Santos Basin is expected to deliver 2.6 mmboed of gross capacity.

The low unit cost of the Santos Basin development is a result of the excellent reservoir characteristics, which deliver high margins and an economic break-even at less than $40/bbl.

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

www.bg-group.com 05

Gas pipeline

Proposed gas pipeline

Oil

Oil pipeline

BG Group operated block

BG Group non-operated block

AREAS OF OPERATION

Brazil 2 Barreirinhas Basin

Brazil 1Santos Basin

1

2

BRAZIL

Key to operations

FPSOCidade de Angra dos Reis

Gas export

line

WA

TER

GA

S/C

O2

WA

TER

GA

S/C

O2

MIS

CIB

LEZO

NE

OIL

BA

NK

FPSOCidade de Angra dos Reis

Upstream: E&PBM-S-9 SapinhoáIn 2008, the Sapinhoá well was announced as a discovery. In 2011, BG Group and partners announced the Declaration of Commerciality (DoC) with the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) for the accumulation of light oil and gas in the Sapinhoá area. The DoC marks the start of the commercial production phase for the field and sets the licence period to run to 2038. In January 2013, first production from the Sapinhoá field commenced through the FPSO Cidade de São Paulo. The installation of the buoyancy supported riser (BSR) system was completed in 2014. In May 2014, the second and third wells achieved flow rates of around 34 000 bopd. With the connection and start-up of the fourth well, the FPSO reached its 120 000 bopd capacity.

The second FPSO (Cidade de Ilhabela) at Sapinhoá North, with capacity of up to 150 000 bopd and 212 million standard cubic feet of gas per day (mmscfd), is expected to be in operation in the second half of 2014.

Lapa (formerly Carioca)In 2007, the Lapa well was declared a discovery and in 2011, the results of an extended well test (EWT) on Lapa North-East indicated potential production of approximately 28 000 bopd, above initial expectations.

In December 2013, the consortium announced the DoC for the Lapa field to the ANP, which included the relinquishment of the areas of Abaré, Abaré West, Iguaçu and Iguaçu Mirim. First oil from a single FPSO development, the Cidade de Caraguatatuba, is expected in 2016.

BM-S-11Lula and IracemaThe Lula discovery well was drilled in 2006 and the Iracema discovery well, which confirmed the presence of light oil in the north-west of the evaluation area, was drilled in 2009. There has been significant activity on Lula and Iracema since the original discoveries were made including appraisal wells, drill stem tests (DSTs) and EWTs, with the information gathered supporting developments.

As at 31 July 2014, two permanent FPSOs on Lula are onstream. Production from the first permanent FPSO on the Lula field, the Cidade de Angra dos Reis, commenced in October 2010. The FPSO currently produces close to its 100 000 bopd capacity from just four producing wells, one conventional injector well and two water alternating gas (WAG) wells. WAG forms a key part of the consortium’s efforts in exploring the potential for enhanced oil recovery mechanisms to be deployed in the Santos Basin in the future. This process involves injecting water and gas alternately for certain time periods. The intention is to improve oil recovery

SANTOS BASIN BLOCKS*

Block BG Group (%) Partners (%) Discoveries Exploration well DoC First FPSO production

BM-S-9 30 Petrobras 45, Repsol Sinopec Brasil 25 LapaSapinhoá

2007 2008

2013 2011

Expected 2016 2013

BM-S-11 25 Petrobras 65, Petrogal Brasil 10 Lula IracemaIara

2006 2009 2008

2010 2010 Expected 2014

2010 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

by reducing the oil’s viscosity and maintaining pressure support to aid the flow of oil towards the production well head. The first WAG well began injecting water in 2012, switching to the gas injection cycle in 2013. The second WAG well began injecting water in 2013. Initial pressure support has been positive. The consortium continues to monitor developments and test elsewhere, with a WAG well expected to be connected on Lula North-East in the first half of 2015.

Production from the Cidade de Paraty FPSO at Lula North-East commenced in June 2013 and is expected to be operating at around its 120 000 bopd capacity around the end of 2014 from just five producing wells, following the installation of the BSR system and additional well connections.

At Iracema, the operator expects to install the Cidade de Mangaratiba in the south of the discovery in the fourth quarter of 2014, with a second FPSO, Cidade de Itaguai, expected to be installed in the north in the fourth quarter of 2015. Both FPSOs have capacity for 150 000 bopd and 283 mmscfd.

In 2014, the BM-S-11 consortium began a confidential arbitration process in accordance with the concession agreement in response to the ANP’s decision determining the unification of the Lula and Iracema discoveries.

06 Data Book 2014

SUBSEA SCHEMATIC WAG SCHEMATIC

Production wells WAG injector wells Gas injector wells

IaraIn 2008, BG Group announced Iara as an oil discovery and in 2011, drilling on the Iara Horst well was successfully completed. The Iara Horst well encountered good quality oil in a thick reservoir section with initial results and subsequent DST demonstrating superior reservoir characteristics to the discovery well located around eight kilometres away.

In 2012, the Iara West well was drilled successfully, confirming the westerly extension of the Iara accumulation. In 2013, a fourth appraisal well was drilled and tested with excellent results. Subsequently, the first high-angle well was drilled, finding similar reservoir characteristics to the original Iara discovery well with the later DST results in line with expectations.

Appraisal activity continues at Iara, gathering data ahead of the DoC, which is due at the end of 2014. In May, a DST was undertaken at a well in the south-west flowing at around 5 000 bopd and a further appraisal well began drilling in the north-east with results, including a DST, expected in the fourth quarter. In June, an EWT began on the Iara-4 appraisal well in the west. Initial average flow rates of around 29 000 bopd were in line with expectations, with testing to continue into the coming months.

Data from these activities, as well as any additional future appraisal work, will help formulate the development plan for the Iara area which will be submitted in 2015 after the DoC. Currently the consortium has allocated two FPSOs to the Iara development.

BM-S-50SagitárioIn 2013, the Sagitário well, the first to be drilled on BM-S-50, was declared a discovery. In May 2014, the consortium completed a formation test on

this well revealing carbonate reservoirs of good quality. The consortium continues with the activities outlined in the approved Discovery Evaluation Plan.

Oil evacuationDuring 2011, BG Group chartered the oil tanker Windsor Knutsen, a conversion from a conventional Suezmax tanker with the capacity to hold 1.1 million barrels (mmbbls) of crude oil, to transport BG Group’s equity oil from Brazil. First crude oil from the Lula FPSO was lifted in July 2011 and delivered in August 2011.

The Windsor Knutsen charter has now ended as the Group has chartered four new Suezmax shuttle tankers to manage the increasing oil production, initially for ten years with certain extension options. The Samba Spirit, Lambada Spirit and Bossa Nova Spirit arrived in Brazil in 2013, with the Sertanejo Spirit arriving in early 2014. All vessels are currently in operation. Oil shipping and marketing activities are managed by GEMS (see pages 34 to 36 for details).

As at 31 July 2014, a total of 31 liftings of around 1 mmbbls each have been made by BG Group from the three producing FPSOs at Lula and Sapinhoá.

Gas evacuationWhile the majority of the gas produced is initially being used for re-injection, development plans for the associated gas resources in the Group’s Santos Basin interests have continued to advance.

In 2010, a new pipeline was installed connecting the Lula field to the Mexilhão gas hub. This pipeline has been used to export gas from the first Lula FPSO since 2011 and has since been connected to the Sapinhoá South and Lula North-East FPSOs.

A second export route, the Cabiúnas pipeline, is currently under construction having received the relevant installation licences in 2014. The pipeline will span approximately 380 kilometres and will connect the Lula field to a terminal in Cabiúnas, 180 kilometres north-east of Rio de Janeiro. The operator expects the pipeline to be installed in 2015, and its onshore gas processing plant to be operational later in 2015. This export route will provide capacity for further FPSOs.

Barreirinhas BasinIn May 2013, BG Group was awarded operatorship of 10 offshore blocks covering around 7 000 square kilometres in the frontier Barreirinhas Basin, along Brazil’s northern equatorial margin.

In April 2014, BG Group farmed down 25% of its interests in the BAR-M-215, 217, 252 and 254 blocks to PTT Exploration and Production Public Company Limited (PTTEP).

In the first five year exploration phase, BG Group’s work programme will incorporate a combination of full block seismic acquisition and processing and a number of wells. Seismic acquisition will begin once the required environmental permitting has been received.

BARREIRINHAS BASIN BLOCKS

BlockBG Group (%)

Partners (%)

BAR-M-298 and 340 100

BAR-M-215, 217, 252 and 254

75 PTTEP Brasil 25

BAR-M-300, 342, 344 and 388

50 Petrobras 40, Petrogal Brasil 10

FPSO SCHEDULE

Number Name: Cidade de Location Chartered/owned Start-up

Capacity – oil (kbopd)

Capacity – gas (mmscfd)

Wells drilled – producers/injectors*

Main riser 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

www.bg-group.com 07

Queensland Curtis LNG

GLADSTONE

ROMA

CHINCHILLA

SURAT

MILES

CONDAMINE

TARA

KOGAN

DALBY

TOOWOOMBA

ST GEORGE

MOURA

THANGOOL

ROCKHAMPTON

EMERALD BLACKWATER

MORANBAH

CLERMONT

MACKAY

COLLINSVILLE

BOWEN

TOWNSVILLE

BRISBANE

Export pipeline

Gas collection header

QUEENSLANDQUEENSLAND

NEW SOUTH WALES

QUEENSLAND

SOU

TH A

UST

RA

LIA

0 120 km

25

20

15

10

5

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

25

21

25

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.

New information ● Completed 540 kilometre pipeline network ● All six Ruby Jo FCSs and CPP operational

Key dates2008 Alliance with Queensland Gas Company

(QGC) established2009 QGC acquisition completed and

Pure Energy acquired2010 Queensland Curtis LNG (QCLNG)

project sanctioned Contract signed with CNOOC for sale

of 3.6 mtpa of LNG2011 Contract signed with Tokyo Gas for sale

of 1.2 mtpa of LNG2013 Binding agreements signed for the sale

of certain interests in the QCLNG project for $1.93 billion

● Major shareholdings in the two-train liquefaction facility, including 100% equity in common facilities such as the LNG storage tanks and jetty; and

● The 140 megawatt Condamine power station.

BG Group entered Australia in 2008 via an alliance with Queensland Gas Company (QGC), acquiring a 20% interest in QGC’s CSG assets in the Surat Basin, southern Queensland, and a 9.9% stake in QGC. After a successful drilling campaign and the decision to develop a multi-train LNG project, the Boards of BG Group and QGC agreed the terms of a takeover, completed in 2009. To secure additional CSG resource BG Group also acquired Pure Energy Resources Limited in 2009.

Subsequently, BG Group sold certain additional interests to CNOOC and Tokyo Gas, with CNOOC now holding 50% equity in Train 1 and Tokyo Gas holding 2.5% equity in Train 2.

QCLNGBG Group is developing a two-train 8.5 mtpa LNG plant supplied by coal seam gas (CSG). The Queensland Curtis LNG (QCLNG) plant is being built on a 270 hectare site on Curtis Island, Gladstone, on the Queensland coast.

BG Group’s business in Australia comprises: ● Licences in four onshore areas of producing and potential gas supply covering a total of around 33 000 square kilometres. The project’s total reserves and resources at the end of 2013 were around 22 tcf (net BG Group):

– Surat Basin CSG play: producing gas for the domestic market and will provide production into the LNG plant;

– Bowen Basin CSG play: exploration and appraisal ongoing;

– Bowen Basin tight gas sand play: exploration and appraisal ongoing;

– Cooper Basin tight gas sand and shale gas plays: exploration and appraisal ongoing;

● A 540 kilometre pipeline network comprising a 200 kilometre gas collection header and a 340 kilometre export pipeline;

08 Data Book 2014

Key to operations Gas pipeline

Gas export pipeline

Gas collection header

BG Group acreage interests

AREAS OF OPERATION

QCLNG Phase 1

Bowen CSG

Bowen Tight Gas

Surat CSG

Australia 1Surat and Bowen Basins

Australia 2Cooper Basin

1

2

AUSTRALIA

Partners QCLNG Train 1

BG Group 50 CNOOC 50

(%) Partners QCLNG Train 2

BG Group 97.5 Tokyo Gas 2.5

(%)

COLOMBIACOLOMBIA

SANTA MARTA

FIELD COMPRESSION STATION (FCS)

GAS SUPPLY & ELECTRICITY GENERATION

CENTRAL PROCESSINGPLANT (CPP)

TEMPORARY WATER STORAGE

GAS WELLS

WATER TREATMENT PLANT

WATER FOR BENEFICIAL USE

CURTIS ISLAND LNG PLANT

AUSTRALIAAUSTRALIA

EXPORT MARKETS

COAL SEAM

GLADSTONE

Upstream: E&PProduction 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 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.

The Ruby Jo, Bellevue, Jordan and Woleebee Creek hubs in the Surat Basin will feed the QCLNG plant. In the South region, the Ruby Jo central processing plant (CPP) commenced operation in April 2014, being supplied by six field compression stations (FCSs). In the Central region, three FCSs and the Bellevue CPP are expected to be ready for operations ahead of 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 four CPPs and 17 FCSs to supply the QCLNG plant’s two trains.

Given the dewatering and ramp up profile of coal seam gas, BG Group is utilising both equity gas and third-party gas to ensure the LNG plant is filled to capacity. During the ramp up of the LNG plant in 2015-16 it is expected that short-term third-party gas will provide around 10-20% of throughput in any given year and less than 5% once on plateau.

In 2010, BG Group and Australia Pacific LNG (APLNG) agreed a framework for the development of jointly owned CSG tenements ATP 648P and ATP 620P. BG Group also entered into conditional gas purchase agreements with APLNG under which BG Group expects to buy 145 petajoules (PJ) of gas over an initial 15 month period, reducing thereafter to an average of 25 PJ per annum. The start of gas sales is aligned with the start of commercial operations at the QCLNG project.

Additionally, to help manage gas ramp-up, BG Group has entered into an agreement with AGL Energy Limited (AGL) whereby AGL will use a depleted field near Wallumbilla in the Surat Basin to store QGC gas for a fee for seven years from 2011.

Exploration and appraisal activities continue in order to develop the most economic resource.

In the Bowen tight gas sand play, four wells have been drilled and preparations are ongoing for a further drilling campaign. The next well is

expected to commence drilling in the fourth quarter of 2014. In the Bowen CSG play, BG Group will focus on monitoring pilot production from existing well stock; a technical review is ongoing to assess the potential for further drilling. The deepening and logging of the first well in the current campaign in the Cooper tight gas and shale gas plays has been completed. Work is now focusing on deepening the second well with production testing due to commence in the third quarter of 2014.

Upstream: InfrastructureBG Group has constructed a 540 kilometre pipeline network, comprising a 200 kilometre gas collection header and a 340 kilometre export pipeline, to link the gas fields in the Surat Basin to the LNG plant on Curtis Island.

BG Group treats produced water for use by local landholders, industry and communities. The water treatment plant at Windibri is in

operation and has a capacity of some 6 million litres per day. The water treatment facility at Kenya, a 92 million litre per day plant, is also in operation with first water exported in 2013. The Northern water treatment plant is situated at Woleebee Creek and will have a capacity of 100 million litres per day.

Upstream: LiquefactionConstruction of the 8.5 mtpa LNG plant continues on Curtis Island. Both LNG storage tank roofs were raised in 2013 and hydrotesting of the first tank was completed in the first quarter of 2014. Progress on the plant continues with the gas turbine generators having begun commissioning in the second quarter of 2014. Commissioning of the refrigeration turbines and compressors is expected in the third quarter of 2014, which are important steps prior to cooling Train 1 and producing first LNG in the fourth quarter.

Not to scale

SCHEMATIC OF FACILITIES AT QCLNG PROJECT

www.bg-group.com 09

LNG Shipping & MarketingAs a key portfolio supply source, QCLNG volumes will be delivered to BG Group’s worldwide customers, including China, Japan, Singapore, India and Chile.

In 2010, BG Group signed a LNG sales contract with CNOOC. Under the terms of parallel agreements between BG Group and CNOOC:

● CNOOC will be supplied with 3.6 mtpa of LNG over a 20 year period;

● CNOOC acquired a 5% equity interest in the reserves and resources of certain BG Group tenements in the Surat Basin in Queensland;

● CNOOC became a 10% equity investor in Train 1; and

● BG Group and CNOOC agreed to participate jointly in a consortium to construct two LNG ships in China that will be owned by the consortium.

Further, in May 2013, BG Group announced it had signed a binding agreement with CNOOC for the sale of certain interests in the QCLNG project for $1.93 billion and the sale of an additional 5 mtpa of LNG from BG Group’s global portfolio, beginning in 2015. Additionally, CNOOC reimbursed BG Group for its share of QCLNG project expenditure incurred from 1 January 2012. In November 2013, transactions were completed with CNOOC. The key terms of the transaction were:

● BG Group sold certain interests in upstream coal seam gas tenements in Australia and a further equity stake in the QCLNG project Train 1 liquefaction facility;

● BG Group will supply CNOOC with a further 5 mtpa of LNG for 20 years beginning in 2015, 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.

The agreements exclude any interest in the Train 2 liquefaction facility, pipelines and QCLNG project common facilities. BG Group retains majority ownership of the QCLNG project. In particular, BG Group has around 74% of its original interest in the upstream resource and related infrastructure; and 100% of the project’s common facilities on Curtis Island (including LNG storage tanks and jetty) and the 540 kilometre natural gas pipeline network linking the gas fields to Curtis Island. Together, these items represent approximately 30% of the estimated $20.4 billion 2011-2014 project spend.

In 2011, BG Group signed a sales agreement with Tokyo Gas. Under the agreement:

● Tokyo Gas will buy 1.2 mtpa of LNG for 20 years from 2015;

● Tokyo Gas acquired a 1.25% interest in the reserves and resources of certain BG Group tenements in the Walloons Fairway; and

● Tokyo Gas became a 2.5% equity investor in the second of the two liquefaction trains.

BG Group also signed a sales agreement with Chubu Electric Power Co. Inc, (Chubu Electric) for the long-term supply of LNG. Under the agreement, Chubu Electric will purchase up to 122 cargoes over 21 years, starting in 2014. Condamine power stationBG Group also operates Condamine power station, which is fuelled by CSG produced at QGC’s gasfields in the Surat Basin. With a potential generating capacity of 140 megawatts, the station provides power to the National Electricity Market.

10 Data Book 2014

150

90

60

120

30

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

132135

112

MEDITERRANEAN SEA

ALEXANDRIA

EGYPTEGYPT

IDKU

DAMIETTA LNG

PORT SAID

CAIRO

Silva

SimSat-P1

Simian, Sienna

Mina-1

Sienna-Up

Rashid North

Solar

SimSat-P2

Swan

Sapsat-2

Sapsat-1

Sama

Egyptian LNG Trains 1 & 2

Serpent, Sparrow

Scarab, Saffron

Sapphire

Saurus

Libra

Sequoia

Notus

East El Burullus

Rashid -1,-2,-3

El Manzala

Harmattan Deep-1

El Burg

N. Gamasa

0 100 km

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.

New information ● BG Group issued Force Majeure under its LNG agreements

● Notus well completed with evaluation ongoing

Key dates1995 Rosetta and WDDM Concessions awarded2001 Rosetta first production2003 WDDM first production2004 Additional 40% in Rosetta acquired2005 Egyptian LNG Trains 1 and 2 exports began2013 WDDM Phase 9a sanctioned

● Non-operated interest in the East El Burullus Offshore Concession (EEBO); and

● Major shareholdings in the two-train Egyptian LNG project.

Upstream development and production activities in Egypt are undertaken through joint operating companies. In the case of Rosetta, this is through Rashid Petroleum Company (Rashpetco), and in the case of WDDM, this is through Burullus Gas Company (Burullus). These operating companies are 50% owned by the Egyptian General Petroleum Corporation (EGPC), the body representing the Egyptian government in the petroleum sector. BG Group and its partners in each concession hold the remaining 50%.

The difficult operating environment in Egypt, coupled with lower reserves estimates, has led the Group to revise its expectations of the value of its Egyptian operations. Production volumes declined throughout 2013 and 2014 as a result of deteriorating reservoir performance and the continuing high level of diversions to the domestic market, where the Group is entitled to a lower share of production.

In January 2014, BG Group issued Force Majeure notices under its LNG agreements in Egypt reflecting the ongoing diversions of gas volumes to the domestic market in excess of the existing pooling arrangements. Looking forward, the strong likelihood of continued diversions to the domestic market, combined with further reservoir deterioration, means that the Group currently expects very limited cargoes to be lifted from Egyptian LNG for the foreseeable future.

In the second quarter of 2014, Upstream and LNG activities in Egypt accounted for 10% of BG Group’s production and around 6% of earnings from continuing operations. The book value of BG Group’s investment in Egypt as at 30 June 2014, including receivables, was $2.8 billion, of which $0.2 billion relates to Egyptian LNG. The receivables balance was $1.5 billion with $1.2 billion overdue. Release of funds for any further development, including Phase 9b, remains contingent upon an improvement in the investment climate including a significant improvement in the outstanding receivable position.

BG Group’s business in Egypt comprises: ● Operatorship of two gas-producing areas offshore the Nile Delta:

– the Rosetta Concession; and – the WDDM Concession;

● Operatorship of three other concessions offshore the Nile Delta:

– El Manzala Offshore (EMO); – El Burg Offshore (EBO); and – North Gamasa Offshore (NGO);

www.bg-group.com 11

Gas

Gas pipeline

Oil pipeline

BG Group-operated block


AREAS OF OPERATION

EGYPT

Key to operations

Trai

n 1

(sta

rt d

ate

200

5)Tr

ain

2 (s

tart

dat

e 20

05)

Gas supply Train equity LNG purchase

Upstream Train equity Downstream

Partners

BG Group

Edison

EGPC

PETRONAS

(%)

2080

501040

5050

25 5025

Rosetta Concession*

Rashid Petroleum Company

WDDM Concession*

Burullus Gas Company

* BG Group operator

Upstream: E&PWDDM ConcessionSince 1994, BG Group and partners have discovered 18 gas fields, with Scarab, Saffron, Simian, Sienna, Sapphire, Serpent, Saurus, Sequoia, SimSat-P2, Sapsat-1, Sapsat-2 and Swan in production. WDDM infrastructure is designed to supply gas to the domestic market and Egyptian LNG at Idku.

Scarab, Saffron Scarab, Saffron, the first deep water sub-sea developments in Egypt, started production in 2003 and supply gas to the domestic market. These facilities consist of eight sub-sea wells connected to a sub-sea manifold, in turn connected by pipelines to an onshore processing terminal. The fields are located approximately 90 kilometres from the shore and in water depths of more than 700 metres.

Simian, Sienna and SapphireThe Simian and Sienna fields are contracted to supply Egyptian LNG Train 1, while the Sapphire field is contracted to supply Egyptian LNG Train 2. These fields are located approximately 120 kilometres offshore Idku, near Alexandria. The facilities consist of 16 sub-sea wells tied into the existing WDDM gas gathering network and a shallow water control platform. The onshore

processing facilities form part of the Idku Gas Hub where the Egyptian LNG facilities are located.

WDDM additional phasesThe WDDM fields have undergone a number of development phases to maximise hydrocarbon recovery. Phase 4 brought seven additional wells onstream during 2008, with Phase 6 in 2009 adding three unitised Sequoia wells, and Phases 8a and 8b delivering another 17 sub-sea wells between 2011 and 2012. With the completion of the Phase 8a and 8b projects, the WDDM Concession has a total of 53 sub-sea wells. Phases 5 and 7 were compression projects, including installation of seven onshore compressors in total and additional gas gathering and receiving facilities, including a new 68 kilometre, 36-inch offshore pipeline.

Phase 9a was sanctioned in 2013 with the first well onstream in July 2014. This nine well development will only temporarily offset underlying production declines.

Rosetta ConcessionRosetta supplies gas to the domestic market and started production in 2001. In 2008, BG Group delivered first gas from the Rosetta Phase 3 field development plan. The project consists of five wells tied back to the first two phases of Rosetta.

SequoiaThe unitised development (Rosetta Phase 4/WDDM Phase 6) of the Sequoia field (BG Group 62.99%), which lies across the boundary of the WDDM and Rosetta Concessions, was sanctioned in 2008. It consists of six sub-sea wells: three wells on each of WDDM and Rosetta tied back to existing infrastructure.

El Manzala Offshore and El Burg Offshore ConcessionsIn 2005, BG Group signed the El Manzala Offshore (EMO) and El Burg Offshore (EBO) concession agreements for the exploration of gas and oil with the Egyptian Natural Gas Holding

Company (EGAS). Exploration drilling on EMO and EBO commenced in 2008. BG Group holds 50% equity in EMO, where the Zonda well was drilled in 2011 but failed to discover commercial hydrocarbons. A two-well programme on EBO commenced in 2012. The first well, Harmattan Deep-1, was declared a discovery in 2012. The Notus well, which is testing a new Oligocene play, encountered gas at a number of target horizons in December 2013. Evaluation of the results for both discoveries is ongoing.

North Gamasa Offshore ConcessionBG Group holds 60% equity in, and is operator of the North Gamasa Offshore (NGO) block. The block covers an area of 281 square kilometres and is located 20 kilometres from the coast in shallow water. The concession agreement formalising the award was signed in early 2010 with 3D seismic acquisition completed later that year. In 2014, the Opera well was drilled. The well failed to discover commercial hydrocarbons.

East El Burullus Offshore ConcessionBG Group farmed in to the EEBO Concession in 2012, taking a 40% interest. The Kala-1 well was completed in December 2013 but was a dry hole.

Upstream: LiquefactionEgyptian LNGThe Egyptian LNG facilities, located at Idku, comprise the two LNG production trains and include the common facilities such as storage tanks, loading jetty and utilities.

Egyptian LNG Company owns both the Egyptian LNG site and common facilities. Its sister company, The Egyptian Operating Company for Natural Gas Liquefaction Projects (Opco) (BG Group 35.5%) undertakes the operation of all trains and common facilities. El Beheira Natural Gas Liquefaction Company (Train 1 Co.) (BG Group 35.5%) owns Train 1, and Idku Natural Gas Liquefaction Company (Train 2 Co.) (BG Group 38%) owns Train 2.

BG Group and partners supply Egyptian LNG with gas from the Simian, Sienna, Sapphire and Sequoia fields in WDDM. Together, these trains have a productive capacity of 7.2 mtpa of LNG.

The 3.6 mtpa productive capacity of Train 1 has been sold to GDF SUEZ under a 20 year SPA. The first LNG cargo was lifted in May 2005.

The 3.6 mtpa productive capacity of Train 2 has been sold under a 20 year agreement to BG Gas Marketing (BGGM), a wholly owned BG Group subsidiary which is operated by GEMS. The first LNG cargo was lifted in September 2005.

In January 2014, BG Group issued Force Majeure notices under its LNG agreements in Egypt reflecting the ongoing diversions of gas volumes to the domestic market in excess of the existing pooling arrangements. Consequently, volumes from Egyptian LNG were severely restricted. As of July 2014, the plant was only running with one train, which was at a significantly reduced level.

GDF SUEZ 100%BG Group 50%

Train 1 – 3.6 mtpaTolling plant

BG Group 35.5%PETRONAS 35.5%EGPC 12%EGAS 12%GDF SUEZ 5%

565 mmscfd – WDDM

BG Group 100%BG Group 50%


BG Group 38%PETRONAS 38%EGPC 12%EGAS 12%

565 mmscfd – WDDM

Gas LNG

Gas LNG

12 Data Book 2014

UNDERLYING CONTRACT STRUCTURE OF EGYPTIAN LNG

MED

IAN

LINE

NORTH SEA

BRENT NINIAN

FLOTTA

SULLOM VOE

NORWAYNORWAY

UKUK

FRIG

G

SAGE

BRITANNIA

FORTIES

FULMAR

CATSLA

NG

ELED

SEA

L

WAGES

FLA

GS

NORPIPE

ABERDEEN

ST. FERGUS

Maria

Gaupe

Armada

Seymour

Everest

Lomond

Elgin Erskine

Jackdaw

Jade

Buzzard

Blake

Faroe Island Licence

Bedlington

Glenelg

Jasmine

Judy/Joanne

Franklin

Dragon LNG

Milford Energy

IRISHSEA UK

TEESSIDE

BACTON

ZEEBRUGGEREADING

SULLOM VOE

ABERDEENST.FERGUS

FLOTTA

NORTHSEA

LONDON

EASINGTON

0 100 km

BG Group has a diverse E&P business offshore UK with interests focused on the central North Sea.

New information ● Jasmine first production ● Sold interest in CATS infrastructure

Key dates1993 Everest and Lomond first production1997 Armada and J-Block first production2001 Blake and Elgin/Franklin first production2002 Jade first production2003 Seymour first production2007 Buzzard, West Franklin and Maria

first production

2009 Asset exchange with BP, concentrating operations in the central North SeaDragon LNG operational

2013 First production from Everest East expansion

www.bg-group.com 13

Gas

Oil

Gas pipeline

Oil pipeline



Gas and Oil/Condensate

AREAS OF OPERATION

UNITED KINGDOM

Key to operations

125

100

75

50

25

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

96105 100

BG Group’s position is focused in the central North Sea where the Group is operator of three mature platforms and infrastructure hubs: Armada, Everest and Lomond. The focus for these assets is on maximising the remaining value and continuing with a rigorous approach to maintenance and asset integrity. In parallel, BG Group continues to pursue suitable opportunities around these infrastructure hubs to increase future value.

BG Group also has a number of important non-operated interests in the central North Sea: the Buzzard field operated by Nexen (a wholly-owned subsidiary of CNOOC), the Elgin/Franklin fields operated by Total and the J-Area fields (J-Block, Jade and Jasmine) operated by ConocoPhillips.

The Group remains interested in exploration opportunities and is also progressing the Jackdaw development which is in the concept select phase.

Upstream: E&P Operated assets Armada Hub Area The Armada gas condensate fields (Fleming, Drake and Hawkins) achieved first production in 1997. The SW Seymour area of the Seymour field was appraised successfully and drilled from the Armada platform, with first production in 2003. A second well in the NW Seymour area was brought into production in 2006 and a replacement well was drilled in 2011.

The Maria field was developed via two sub-sea wells tied back to the Armada platform, with first production in 2007.

The commingled stream of Armada, Seymour and Maria gas is exported via the Central Area Transmission (CATS) terminal on Teesside. Liquids are transported through the Forties Pipeline System (FPS) to the Kinneil processing plant at Grangemouth.

The Armada hub also services two fields in the Norwegian sector of the North Sea via tie-backs: the third-party Rev field and the BG Group-operated Gaupe field.

Blake The Blake field, located in the Outer Moray Firth, had first production in 2001. The field was developed in two phases. Phase One was the Blake Channel, which is a sub-sea development of six producing wells and two water-injection

Hub Field/Block BG Group (%)

First production 2013 net production (kboed)

Other partners (%)

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 Lomond

Everest 100.0 1993 16

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 Jade Area

J-Block 30.5 1997 8 ConocoPhillips 36.5, Eni 33.0

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

wells, tied back to an existing floating production, storage and offloading vessel (FPSO) located over the third-party Ross field some 9.5 kilometres away. Development of Phase Two, the Blake Flank, was completed and production commenced from two wells in 2003. This sub-sea development is tied back through the existing Blake facilities to the Ross FPSO.

Everest and Lomond Everest and Lomond are located in the central North Sea and first production began on each in 1993. Gas produced from the two fields is exported via the CATS pipeline and produced liquids are exported via FPS to the Kinneil processing plant.

The Lomond platform also provides production facilities for the Erskine field.

Everest field production was enhanced in March 2013 with first gas from the Everest East expansion project, which comprises two sub-sea wells tied back to the North Everest platform and brownfield modifications to the existing production system. Investment in maintenance and asset integrity continues on both facilities with a major flotel campaign due to start in October 2014 and last for around six months.

Jackdaw The Jackdaw discovery is one of the largest undeveloped gas discoveries in the UK Continental Shelf. Discovered in 2005, the field was appraised between 2007 and 2012. Results from the exploration and appraisal programme are being used to evaluate potential development concepts.

14 Data Book 2014

Non-operated assetsBuzzardThe Nexen-operated Buzzard oil field in the Outer Moray Firth came onstream in 2007. The facilities consist of a complex of four bridge-linked platforms, with oil export via FPS and gas export via the Frigg System. In 2010, an additional processing platform to remove hydrogen sulphide and extend plateau production was installed. Commissioning and start-up of this platform was completed in 2011.

The development drilling programme and field production plateau have continued significantly beyond initial expectations. The field partners anticipate sanctioning the Buzzard Phase 2 project in 2015, including the development of the northern area of the field plus the resumption of infill drilling at the existing platform location. Estimated total recoverable resources from the Buzzard field are around 800 mmboe.

Elgin/Franklin Area The high-pressure/high-temperature (HPHT) Elgin/Franklin gas condensate fields are located in the Central Graben area of the central North Sea and operated by Total. The fields began production in 2001. In March 2013, production restarted from three wells on Elgin/Franklin following a year-long shut-in. Production is not expected to recover to pre shut-down levels until 2016.

West Franklin started production in 2007. In 2008, the West Franklin B appraisal well identified additional potential reserves and Phase 2 of the development of the West Franklin field was sanctioned. It aims to produce estimated reserves of 85 mmboe. The development involves the drilling of three wells and the installation of a new platform tied back to the Elgin/Franklin facilities. Production is expected to commence in the fourth quarter of 2014.

The HPHT Glenelg field started production in 2006. The field has been developed through a single well drilled from the Elgin wellhead platform.

Elgin/Franklin, West Franklin and Glenelg gas is exported through SEAL to the onshore gas reception facilities at Bacton in Norfolk. Liquids are exported through FPS to the Kinneil processing plant at Grangemouth.

ErskineGas and liquids produced from the HPHT Erskine field, located in the central North Sea, are processed on the Lomond platform, with gas then transported via the CATS pipeline and liquids via FPS.

J-Area The Judy/Joanne (J-Block) gas condensate/oil fields and Jade gas condensate field are located in the central North Sea. Production from J-Block commenced in 1997 and from Jade in 2002.

The Joanne field is a sub-sea development tied back to the manned Judy platform through two 5.5 kilometre pipelines. The Judy/Joanne fields currently produce from 16 wells.

Jade was developed using a normally unmanned wellhead platform and currently produces from eight wells. Production from Jade is exported via a sub-sea pipeline to the Judy platform where it is commingled and processed with Judy and Joanne production. Gas processed on the Judy platform is transported through the CATS pipeline and liquids are transported to Teesside through the Norpipe system.

Jasmine lies nine kilometres east of the Judy platform and straddles Blocks 30/6 and 30/7. The development started production in November 2013 and comprises a wellhead platform, with a separate bridge-linked accommodation platform, tied back via a multi-phase pipeline and a new riser platform to the existing Judy production facilities.

Offshore pipelines SEAL and SILK BG Group has a 7.86% interest in SEAL, a 474 kilometre gas export pipeline to the Bacton terminal. With capacity of around 1 150 mmscfd of dry gas, it has been transporting gas from the Elgin/Franklin and Shearwater fields since 2001.

BG Group also has a 15.98% interest in the 900 metre SILK pipeline that provides direct access from the SEAL pipeline to the UK-Continent Interconnector pipeline.

CATS In July 2014, BG Group sold its 62.78% interest in the CATS pipeline and terminal system. The sale does not impact BG Group’s rights to capacity in CATS, as a shipper.

LNG Shipping & MarketingBG Group’s UK downstream activities are managed by GEMS and encompass LNG importation, via Dragon LNG, and energy marketing. BG Group sells gas on a wholesale basis and exports gas to, and imports from, mainland Europe via the Interconnector. For details, see GEMS section on pages 34 to 36.

www.bg-group.com 15

NORWAYNORWAY

SWEDEN

HAUGESUND

STAVANGER

KRISTIANSUND

NYHAMNA

UK

PL522

PL393

Gaupe

PL143

PL534

MID-NORWAY

NNS

CNS

PL638

Knarr

PL679S

PL688

OSLO

BARENTS SEA

PL534

PL393

0 500 km

5

4

3

2

1

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

3

2

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

Key dates2003 First licence awarded 2008 Discoveries made at Gaupe and Knarr 2011 PDO for Knarr field approved2012 Gaupe field first production

Awarded block PL638

Upstream: E&P Central North Sea (CNS)(3 licences, 2 operated) BG Group first entered Norway in the central North Sea, applying its UK Central Graben expertise and experience across the Norwegian median line area.

In 2008, a discovery was declared on Pi North, now renamed Gaupe. Gaupe spans PL292 and PL292B (BG Group 60% and operator). The field began production in 2012 through a two-well sub-sea tie-back to the Group’s Armada infrastructure in the UK.

Northern North Sea (NNS)(4 licences, 3 operated) In 2008, a discovery was made with the Jordbær exploration well (PL373S) (BG Group 45% and operator), renamed Knarr. The development of Knarr West was integrated into the Knarr project in 2011, raising gross reserves to around 80 mmboe. The Knarr FPSO is due to come onstream in the fourth quarter of 2014, subject to the receipt of Norwegian regulatory approvals and favourable weather conditions during mooring and well connection activities.

In 2012, BG Group was awarded PL638 in the Knarr area (BG Group 36% and operator). Two further licences, PL679S (BG Group 60%

and operator) and PL688 (BG Group 50%), were awarded in 2013.

Mid-Norway (1 licence, 1 operated) In 2009, BG Group completed a seismic survey on PL522 and drilled a commitment well in 2011. BG Group is currently reviewing its acreage in mid-Norway.

Barents Sea (2 licences, 1 operated) In 2007, the Nucula well in PL393 (BG Group 20%) was declared a discovery and was subsequently appraised in 2008.

The Hegg licence (PL534) (BG Group 40% and operator), was awarded in 2009 and a 3D seismic survey acquired in 2010.

BG Group is currently participating in the Barents Sea South East seismic campaign ahead of a possible future licence bid.

16 Data Book 2014

Key to operations Gas

Oil

Gas pipeline

Pipeline – proposed

or under construction

Oil pipeline


BG Group non-operated

block

AREAS OF OPERATION

NORWAY

CPC

BLACK SEA

CASPIAN SEA

BOLSHOI CHAGAN

ORENBURG

ATYRAU

TENGIZ

AKTAU

ASTRAKHAN

NOVOROSSIYSK

UKRAINEUKRAINE

KAZAKHSTANKAZAKHSTAN

RUSSIARUSSIACPC

Karachaganak

Atyrau-Samarapipeline

Karachaganak-to-CPC pipeline

125

100

75

50

25

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

9810292

0 400 km

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.

Upstream: E&PKarachaganakKarachaganak, discovered in 1979, is one of the world’s largest gas and condensate fields. Located in north-west Kazakhstan, it holds estimated hydrocarbons initially in place (HIIP) totalling 9 billion bbls of condensate and 48 tcf of gas, with estimated gross reserves of more than 2.4 billion bbls of condensate and 16 tcf of gas. Only around 10% of the HIIP has been recovered to date.

Production from the Karachaganak field began in 1984. Since the signing of the Final Production Sharing Agreement (FPSA) in 1997, the Karachaganak partners have made substantial investment in wells, facilities and pipelines. In addition to its size, Karachaganak presents the operators with formidable challenges because of extreme climate swings (+/- 40 degrees centigrade) and the requirement to re-inject high pressure sour gas.

The FPSA envisaged a phased development programme. Phase 2, which came onstream in 2004, involved investment to enhance the existing facilities, construction of new gas and liquids processing and gas injection facilities, workover of more than 100 wells, construction of a 120 megawatt power station and a new 650 kilometre pipeline to connect the field to the Caspian Pipeline Consortium (CPC) pipeline at Atyrau.

Most of the liquids are exported to the west (92% in 2013), with some oil and all raw gas sold locally and into Russia. Since 2004, oil exports have been mainly channelled via the CPC pipeline and, since 2006, additional oil exports have been routed via the Atyrau-Samara pipeline enabling sales to achieve international prices. In 2011, a fourth liquids stabilisation train commenced operation. The project increased firm stabilisation capacity up to 10.3 mtpa.

Key dates1997 40 year Karachaganak FPSA signed2004 Phase II Karachaganak

development completedFirst exports via CPC pipeline to Novorossiysk on the Black Sea

2006 Oil exports commenced via the Atyrau-Samara pipeline

2008 Upstream and downstream cooperation agreements with KazMunaiGas signed

2010 CPC expansion project sanctioned2011 Start-up of the fourth liquids

stabilisation train2012 Binding settlement agreement

resulting in KazMunaiGas joining the contractor group

www.bg-group.com 17

AREAS OF OPERATION

Key to operations Gas and Oil/Condensate

Gas pipeline

Oil pipeline

KAZAKHSTAN

Stabilised oil Un-stabilised oil

Capacity 2013 * Firm capacity of 7.0 mtpa plus access to additional capacity

Gas

Karachaganak export routes and capacity

KARACHAGANAKFIELD

Orenburg8.4 bcma

Small refinery0.6 mtpa

Gas re-injection

Orenburg4 mtpa

Atyrau-Samara3.3 mtpa

CPC8 to 9 mpta*

BG Group (joint operator) 29.25

Eni (joint operator) 29.25 KazMunaiGas 10.00

Chevron 18.0

LUKOIL 13.50

Partners Karachaganak (%)

BG Group (joint operator) 29.25

Eni (joint operator) 29.25 KazMunaiGas 10.00

Chevron 18.0

LUKOIL 13.50

Partners Karachaganak (%)

Partners Karachaganak

BG Group (joint operator) 29.25 LUKOIL 13.50

(%)

Eni (joint operator) 29.25

Chevron 18.0

KazMunaiGas 10.00

In 2012, a settlement agreement between the Republic of Kazakhstan (the Republic) and the Karachaganak partners was completed. Under the terms of the agreement, the Republic acquired a 10% interest in the FPSA from the consortium for $2.0 billion cash and $1.0 billion non-cash consideration (pre-tax) including the final and irrevocable settlement of all cost recovery claims, with each of the contracting companies’ equity shares reducing proportionately (BG Group’s share reducing from 32.5% to 29.25%). The Republic’s interest is held by a subsidiary of the national oil company, KazMunaiGas (KMG). The consideration under the agreement also includes the allocation of an additional 2 mtpa capacity in the CPC export pipeline over the remaining life of the FPSA, bringing total capacity for the use of the Karachaganak project to 10.4 mtpa on completion of the CPC expansion project, expected in 2016.

The partners are currently conducting a number of projects aimed at extending the liquids offtake from the field. This includes an ongoing drilling programme comprising horizontal development wells into the oil rim and a number of medium-sized projects intended to de-bottleneck the field’s gas processing and injection facilities.

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.

OtherCaspian Pipeline Consortium (CPC)BG Group has a 2% equity share in the pipeline but is entitled to 2.75 mtpa (55 000 bopd) of capacity (around 10% of the total), which is used to transport liquids. BG Group and the Karachaganak partners also have the opportunity to capture capacity unused by other shareholders. Liquids deliveries into CPC began in 2004 and, in 2013, 8.3 million tonnes of liquids from Karachaganak were transported via CPC (BG Group 2.1 million tonnes).

In 2010, the CPC shareholders sanctioned the CPC expansion project, which will more than double capacity in three phases, with completion expected in 2016. Total gross capacity will increase to 67 mtpa. Following expansion, and the allocation of an additional 2 mtpa capacity to the Karachaganak partners as part of the 2012 settlement agreement, BG Group’s entitlement will rise to 3 mtpa (60 000 bopd) while the total capacity for BG Group and the Karachaganak partners will increase to 10.4 mtpa. The CPC expansion project includes the addition of 10 pump stations in Russia and Kazakhstan, six crude oil storage tanks near Novorossiysk and a third single-point mooring at the CPC Marine Terminal.

Shareholders CPC (%)

BG Group 2.00

Russian government 24.00

Kazakh government 19.00

Chevron 15.00

LUKARCO 12.50

ExxonMobil 7.50

Rosneft-Shell 7.50

CPC Company 7.00

Eni 2.00

Oryx 1.75

KPV 1.75

18 Data Book 2014

CARIBBEAN SEA

ATLANTIC OCEAN

GULF OFPARIA

VENEZUELA

TRINIDAD AND TOBAGO

POINT FORTINBEACHFIELD

PHOENIX PARK

PORT OF SPAIN

TRINIDADTRINIDAD

TOBAGOTOBAGO

VENEZUELAVENEZUELA

North Coast Marine Area (NCMA)

East Coast Marine Area (ECMA)

Petrotrin Refinery Pointe-à-Pierre

Poinsettia

Chaconia

Hibiscus

TTDAA 5

TTDAA 6

Endeavour

Block 5(c)

Bounty

Starfish

Block E

Victory

Block 5(d)

Dolphin Deep

Atlantic LNG

Central Block

Block 6(b)

Block 5(a)

Dolphin

Loran-Manatee

Block 6(d)

0 100 km

80

60

40

20

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

737570

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.

New information ● Acquired remaining 25% in Block 5(c) ● Farmed in to Blocks TTDAA 5 and 6

Key dates1996 Dolphin first production1999 Atlantic LNG Train 1 start-up2002 Atlantic LNG Train 2 start-up2003 Atlantic LNG Train 3 start-up2005 Manatee-1 discovery and Atlantic

LNG Train 4 start-up2009 New 220 mmscfd contract to supply

the National Gas Company commenced2010 Loran-Manatee field treaty ratified2012 Production Sharing Contract (PSC)

for Block 5(d) executed

Upstream: E&PEast Coast Marine Area (ECMA)The BG Group-operated ECMA development comprises the Dolphin gas field, located 83 kilometres off the east coast of Trinidad in Block 6(b), which commenced production in 1996, and the Dolphin Deep gas field in the adjacent Block 5(a), which started up in 2006. Both Dolphin and Dolphin Deep are contracted to supply domestic gas to the National Gas Company (NGC) and LNG exports to BG Gas Marketing (BGGM), a wholly owned BG Group subsidiary which is operated by GEMS, via Atlantic LNG Train 3 and Atlantic LNG Train 4.

The gas is produced under a Combined Development Plan for the fields in Blocks 5(a), 6(b) and E. Production is currently delivered from the Dolphin field through 13 platform wells, and the Dolphin Deep field from two sub-sea wells. The Dolphin Deep sub-sea facilities are tied back to facilities on the Dolphin platform. In 2012, the Starfish development was sanctioned. This will comprise four sub-sea wells, tied back to the Dolphin platform,

with first gas expected in the fourth quarter of 2014.

ECMA gas is delivered to NGC via a pipeline to the Poui platform where it connects to the domestic network. ECMA gas is also delivered to Atlantic LNG through a second offshore pipeline, bringing gas from the Dolphin platform to shore at the Beachfield receiving terminal. It then connects to NGC’s 76 kilometre onshore Cross Island Pipeline extending from Beachfield to Atlantic LNG at Point Fortin.

In 2005, BG Group and partner completed the Manatee-1 well in Block 6(d), which indicated gross resources of 1.8 tcf. This discovery demonstrated the extension of the Loran field from Venezuela into Block 6(d) in Trinidad and Tobago. In 2010, the governments of Trinidad and Tobago and Venezuela ratified the field-specific treaty for the cross-border Loran-Manatee field, providing a framework for advancing a field development plan by the partners.

www.bg-group.com 19

Gas

Oil pipeline

Gas pipeline



AREAS OF OPERATION

TRINIDAD AND TOBAGO

Key to operations

Partners ECMA

BG Group (operator) 50

(%)

Chevron 50

Partners Central Block

BG Group (operator) 65

(%)

Petrotrin 35

Partners NCMA

BG Group (operator) 45.88

(%)

Petrotrin 19.50

Eni 17.31

NSGP (Ensign Limited) 17.31

North Coast Marine Area (NCMA)The BG Group-operated NCMA development, located 40 kilometres off the north coast of Trinidad, includes the Hibiscus, Poinsettia and Chaconia gas fields. There is a Unitisation Agreement with Petrotrin for the development of accumulations within the NCMA Unit Area. These fields are being developed in four phases to supply gas to Atlantic LNG Trains 2, 3 and 4. Phases 1 and 2 comprised the installation of the Hibiscus platform in 2001, together with a pipeline from NCMA to Atlantic LNG at Point Fortin.

The development of the Poinsettia field as part of Phase 3 included accessing the Heliconia and Bougainvillea accumulations. A pipeline connects the platform to the existing Hibiscus platform 20 kilometres away. First gas production from Poinsettia was achieved in 2009. The six development well drilling programme completed in 2010, thereby increasing NCMA deliverability to Atlantic LNG.

The NCMA 4a compression project, which will sustain existing production from the NCMA fields, was sanctioned by BG Group and partners in 2010. Construction of the compression unit commenced in 2012, with first gas achieved in June 2014.

Central Block BG Group acquired a 65% interest in, and assumed operatorship of, this block in 2004 under an exploration and production licence. Following acreage relinquishment in 2012, this onshore block now covers 27 square kilometres and includes the currently producing Carapal Ridge, Baraka and Baraka East developments.

A gas plant with a capacity of approximately 65 mmscfd was commissioned in 2007, near the existing production site at Carapal Ridge. This was de-bottlenecked to 80 mmscfd in 2010.

BG Group supplies both gas and condensate to Petrotrin, for use in its refinery at Pointe-à-Pierre, Trinidad. Gas is transported via a 12 kilometre pipeline that connects to the NGC network. BG Group also supplies export gas to Atlantic LNG Train 4. The development of the Baraka and Baraka East discoveries and compression (known as the BTIC project) was sanctioned in 2009 with first gas delivered in 2012, allowing for the extension of the gas supply contracts.

Block 5(c)In 2007, BG Group signed a farm-in agreement for Block 5(c), 94 kilometres off the east coast of Trinidad. BG Group took a 30% working interest in the PSC and assumed operatorship in 2009. In 2009, BG Group exercised its pre-emption rights under the Joint Operating Agreement to increase its stake in the block to 75%, which became effective later that year. In March 2014, BG Group purchased the remaining 25% of the block.

Each of the three wells drilled on Block 5(c) since 2007 have encountered hydrocarbons and has been successfully tested. The first well, Victory-1, was drilled 10 kilometres north-east of the Dolphin platform. The second well, Bounty-1, targeted a separate prospect, approximately four kilometres away from the Victory-1 well. Drilling and testing of the third exploration well, Endeavour-1, was completed

in 2009. Declaration of Commerciality was made in 2011. An appraisal drilling programme is proposed to commence in 2015.

Block 5(d)In 2012, BG Group (100% and operator) executed a PSC for Block 5(d), which sits adjacent to Block 5(c). An extensive seismic survey has been completed with final processed products delivered in the first quarter of 2014. The exploration potential is currently being evaluated utilising this dataset.

Trinidad and Tobago Deepwater Atlantic Area (TTDAA)In June 2014, BG Group farmed in to TTDAA Blocks 5 and 6, with 35% equity in each block. BHP Billiton retained 65% equity and operatorship

ConcessionBG Group interest (%) Field Supplying DCQ gross

Contract

Start End

ECMA 50 Dolphin NGC 250 mmscfd 1996 2015

Dolphin Deep Atlantic LNG Train 3 100 mmscfd 2004 2026

Atlantic LNG Train 4 120 mmscfd 2007 2027

NGC 220 mmscfd 2009 2023

NCMA 45.88 Hibiscus Atlantic LNG Train 2 240 mmscfd 2004 2023

Poinsettia Atlantic LNG Train 3 45 mmscfd 2004 2023

Chaconia Atlantic LNG Train 4 80 mmscfd 2007 2017

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

20 Data Book 2014

Trai

n 1

(sta

rt d

ate

199

9)

Trai

n 2

(sta

rt d

ate

200

2)

Upstream Train equity Downstream

Trai

n 3

(sta

rt d

ate

200

3)Tr

ain

4 (s

tart

dat

e 20

05)

Gas supply Train equity LNG purchase

Upstream: LiquefactionAtlantic LNGThe Atlantic LNG Company of Trinidad and Tobago, in which BG Group is a shareholder, constructed its LNG plant at Point Fortin, south-west Trinidad, which began operating in 1999.

The first train has a productive capacity of 3.1 mtpa LNG. Train 2 commenced production in 2002 and Train 3 in 2003. These additional two trains have a combined productive capacity of approximately 6.6 mtpa. With the completion of the 5.2 mtpa Train 4 in 2005, the total LNG production capacity of Atlantic LNG is approximately 15 mtpa.

The LNG produced from gas supplied to Trains 2 and 3 by BG Group and its partners is sold to BGGM for sale into global markets. LNG produced from the BG Group liquefaction capacity in Train 4 is also sold under a long-term contract to BGGM for onward sale.

Atlantic LNG Trains 2, 3 and 4 represent fully integrated projects for BG Group.

GDF SUEZ 60.0%Gas Natural 40.0%

BG Group 45.0%Others 55.0%



Gas

Gas

Gas

Gas

LNG

LNG

LNG

LNG

BG Group and upstream partners 50.0%



Train 1 – 3.1 mtpaMerchant plant




c520 mmscfd (non-BG Group supply)

c560 mmscfd

c560 mmscfd

c800 mmscfd

BG Group 26%BP 34%Shell 20%China Investment Corp. 10%NGC 10%

BG Group 32.5%BP 42.5%Shell 25.0%

BG Group 32.5%BP 42.5%Shell 25.0%

BG Group 28.9%BP 37.8%Shell 22.2%NGC 11.1%

www.bg-group.com 21

NCMA, ECMA, CENTRAL BLOCK AND ATLANTIC LNG: INTEGRATED UPSTREAM AND DOWNSTREAM

GULF OF MEXICO

HOUSTON

ATLANTA

USAUSA

CANADACANADA

MEXICOMEXICO

WASHINGTON D.C.

Lake Charles

Haynesville shale*

Elba Island

Marcellus shale*

0 600 km

80

60

40

20

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

7973

58

PACIFICOCEAN

CANADA

Prince Rupert

ANCHORAGE

ALASKAALASKA

PRUDHOE BAYBEAUFORT SEA

Foothills Area

Upstream: E&PBG Group is partnered with EXCO Resources, Inc. (EXCO) to develop shale gas opportunities in the Haynesville Basin (east Texas and north Louisiana) and in the Appalachian Basin (Pennsylvania and West Virginia).

Haynesville shaleBG Group acquired its shale gas position via an alliance with EXCO in 2009 through which the Group:

● acquired a 50% interest in EXCO’s acreage in east Texas and north Louisiana, predominantly in the Haynesville shale gas formation, which is operated by EXCO;

● entered into a joint development agreement with EXCO to cooperate in the further development and production of shale gas in east Texas and north Louisiana; and

● acquired a 50% interest in related and complementary EXCO gas gathering and transport assets, known as TGGT.

In 2010, BG Group and EXCO jointly purchased Common Resources, L.L.C. (Common), which owned operations in Texas. Later in 2010, the partners purchased acreage from Southwestern Energy.

In March 2013, BG Group divested all its interests in the shallow, non-core, conventional producing assets and acreage in the Cotton Valley formation in east Texas and north Louisiana. In November 2013, BG Group sold its equity holding in TGGT.

In line with the Group’s strategy of focusing on value, and the continuing low US natural gas price, BG Group expects to continue to develop its Haynesville position with rig numbers being optimised based on realised gas prices.

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

Key dates2009 Entry into US shale via alliance with

EXCO Resources, Inc. (EXCO)2010 Acquisition of Common Resources L.L.C.

and acreage from Southwestern EnergyNew joint venture with EXCO in the Appalachian Basin

22 Data Book 2014


Potential gas pipeline

Oil pipeline

*Approximate shale area

AREAS OF OPERATION

BG Group jointly operated

BG Group non-operated

UNITED STATES OF AMERICA

PACIFICOCEAN

CANADACANADA

USAUSA

ALASKAALASKA

PRUDHOE BAY

BEAUFORT SEA

ANCHORAGE

Foothills Area

Prince Rupert

0 500 km

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

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 low US natural gas price, BG Group is continuing to evaluate its drilling strategy in the Marcellus shale for 2015.

AlaskaIn 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 out in this area between 2007 and 2012. BG Group continues to evaluate its opportunities in the region.

LNG Shipping & Marketing BG Group’s LNG and gas marketing activities include the Lake Charles and Elba Island LNG import facilities. BG Group is progressing applications 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).

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.

BG Group is evaluating a potential LNG project at Prince Rupert in British Columbia.

www.bg-group.com 23

AREAS OF OPERATION

CANADA


Potential gas pipeline

Oil pipeline


BANGKOK

KHANOM

RAYONG

RATCHABURI

Block 9A

Blocks 7, 8, 9

Bongkot

0 200km

ANDAMAN SEA

GULF OFTHAILAND

THAILANDTHAILAND

CAMBODIACAMBODIA

MYANMARMYANMAR

0 250 km

50

40

30

20

10

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

36

27

41

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.

New information ● Bongkot North Phase 3L onstream ● Bongkot South Phase 4B onstream

Key dates1990 Entered into Participation and

Operating Agreement with partners1993 Bongkot North first production2001 Memorandum of Understanding

(MoU) between Thailand and Cambodia 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 Bongkot South signed

2012 Bongkot South first production

The Bongkot North development consists of a central complex for gas gathering, processing, export and worker accommodation; a condensate floating storage and offloading (FSO) vessel; 31 remote wellhead platforms; and over 400 development wells. Production commenced in 1993 and gross daily gas production has risen and been sustained at more than 600 mmscfd through a phased programme of field development.

Phase 3K, consisting of two remote wellhead platforms and 16 wells, came onstream in August 2013. Phase 3L, consisting of two remote wellhead platforms and 18 wells, came onstream in June 2014, while Phase 3M is expected onstream in 2015 and Phase 3N is underway.

BG Group and its partners continue to explore further opportunities to extend the Bongkot North production plateau. Programmes of well intervention, infill drilling and booster compression are being implemented to improve hydrocarbon recovery and an active programme of exploration drilling is underway to discover reserves for further incremental phases of development.

Bongkot South is located some 70 kilometres to the south of Bongkot North and involves the development of further reserves through new standalone facilities with processing capacity of 350 mmscfd and 15 000 barrels of condensate per day. Production commenced in 2012 and at plateau, Bongkot South delivers some 14 000 boed net to BG Group. Phase 4B of Bongkot South, consisting of four further wellhead platforms, came onstream in early 2014. Bongkot South Phase 4C is underway and consists of three wellhead platforms with first gas expected in 2015. Gas from the project is exported via a new-build spur line connected to existing gas export infrastructure, while condensate is exported to the FSO vessel at Bongkot North. Production is sold to PTT Public Company.

Blocks 7, 8 and 9BG Group is the operator of Blocks 7, 8 and 9 in the Gulf of Thailand (BG Group 66.67%), in an area subject to overlapping claims by Thailand and Cambodia. Activity in these blocks is suspended until these claims are resolved. BG Group also has an Overriding Royalty Agreement covering production from Block 9a.

Upstream: E&PBongkotBG Group has a 22.22% interest in the Bongkot field in the Gulf of Thailand. The field is operated by PTT Exploration and Production (PTTEP). In 2012, the Bongkot Concession passed the milestone of producing more than 1 bcf of sales gas per day from the Bongkot North and Bongkot South fields combined.

24 Data Book 2014

Gas

Oil

Gas pipeline

Oil pipeline

Gas and Oil/Condensate



AREAS OF OPERATION

THAILAND

Key to operations

ALGERIAALGERIA

SICILYSICILY

LIBYALIBYA

BIZERTE

SOUSSE

SFAXBEN SAHLOUN

GABÈS

TUNISIATUNISIA

GULF OF GABÈS

MEDITERRANEAN SEA

TUNIS

LA SKHIRA

Hasdrubal

Hannibal plant

Hasdrubal plant

Hannibal condensate pipeline

LPG facility

Amilcar

Miskar

0 200 km

50

40

30

20

10

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

3740 38

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.

New information ● Well intervention campaigns on Miskar and Hasdrubal fields

Key dates1989 Tenneco assets acquired1996 Miskar field first production2009 Hasdrubal field first production2011 LPG pipelines start-up

Offshore compression was commissioned in 2005 to maintain the production plateau of the field. Six infill wells were drilled between 2007 and 2010. There is currently an ongoing workover campaign, comprising well re-perforations and well re-fracturing operations. As a result, there are 18 producing wells.

A 60 kilometre condensate pipeline was completed in 2007 to transport Miskar condensate from Hannibal to La Skhira storage terminal. The condensate is mainly exported to the international market.

Hasdrubal Hasdrubal came onstream in 2009, with gas being sold to STEG on a long-term contract, while condensate and LPG are sold to both international and local markets.

The Hasdrubal onshore gas processing facility (BG Group 50%, Entreprise Tunisienne d’Activités Pétrolières (ETAP) 50%) and LPG production facility (BG Group 100%) have been built adjacent to the Hannibal plant.

Production is delivered from three gas wells through an unmanned offshore platform to dedicated offtake facilities. Condensate from Hasdrubal is transported to La Skhira storage terminal through the Hannibal condensate pipeline. The condensate is mainly exported and jointly sold with Miskar condensate to the international market. The LPG storage terminal has been constructed in Gabès to receive and deliver butane for sale locally to Société Tunisienne des Industries de Raffinage (STIR) and propane for export to the international Med LPG market. Two 6-inch, 130 kilometre parallel pipelines commissioned in 2011 are used to deliver LPG to the terminal from Hasdrubal.

Amilcar permitBG Group is operator and joint permit holder with ETAP, the Tunisian state-owned company, of the 1 016 square kilometre Amilcar exploration permit, in the Gulf of Gabès. Approval has been granted in principle for an extension to December 2014, pending decree publication.

Upstream: E&PMiskarGas from the Miskar field is processed at the BG Group-operated Hannibal plant and sold into the Tunisian gas system. BG Group has a long-term gas sales contract with the Tunisian state electricity and gas company, Société Tunisienne de l’Electricité et du Gaz (STEG).

www.bg-group.com 25

Gas

Oil

Gas pipeline

Oil pipeline


AREAS OF OPERATION

TUNISIA

Key to operations

TARIJAVILLAMONTES

BOLIVIABOLIVIA

ARGENTINAARGENTINA

PARAGUAYPARAGUAYMargarita

La Vertiente

Charagua

Tarija XX East

Los Suris

CaipipendiHuacareta

Tarija XX West

Itaú

0 100 km

40

30

20

10

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

28

19

36

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

New information ● First production from Margarita Phase II ● First production from Itaú Phase II

Key dates1998 Margarita field discovered1999 Itaú field discovered 2004 First production from Margarita

Early Production Facility2006 Supreme Decree on Nationalisation issued

New Operations Contracts signed2010 Margarita delivery agreement amended

to include volumes to Argentina2011 Itaú Phase I first production2012 Margarita Phase I first production2013 Awarded Huacareta exploration block

Upstream: E&POperated licences (all 100% BG Group equity)La VertienteThe La Vertiente licence contains the La Vertiente, Escondido and Taiguati gas fields. Production in these fields is processed at the La Vertiente gas plant before delivery to YPFB. Los SurisThe Los Suris licence contains the Los Suris gas field. Production from this field is processed at the La Vertiente gas plant.

Tarija XX East The Tarija XX East licence contains the Palo Marcado gas field where production is processed at the La Vertiente plant. The Ibibobo field is in the process of being relinquished.

HuacaretaIn 2013, BG Group was awarded the 4 500 square kilometre Huacareta licence block. The first five year exploration phase will include a combination of seismic acquisition and interpretation, and could include the drilling of one well.

BG Group has both operated and non-operated interests in seven licences. Both gas and condensate production in these interests are delivered to Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), the national oil company, to supply Brazilian, Argentine and domestic markets. Exploration activity is focused on the 100% owned Huacareta licence block.

Non-operated licencesCaipipendiBG Group has a 37.5% interest in the Caipipendi licence, which contains the large Margarita gas condensate field. The consortium sanctioned Phase I in 2010, with first gas produced in 2012. In 2011, the consortium sanctioned Margarita Phase II, with first gas produced in the third quarter of 2013, increasing BG Group net production capacity from the Margarita field to around 42 000 boed.

Tarija XX WestBG Group has a 25% interest in the Tarija XX West licence, which contains the Itaú gas condensate field. In 2011, Itaú Phase I came onstream. Phase II came onstream in the fourth quarter of 2013, raising BG Group net production capacity to 10 000 boed.

CharaguaBG Group has a 20% interest in the Charagua licence, which contains the Itatiqui Retention Area. The partnership is in the process of relinquishing their interests in this licence.

26 Data Book 2014

Gas

Oil

Gas and Oil/

Condensate

Gas pipeline

Oil pipeline



AREAS OF OPERATION

BOLIVIA

Key to operations

GULF OF CAMBAY

ARABIAN SEA

BHARUCH

ANKLESHWAR

SURAT

HAZIRA

AHMEDABAD

VADODARA

DAHEJ

MUMBAI

Tapti

Mukta

HVJ pipeline

Mahanagar Gas

MB-DWN-2010/1

Panna

KG-DWN-2009/1 (A)

KG-DWN-2009/1 (B)

INDIA

BHUBANESHWARCUTTACK

PURI

KAKINADA

2

INDIA1

0 100 km

40

30

20

10

0


Gas

Oil & liquids

2011 2012

(kboed)

2013

25

31

20

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.

Key dates1995 Mahanagar Gas Ltd (MGL) formed2002 30% participating interest in the

Panna/Mukta and Mid and South Tapti (PMT) fields acquired

2008 Agreement signed by BG Group with GAIL (India) Limited to purchase PMT gas

2010 PSC for Block KG-DWN-2009/1 signed2013 Agreement for initial supply of 1.25 mtpa of

LNG to GSPC from 2015 for up to 20 years

Upstream: E&PBG Group has a 30% interest in the Mid and South Tapti gas fields and the Panna/Mukta (PMT) oil and gas fields. Incremental development of the existing fields via well intervention and infill drilling campaigns, as well as evaluating new projects and further development opportunities, is being planned.

In 2012, a consortium led by BG Group (50% and operator) was awarded the exploration block MB-DWN-2010/1, in the Mumbai Basin, offshore the west coast of India. The block covers an area of nearly 8 000 square kilometres in water depths of around 3 000 metres. In 2013, a 2D seismic survey was completed. Data is currently being interpreted after completion of initial processing.

BG Group (30% and operator) holds exploration block KG-DWN-2009/1 (both A and B) in deep water in the Krishna Godavari (KG) Basin.

LNG Shipping & MarketingIn 2013, BG Group completed an agreement with Gujurat State Petroleum Corporation (GSPC) for the initial supply of 1.25 mtpa of LNG beginning in 2015 for up to 20 years, potentially increasing to 2.5 mtpa after two years.

Other Mahanagar Gas Ltd (MGL)MGL, based in Mumbai, is India’s largest gas distribution company in terms of size of customer base, serving more than 690 000 residential, commercial and industrial customers and fuelling more than 340 000 vehicles with CNG at the end of December 2013. BG Group and GAIL (India) Limited each have a 49.75% stake in MGL, with the residual stake held by the government of Maharashtra.

www.bg-group.com 27

AREAS OF OPERATION

India 1

India 2

INDIA


Oil

Gas pipeline

Oil pipeline


INDIANOCEAN

Pweza

Block 3

Papa

Chewa

Block 1

Mzia

Taachui

Jodari North

Jodari

Chaza

Mkizi

Ngisi

Block 4

MTWARA

MOZAMBIQUEMOZAMBIQUE

TANZANIATANZANIA

LINDI

KILWA KIVINJE

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.

New information ● Mzia confirmed as second giant gas discovery, after Jodari

● Taachui gas discovery in Block 1 ● LNG site MoU signed with the government ● HoA signed with Block 2 partners: BG Group is lead developer for pre-FEED

● Contracts for upstream and LNG plant pre-FEED awarded

Key dates2010 BG Group farmed into Blocks 1, 3 and 4

Pweza and Chewa gas discoveries2011 Chaza gas discovery

BG Group became operator of Blocks 1, 3 and 4

2012 Jodari, Mzia, and Papa gas discoveries 2013 First DST offshore Tanzania conducted

at Jodari Ngisi and Mkizi gas discoveries

Block 1 Six discoveries have been made in Block 1 since 2010. All are within 100 kilometres of the shore and in water depths of 900 to 1 600 metres. Four of these are Tertiary reservoirs (Chaza, Jodari, Jodari North and Mkizi) and two are Cretaceous (Mzia and Taachui). Mzia (4.7 tcf total gross resource) and Jodari (4 tcf total gross resource) are both classified as giant discoveries. Four DSTs have been conducted on Jodari, Mzia (two DSTs) and Taachui.

Block 3 In 2012, the joint venture successfully drilled the Papa discovery well into the deeper Cretaceous reservoir. The well is around 100 kilometres offshore Tanzania in water depth of approximately 2 180 metres.

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.

Upstream: E&PIn 2010, BG Group farmed in to Blocks 1, 3 and 4 offshore southern Tanzania taking 60% equity in each, assuming operatorship in 2011. The blocks cover around 20 850 square kilometres of the Mafia Deep Offshore Basin and the northern part of the Rovuma Basin.

Since entering Tanzania, the joint venture has acquired over 13 000 square kilometres of 3D seismic data, and has had 15 consecutive drilling successes, including 10 gas discoveries and five appraisal wells. The joint venture has also conducted five drill stem tests (DSTs). This exploration and appraisal activity has led to estimates of total gross resources of around 15 tcf, with further exploration upside. A contract for the upstream pre-FEED was awarded in May 2014.

Upstream: LiquefactionIn April 2014, the partners in Blocks 1, 3 and 4 and the partners in Block 2 signed a Heads of Agreement (HoA) setting out how the companies will collaborate on development of a potential joint LNG project. Under the agreement, BG Group will be the lead developer during the pre-FEED phase. A contract for the LNG plant pre-FEED was awarded in August 2014.

A Memorandum of Understanding (MoU) between the government of Tanzania, the partners in Blocks 1, 3 and 4 and the partners in Block 2 was signed in April 2014. The MoU covers the site selected for the LNG plant, the process for acquiring the site, the lease to be negotiated, and how any resettlement will be managed.

28 Data Book 2014

Gas BG Group-operated block

AREAS OF OPERATION

0 100 km

TANZANIA

Key to operations

PEMBA ISLAND

TANZANIATANZANIA

KENYAKENYAINDIANOCEAN

L10A

L10B

MOMBASA

MOZAMBIQUEMOZAMBIQUEMOZAMBIQUEMOZAMBIQUE MADAGASCARMADAGASCARMADAGASCARMADAGASCAR

SOUTH AFRICASOUTH AFRICASOUTH AFRICASOUTH AFRICA

TANZANIATANZANIATANZANIATANZANIA

ETHIOPIAETHIOPIASOMALIASOMALIA

KENYAKENYA

ANTANANARIVO

Majunga Offshore Profond

0 100 km 0 1 000 km

Upstream: E&PIn 2011, BG Group signed Production Sharing Contracts with the government of Kenya for two offshore exploration blocks – L10A and L10B. BG Group is operator of both blocks and holds a 50% equity interest in Block L10A (PTTEP 31.25%, Pancontinental 18.75%) and a 75% interest in Block L10B (Pancontinental 25%).

BG Group completed two 3D seismic surveys with approximately 4 700 square kilometres of 3D seismic acquired. In March 2014, the 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.

Upstream: E&PBG Group (30%) partners with ExxonMobil (50% and operator), SK Innovation (10%) and PVEP Corp (10%) in the Majunga Offshore Profond exploration block.

The block covers around 15 840 square kilometres in water depths ranging from around 200 metres to in excess of 3 000 metres, offshore the north-west coast of Madagascar. The block is believed to be oil-prone and it forms part of a largely unexplored frontier basin.

BG Group entered Kenya in 2011, acquiring an interest in offshore blocks L10A and L10B.

BG Group owns a 30% interest in the Majunga Offshore Profond exploration block in Madagascar.

www.bg-group.com 29

Key to operations BG Group-operated block Gas pipeline

Oil pipeline


AREAS OF OPERATIONAREAS OF OPERATION

KENYA MADAGASCAR

Key to operations

Block 9

Block 8

Block 13

Southern Cross pipeline

Gas Link pipeline

URUGUAY

ARGENTINA

BRAZIL

PUNTA LARA

MONTEVIDEO

BUENOS AIRES

0 150 km

Patuca and Mosquitia Basins

NICARAGUANICARAGUA

HONDURASHONDURAS

BELIZEBELIZE

TEGUCIGALPA

SAN PEDRO SULALA CEIBA

0 200 km

Upstream: E&P In 2012, BG Group successfully bid for three offshore blocks (8, 9 and 13) in the second licensing round held by the Republic of Uruguay. The PSCs commit BG Group (100% and operator) to a seismic work programme intended to evaluate the blocks in the first three year exploration period. Acquisition of 13 080 square kilometres of 3D seismic was completed in February 2014. Sub-surface analysis and prospect mapping is underway. A well commitment is required on each block in order to enter the second three year exploration phase.

OtherBG Group is operator, with a 40% share, in the Southern Cross pipeline linking Punta Lara in Argentina to Montevideo. Through its holding 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 to the Argentine transportation network.

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

BG Group holds an offshore frontier exploration licence covering approximately 35 000 square kilometres.

Upstream: E&PBG Group is the sole licence holder of an approximately 35 000 square kilometre offshore frontier exploration block covering the Patuca and Mosquitia sedimentary basins. BG Group submitted an Exploration Licence Application in 2012. The Operating Contract was approved by legislative decree and commenced in 2013.

The initial four year exploration period will focus on reviewing existing exploration data, conducting a gravity gradiometry survey to map the entire block, seabed sampling and seismic surveys. The acquisition of data from the gravity gradiometry survey was undertaken between March and May 2014 and will enable targeted seismic surveys, planned for 2015 and 2016. The seabed coring survey began in July 2014.

In 2017, BG Group will relinquish 50% of the acreage to the government 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.

30 Data Book 2014

AREAS OF OPERATION



URUGUAY HONDURAS

Key to operations BG Group-operated block

AREAS OF OPERATION

COLOMBIACOLOMBIA

VENEZUELAVENEZUELA

ARUBAARUBAARUBAGAP

GULF OFVENEZUELA

Guajira Offshore 3

0 200 km

COLOMBIACOLOMBIA

VENEZUELAVENEZUELA

PANAMAPANAMA

CARIBBEANSEA

PACIFICOCEAN

CARTAGENA

BOGOTÁ

Guajira Offshore 30 200 km

Upstream: E&PIn June 2014, BG Group agreed to acquire a 30% interest in an exploration block, offshore Aruba. The block covers 14 356 square kilometres in water depths ranging between 400 metres and 1 800 metres.

A Production Sharing Agreement is in place and a 3D seismic programme will be completed in 2014. The Group’s farm-in agreement is subject to approval by the Compania Arubano di Petroleo N.V.

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

Upstream: E&PIn January 2014, BG Group signed an agreement to acquire a 30% equity interest in the Guajira Offshore 3 Block (Shell 70% and operator). The agreement is subject to approval from the government’s Agencia Nacional de Hidrocarburos (ANH). The block is held under a Technical Evaluation Agreement and is located approximately 70 kilometres offshore in water depths of 1 500 to 4 000 metres. The 2014 work programme consists of a 3D seismic survey and seabed coring.

In 2014, BG Group farmed in to an offshore frontier exploration block.

www.bg-group.com 31

AREAS OF OPERATION

ARUBA


Key to operationsKey to operations BG Group non-operated block

AREAS OF OPERATION

COLOMBIA

THAILANDTHAILAND

MYANMARMYANMAR

BAY OFBENGAL

ANDAMANSEA

GULF OFTHAILAND

YANGON

NAYPYIDAW

A-4

AD-2

A-7

AD-5

0 200 km

SINGAPORE

MALAYSIAMALAYSIA

INDONESIAINDONESIA

0 250 km

In 2014, BG Group was awarded four blocks of frontier acreage in Myanmar.

Upstream: E&PIn March 2014, BG Group was awarded, subject to finalisation of the Production Sharing Contracts, exploration acreage in the Bay of Bengal, offshore western Myanmar, as part of the government’s 2013 offshore bid round. Total gross acreage awarded to BG Group and partners was more than 34 350 square kilometres in water depths of up to 2 600 metres.

The Group was awarded four blocks: ● AD-2 with 55% equity and operatorship (Woodside Energy 45%); ● A-4 with 45% equity and operatorship (Woodside Energy 45%, Myanmar Petroleum Exploration and Production (MPEP) 10%);

● AD-5 with 45% equity (Woodside Energy 55% and operator); and ● A-7 with 45% equity (Woodside Energy 45% and operator, MPEP 10%).

BG Group and its partners have committed to a 3D seismic acquisition programme in each block, which is expected to begin in 2015 following an Environmental and Social Impact Assessment, with plans beyond that for exploration drilling.

LNG Shipping & MarketingIn April 2014, BG Group moved the centre of its global LNG and oil marketing business to Singapore, reflecting the long-term importance of Asian energy markets. This move builds on the Group’s presence in the country, having been appointed by the Energy Market Authority (EMA) in 2008 as the sole aggregator of Singapore’s first 3.0 mtpa of LNG 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 Aggregator Agreement was signed in 2009. Beginning in 2010, BG Group signed gas sales contracts with a variety of customers, including six large scale power generation companies. The total LNG contracted under this agreement by the end of July 2014 was approximately 2.7 mtpa, with the Group having delivered a total of 30 cargoes since the first commercial delivery to the LNG terminal on Jurong Island in May 2013. The aggregator is also required to develop trading activity and market short-term and spot gas sales agreements to the Singapore market.

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.

BG Group’s global centre for LNG and oil 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.

32 Data Book 2014

MYANMAR

Key to operations BG Group-operated block


AREAS OF OPERATION AREAS OF OPERATION

SINGAPORE

MEDITERRANEAN SEA

ISRAELISRAEL

LEBANON

EGYPTEGYPT

GAZAGAZA

Offshore GazaMarine licence

Gaza Marine

0 50 km

Upstream: E&PBG 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.

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

www.bg-group.com 33



AREAS OF OPERATION

AREAS OF PALESTINIAN AUTHORITY

CANADA*

USA

TRINIDAD & TOBAGO*

CHILE

UK*

EGYPT*

NIGERIA EQUATORIAL GUINEA

TANZANIA*

INDIA

JAPANS.KOREA

CHINA

SINGAPORE

AUSTRALIA*

15

12

9

6

3

0

LNG delivered volumes

2011 2012

(mtpa)

2013

12.112.8

10.9

Train 2, and in 2007, purchases from Atlantic LNG Train 4 commenced.

In 2006, BG Group lifted its first third-party cargo from Nigeria LNG (NLNG) Trains 4 and 5. In 2007, the Group lifted its first cargo from the Equatorial Guinea LNG (EGLNG) project.

BG Group expects first LNG in the fourth quarter of 2014 from its two-train 8.5 million tonnes per annum (mtpa) QCLNG project currently in development in Australia.

In 2011, BG Group signed the first long-term LNG purchase agreement from a project on the US Gulf Coast, agreeing to take 3.5 mtpa of LNG over a 20 year period from Train 1 of the Sabine Pass LNG terminal. In 2012, BG Group agreed to purchase an additional 2.0 mtpa from Trains 2, 3 and 4 over a 20 year period. The operator expects the Sabine Pass project to commence production of LNG in late 2015.

New information ● Lake Charles FERC application filed for proposed LNG export project

Key dates2001 Agreement signed for Lake Charles

import capacity2003 Access to Elba Island terminal capacity2004 First long-term equity LNG supply

purchased from Atlantic LNG2006 First long-term third-party supply

purchased from NLNG2010 Initial 3.6 mtpa LNG sales contract

signed with CNOOC2012 Sabine Pass US LNG exports purchase

agreement increased to 5.5 mtpa2013 First cargo delivered into Singapore

under the LNG Aggregator Agreement with the EMA

Agreement to supply further 5 mtpa of LNG to CNOOC for 20 yearsLake Charles LNG exports approved for non-FTA countries

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.

GEMSGEMS activities cover global liquefied natural gas (LNG) marketing, gas marketing, oil marketing and shipping. In April 2014, BG Group moved the centre of its global LNG and oil marketing business to Singapore from its head office in the UK, reflecting the long-term importance of Asian energy markets (see page 32 for more details).

LNG supplyBG Group pursues a number of opportunities to create a diversified supply portfolio. These include buying LNG from third parties as well as from BG Group equity LNG projects in Egypt and Trinidad and Tobago currently, and Queensland Curtis LNG (QCLNG) in Australia from the fourth quarter of 2014.

In 2004, BG Group purchased its first long-term LNG cargo of equity gas from Atlantic LNG Trains 2 and 3 under a 20 year contract. This was followed in 2005 with the first purchases of equity gas from Egyptian LNG

34 Data Book 2014

LNG AREAS OF OPERATION

Key to operations Existing long-term supply source Supply source under construction

Existing import capacity/Term customer Potential supply source

*BG Group equity project

GLOBAL ENERGY MARKETING AND SHIPPING

Diversified andflexible LNG

supply

Flexibleportfolio

Extensivecustomernetwork

BG Group’s LNG strategy

250

200

150

100

50

0

208 197178

201320122011

Cargo supply by source

Atlantic LNG

Egyptian LNG

Equatorial Guinea

Nigeria

Spot purchases

250

200

150

100

50

0

208 197178

201320122011

Cargo deliveries by geographical region

Asia

South America

North America

Europe & Others

In 2010, BG Group signed a sales contract 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 portfolio, including QCLNG. Deliveries under this contract have commenced. Further, in 2013, BG Group committed to supply an additional 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 be 8.6 mtpa, making the Group the largest supplier of LNG to the world’s fastest-growing energy market.

In 2011, BG Group contracted to supply Tokyo Gas Co., Ltd. (Tokyo Gas) with 1.2 mtpa of LNG for 20 years from 2015. Tokyo Gas will be supplied with LNG from the Group’s portfolio, including QCLNG (see page 10 for more details).

BG Group also signed a sales contract with Chubu Electric Power Co., Inc. (Chubu Electric) for the long-term supply of LNG. Under the agreement, Chubu Electric will purchase up to 122 cargoes over 21 years, starting in 2014. Chubu Electric will be supplied from the Group’s portfolio, including QCLNG.

In 2013, BG Group signed a sales contract for the long-term supply of LNG to Gujarat State Petroleum Corporation Limited (GSPC) in India. BG Group will initially supply 1.25 mtpa of LNG beginning in 2015 for up to 20 years, potentially increasing to 2.5 mtpa after two years. GSPC will be supplied from the Group’s portfolio.

BG Group currently expects very limited cargoes to be lifted from Egyptian LNG for the foreseeable future, with Force Majeure in place on the LNG purchase agreements in Egypt (see page 11 for more details).

BG Group’s LNG supply growth opportunity set includes projects at Lake Charles (USA), Prince Rupert (Canada) and Tanzania.

In 2011, the US Department of Energy granted authorisation for LNG export from the Lake Charles terminal to free trade agreement (FTA) countries. In August 2013, authorisation for the export of up to 15 mtpa of LNG to non-FTA countries was received.

In March 2014, subsidiaries of Energy Transfer filed an application with the Federal Energy Regulatory Commission (FERC) seeking authorisation for the siting, construction, ownership and operation of the proposed Lake Charles LNG export project. Pending receipt of all necessary approvals and a final investment decision, expected in 2015, construction could then start shortly afterwards, with first LNG exports anticipated in 2019. Energy Transfer will own and finance the proposed facility and BG Group will manage construction and operate the proposed facility, while being responsible for the offtake.

More information on the Group’s potential growth projects in Canada and Tanzania can be found on their country pages, 23 and 28 respectively.

Further details of LNG supply can be found on page 48 within the Statistical Supplement.

LNG marketing 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 been built around its portfolio of diversified and flexible LNG supplies that are sold globally

to an extensive customer network. In addition to marketing its own contracted portfolio of volumes, the Group also buys and sells spot LNG cargoes. BG Group has made LNG sales to more than 60 customers around the globe, in 26 of the current 27 LNG importing countries, having also bought LNG from 15 of the 19 LNG producing countries.

The Group has a long-term contract to supply the Quintero LNG terminal in Chile with up to 3.0 mtpa until 2030.

In 2008, BG Group was selected by the Energy Market Authority (EMA) of Singapore to source and supply the Singapore market on an exclusive basis with up to 3.0 mtpa of LNG for up to 20 years from the Group’s portfolio. The Singapore receiving terminal commenced commercial operations in May 2013, and as at 31 July 2014, the Group had delivered a total of 30 cargoes.

As the Group’s LNG supply increases with the start-up of the QCLNG and Sabine Pass projects, the Group has entered into a number of additional long-term sales contracts.

www.bg-group.com 35

50

60

40

30

20

10

0

4146

51

20132011 2012

Oil liftings by source(mmbbls)

Brazil

Kazakhstan*

North Sea**

In addition to these long-term sales contracts, BG Group has regasification capacity at the Lake Charles and Elba Island terminals in the USA, and the Dragon LNG terminal in the UK. The Group uses this terminal capacity when prices are attractive. Given the strong demand in Asia and South America in particular, and the impact of increasing US shale gas production, GEMS has reduced LNG imports into these markets freeing valuable cargoes for diversion to Asia and South America.

Gas marketingGEMS undertakes gas marketing in North America, Europe, Australia and Singapore. Sales are made under various short, medium and long-term arrangements. BG Group’s customers include leading gas and electric utilities, as well as industrial companies and wholesale gas merchants.

In North America, BG Group has a gas marketing business of around 3.4 bcfd and controls pipeline capacity of more than 3.9 bcfd. It markets the Group’s own shale gas as well as imported LNG, along with third-party gas supplies, to multiple intermediary and end-use customers via the US and Canadian natural gas pipeline infrastructure. In addition to the LNG storage facilities at Lake Charles and Elba Island, BG Group will from time to time contract for natural gas storage capacity on a seasonal and/or medium to long-term basis to facilitate its operational and commercial requirements.

In the UK, BG Group sells gas on a wholesale basis principally at the UK National Balancing Point (NBP) under contracts with varying durations. This includes the Group’s production of 0.2 bcfd of gas from the UK and Norwegian Continental Shelf, which in 2013 was the equivalent of approximately 3% of UK gas demand. BG Group is an active participant in the capacity auctions held by National Grid and in the on-the-day commodity market and other electronic trading systems that help shippers balance their supply and demand. BG Group owns both import and export capacity in the Interconnector pipeline (UK to mainland Europe), which it uses to ship gas to take advantage of market price differentials and for sub-lets to third parties.

In Australia, BG Group has a gas and power marketing business that includes both domestic gas sales and the dispatch of electricity from Condamine power station into the National Electricity Market. Domestic gas sales range from short to long-term covering both firm and flexible volumes.

In Singapore, BG Group currently has finalised contracts for the supply of around 2.7 mtpa of LNG out of its franchise 3.0 mtpa agreement. The Group has signed gas sales contracts with a variety of customers in Singapore, including six large scale power generation companies.

Oil marketingGEMS markets oil production from BG Group’s assets in the North Sea, Kazakhstan and Brazil. With the planned ramp up in production from the Group’s interests in the Santos Basin in Brazil, more than 300 Suezmax cargoes (or 300 mmbbls) of crude oil over the next five years are expected to be lifted from these assets alone.

In 2011, BG Group took delivery of its first chartered dynamically positioned oil shuttle tanker, the Windsor Knutsen, to shuttle crude oil to markets from the floating production, storage and offloading (FPSO) units in the Santos Basin, offshore Brazil. This vessel was chartered by BG Group until the end of July 2014. Further in 2011, the Group signed 10 year

* Kazakhstan represents CPC export volumes sold by BG Group. It excludes volumes sold locally and into Russia.

** North Sea includes Forties, Ekofisk and Ross blend crude only from BG Group’s interests in both the UK and Norwegian Continental Shelf.

time charters for four new-build oil shuttle tankers for deployment in the Santos Basin. The Samba Spirit, the Lambada Spirit and the Bossa Nova Spirit arrived in Brazil in 2013, with the Sertanejo Spirit arriving in early 2014. All four vessels are now in operation.

As production grows, the Group will ensure it has sufficient shipping capacity to meet lifting requirements through a variety of sources, which could include additional short, medium and long-term chartered vessels.

LNG ShippingBG Group has a long history in LNG shipping, having been involved in the development of both the prototype and the industry’s first working LNG carriers.

The Group secures and controls a competitive, flexible and safe LNG shipping portfolio with sufficient capacity to meet expected LNG transportation requirements and capture business opportunities. The fleet is predominantly a combination of short, medium and long-term charters. This flexible, strategic approach allows BG Group to seize new opportunities by managing long-range delivery logistics, with the Group regularly diverting cargoes from the Atlantic Basin to the Pacific Basin.

In 2010, BG Group took delivery of four new generation, energy-efficient LNG carriers. The ships have a capacity of 170 000 cubic metres and are among the first carriers in the world to integrate onboard reliquefaction with the propulsion system, allowing natural gas boil-off to be reliquefied and returned to cargo tanks.

As part of the LNG sales agreements signed with CNOOC in 2010 and 2013, BG Group and CNOOC tendered for the design and construction of four LNG vessels. In June 2014, BG Group divested its share of the vessels to Teekay LNG Operating LLC. The vessels, which will be constructed at the Hudong-Zhonghua shipyard in China, will be chartered into the Group’s portfolio for 20 years.

RegasificationCapacity rights

(%)Net capacity rights

(bcfd) Contract ends

Lake Charles, USA* 100 1.80** 2030

Elba Island, USA 40 0.63** 2027

Dragon LNG, UK*** 50 0.30 2029

* 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.

** Data represents sustainable baseload capacity.*** BG Group has 50% equity in the Dragon LNG terminal (Petronas 50%), including a combined heat and power plant

which uses natural gas boil-off to supply up to an aggregate of 48 megawatt of electricity to Dragon LNG and the grid, and 73 megawatt thermal of heat, in the form of hot water for Dragon LNG.

36 Data Book 2014

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

www.bg-group.com 37

CONTENTS

IntroductionFinancial and operating statisticsThis financial and operating information includes extracts from the BG Group Annual Report and Accounts 2013 (BG Group ARA) and quarterly results statements. Reference to these reports will assist in the understanding of the figures in this document. The financial information in this document is unaudited and is not intended to be the statutory accounts of BG Group plc.

Business performanceBusiness performance excludes discontinued operations and 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.

For further explanation of Business performance and the presentation of results from joint ventures and associates, please refer to the Presentation of non-GAAP measures on page 146 of the BG Group ARA.

Reference conditions (2014) ● Brent Oil price real (1/1/2014): $100/bbl ● US Henry Hub real (1/1/2014): $4.00/mmbtu ● US/UK exchange rate of $1.55:£1 ● US/AUD exchange rate of $1:A$1.05 ● US/BRL exchange rate of $1:BRL2.10 ● Prepared under International Financial Reporting Standards

● All production includes fuel gas

Legal noticesSteps have been taken to verify the information contained in this Data Book and, unless otherwise indicated, it is believed to be accurate as at 31 July 2014. However, no representation or warranty, express or implied, is or will be made in relation to the accuracy or completeness of the information in this publication and no responsibility or liability is or will be accepted by BG Group plc or any of its respective subsidiaries, affiliates and associated companies (or by any of their respective officers, employees or agents) in relation to it.

Certain statements included in this Data Book contain forward-looking statements concerning BG Group’s strategy, operations, financial performance or condition, outlook, growth opportunities or circumstances in the countries, sectors or markets in which BG Group operates. By their nature, forward-looking statements involve uncertainty because they depend on future circumstances, and relate to events, not all of which are within BG Group’s control or can be predicted. Although BG Group believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct. Actual results could differ materially from those set out in the forward-looking statements in this Data Book for a number of reasons. For a detailed analysis of the factors that may affect our business, financial performance or results of operations, we urge you to look at the “Principal risks and uncertainties” included on pages 38 to 43 of the BG Group ARA. Nothing in this Data Book should be construed as a profit forecast, and no part of this publication constitutes, or shall be taken to constitute, an invitation or inducement to invest in BG Group plc or any other entity, and must not be relied upon in any way in connection with any investment decision. BG Group undertakes no obligation to update any forward-looking statements.

Explanatory note for US investors relating to gas and oil reserves and resourcesOn 20 December 2007, BG Group ceased to be a United States Securities and Exchange Commission (SEC) registered company and the Group’s SEC reporting obligations also ceased with effect from that date. BG Group continued voluntarily to use the SEC definition of proved reserves, and from 2009 of probable reserves, to report proved gas and oil reserves and disclose certain unaudited supplementary information until 2013. BG Group has decided, from the year ended 31 December 2013 onwards, to adopt the reserves definitions and guidelines consistent with the internationally recognised Petroleum Resources Management System published by the Society of Petroleum Engineers, American Association of Petroleum Geologists, World Petroleum Council and the Society of Petroleum Evaluation Engineers, known as the SPE PRMS, in accordance with recommendations issued by the European Securities and Markets Authority (ESMA) and to achieve greater consistency across its reporting of reserves and resources.

BG Group has used gas and crude oil price forecasts that are based on its reference conditions to determine reserves estimates for the year ended 31 December 2013. This report also contains additional information about other BG Group gas and oil reserves and resources that would not be permitted in SEC filings.

Reserves (proved and probable) are measured in accordance with SPE PRMS definitions and guidelines and, in this transition year, are voluntarily shown together with the estimates under the SEC definitions, which formed the basis for measurement previously used by the Group.

For further details of BG Group’s proved reserves as at 31 December 2013, and related 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

38 Data Book 2014

INTRODUCTION AND LEGAL NOTICES

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

www.bg-group.com 39

PEOPLE AND COMMUNITIES

BUSINESS PERFORMANCE(1)

2013 2012Restated(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

40 Data Book 2014

SUMMARISED BG GROUP ANNUAL RESULTS

BUSINESS PERFORMANCE(1)

Q2 2014

Q1 2014

Q4 2013

Q3 2013

Q2 2013

Q1 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

www.bg-group.com 41

SUMMARISED BG GROUP QUARTERLY RESULTS

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: UKAtlantic Basin – Canada, Egypt, Nigeria, Trinidad and Tobago and the USAAsia and the Middle East – Areas of Palestinian Authority, Australia, China, India, Kazakhstan and ThailandRest of the World – Algeria, Bolivia, Brazil, Colombia, Honduras, Kenya, Madagascar, Norway, Tanzania, Tunisia and Uruguay

ESTIMATED NET PROVED RESERVES OF NATURAL GAS

UK bcf

Atlantic Basin

bcf

Asia and Middle East

bcf

Rest of World

bcfTotal

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)


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)


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

UK bcf

Atlantic

Basin bcf


bcf

Rest of World

bcfTotal

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

42 Data Book 2014

EXPLORATION AND PRODUCTION: ESTIMATED NET RESERVES OF NATURAL GAS

ESTIMATED NET PROBABLE RESERVES OF NATURAL GAS

UK bcf

Atlantic Basin

bcf


bcf

Rest of World

bcfTotal

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.

www.bg-group.com 43

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

UK mmbbl

Atlantic

Basin mmbbl


mmbbl

Rest of World

mmbblTotal

mmbbl

As at 31 December 2010 151.4 9.8 322.9 461.7 945.8


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


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


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

UK mmbbl

Atlantic

Basin mmbbl


mmbbl

Rest of World

mmbblTotal

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

UK mmbbl

Atlantic Basin

mmbbl


mmbbl

Rest of World

mmbblTotal

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



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



44 Data Book 2014

EXPLORATION AND PRODUCTION: ESTIMATED NET RESERVES OF OIL

PRODUCING FIELDS

Gas production kboed

Oil and liquids production kboed

Total production 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.

www.bg-group.com 45

EXPLORATION AND PRODUCTION: FIELD INTERESTS

Country Interest detailsNumber

of blocks Type of fields(1)BG Group-

operatedBG Group

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










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

46 Data Book 2014

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

Country Interest detailsNumber

of blocks Type of fields(1)BG Group-

operatedBG Group

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

www.bg-group.com 47

EXPORT TERMINALS

TrainBG Group equity (%)

Total capacity

(mtpa) Gross

Total capacity (mtpa)

Net Status

Atlantic LNG 1 26.00 3.1 0.81 Since April 1999



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

(mtpa) Gross(1)

Total capacity (mtpa)

Net(1)

Total capacity (bcfd)

Net Status

Lake Charles, USA 13.1 13.1 1.8(2)

100% since 1 January 2004 Phase 2 expansion completed July 2006

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

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

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

48 Data Book 2014

LIQUEFACTION: FACILITIES CAPACITYAs at 31 July 2014

As at 31 July 2014

As at 31 July 2014

Q2 2014

Q1 2014

Q4 2013

Q3 2013

Q2 2013

Q1 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

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

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

Flexible fleet Various/Spot market 2005-20121 000 000-2 000 000 – – VC(5)

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

www.bg-group.com 49

LNG SHIPPING & MARKETING: CARGOES

As at 31 July 2014

As at 31 July 2014

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 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:

Rating agencyLong-term

ratingDate rating

assigned OutlookDate 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 OfficeEquiniti LimitedAspect House, Spencer RoadLancing, West SussexBN99 6DATel: 0871 384 2064+44 121 415 7029 (outside UK)www.shareview.co.ukEmail via https://help.shareview.co.uk

Stock Exchange InformationLondon Stock ExchangeTicker symbol: BG.LSEDOL number: 0876289

One ADR: one ordinary sharePink OTC Markets symbol: BRGYYAmerican Depositary Receipts

Deutsche Bank Trust Company Americasc/o American Stock Transfer & Trust Company6201 15th Avenue, Brooklyn NY 11219, USATel: +1 800 937 5449 (toll free for US residents)Tel: +1 718 921 8124 (outside USA)www.adr.db.comEmail: [email protected]

ISSUED SHARE CAPITAL AND DIVIDEND HISTORY

50 Data Book 2014

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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BG Group plc100 Thames Valley Park DriveReading, Berkshire RG6 1PTUnited Kingdom

www.bg-group.com

Registered in England & Wales No. 3690065

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