2006 Data Book (PDF) - BG Group

Building our portfolio 

for long-term growth 

BG Group 

Data Book 2006 


Natural gas is our business. 

We are a rapidly growing company, 

with expertise across the gas 

chain. Our vision is to be the 

leading natural gas company 

in the global energy market – 

operating responsibly and 

delivering outstanding value 

to our shareholders. 

Contents 

1 Overview 

4 Europe and Central Asia 

14 South America 

19 Asia Pacific 

25 Mediterranean Basin and Africa 

33 North America and the Caribbean 

39 Statistical Supplement

Contents 

EUROPE AND CENTRAL ASIA 

NW Europe Downstream 4 

UK Upstream 6 

Norway 10 

Italy 11 

Kazakhstan 12 

SOUTH AMERICA 

Argentina and Uruguay 14 

Bolivia 15 

Brazil 17 

ASIA PACIFIC 

India 19 

China, Malaysia and Singapore 21 

Philippines 22 

Thailand 23 

Oman 24 

MEDITERRANEAN BASIN AND AFRICA 

Egypt 25 

Israel and areas 

of Palestinian Authority 28 

Algeria, Libya and Madagascar 29 

Mauritania 30 

Nigeria 31 

Tunisia 32 

NORTH AMERICA AND THE CARIBBEAN 

Canada and Alaska 33 

Trinidad and Tobago 34 

United States of America 37 

STATISTICAL SUPPLEMENT 

Social & Environment Data 41 

Group Financial Data 42 

Exploration and Production 45 

LNG 50 

Transmission and Distribution 51 

Power 51 

Corporate Information 53 

Definitions 54 

For more information: www.bg-group.com 

Key to assets 

Exploration and Production (E&P) 

BG Group explores, develops, produces and markets 

gas and oil around the world. Around 73% of 2005 

production was gas. The Group uses its technical, 

commercial and gas chain skills to deliver projects 

at low cost, whilst maximising the sales value 

of its hydrocarbons. 

Liquefied Natural Gas (LNG) 

BG Group’s LNG activities combine the development 

of LNG liquefaction and regasification facilities with 

the purchasing, shipping and sale of LNG. The Group 

uses its expertise in LNG to connect its own and 

other producers’ gas reserves to markets. 

Transmission and Distribution (T&D) 

BG Group’s T&D expertise and activities develop 

markets for natural gas and provide them with 

supply from its own and others’ reserves through 

transmission and distribution networks and 

complementary businesses. 

Power 

A large proportion of the worldwide demand for 

gas is attributable to power stations. BG Group 

develops, owns and operates gas-fired power 

generation plants. 

Other activities 

BG Group leverages its distribution customer base to 

develop complementary businesses that stimulate 

gas demand. These include compressed natural gas 

for vehicles and co-generation. 

Key to maps 

Gas 

Oil 

Gas and oil/condensate 

Gas pipeline 

Pipeline – proposed or under construction 

Oil pipeline 

Pipeline – proposed or under construction 

BG Group-operated block 

BG Group non-operated block 

BG Group equity field/asset/licence 

BG Group’s global operations 

NORTH AMERICA AND THE CARIBBEAN 

BG Group is a major gas producer in Trinidad and 

Tobago, supplying both the domestic market and 

exporting gas as LNG to the USA and Europe from its 

participation in four liquefaction trains. BG Group holds 

all the rights to the current and planned regasification 

capacity at one of the largest LNG import terminals 

in the USA – Lake Charles, Louisiana. BG Group has 

further regasification capacity rights at the Elba Island 

LNG import terminal in Georgia, USA, and operates 

a shipping fleet to service its LNG business. BG Group 

also owns producing and prospective E&P assets in 

Alaska and Canada. 

BG Group holds the controlling stake in the 

largest natural gas distribution company in 

Brazil – Comgas in São Paulo. BG Group sells 

gas in Bolivia and Brazil, and supplies liquids 

markets in Bolivia, from Bolivian reserves. 

BG Group also holds interests in 14 exploration 

blocks on- and offshore Brazil and in the 

transmission pipelines from Bolivia to Brazil 

and Argentina to Uruguay. The Iqara subsidiary 

in São Paulo provides compressed natural gas, 

co-generation and related services in the states 

of São Paulo and Rio de Janeiro. 

Production in this region is principally from 

Egypt, where it has increased dramatically in 

recent years, and from Tunisia, with exploration 

acreage in Algeria, Israel and areas of Palestinian 

Authority, Libya, Madagascar, Mauritania and 

Nigeria. LNG exports from Egyptian LNG 

commenced in the second quarter 2005. 

BG Group also has long-term agreements to 

buy LNG from Egypt, Equatorial Guinea and 

Nigeria to supply the USA and Europe. 

EUROPE AND CENTRAL ASIA 

SOUTH AMERICA MEDITERRANEAN BASIN AND AFRICA ASIA PACIFIC 

With interests in over 20 UK Continental Shelf (UKCS) 

fields, BG Group has a significant offshore E&P business 

in the UK and has built a portfolio of 23 licences in 

Norway. BG Group’s downstream activities in the 

region encompass gas marketing, gas transmission and 

power generation. BG Group is also jointly developing 

a LNG import and regasification facility in Wales. In 

Italy, BG Group is developing the Brindisi LNG import 

and regasification facility and has interests in E&P and 

power plants. In Kazakhstan, the giant Karachaganak 

oil and gas condensate field accounted for 19% of 

BG Group’s production in 2005. 

In the expanding Indian gas market, BG Group 

has a growing E&P business and has interests 

in two gas distribution companies, Gujarat Gas 

in Gujarat, and Mahanagar Gas in Mumbai. 

BG Group also has power generation businesses 

in Malaysia and the Philippines, together with 

gas and condensate production in Thailand and 

exploration acreage in Oman and offshore China.

BG Group – the integrated gas major 

E&P Production (‘000 boed) 

Production volumes have grown at a 

CAGR of 9% between 2003 and 2005 

700 

600 

500 

400 

300 

200 

100 

0 

428 

457 

03 04 05 06 

Actual gas 

Actual oil and liquids 

Target 

504 

T&D Throughput (bcma) 

Volume throughput has increased by 

3% per annum on a compound basis 

since 2003 

16 

12 

8 

4 

0 

12.5 

13.4 

13.2 (a) 

600 

11.7 (b) 

03 04 05 06 

Actual 

Target 

(a) Reduction due to sale of Premier 

Transmission Limited (PTL) 

(b) Previous target of 14 bcma has been 

amended to allow for disposal of PTL 

and reduced holding in MetroGAS 

Increased Exploration Acreage 

Access to resources is a key issue 

facing the industry. In the first half 

of 2006, BG Group made important 

discoveries in Egypt and the UK. In 

the 18 months from the start of 

2005, the Group also increased its 

exploration portfolio by over 

100 000 sq km gross, enhancing 

existing positions in Brazil, Canada, 

Egypt, India and the UK and entering 

Algeria, China, Libya, Madagascar, 

Nigeria, Oman and Alaska. 

LNG Production (mtpa) 

LNG production has grown 21% 

per annum on a compound basis 

since 2003 

8 

7 

6 

5 

4 

3 

2 

1 

0 

2.8 

Actual 

Target 

3.2 

4.1 

7.1 

03 04 05 06 

Power Capacity (GW) 

3.0 

2.5 

2.0 

1.5 

1.0 

0.5 

0.0 

2.5 

Actual 

Target 

2.8 

2.8 

2.8 

03 04 05 06 

E&P: Reserves and resources 

Total operating profit (£m) 

CAGR 40% 1997-2005 

2500 

2000 

1500 

1 000 

500 

160 

330 

229 

888 

833 

688 

1513 

1279 

0 

97 98 99 00 01 02 03 

04 

2 380 

05 

E&P 

T&D, LNG, Power & Other 

Continuing operations excluding disposals 

and certain re-measurements. Results 

prior to 2003 stated under UK GAAP 

Total operating profit includes BG Group’s 

share of pre-tax operating results from 

joint ventures and associates 

2005 Production (mmboe) 

UK 55 

Egypt 35 

Kazakhstan 35 

Trinidad and Tobago 18 

Tunisia 13 

India 9 

Thailand 9 

Bolivia 6 

Canada 3 

Cumulative 

reserves/ Reserves/ 

resource Production* 

mmboe years 

Risked Exploration (2 440 mmboe) 7 071 38 

Unbooked Resources (1 211 mmboe) 4 631 25 

Probable Reserves (1 236 mmboe) 3 420 19 

SEC Proved Reserves 2 184 12 

As at 31 December 2005 

*Based on 2005 production of 183.8 mmboe 

1 

GROUP OVERVIEW

2 

GROUP OVERVIEW 

BG Group – the integrated gas major continued 

Import capacity – 2010 

(mtpa) 

25 

20 

15 

10 

5 

0 

BG 

GN/Repsol 

GdF 

QP 

Shell 

Total 

Statoil 

ConocoPhillips 

Chevron 

Anadarko 

Eni 

Liquefaction capacity – 2010 

(mtpa) 

12 

9 

6 

3 

0 

Market leader in Atlantic Basin LNG 

ExxonMobil 

BG 

Total 

BP 

Shell 

ConocoPhillips 

Eni 

Repsol 

Tractebel 

Union Fenosa 

ExxonMobil 

Marathon 

BG Group’s upstream performance 

continues to rank top quartile. The 

Group again ranked highly in finding 

and development (F&D) costs and unit 

Three year Finding and 

Development costs ($/boe) 

2003-2005 ranking 

$0 $2 $4 $6 $8 $10 $12 $14 


Peers 

Source for both charts: BG based on Wood Mackenzie data 

Top quartile E&P performance 

In the last 10 years, BG Group has 

developed a leading position in Atlantic 

Basin LNG. BG Group has access to 

markets on both sides of the Atlantic 

and a portfolio of equity and contracted 

supply. Access to markets remains key 

BALANCING GROWTH OF MARKETS AND SUPPLIES 

ELBA ISLAND PROVIDENCE 

MILFORD HAVEN 

LAKE CHARLES BRINDISI 

ATLANTIC LNG 

Train 1 

Train 2 

Train 3 

Train 4 

Train X 

CHILE LNG 

ONSTREAM 

IN DEVELOPMENT 

SHIPPING 

Annual unit operating cost ($/boe) 

2005 results 

$0 $2 


Peers 

$4 $6 $8 $10 

NIGERIA LNG 

BRASS LNG 

EQUATORIAL 

GUINEA 

OKLNG 

operating cost also remained top 

quartile during 2005. The Group’s track 

record on cost control is matched by its 

history of exploration success feeding 

and the company is expanding its capacity 

in the US and Europe. BG Group continues 

to develop its supply portfolio through 

new projects in Nigeria and expansions 

in Trinidad and Tobago and Egypt. 

EGYPTIAN LNG 

Train 1 

Train 2 

Train 3 

DAMIETTA 

Source for all three charts: Evaluate Energy 2006, BG Group. Peer Group includes Super Majors, US and European Integrated Majors 

Three year proved reserve 

replacement rate (%) 

2003-2005 ranking 

EXPORTS 

PURCHASE 

IMPORTS 

through to another strong performance 

for three year reserve replacement ratio 

2003-2005. 

-60% 0% 


Peers 

60% 120% 180% 240%

E&P: PRODUCTION 

BG net production (’000 boepd) 

1 000 

800 

600 

400 

200 

0 

2005A 

2006 

GLOBAL LNG SUPPLY 

BG supply (mtpa) 

30 

25 

20 

15 

10 

Long-term growth 

2 

0 

2004A 

2005A 

CAGR 6-10% 2005-12 

CAGR 5-7% 2006-09 

MEDIUM-TERM 

2007-09 

2009 

CAGR 20-25% 2005-12 

Overall 2012 outcome of 24-30 mtpa 

CAGR 28% 2005-09 


SUMMARY OF GROWTH PROJECTS 

2009 

LONG-TERM 

2010-12 

2007-2012 Key projects & opportunities 

Key developments on stream 2007-09 

• Hasdrubal 

• Karachaganak 

• Panna/Mukta/Tapti 

• Dolphin 

• Dragon 

• Brindisi LNG 

• Lake Charles (fuel savings/NGLs) 

• LNG long-term firm supply 

• LNG ships 

• Comgas 

• Exploration capex 

Investment £4.8 billion 

2012 

2012 

MEDIUM-TERM 2007-09 

Key projects: 

Buzzard 

Hasdrubal 

Karachaganak 

Dolphin 

Panna/Mukta/Tapti 

At 2006 reference conditions. Growth is not linear 

SUPPLY OPTIONS 

• Brass 

• OKLNG 

• ELNG Train 3 

Planned 

Spot 

Other firm supply 

Long-term firm supply* 

*For details refer to page 50 

At 2006 reference conditions. Growth is not linear 

Key opportunities 2010-12 

LONG-TERM 2010-12 

Key opportunities: 

Karachaganak expansion 

Bongkot South 

UK 2005/06 discoveries 

Manatee 

Gaza Marine 

Margarita full-field 

Risked exploration 

• New Trinidad 

• Further Nigeria 

• Algeria 

• Spot 

• Karachaganak expansion 

• Bongkot South 

• UK 2005/06 discoveries 

• Manatee 

• Gaza Marine 

• Margarita full-field 

• OKLNG 

• Elba expansion 

• New Trinidad LNG train 

• ELNG Train 3 

• Comgas expansion 

• Exploration and Business Development risked outcome 

Investment £6-7 billion 

3 

GROUP OVERVIEW

4 

NW EUROPE DOWNSTREAM 

Europe and Central Asia 

NW Europe Downstream 

New information 

• Phase 1 Interconnector import 

flow expansion completed 

Key dates 

1997 Premier Power Limited converted 

from oil to natural gas 

1998 Interconnector between UK and 

Belgium became operational 

2000/ Seabank Phases 1 and 2 

2001 entered full operation 

2003 Completion of 600 MW CCGT 

plant at Premier Power 

2005 Interconnector import flow 

expansion Phase 1 completed 

2006 Interconnector import flow 

expansion Phase 2 expected 

to be operational 

Shareholders Dragon LNG (%) 

BG Group 50 

PETRONAS 30 

Petroplus 20 

IRISH SEA 

BG Group’s NW Europe Downstream 

activities encompass power generation, 

gas transmission and energy marketing. 

The Group is also jointly developing 

a LNG import and regasification facility 

at Milford Haven, Wales (see page 11). 

After purchasing Premier Power in 1992, 

BG Group converted the plant to gas, 

which supported the development of 

the gas interconnector from Scotland 

to Northern Ireland. 

Elsewhere in the NW Europe region, 

BG Group has a stake in the Seabank 

power station and in the UK-Continent 

Interconnector pipeline. 

BG Group sells gas on a wholesale basis at 

beach terminals and ships gas to the UK 

National Balancing Point. Sales are under 

short-, medium- and long-term contracts. 

BG Group also exports gas for sale to and 

purchases gas for import from mainland 

Europe, via the Interconnector. 

PREMIER POWER LIMITED 

The Ballylumford power station, near 

Larne, has a potential maximum capacity 

of 1 316 MW. The power station is gas-fired 

with dual fuel capability and is owned 

and operated by Premier Power Limited, 

a wholly owned subsidiary of BG Group. 

The 600 MW CCGT plant was commissioned 

in 2003 on a brown field site adjacent 

ABERDEEN 

Further information on Premier Power Limited can be found on its website, www.premier-power.co.uk 

LARNE 

Premier Power 

BELFAST 

Dragon LNG, 

Milford Haven 

Seabank 

TEESSIDE 

UK 

THEDDLETHORPE 

Microgen 

READING 

BACTON 

PETERBOROUGH 

Interconnector 

LONDON 

ZEEBRUGGE 

to the existing Ballylumford plant. CCGT 

technology is significantly more efficient 

than a conventional generating plant, 

giving around 40% more electricity from 

the same amount of gas. 

SEABANK POWER LIMITED 

Built in two phases, Seabank is a 

1 130 MW CCGT power station near 

Bristol. It is owned and operated by 

Seabank Power Limited, a 50:50 joint 

venture between BG Group and Scottish 

and Southern Energy. Phase 1 of Seabank 

(750 MW) entered full commercial 

operation in March 2000 and Phase 2 

(380 MW) in January 2001. 

INTERCONNECTOR (UK) LIMITED 

BG Group has a 25% shareholding in 

Interconnector (UK) Limited, which 

developed the pipeline that links the 

UK and Continental European gas 

transmission systems. All the capacity 

in the Interconnector has been sold 

on long-term contracts until 2018. 

Interconnector (UK) Limited manages 

and operates the asset for its shippers 

and shareholders. 

The pipeline, which runs from Bacton in 

England to Zeebrugge in Belgium, has 

been fully operational since October 1998. 

Up to 745 bcf (20 normal bcm) natural 

gas per year can be transported from

the UK through the 230 km 40-inch 

diameter sub-sea pipeline to a reception 

terminal at Zeebrugge and then into the 

Continental European grid. In addition, 

the pipeline’s Phase 1 reverse flow import 

capacity expansion from 317 bcf (8.5 

normal bcm) to 615 bcf (16.5 normal bcm) 

became operational on 8 November 2005. 

The second phase, designed to boost 

the UK import capacity to 876 bcf 

(23.5 normal bcm), is expected to be 

available from December 2006. BG Group 

uses its own capacity for long-, mediumand 

shorter-term sub-lets to third parties 

and also ships gas to take advantage of 

market price differentials between the 

ends of the pipeline. 

Interconnector (UK) Limited is 

contemplating a further expansion to 

increase import capacity by around 75 bcf 

(2 normal bcm) to around 24.2 bcf 

(25.5 normal bcm), which could be 

available before the end of 2007. 

ENERGY MARKETING 

In 2005, BG Group produced 6.2 bcm of 

gas from the UK Continental Shelf (UKCS), 

approximately 6% of the UK’s gas 

demand. The Group sells its UKCS gas 

on a wholesale basis at the entry to the 

NTS and ships gas on the NTS to sell at 

the National Balancing Point under long-, 

medium- and short-term contracts. 

BG Group is an active participant in 

the NTS entry capacity auctions held 

by National Grid and the on-the-day 

commodity market and other electronic 

trading systems that help shippers balance 

their daily supply and demand. BG Group 

further optimises its portfolio through the 

use of rented gas storage capacity. 

DRAGON LNG 

In December 2004, BG Group and partners 

announced the signing of shareholder and 

other related agreements confirming their 

commitment to develop a £250 million 

LNG import terminal at Milford Haven 

in Wales. The agreements confirm the 

ownership of the terminal (BG Group 50%, 

Petronas 30% and Petroplus 20%), as 

well as the 20 year arrangements 

governing the use of capacity rights 

(BG Group 50%, Petronas 50%) allowing 

BG Group and Petronas each to send 

out 3 bcm (106 bcf) gas per year, from 

around 2.2 mtpa LNG. 

Dragon LNG is progressing with the 

construction of the terminal, which 

is scheduled to be operational in the 

fourth quarter of 2007. 

NEW BUSINESS 

Microgen is an innovative energy system 

being developed by BG Group for 

individual homes and small businesses. 

Microgen generates heat for water and 

space heating and simultaneously produces 

electricity, reducing use of externally 

generated power. The typical per-household 

carbon dioxide emissions reduction from 

replacing a conventional boiler with 

Microgen is expected to be 1.5 tpa and 

consumers should see significant 

reductions in their electricity bills. 

BG Group has established a website to facilitate its short-term capacity sales, www.bg-ezeecapacity.com 

Further information can be found at www.interconnector.com and www.dragonlng.co.uk 

Interconnector capacity (year end) 

(normal bcma) 

25 

20 

15 

10 

5 

0 

20 

8.5 

20 

16.5 

20 

2004 2005 2006 

Capacity per annum actual 

Reverse flow capacity actual 

Capacity per annum projected 

Reverse flow capacity projected 

23.5 

Shareholders Interconnector (%) 

BG Group 25.00 

E.ON Ruhrgas 23.59 

Distrigas 16.41 

ConocoPhillips 10.00 

Gazprom 10.00 

Total 10.00 

Eni 5.00 

5 

NW EUROPE DOWNSTREAM

6 

UK UPSTREAM 


UK Upstream 


• North West Seymour, Glenelg and 

Atlantic/Cromarty fields onstream 

Key dates 

1997 Armada began production 

1999 ECA Phase 1 first gas 

2001 Blake first oil 

2002 ECA Phase 2 first gas 

2003 Seymour first gas 

2006 Atlantic/Cromarty onstream Q2 

Buzzard first oil planned 

Partners Armada (%) 

BG Group (operator) 46.77 

BP 18.20 

Total 12.53 

ConocoPhillips 11.45 

Centrica 11.05 

With interests in over 20 UK Continental 

Shelf (UKCS) fields, BG Group has one 

of the most significant exploration and 

production businesses in the offshore 

waters of the UK. On the UKCS, BG Group 

operates the Armada fields (Fleming, 

Drake and Hawkins), the Maria field and 

the Seymour field in the central North 

Sea, the Blake and Atlantic fields in the 

Outer Moray Firth, and the Neptune, 

Mercury, Minerva and Apollo fields in the 

Easington Catchment Area (ECA) in the 

southern North Sea. 

BG Group believes there is significant 

remaining potential in the UKCS and 

is actively pursuing opportunities both 

around infrastructure hubs and by 

extending out from existing core areas. 

IRISH SEA 

In addition to the core production hubs 

and exploration and appraisal interests on 

the UKCS, BG Group has a 51.18% interest 

in the Central Area Transmission System 

(CATS) offshore pipeline and onshore 

processing facilities, and a 7.86% stake in 

the Shearwater Elgin Area Line (SEAL). 

PRODUCING ASSETS 

Amethyst 

BG Group has a 24.15% interest in the 

BP-operated Amethyst field located in the 

southern North Sea. Amethyst East started 

production in October 1990 and Amethyst 

West in October 1991. The development’s 

four offshore platforms are unmanned 

with production being controlled via the 

onshore terminal facilities. 

SULLOM VOE 

FLOTTA 

TEESSIDE 

ST. FERGUS 

ABERDEEN 

UK 

READING 

2 

NORTH SEA 

1 

THEDDLETHORPE 

LONDON 

BACTON 

Production is exported via a dedicated 

30-inch diameter line from the A2D 

platform 40 km to the Easington terminal, 

where it is processed. The average daily 

rate in 2005 was 48 mmscfd. 

Amethyst gas is sold under a life 

of field contract. 

Armada/Seymour 

The BG Group-operated Armada gas 

condensate fields (Fleming, Drake and 

Hawkins) (46.77% BG Group equity) extend 

over 31 sq km and span five exploration 

blocks. Production began in October 1997, 

following the successful completion of the 

Phase 1 project (facilities plus eight wells) 

on schedule and at a gross project cost 

of £437 million, some £100 million below 

the original budget. 

Completed in September 2002 at a gross 

cost of £76 million, the Armada Phase 2 

drilling programme added a further 

three wells, extending the production 

plateau and lengthening field life. An 

average rate of 170 mmscfd and 6 400 bpd 

was achieved in 2005. 

The SW Seymour area of the BG Groupoperated 

Seymour field (57% BG Group 

equity) was appraised successfully and 

drilled from the Armada platform in 2002. 

The gross project costs were £23 million. 

First production was achieved on 

15 March 2003 and an average rate 

of 48 mmscfd and 1 500 bpd was 

achieved in 2005. 

3

A second well drilled in 2004 into the NW 

Seymour area was brought on production 

in April 2006. This well produces black oil 

across the Armada platform, the first time 

this has occurred. 

The commingled stream of Armada and 

Seymour gas is exported via the CATS 

pipeline to Teesside. Liquids are transported 

through the Forties Pipeline System 

(Forties) to the Kinneil processing plant 

at Grangemouth. 

Atlantic/Cromarty 

BG Group has a 75% interest in the 

Atlantic discovery (Block 14/26a) in the 

Outer Moray Firth. BG Group also holds 

10% in the adjacent Cromarty discovery in 

Block 13/30a. The joint Atlantic/Cromarty 

development received DTI approval in 

December 2003. The fields have been 

developed with three wells and a long 

sub-sea multiphase flow pipeline, the 

Western Area Gas Evacuation System 

(WAGES), tied into the SAGE terminal at St 

Fergus. Total investment was £235 million. 

Production began in June 2006, with an 

expected plateau rate of 220 mmscfd. 

Blake and Blake Flank 

BG Group has a 44% interest in, and is 

operator of, the Blake field. The field is 

located 100 km from Aberdeen in the 

Outer Moray Firth. First production was 

achieved in June 2001, just 18 months 

after sanction, and the project was 

delivered 10% under budget. 

The field was developed in two phases. 

The first phase was the Blake Channel, 

which is a sub-sea development of six 

producing wells and two water-injection 

wells, tied back to an existing floating 

production, storage and offloading 

(FPSO) vessel located over the Ross 

field some 9.5 km away. 

Development of the second phase, Blake 

Flank, was completed and production 

commenced from two wells in the second 

half of 2003. This sub-sea development 

is tied back through the existing Blake 

facilities to the Ross FPSO vessel. An 

average total field rate of 25 500 bpd 

was achieved in 2005. 

ECA 

The Neptune, Mercury, Minerva, Apollo, 

Wollaston and Whittle gas fields in the 

southern North Sea are collectively 

referred to as the ECA. 

Neptune and Mercury are BG Groupoperated 

and were developed as the 

first phase of the ECA project. The DTI’s 

approval for the project was received 

in November 1998 and first production 

commenced just 13 months later 

in December 1999. 

1 

2 

3 

FLAGS 

ST. FERGUS 

ABERDEEN 

Faroe Island Licence 

Minerva 

Mercury 

EASINGTON 

Amethyst 

FRIGG 

SAGE 

BRITANNIA 

FORTIES 

FULMAR 

NORTH SEA 

Bedlington 

SHETLAND 

ISLANDS 

FLOTTA 

Atlantic 

Blake 

Cromarty 

Buzzard 

LANGELED 

ST. FERGUS 

THEDDLETHORPE 

SULLOM VOE 

Glenelg 

Franklin 

Judy/Joanne 

BACTON 

FLAGS 

BRENT 

SAGE 

Neptune 

Apollo 

SEAL 

LANG ELED 

BRITANNIA 

FORTIES 

FULMAR 

CATS 

NINIAN 

FRIGG 

NORTH 

SEA 

SEAL 

CATS 

NORTH SEA 

Maria 

Armada 

Seymour 

Everest 

Lomond 

Elgin 

Jade 

Armada 

Everest 

UK-Continent 

Interconnector 

7 

UK UPSTREAM

8 

UK UPSTREAM 


UK Upstream continued 

Partners Seymour (%) 

BG Group (operator) 57 

Total 25 

Centrica 18 

Partners Blake (%) 


Talisman 53.6 

Petro Summit 2.4 

Partners Buzzard (%) 


Nexen (operator) 43.21 

PetroCanada 29.89 

Dyon 5.16 

Figures rounded to 2 decimal places 

The ECA Phase 1 facilities consist of a 

sub-sea production system at Mercury, 

a normally unmanned platform at 

Neptune, the ECA Riser Tower platform 

installed adjacent to the existing 

BP-operated Cleeton facilities and 

pipelines connecting the platforms 

and production systems. 

The Mercury sub-sea wells are tied back 

via a manifold and pipeline to the 

Neptune platform. The fluids produced 

from Mercury are commingled with fluids 

from the Neptune production wells before 

export to Cleeton for final separation, 

metering and transmission into the 

Southern North Sea Pipeline System 

infrastructure to the Dimlington 

processing terminal. BG Group holds 

73.33% in Mercury and 79% in Neptune. 

Phase 2 of the ECA project consists of the 

BG Group-operated Minerva Hub fields, 

Minerva and Apollo (BG Group 65%), and 

the BP-operated Whittle Hub Fields, 

Wollaston and Whittle (BG Group 30.77%). 

Making use of the existing ECA 

infrastructure, the ECA Phase 2 facilities 

consist of a normally unmanned platform 

at Minerva and a sub-sea production 

manifold at Apollo, tied back to the 

Minerva platform. The platform exports 

all production to the ECA Riser Tower. 

The Wollaston and Whittle Field wells 

are tied back via a manifold and pipeline 

directly to the ECA Riser Tower. All 

production from the Minerva and Whittle 

Hubs is then commingled with Neptune 

and Mercury production at Cleeton. 

First production from the Whittle Hub 

commenced on 31 December 2002, with 

first production from the Minerva Hub 

following shortly after, in early January 

2003. A combined average production 

rate of 215 mmscfd was achieved by 

ECA during 2005. 

Elgin/Franklin Area 

The Elgin/Franklin high pressure and 

high temperature (HPHT) gas condensate 

fields are located in the central North Sea. 

Following their £1.7 billion (gross) joint 

development, the fields began production 

in 2001. 

A total of 12 wells, six each in Elgin and 

Franklin, produced at an average rate of 

514 mmscfd and 116 000 bpd during 2005. 

Total operates the Elgin/Franklin fields in 

which BG Group has a 14.11% interest. 

Development sanction for the HPHT 

Glenelg field (BG Group 14.7%), in Block 

29/4d, was given by the DTI in July 2004. 

The field has been developed through a 

single high departure well drilled from the 

Elgin wellhead platform. The Glenelg well 

started production in March 2006. 

Elgin/Franklin and Glenelg gas is exported 

through SEAL, a common export pipeline 

shared with the nearby Shell-operated 

Shearwater field, to the onshore gas 

reception facilities at Bacton in Norfolk. 

Gas then flows into the NTS or via the 

Interconnector into Europe. Liquids are 

exported through Forties to the Kinneil 

processing plant at Grangemouth. Gas 

and liquids from West Franklin will follow 

the same export routes. 

Everest and Lomond 

Also situated in the central North Sea are 

the BP-operated Everest and Lomond 

fields in which BG Group holds 

respectively a 58.31% and 61.11% interest. 

The fields were developed in parallel, with 

first production in May 1993. 

In 2001, two additional wells were added 

to each of Everest and Lomond as part of 

the four well Phase 2 programme. These 

wells extended plateau production levels 

and accessed reserves in South Everest. 

Drilling of two further wells is planned 

for Everest commencing in the third 

quarter of 2006. 

A combined average production rate 

of 248 mmscfd and 6 000 bpd was 

achieved in 2005. Everest and Lomond 

gas is exported via the CATS pipeline and 

is sold to Teesside Power Limited under 

a long-term contract. Produced liquids 

go via Forties to Kinneil. 

J-Block and Jade 

The ConocoPhillips-operated Judy/Joanne 

(J-Block) (gas condensate/oil) and Jade 

(gas condensate) fields are located in the 

central North Sea. BG Group has a 30.5% 

interest in J-Block and a 35% interest in 

Jade. Production began from J-Block in 

July 1997 and from Jade in February 2002. 

The 2005 combined average production 

rate from the fields was 362 mmscfd and 

40 200 bpd. 

Jade was developed using a normally 

unmanned wellhead platform and 

currently produces from six wells. The 

Jade South West exploration well, drilled 

from the Jade platform, was successful 

and was brought on production during 

June 2006. 

Production from Jade is exported via 

a sub-sea pipeline to the manned Judy 

platform where it is commingled and 

processed with Judy and Joanne 

production. The combined gas stream 

is then exported via the CATS pipeline 

to Teesside and the combined liquids 

stream exported via Norpipe to the 

Norsea oil terminal at Teesside. 

The Judy/Joanne fields currently produce 

from 13 wells. A further successful 

development well was drilled in the

second quarter of 2006 and another 

development well was spudded in July 

2006. A successful Jade exploration well 

was drilled in the second quarter of 2006. 

DEVELOPMENT FIELDS 

Buzzard 

The Buzzard oil discovery, located in the 

Outer Moray Firth, 100 km north-east of 

Aberdeen, was announced in June 2001. 

A six-well appraisal programme was 

completed in June 2002. The discovery 

was made in an area covered by two 

adjacent licences in which the partners 

had different equity stakes. However, an 

agreement between the owners was 

reached that equalised their interests 

in the two licences and resulted in 

BG Group holding a 21.73% interest in 

the Buzzard field and the surrounding 

exploration acreage. 

In November 2003, the development plan 

for the field was approved by the DTI. 

With a forecast peak production of 

190 000 bpd, the field is believed to be 

one of the largest discovered in the North 

Sea for over ten years. The total estimated 

proved and probable reserves are around 

500 mmboe. 

The facilities will consist of a three-bridge 

linked platform complex with oil export 

via Forties and gas via the Frigg system. 

The wellhead deck and the three jackets 

were installed in the summer of 2005. 

Pre-drilling of the production wells 

commenced in October 2005. Both the 

main process deck and the utilities and 

quarters deck were installed in June 2006. 

First production is anticipated by the 

end of 2006, with peak annual production 

in 2008. 

Maria 

In December 2003, BG Group assumed 

operatorship, on behalf of a consortium 

with Total and Centrica, of the fallow 

Maria 16/29a-11Y discovery. An appraisal 

well drilled in September 2004 identified 

a 900-foot oil column and confirmed the 

viability of the Maria discovery. Sidetrack 

drilling then confirmed an extension into 

the adjacent Maria Horst prospect. 

Production from Maria will be tied back 

to Armada, with gas exported via CATS to 

Teesside and liquids through Forties to the 

Kinneil processing plant at Grangemouth. 

Recoverable reserves for Maria and Maria 

Horst are estimated to be in the region of 

30 mmboe. First production is scheduled 

for early 2007. 

UKCS EXPLORATION 

In the 23rd Licensing Round in 2005, 

BG Group was awarded an interest in, 

and operatorship of, a total of four blocks, 

three in the Moray Firth close to the Blake, 

Buzzard and Atlantic/Cromarty fields 

(13/21c, 20/2b and 20/3d) and one in the 

Central North Sea close to the Everest 

platform (22/8a). A new 3D seismic shoot 

was successfully concluded over the 

Greater Armada area. 

BG Group has acquired a number of 

additional interests in exploration acreage 

including Blocks 14/28b and 22/30a. 

BG Group is undertaking a significant 

drilling campaign that, over the course 

of 2005/2006, should deliver a total 

of 16 exploration and appraisal wells. 

OFFSHORE PIPELINES 

CATS 

BG Group has a 51.18% interest in the CATS 

pipeline and terminal, which is operated 

by BP. The 404 km 36-inch diameter CATS 

offshore pipeline became operational in 

1993 and now transports gas to Teesside 

from the Everest, Lomond, Andrew, 

Armada, Seymour, Judy, Joanne, Jade, 

Erskine, Banff and Eastern Trough Area 

Project (ETAP) fields (all in the central 

North Sea). The pipeline has a peak gas 

capacity of around 1 700 mmscfd. 

Onshore, the CATS Teesside terminal 

includes two trains of gas processing 

equipment providing firm services to the 

Armada, Seymour, Erskine, ETAP and Banff 

fields. Train 1 became operational in 1997 

originally for Armada and Erskine and 

Train 2 was brought onstream in 1998 

for ETAP and Banff. The total processing 

capacity of the terminal is around 

1 200 mmscfd. 

The CATS owners have recently contracted 

additional business from the Maria and 

Montrose Arbroath fields. 

SEAL and SILK 

BG Group has a 7.86% interest in SEAL, a 

480 km long 34-inch diameter gas export 

pipeline to Bacton. The pipeline was 

completed in 2000 for the Elgin/Franklin 

and Shearwater fields. With capacity of 

around 1 150 mmscfd of NTS-quality dry 

gas, it has been transporting gas since 

May 2001. 

BG Group also has a 15.98% interest in the 

900 metre long 34-inch diameter SEAL 

Interconnector Link (SILK) pipeline that 

provides direct access from SEAL into the 

UK-Continent Interconnector pipeline. 

FAROE ISLANDS 

BG Group negotiated the transfer of its 

interest and remaining well obligation in 

Faroes Licence 001 to Licence 006 and is 

currently participating in the drilling of 

the Brugdan well, which spudded in July 

2006. Additional opportunities are also 

being evaluated. 

9 

UK UPSTREAM

10 

NORWAY 


Norway 


• Awarded 4 new licences in the 

Norwegian APA 2005 Licensing Round 

• Awarded 8 new licences in the 

19th Licensing Round 

• Acquired 2 licences in the 

Norwegian North Sea 

Key dates 

2005 Acquired 20% interest in PL 251 

from Statoil 

Acquired 80% interest and 

operatorship in PL 274BS 

from Dong 

Awarded 4 licences in APA 2005 

Licensing Round 

2006 Awarded 8 licences in the 

19th Licensing Round 

Partners PL335 (%) 


Lundin 18 

Talisman 18 

RWE 12 

PL396 

PL395 

PL393 

NORWAY 

UK 

PL392 

PL324 

PL325 

PL388 

PL251 

PL372BS 

PL374S 

PL373S 

PL274BS 

BG Group entered Norway in 2004 with the 

award of PL297 in the North Sea. The Group 

now has 23 licences (13 as operator) gained 

through licensing rounds and acquisitions. 

The acreage lies in four core areas and in 

some cases was gained as a result of the 

Group’s experience and expertise across 

the border in the UK. BG Group expects 

to drill its first operated wells in 2007. 

Southern North Sea 

(8 licences, 4 operated) 

This was BG Group’s entry point into 

Norway. Geologically it is an extension of 

the UK Central North Sea and the Group 

has drawn upon this experience and 

expertise in acquiring and working the 

acreage. Many of the plays are similar 

to those matured and producing in the 

UK, ranging from relatively shallow and 

conventional plays to more challenging 

high pressure/high temperature 

prospects. BG Group expects to drill 

two operated wells in this area, the 

first on PL335 in 2007. 

North Tampen 


This is a new core area for BG Group in 

Norway, established with awards in the 

2005 APA and the 19th Licensing Round. 

The area is a structural extension of the 

prolific Tampen Spur area. BG Group 

will acquire 3D seismic in 2006, with 

an exploration well scheduled for 2007. 

Proposed 

Ormen Lange 

Pipeline 

PL372S 

PL391 

PL382 

PL390 

KRISTIANSUND 

NYHAMNA 

NORWAY 

HAUGESUND 

STAVANGER 

PL337 

PL292 

PL335 

PL143, PL143CS & 298 

PL297 

SWEDEN 

Mid-Norway 


BG Group now holds a significant position 

in this deep water area, with depths 

ranging from 400 to 1 500 metres. The 

area is predominantly gas prone and, like 

the southern North Sea, synergies with 

existing UK production are being explored. 

BG Group’s first exploration well in 

Mid-Norway on Statoil-operated PL251 

Tulipan was drilled in 2005 and encountered 

small volumes of hydrocarbons (not 

commercial). The next well will be PL324 

Gemini, operated by Eni. In addition, 

BG Group will commence extensive 

3D seismic acquisition in 2007 on licences 

gained in the 19th Licensing Round. 

Barents Sea 


The Barents Sea is the latest core area 

for BG Group in Norway to be established 

with the award of three licences in the 

19th Licensing Round. Seismic acquisition 

is expected to commence in 2006/2007.


Italy 


• Italian authorities and European 

Commission confirmed 20% thirdparty 

access at Brindisi LNG 

• Construction of Brindisi LNG began 

Key dates 

1998 SERENE power stations 

began operation 

2004 Brindisi LNG EPC awarded 

Active in Italy since 1992, BG Group is 

further developing its gas chain capability. 

Italy is a major net importer of gas, a 

commodity upon which it is becoming 

increasingly dependent as the government 

focuses on environmentally friendly 

energy sources. BG Group is positioning 

itself within the Italian market to supply 

this rising demand. 

Current activity in Italy includes: LNG, 

where BG Group is building a LNG import 

terminal on the south-eastern coast; E&P, 

where BG Group holds six exploration 

permits and two applications; and Power, 

through a joint venture that owns and 

operates five power plants. 

LNG 

BG Group is building an 8 bcma (6 mtpa) 

LNG import terminal in the outer harbour 

of the port of Brindisi (BG Group 100%). 

The EPC contract was awarded in 

December 2004. Offsite works began 

early 2005, followed by onsite works in 

the second half of 2005, ready to receive 

first LNG by 2009. 

BG Group will have the rights to 80% of 

the capacity in the terminal on a priority 

basis, whilst the remainder will be subject 

to regulated third-party access. The 

terminal is strategically located to receive 

LNG from the Mediterranean and Atlantic 

Basins and the Gulf States. 

TURIN 

RIVALTA 

MILAN 

Po Valley 

MEDITERRANEAN SEA 

TUNISIA 

EXPLORATION 

BG Group is concentrating its Italian 

exploration and production activity 

on acreage in the Po Valley, where the 

Group holds six exploration permits 

(four operated) and two applications 

(both operated). 

BG Group resumed its operated 

exploration activity in 2005, with the 

acquisition of a large 3D seismic survey 

and the drilling of the Mignano-1 

exploration well. Although Mignano 

encountered good gas shows, the well 

was plugged and abandoned following 

an unsuccessful well test. 

The high pressure Robbio-1 exploration 

well is planned to spud in the third 

quarter of 2006. Robbio will be an 

important test of an under-explored play. 

BG Group is evaluating further drilling 

and seismic opportunities within the 

existing portfolio and from potential 

new licence applications. 

ITALY 

ROME 

POWER 

BG Group has a 33.68% interest in SERENE, 

a joint venture company that owns and 

operates approximately 400 MW of 

co-generation at five locations adjacent to 

Fiat Auto factories. Three 100 MW power 

stations are located at Melfi, Termoli 

and Cassino, with the 50 MW stations 

at Sulmona and Rivalta. The plants have 

SULMONA 

CASSINO 

NAPLES 

TYRRHENIAN SEA 

HUNGARY 

SLOVENIA 

CROATIA 

ADRIATIC SEA 

TERMOLI 

MELFI 

BOSNIA & 

HERZEGOVINA 

Planned regas facility 

BRINDISI 

IONIAN SEA 

been in operation for seven years and 

are located to supply steam to Fiat Auto 

plants. SERENE supplies nearly 3 000 GWh 

per year of electricity to the grid operator, 

GRTN, and 344 000 tons of steam 

primarily to Fiat. Fuel gas is supplied 

to the plants by Eni and Edison. 

SPAIN 

In September 2005, BG Group filed a 

formal proposal with the Ministry of 

Industry to relinquish all seven exploration 

licences offshore Spain, having fulfilled 

the exploration work programme. A formal 

response to the relinquishment proposal 

is expected in the third quarter of 2006. 

11 

ITALY

12 

KAZAKHSTAN 


Kazakhstan 


• Oil exports commenced via the 

Atyrau Samara pipeline 

• Over 70% of liquids exported through 

Caspian Pipeline Consortium (CPC) 

to world markets 

Key dates 

1996 Acquired 2% stake in 

restructured CPC 

1997 Karachaganak and North 

Caspian PSAs signed 

2001 CPC fully operational 

2003 First liquids from new 

Karachaganak facilities 

2004 Phase II Karachaganak 

development completed 

First exports via Novorossiysk 

2005 Completed sale of interest in 

North Caspian Sea PSA 

Partners Karachaganak (%) 

BG Group (joint operator) 32.5 

Eni (joint operator) 32.5 

Chevron 20.0 

LUKoil 15.0 

BLACK SEA 

NOVOROSSIYSK 

CPC 

BG Group has been active in Kazakhstan 

for more than a decade. It is joint 

operator of the giant Karachaganak 

gas condensate field in north-west 

Kazakhstan and a shareholder in the CPC. 

The CPC pipeline links reserves in western 

Kazakhstan to the Black Sea, providing 

access to world markets. 

KARACHAGANAK 

The Karachaganak field, discovered in 1979, 

is one of the world’s largest gas and 

condensate fields. Located in north-west 

Kazakhstan, it holds estimated gross 

reserves of over 2.4 billion bbls condensate 

and HIIP 9 billion bbls condensate and 

48 tcf gas. 

Since the signing of the Final Production 

Sharing Agreement (FPSA), (November 

1997 but effective 27 January 1998), the 

Karachaganak owners have invested in 

wells, facilities and pipelines, which 

achieved a peak rate of over 402 000 boed 

in 2005, with 51 mmboe exported via the 

CPC in 2005. 

In addition to its size, Karachaganak 

presents formidable challenges to the 

operators due to extreme climate swings 

(+/- 40 degrees centigrade) and the 

requirement to reinject high pressure 

sour gas. Despite these challenges, 

BG Group’s total production from 

Karachaganak in 2005 was 35 mmboe, 

an increase from 31 mmboe in 2004. 

ASTRAKHAN 

BOLSHOI CHAGAN 

to SAMARA 

CASPIAN SEA 

AKTAU 

ORENBURG 

Karachaganak 

UKRAINE 

Karachaganak 

CPC pipeline 

KAZAKHSTAN 

RUSSIA 

CPC 

ATYRAU 

GEORGIA 

TENGIZ 

Production from the Karachaganak field 

began in 1984 when Kazakhstan was still 

part of the Soviet Union. BG Group first 

investigated the possibility of investing 

in the field in 1990, and in 1992 the 

Kazakhstan authorities granted BG Group 

and Agip (now Eni) exclusive rights to 

negotiate a development agreement. 

In 1995, a Production Sharing Principles 

Agreement (PSPA) was signed, under 

which BG Group and Agip took over 

operatorship of the field in order to 

halt rapid production decline and to 

improve the safety and environmental 

performance of the facilities. Gazprom 

was also brought into the venture in 1995. 

Texaco (now Chevron) acquired a 20% 

share of Karachaganak from BG Group and 

Agip in August 1997, and two months later 

LUKoil took over the 15% share formerly 

held by Gazprom. In November 1997, a FPSA 

was signed (effective on 27 January 1998), 

superseding the PSPA and providing for 

the full development of the field. 

The FPSA envisaged a phased development 

programme. Phases I and II are now 

complete. Phase II involved investment 

of over US$1 billion (net BG Group) to 

enhance the existing facilities, construct 

new gas and liquids processing and gas 

injection facilities, work-over more than 100 

wells, construct a 120 MW power station 

and lay a new 650 km pipeline to connect 

the field to the CPC pipeline at Atyrau.

Phase II facilities came fully onstream 

in May 2004. Historically, virtually all 

production was sold into Russia. Now 

that Phase II facilities are onstream, 

most liquids are being sold via CPC 

(currently around 70%), though some 

condensate and all sales gas will continue 

to be sold into Russia. Exports via the 

CPC have achieved realisations closer 

to Mediterranean prices, which are 

substantially higher than those achieved 

by selling into Russia. An additional oil 

export route via the Atyrau Samara 

pipeline leading into the Transneft system, 

became available and oil exports through 

this route began on 19 June 2006. 

The Phase IIM drilling programme, 

incorporating an additional 16 production 

wells, was approved in 2005. Planning is 

underway for the Phase III development 

to increase liquids and gas production 

rates and to recover additional reserves. 

CASPIAN PIPELINE CONSORTIUM 

CPC was formed to build a pipeline system 

to transport oil from western Kazakhstan 

to the Black Sea near Novorossiysk in 

Russia. The pipeline system consists of 

a new-build line, new marine terminal 

facilities near Novorossiysk, plus an 

upgraded pipeline. The first phase of the 

system, known as the Initial Construction 

Project (ICP), has a capacity of 28.2 mtpa 

(560 000 bopd), all of which has been 

allocated to CPC shareholders. The ICP 

cost around US$2.6 billion to complete, of 

which BG Group contributed approximately 

US$70 million. The pipeline commenced 

operations along its full length in 

October 2001. FEED and CPC shareholder 

discussions related to the expansion of 

the pipeline system are continuing. 

BG Group has a 2% equity share in the line 

but is entitled to 2.75 mtpa (55 000 bopd) 

of CPC initial capacity, around 10% of the 

total, which, with other Karachaganak 

partners’ entitlements, is being used to 

transport liquids from the Karachaganak 

field. The first phase of expansion will 

increase BG Group’s preferential capacity 

rights to 3 mtpa (60 000 bopd) and there 

is potential to increase the total gross 

capacity of the pipeline to some 67 mtpa 

(1.45 million bopd) over time. In 2005 

Karachaganak was involved in 69 tanker 

loadings, lifting over 6.5 million tonnes 

(51 million barrels). 

Karachaganak, operating via Karachaganak 

Petroleum Operating Company (KPO), 

began delivering liquids into CPC in 

May 2004 and is now fully utilising the 

partners’ capacity entitlements. 

Effective shareholders CPC (%) 


Russian Government 24.00 

Kazakh Government 19.00 

Chevron 15.00 

LUKARCO 12.50 

ExxonMobil 7.50 

Rosneft-Shell 7.50 

Omani Government 7.00 

Eni 2.00 

Oryx 1.75 

KPV 1.75 

13 

KAZAKHSTAN

14 

ARGENTINA AND URUGUAY 

South America 

Argentina and Uruguay 


• Debt-restructuring 

negotiations concluded 

Key dates 

1992 Purchase of MetroGAS 

distribution licence 

1994 MetroGAS Initial Public Offering 

on NYSE 

2002 Devaluation of Argentine Peso. 

MetroGAS suspends payments of 

principal and interest on its debt 

Southern Cross and Gas Link 

pipelines operational 

2005 MetroGAS deconsolidation 

from BG Group’s accounts 

Launch of MetroENERGIA 

gas marketing 

2006 MetroGAS debtrestructuring 

completed 

MetroGAS effective 

shareholders (%) 

(as result of GASA restructuring, and 

subject to regulatory approvals) 


Gas Argentino S.A. (GASA)* 51.00 

Marathon Funds 15.35 

Retail 

Former Gas del 

13.20 

Estado employees 10.00 

Ashmore Funds 3.65 

*GASA (BG Inversiones Argentinas 38.3%; 

YPF Inversora Energética 31.7%; 

Ashmore Internacional Utilities 30.0%) 

PACIFIC OCEAN 

CHILE 

METROGAS 

MetroGAS is the largest natural gas 

company in South America. BG Group 

acts as technical operator. 

On 7 December 2005, GASA (MetroGAS’ 

holding controlling company) reached 

agreement with its creditors for a 

comprehensive restructuring, subject to 

regulatory and local competition authority 

approvals. The agreement reduced BG 

Group’s interest in GASA to 38.3%, lowering 

its indirect shareholder interest in MetroGAS 

to 19.5%. Given that BG Group maintains a 

6.8% direct interest in MetroGAS, its total 

stake will now represent 26.3%. This led to 

the deconsolidation of MetroGAS from BG 

Group’s accounts in 2005. 

Total revenue increased by 9.2% (including 

exchange rate variation) during 2005, 

amounting to £163.5 million, compared to 

£149.7 million in 2004. Growth was mainly 

due to the impact of higher commodity 

prices on sales tariffs to power and 

industrial customers. The increase 

was partially offset by lower volumes 

delivered to power plants, due to increased 

hydro generation and maintenance at 

two main power plants. 

MetroGAS supplies two million customers 

in the city of Buenos Aires, and in 2005 

delivered 7.9 bcm gas through 15 938 km 

of pipelines. In 2005, MetroGAS launched 

Further information on MetroGAS can be found on its website, www.metrogas.com.ar 

ARGENTINA 

BUENOS AIRES 

MetroGAS 

ATLANTIC OCEAN 

BRAZIL 

URUGUAY 

MONTEVIDEO 

Southern Cross and 

Gas Link Pipelines 

the 95% controlled subsidiary 

MetroENERGIA, which already ranks 

among the three largest gas marketers 

in Argentina. 

In January 2002, the Argentine government 

declared a state of “public emergency”, 

forcing the re-negotiation of public utility 

contracts. The timing and outcome of this 

process remains uncertain. 

As a result, in March 2002, MetroGAS 

suspended payments on all of its financial 

debt. In November 2003, the Company 

launched a debt-restructuring plan. In 

May 2006, MetroGAS reached a successful 

outcome of the debt-restructuring 

process, with a 95% level of consent 

from its creditors. 

URUGUAY 

BG Group is operator with a 40% share in 

the Southern Cross Pipeline (SCP) linking 

Argentina to Montevideo. The pipeline 

became operational in November 2002 at 

the start of a 30 year concession period. 

Through its holding in Dinarel, BG Group 

holds a 25.5% interest in Gas Link, a 40 km 

gas pipeline connecting the SCP to the 

Argentine transportation network.

South America 

Bolivia 

Key dates 

1998 Discovered Margarita 

1999 Itau field discovered 

Purchased Bolivian assets 

from Tesoro 

2001 La Vertiente processing 

expanded to 160 mmscfd 

2004 First production from Margarita 

Early Production Facility 

2005 New hydrocarbons law passed 

in May 

2006 Supreme Decree (No. 28701/6) on 

Nationalisation issued in May 

Partners Margarita (%) 


Repsol YPF (operator) 37.5 

Pan American Energy 25.0 

Caipipendi 

LA PAZ 

TARIJA 

BOLIVIA 

Margarita 

Itau 

VILLAMONTES 

CHILE ARGENTINA 

BG Group has eight exploration/ 

exploitation and retention blocks 

(which hold discoveries that have not 

yet commenced production) and holds 

a participating interest in Itau and 

Margarita, two of the largest discovered 

gas condensate fields in the country. 

BG Group exports gas to Brazil through 

an integrated gas chain linking producing 

fields in Bolivia to its Brazilian distribution 

subsidiary, Comgas, in São Paulo. This 

is achieved through processing at its 

La Vertiente gas plant and transportation 

through the Bolivia Brazil pipeline (see 

page 17). 

Bolivia enacted a hydrocarbons law 

on 19 May 2005. Following a national 

referendum covering gas exports, 

hydrocarbon taxes and the management of 

the hydrocarbon sector held on 18 July 2004, 

the Government issued a Supreme Decree 

on Nationalisation on 1 May 2006. The law 

provides that ownership of the production 

at wellhead reverts to the State, mandates 

a renegotiation of current concession 

contracts, creates a new, non-creditable, 

32% royalty-type tax on wellhead 

production and provides for increased 

state control over the sector. Bolivian 

production represented just over 3% 

of Group production in 2005. 

100% OPERATIONS 

Following the acquisition in December 

1999 of Tesoro Bolivia Petroleum Company, 

BG Group continues to hold and operate 

Charagua 

La Vertiente 

Ibibobo-Mistol 

Palo Marcado 

Los Suris 

PARAGUAY 

(100%) several exploitation and retention 

licences containing six gas condensate 

fields. BG Group supplies gas to Brazilian 

markets through two sales contracts: 

• 1.4 mmcmd supply into the Yacimientos 

Petroliferos Fiscales Bolivianos (YPFB) – 

Petrobras contract 

• 0.65 mmcmd supply to Comgas. 

La Vertiente 

The 375 sq km La Vertiente exploitation 

block contains the La Vertiente, Escondido 

and Taiguati gas condensate fields. 

Production from La Vertiente began in 

August 1978 and from Escondido in 

October 1989. 

Los Suris 

The 50 sq km Los Suris exploitation block 

contains the Los Suris gas condensate field 

which began production in August 1999. 

XX Tarija East 

Two discovered gas condensate and 

oil fields, Ibibobo and Palo Marcado, 

have been held as Retention Areas 

awaiting development. 

NON-OPERATED BLOCKS 

Margarita Exploitation 

BG Group has a 37.5% equity share of the 

giant Margarita gas condensate field 

which lies in the 874 sq km Margarita 

exploitation area. Following discovery in 

November 1998, the Margarita X2 and X3 

appraisal wells were drilled in 1999 and 

the X4 appraisal well successfully tested 

gas in May 2004. 

15 

BOLIVIA

16 

BOLIVIA 

South America 

Bolivia continued 

Partners Itau Retention Area (%) 


Total Bolivie (operator) 41 

ExxonMobil 34 

Partners Caipipendi (%) 


Repsol YPF (operator) 37.5 

Pan American Energy 25.0 

Partners Charagua (%) 


Chaco (Pan American) 50 

Repsol YPF (operator) 30 

First production from Margarita began in 

December 2004 under an interconnection 

agreement with Petrobras for the 

temporary use of their gas and liquids 

lines. Part of BG Group’s Margarita gas 

production (0.25 mmcmd) supplies 

the YPFB-Petrobras contract and part 

(0.50 mmcmd) is being sold domestically 

under short-term arrangements. 

Itau Retention Area 


Itau Retention Area, which contains 

the Itau gas condensate field. 

Caipipendi 

The Caipipendi exploration block contains 

several large gas condensate exploration 

leads and prospects. 

Charagua 


787 sq km Charagua block, which 

contains the Itatiqui Retention Area.

South America 

Brazil 


• Record volumes at Comgas, up 10% 

in the first half of 2006 (Q on Q) 

• Iqara has installed 68 CNG filling 

stations primarily in the states of Rio 

de Janeiro and São Paulo 

• Success in 7th Licensing Round 

Key dates 

1999 Purchased controlling stake 

in Comgas 

Bolivia-Brazil pipeline connected 

to São Paulo 

2005 Drilling programme began 

in deep water Santos Basin 

and further exploration 

concessions awarded 

Effective shareholders BBP (%) 


Petrobras 40.46 

Transredes 22.27 

El Paso 7.65 

Enron 7.42 

Shell 7.42 

Total 7.12 


Bolivia-Brazil Pipeline 

PARAGUAY 

ARGENTINA 

URUGUAY 

BRAZIL 

PORTO ALEGRE 

Brazil is an integral part of BG Group’s 

South America strategy. BG Group has 

a controlling stake in Comgas, which is 

Brazil’s largest gas distribution company. 

Comgas has over 500 000 customers in 

São Paulo and increased the volume of 

gas distributed in 2005 by 14%. 

The concession area has a population 

of over 25 million and Comgas anticipates 

continued growth opportunities. 

BG Group has an equity position in 

the Bolivia-Brazil Pipeline (BBP) and in 

eight offshore exploration blocks in the 

Santos Basin and six blocks onshore. 

EXPLORATION 

On 15 September 2003, BG Group entered 

the Second Exploration period for the nonoperated 

BM-S-9, 10 and 11 blocks in the 

deep water (>2 000 metres water depth) 

Santos Basin. Each block carries a two-well 

drilling commitment to be completed by 

14 September 2006. Drilling commenced 

on Block BM-S-10 in January 2005 and 

continued into 2006. 

In July 2004, BG Group acquired a 100% 

operated interest in the BM-S-13 

exploration block in the shallow water 

(100 to 200 metres water depth) Santos 

Basin. Entry to the Second Exploration 

period commenced 28 September 2004. 

This included a two-well commitment 

that BG Group completed during 2006. 

In October 2005, BG Group´s exploration 

portfolio was further extended following 

SÃO PAULO 

CURITIBA 

BELO HORIZONTE 

Comgas 

BT-SF-2 

BM-S-47 

RIO DE JANEIRO 

BM-S-50, 52 

BM-S-13 

BM-S-9, 10, 11 

success in the 7th Annual Brazil Licensing 

Round. Three concessions were awarded in 

the offshore Santos Basin (BM-S-47, BM-S-50 

and BM-S-52) and one onshore concession 

was awarded in the São Francisco Basin in 

Minas Gerais State (BT-SF-2). 

BOLIVIA-BRAZIL PIPELINE 

With total capacity of 30 mmcmd, the 

BBP is 3 150 km long, of which 2 593 km 

is in Brazil. The project was developed 

through two different companies: Gas 

Transboliviano (GTB), which owns 

and operates the assets in Bolivia and 

Transportadora Brasileira Gasoduto 

Bolivia Brasil (TBG), which owns 

and operates the Brazilian portion of 

the pipeline. Operation of the two 

pipelines is co-ordinated through an 

Interconnection Agreement. 

BG Group participates in TBG through 

BBPP Holdings, together with El Paso and 

Total. BG Group’s one third equity in BBPP 

Holdings represents a 9.67% interest in 

TBG. BG Group holds a 2% interest in GTB. 

Based upon the cost of the two sections 

of BBP, BG Group has an effective overall 

interest of 7.65%, although this does 

not represent a direct equity holding, as 

GTB and TBG are two separate entities. 

Construction of the pipeline was 

completed in March 2000, at a cost 

of US$2.2 billion, opening the Brazilian 

energy market to Bolivian gas reserves. 

BG Group, through its Brazilian subsidiary 

BG Comércio is the first Bolivian gas 

17 

BRAZIL

18 

BRAZIL 

South America 

Brazil continued 

Effective shareholders Comgas 

(%) 


Public 18.6 

Shell 18.2 

CPFL 3.1 

Comgas (bcma) 

Comgas achieved double-digit volume 

growth year-on-year from 2003 to 2005 

5 

4 

3 

2 

1 

0 

03 

Industrial 

Residential 

Commercial 

NGV 

Co-generation 

Power 

Source: Comgas 

04 

05 

Financial and operating summary 

– Comgas 

2005 2004 2003 

Revenue 

(£million) 

EBIT 

532 397 391 

(£million) 

Customers at 

147 80 57 

year end (‘000) 

Sales volumes 

485 451 416 

(mmcm) 4346 3 812 3 418 

producer, other than Petrobras, to supply 

the Brazilian market directly. BG Bolivia 

has an agreement to supply Comgas with 

up to 0.65 mmcmd of equity gas until 

2011. With this agreement, BG Group 

established an integrated gas chain 

from the well head to the end customer. 

COMGAS 

Comgas 2005 results: 

• 13.9% increase in the total volume 

of gas sales 

• 9.3% increase in industrial segment sales 

• 17.1% increase in Natural Gas Vehicle 

(NGV) sales 

• 594 km of network expansion 

BG Group, with its partner Shell, has a 

controlling interest in Comgas, Brazil’s 

biggest gas distribution company. 

Comgas increased its total net income 

by 32% to BRL 319.1 million in 2005 and 

increased its investment programme 

by 69% to BRL 473 million. 

BG Group and Shell have been the 

majority shareholders in Comgas since 

April 1999, when the state-owned power 

generation utility, Companhia Energética 

São Paulo, sold its controlling stake 

in Comgas. BG Group and Shell paid 

BRL 1 653 million (US$988 million) for 52.7% 

(BG Group 50.1%, Shell 2.6%) of Comgas. 

As part of the original Comgas deal, Shell 

incorporated its previously held 15.6% 

shareholding in the company into the 

controlling consortium. Since this initial 

acquisition, BG Group has also purchased 

a further 10.0% of the shares of Comgas, 

taking BG Group’s total interest to 60.1%. 

The Comgas concession is a 30 year 

franchise, with a potential for a further 

20 years. The concession area has 

6.3 million households and is in the 

industrial heartland of Brazil, accounting 

for about 24% of Brazil´s GDP. The 

business focus continues to be the 

connection of higher margin commercial 

and residential customers. 

The concession contract requires a 

tariff review every five years. The first, 

concluded in May 2004, defined the 

overall level and structure of tariffs 

for the period June 2004 to May 2009, 

and allows Comgas to make sufficient 

margins to encourage further investment 

in infrastructure, to grow the business. 

Further information on Comgas can be found on its website, www.comgas.com.br 

Further information on Iqara can be found on its website, www.iqara.co.uk 

During the tariff review, Comgas outlined 

its plans to invest US$400 million 

(BRL 940 million) over the next five years 

to expand its service to 18 municipalities 

in São Paulo state and expand its natural 

gas distribution network by 1 000 km. 

Comgas purchases gas indexed to a 

basket of oil-related fuels. Brazilian gas 

supplies of 3.0 mmcmd are contracted 

until December 2007. Bolivian gas supplies 

from Petrobras began in July 1999 under 

a 20 year contract, with volume increasing 

from 4.0 mmcmd in 1999 to 8.75 mmcmd 

in 2006. 

In addition, in December 2002, Comgas 

signed an extension to the existing 

agreement between BG Group and 

Comgas, resulting in the purchase 

of up to 0.65 mmcmd of gas from 

BG Group’s Bolivian fields until 2011, 

under a firm contract. 

Comgas was founded in 1872, and at the 

end of 2005 had 4 400 km of pipelines 

covering 52 municipalities and supplied 

gas to 902 industrial, 8 171 commercial 

and 475 122 residential customers in the 

state of São Paulo. Additionally, Comgas 

supplied 317 NGV filling stations and 

15 customers in the thermo generation 

and co-generation market. Comgas 

has increased the average daily volume 

from 3.0 mmcmd in 1999 to 11.9 mmcmd 

in 2005. 

NEW BUSINESS 

Iqara Gas Natural, launched in 2001, 

provides compression services to the rapidly 

growing Brazilian NGV markets. There are 

currently 68 Iqara Gas Natural CNG service 

stations, primarily distributed in the states 

of Rio de Janeiro and São Paulo. 

During 2004, BG Group continued to 

expand the provision of energy solutions 

(co-generation, peak shaving electric power 

generation, cold and heat generation) 

tailored to clients’ specific needs using 

natural gas as the primary fuel. 

At the end of 2005, BG Group sold 

its entire interest in Iqara Telecoms 

to Companhia de Telecomunicações 

do Brasil Central.

Asia Pacific 

India 


• 9 mmboe net production from 

Panna field in 2005 

Key dates 

1995 Mahanagar Gas Ltd 

(MGL) formed 

1997 Acquired majority stake in 

Gujarat Gas Company Ltd (GGCL) 

2002 Acquired 30% interest in 

Panna/Mukta and Tapti 

(PMT) fields 

2004 Government approval for 

US$200 million Panna 

development plan 

2005 Government approval for 

US$492 million Mid Tapti 

development plan 

Partners Panna/Mukta and 

Tapti Fields (%) 

BG Group (joint operator) 30 

ONGC (joint operator) 40 

Reliance Industries 30 

Mukta 

ARABIAN SEA 

Tapti 

GULF OF CAMBAY 

AHMEDABAD 

ANKLESHWAR 

GGCL transmission pipeline 

BG Group has emerged as a key private 

sector player within the gas industry in 

India, with a significant presence in the 

E&P and T&D segments (BG Group has 

a 65.12% controlling stake in GGCL and 

a 49.75% stake in MGL). The Group is 

seeking to play an expanding role in 

India’s growing natural gas sector by 

consolidating and further developing 

its upstream position through licensing 

rounds and acquisitions, and downstream 

in new markets in the south of the 

country. Natural gas demand in India 

is projected to more than double over 

the next two decades to approximately 

13 910 mmscfd in 2026/2027*. BG Group 

is keen to grow its existing business and 

enhance its position in each element of 

the gas chain. 

UPSTREAM 

In February 2002, BG Group completed 

the US$350 million acquisition of a 30% 

interest in the Tapti gas field and the 

Panna/Mukta oil and gas fields. The 

transaction significantly enhanced 

BG Group’s position as a leading player 

in the large and rapidly growing Indian 

energy sector. In 2005, the combined 

fields produced around 33 mmboe (gross) 

– approximately 8% of India’s domestic 

oil and gas production. 

Oil production from the Panna/Mukta 

complex is purchased by the Indian Oil 

Corporation (IOC). On 26 April 2005, 

BG Group and partners announced 

*Draft on Integrated Energy Policy. 

HAZIRA 

Panna 

VADODARA 

SURAT 

BHARUCH 

Gujarat Gas 

Tapti gas pipeline 

INDIA 

MUMBAI 

Mahanagar Gas 

an investment of approximately 

US$500 million for development and 

expansion of the Tapti gas field. The 

Government of India has approved the 

investment plan for the development of 

the Mid Tapti field with installation of a 

processing platform and new compression 

facilities to increase production in 2007. A 

single wellhead platform will be installed 

to drill up to eight new wells in order to 

raise gas production capacity from the 

current rate of 250 mmscfd to 450 mmscfd. 

In November 2004, the partners announced 

the installation of compression facilities 

on the South Tapti field, at a cost of 

US$16 million, increasing gas production 

capacity from 180 mmscfd to 250 mmscfd. 

An extensive drilling programme 

continued as part of the expansion 

programme for the Panna field. This 

involved an 18-well infill programme that 

has significantly increased production 

from the Panna wellhead platforms. 

Successfully completed in January 2006, 

the additional wells are expected to help 

increase recovery by 35 mmbbls oil and 

130 bcf gas. 

Approval was also given for an Expanded 

Plan of Development in Panna involving 

installation of two wellhead platforms 

and drilling of 11 firm wells at a cost of 

US$140 million, implementation of which 

is expected to result in gross incremental 

reserves of approximately 18 mmbbls oil 

and 74 bcf gas. 

19 

INDIA

20 

INDIA 

Asia Pacific 

India continued 

Following government approval announced 

in 2004, the PMT joint venture partners 

were able to begin direct selling of gas 

into the domestic market. The move was 

welcomed as good news for the industry, 

a boost for investment and a further shift 

towards liberalisation of India’s gas supply. 

In December 2005, following a competitive 

tender process, ONGC accepted BG Group’s 

bid for 50% participation in three deepwater 

exploration blocks in the Krishna Godavari 

basin on the east coast (GD, KD and KD 

Extn). The Group’s participation in these 

blocks is subject to Government of India 

approval, including agreement on a suitable 

work programme, and the execution of 

a PSC. 

DOWNSTREAM 

Gujarat Gas Company Limited 

GGCL is India’s largest natural gas 

distribution company, supplying 

approximately 2.5 mmscmd. At the 

end of 2005, GGCL had around 175 000 

domestic, commercial and industrial 

customers, and serviced some 25 000 

CNG users. The company has been part 

of the BG Group portfolio since 1997. 

In 2005, GGCL recorded another year of 

substantial growth in gas sales and in 

the CNG sector. During the year, more than 

18 000 vehicles converted to run on this 

clean fuel and GGCL added five CNG 

stations to its network in Surat and 

upgraded two existing outlets. Sales 

of CNG for the year amounted to 

approximately 15 million kg. Industrial 

take-up of gas continued to be firm with 

more than 100 new customers signing 

up during the year. The retail sector saw 

particularly strong growth, with new 

contracts accounting for more than 

500 000 scmd of additional gas. This 

included more than 46 MW of Combined 

Heat and Power (CHP) load. Growth in 

domestic demand also continued. The 

volume of gas sold increased by 17% 

from 691 mmscm to 811 mmscm. 

Investment to enlarge and upgrade 

GGCL’s pipeline network and associated 

infrastructure continued throughout 2005. 

Mahanagar Gas Ltd 

MGL is based in India’s commercial capital, 

Mumbai. It is India’s largest natural gas 

company, in terms of customer base. It has 

400 000 customers, including more than 

166 000 CNG vehicles. At present there 

are 117 CNG outlets, with 578 dispensing 

points in Mumbai and Thane. MGL owns 

and controls almost 2 000 km of pipeline 

Further information on GGCL can be found on its website, www.gujaratgas.com 

Further information on MGL can be found on its website, www.mahanagargas.com 

and is extending its network beyond 

Mumbai into the neighbouring cities of 

Thane, Mira-Bhayander and Navi Mumbai. 

BG Group and GAIL (India) each have 

a 49.75% stake in the company with 

the balance held by the government 

of Maharashtra. 

Currently, MGL supplies natural gas to 

more than 246 000 homes and 755 small 

commercial and industrial establishments 

in Mumbai. 

In 2005, MGL increased gas sold to 

445.92 mmscm, an increase of nearly 

14% on the previous year. Further 

expansion of the pipeline network to 

neighbouring towns is scheduled for 

completion by 2008. 

NEW BUSINESS 

BG India Energy Services Private Ltd 

(BGIESPL) 

BGIESPL was set up in December 2004 to 

bring co-gen to medium-sized energy users. 

BGIESPL’s business has been transferred 

to GGCL to take advantage of operational 

synergies. The move was completed 

during the second quarter 2006.

Asia Pacific 

China, Malaysia and Singapore 

CHINA 

In June 2006, BG Group signed two PSCs 

with CNOOC covering deep water Blocks 

64/11 and 53/16 and a Geophysical Survey 

Agreement for Block 41/06, offshore China. 

Under the terms of the PSCs, BG Group 

will be the operator of the blocks and has 

a 100% interest during the exploration 

phase. In the event of a commercial 

discovery, CNOOC has the right to take 

an interest of up to 51% in the newly 

discovered field. Under the terms of the 

Geophysical Survey Agreement, upon 

completion of the mandated work 

programme, BG Group has an exclusive 

option to enter into a PSC for Block 41/06. 

Government approval was received in 

August 2006. 

The exploration work programmes for 

the PSC blocks will be carried out in three 

phases and involve the acquisition of 

2D and 3D seismic and the drilling of 

exploration wells on each block. The 

Geophysical Survey Agreement involves 

the acquisition and processing of 

2D seismic. 

The blocks, covering a total of 

approximately 25 800 sq km, are largely 

unexplored and well placed to supply the 

high growth markets of southern China. 

MALAYSIA 

BG Group has a downstream interest in 

the Malaysian energy sector. BG Group 

jointly developed one of the country’s 

main power stations, Genting Sanyen 

Power, located south of the capital, 

Kuala Lumpur. 

Genting Sanyen Power 

BG Group was co-developer of this 

760 MW combined cycle gas-fired power 

station and retains a 20% interest. The 

total investment for the project was 

£400 million. Located in Kuala Langat, 

70 km south of Kuala Lumpur, Genting 

Sanyen began operations in January 1996 

and has a 21 year contract to sell power to 

Tenaga Nasional Berhad, the Malaysian 

national power company. 

SINGAPORE 

BG Group’s Asia Pacific headquarters are 

located in Singapore, providing leadership 

and expertise in the fields of finance, 

law, tax, exploration and business 

development in support of projects 

and investments in the region. 

YANGPU 

DONGFANG TERMINAL DONGFANG 

KUALA 

LUMPUR 

SINGAPORE 

Genting 

Sanyen Power 

SUMATRA 

SANYA 

DANZHOU 

MALAYSIA 

INDIAN 

OCEAN 

CHINA 

HAIKOU 

64/11 

BORNEO 

GUANGZHOU 

53/16 

MACAO HONG KONG 

Qiongdongnan Basin 

INDONESIA 

41/06 

Pearl River Mouth Basin 

21 

CHINA, MALAYSIA AND SINGAPORE

22 

PHILIPPINES 

Asia Pacific 

Philippines 

Key dates 

1995 Signed Power Purchasing 

Agreement (PPA) with Meralco 

for Santa Rita power station 

2002 Conversion of Santa Rita 

to natural gas 

Signed PPA with Meralco for 

San Lorenzo power station 

San Lorenzo completed 

and commercial operation 

commenced 

Shareholders Santa Rita (%) 


First Generation 

40 

Holdings Corporation 60 

Shareholders San Lorenzo (%) 


Unified Holdings Corporation 60 

SOUTH CHINA SEA 

MINDORO 

MALAMPAYA FIELDS 

BG Group is focused on the downstream 

sector of the gas chain with interests in 

two gas-fired power generation plants, 

Santa Rita and San Lorenzo, located on 

the island of Luzon, 80 km south of 

Manila, which supply about 12% of the 

electricity demand for Luzon Island, 

including Manila. 

FIRST GAS HOLDINGS 

CORPORATION (FGHC) 

Santa Rita Power Station 

The Santa Rita power station is owned 

by First Gas Power Corporation (FGPC), 

a 100% subsidiary of FGHC, in which 

BG Group has a 40% interest. The 

remaining 60% of FGHC is owned by 

First Generation Holdings Corporation 

(First Generation), which is a subsidiary 

of First Philippines Holdings Corporation 

(FPHC). The Santa Rita 1 000 MW power 

plant entered full operation in August 

2000. The project was completed below 

the budgeted £556 million. 

LUZON 

Santa Rita/San Lorenzo 

Siemens AG was the main contractor for 

the plant’s EPC contract and operates 

the plant on behalf of FGPC. Gas and 

condensate purchase agreements were 

signed in 1997 and, on 1 January 2002, the 

plant switched to natural gas operations 

when gas became available from the 

Shell/Chevron/PNOC Malampaya field. 

FGPC sells electricity to the Manila Electric 

Company (Meralco) under a PPA that is 

effective until 2025. 

SULU SEA 

PALAWAN 

MANILA 

BATANGAS 

PHILIPPINE SEA 

PANAY 

FIRST GAS POWER CORPORATION 

San Lorenzo Power Station 

BG Group, in partnership with Unified 

Holdings Corporation, a 100% subsidiary of 

First Generation, developed, financed and 

constructed the San Lorenzo power plant 

through a special purpose company, FGP 

Corp, in which BG Group has a 40% 

interest and Unified Holdings Corporation 

has a 60% interest. San Lorenzo, which 

is located adjacent to the Santa Rita power 

plant, has a capacity of approximately 

500 MW. Siemens AG operates the plant. 

The construction of the project was 

completed within the £303 million budget. 

Gas and condensate purchase agreements 

were enacted similar to those for the 

Santa Rita project. San Lorenzo entered full 

commercial operation in October 2002, 

selling power to Meralco under a power 

purchase agreement valid until 2027. 

TRANSMISSION AND DISTRIBUTION 

In January 2001, FGHC was granted a 

25 year franchise to install, own, operate 

and maintain a natural gas transmission 

and distribution pipeline business 

serving Luzon Island, including 

metropolitan Manila. 

BG Group continues to seek participation 

in additional gas-fired power projects 

through FGHC.

Asia Pacific 

Thailand 

Key dates 

1990 Entered a Participation 

and Operating Agreement 

with partners 

1993 Bongkot came onstream 

2001 MoU between Thailand 

and Cambodia for a Joint 

Development Area 

Partners Bongkot (%) 


PTTEP (operator) 44.45 

Total 33.33 

MYANMAR 

ANDAMAN SEA 

BG Group’s investment in Thailand 

is concentrated on upstream activities, 

including an interest in the large 

offshore Bongkot field, which supplies 

approximately 20% of the country’s 

gas demand. 

KHANOM 

BONGKOT GAS FIELD 

BG Group has a 22.22% interest in the 

Bongkot field, in the Gulf of Thailand, 

which came onstream in July 1993. The 

field is operated by PTT Exploration and 

Production (PTTEP). The current DCQ 

has risen to 550 mmscfd (from an 

initial 150 mmscfd) through a phased 

development plan. The Bongkot field 

development currently consists of 

a central complex for gas gathering, 

processing, export and accommodation; 

a floating condensate storage and 

offloading (FSO) vessel; and 14 wellhead 

platforms, 13 of which are remote from 

the central complex. 

The commissioning of the Sour Processing 

Platform in 2005 and planned additional 

phases of field development in future 

years are designed to extend the life of 

the field beyond the next decade. 

EXPLORATION 

BG Group is the operator (BG Group 50%) 

of Blocks 7, 8 and 9 in the Gulf of Thailand, 

in an area subject to overlapping claims 

by Thailand and Cambodia. 

THAILAND 

RATCHABURI 

Block 7 

Block 8 

Block 9 

BANGKOK 

RAYONG 

Bongkot 

Block 9A 

GULF OF 

THAILAND 

CAMBODIA 

In June 2001, a MoU was signed by the 

Governments of Thailand and Cambodia 

aimed at concluding an agreement for 

the exploration and development of 

hydrocarbons in the overlapping claims 

area. A Joint Technical Committee is 

working to agree a mutually acceptable 

basis for resolution. In July 2003, a small 

portion of Block 9 (referred to as Block 9A), 

which is not disputed, was transferred to 

the owners of the adjacent Tantawan 

Production Area to enable development 

via existing infrastructure. 

23 

THAILAND

24 

OMAN 

Asia Pacific 

Oman 

Key dates 

2006 Signed an Exploration 

and Production Sharing 

Agreement for Block 60 

YEMEN 

UNITED 

ARAB 

EMIRATES 

SAUDI 

ARABIA 

OMAN 

OMAN 

On 30 April 2006, BG Group signed an 

Exploration and Production Sharing 

Agreement (EPSA) with the Government 

of the Sultanate of Oman for a 100% 

interest in and operatorship of Block 60, 

onshore Oman. 

The block, which covers almost 1 500 sq km 

contains the Abu Butabul gas and 

condensate discovery which was made 

in 1998. In addition to this discovery, 

there are other exploration prospects 

within the block. 

BG Group will acquire seismic over the 

area and conduct a comprehensive 

appraisal drilling programme to assess 

fully the reserve potential. 

This marks BG Group’s entry into the 

natural gas sector within the Sultanate, 

with the intention of appraising and 

commercialising potential reserves for 

supply into the domestic market. 

Block 60 

GULF OF 

OMAN 

ARABIAN 

SEA 

MUSCAT

Mediterranean Basin and Africa 

Egypt 


• Silva and Mina discoveries 

• Sapphire began production 

• First commercial cargoes from Egyptian 

LNG Train 1 and Train 2 

• Awarded three new concessions: 

El Burg, El Manzala and North 

Sidi Kerir Deep 

Key dates 

1995 Rosetta and WDDM 

concessions awarded 

1998 Nile Valley Gas Company formed 

2001 LNG Export Agreement signed 

Rosetta onstream 

2002 Train 1 EPC and SPA signed 

2003 Scarab Saffron onstream 

Train 2 EPC and SPA signed 

2004 Acquired extra 40% in 

Rosetta concession 

2005 Damietta and Egyptian LNG Train 1 

and Train 2 exports began 

Simian, Sienna and Sapphire 

onstream 

Partners Rosetta Concession (%) 


Edison 20 

Partners Rashid 

Petroleum Company (%) 


EGPC 50 

Edison International 10 

Scarab 

Saffron 

Saurus 

Sequoia 

Rosetta 

North Sidi Kerir Deep 

ALEXANDRIA 

IDKU 

Egypt is a core part of BG Group’s global 

portfolio and a cornerstone of its Atlantic 

Basin LNG strategy. BG Group is also one 

of the largest investors in Egypt’s natural 

gas business. 

BG Group’s activities in Egypt span the 

gas chain from exploration, through 

development and production, to 

downstream projects in LNG and 

distribution. BG Group’s business 

in Egypt comprises: 

• operatorship of two gas-producing areas 

offshore the Nile Delta – the Rosetta 

Concession (BG Group: 80%, Edison: 

20%) and the West Delta Deep Marine 

(WDDM) Concession (BG Group: 50%, 

Petronas: 50%); 

• operatorship of three other concessions 

offshore the Nile Delta – El Manzala 

Offshore (BG Group: 100%), El Burg 

Offshore (BG Group: 70%, Petronas: 30%) 

and North Sidi Kerir Deep (BG Group: 

50%, Petronas: 50%); 

• production of gas from the Rosetta 

Concession supplying the Egyptian 

domestic market at a DCQ of 

345 mmscfd; 

• production of gas from the Scarab 

Saffron fields in WDDM supplying the 

Egyptian domestic market. On 1 January 

2005, the DCQ rose to 626 mmscfd. 

Scarab Saffron supplies the domestic 

market with a minimum of 475 mmscfd 

and, in addition, processes 225 mmscfd 


West Delta Deep Marine 

Egyptian LNG 

Trains 1 & 2 

CAIRO 

Simian 

Solar 

Sienna 

Serpent 

Sapphire 

Sienna-Up 

DAMIETTA LNG 

EGYPT 

PORT SAID 

El Burg 

El Manzala 

through Damietta LNG (Union Fenosa JV 

Co SEGAS) for five years. BG Group and 

Scarab Saffron partner Petronas will lift 

the equivalent volume of LNG; 

• production of gas from the Simian, 

Sienna and Sapphire fields in WDDM 

supplying Egyptian LNG Train 1 at 

565 mmscfd and Egyptian LNG Train 2 

at 565 mmscfd; 

• major shareholdings in the Egyptian 

LNG project (Train 1: 35.5% and 

Train 2: 38%); and 

• exploration of the WDDM Concession, 

with additional exploration wells to 

be drilled in 2006. 

BG Group undertakes upstream 

development and production activities in 

Egypt through joint operating companies. 

In the case of Rosetta this is the Rashid 

Petroleum Company (Rashpetco) in which 

BG Group has a 40% shareholding and in 

the case of WDDM, this is Burullus Gas 

Company (Burullus) in which BG Group 

has a 25% shareholding. 

These operating companies are 50% 

owned by the Egyptian state-owned oil 

company, Egyptian General Petroleum 

Corporation (EGPC). BG Group and its 

partners in each concession hold the 

remaining 50%. 

EXPLORATION 

West Delta Deep Marine Concession 

In the first half of 2006, BG Group and 

partners drilled two successful 

25 

EGYPT

26 

EGYPT 


Egypt continued 

Partners WDDM Concession (%) 


PETRONAS 50 

Partners Burullus 

Gas Company (%) 


EGPC 50 

PETRONAS 25 

Partners El Burg Concession (%) 


PETRONAS 30 

exploration wells, Mina-1 and Silva-1. 

Both wells discovered hydrocarbons and 

development options are being evaluated. 

BG Group and partners have previously 

drilled 17 successful exploration and 

appraisal wells in WDDM since 1997 and 

this has resulted in the discovery of nine 

gas fields: Scarab Saffron, Simian, Sienna, 

Sapphire, Serpent, Saurus, Sequoia, Solar 

and Sienna Up. 

El Manzala Offshore and El Burg 

Offshore concessions 

On 28 July 2005, BG Group signed El Burg 

and El Manzala concession agreements 

for exploration of gas and oil in the 

Mediterranean Sea with the Egyptian 

Natural Gas Holding Company (EGAS). 

Interpretation of 3D seismic on El Manzala 

will be followed by drilling, expected 

during 2007. 

A large, shallow water 3D seismic survey 

was completed on the adjacent El Burg 

concession in the second quarter of 2006 

and further seismic is planned for the 

fourth quarter of 2006. BG Group expects 

to spud the first well on this block in 2007. 

North Sidi Kerir Deep Concession 

The North Sidi Kerir Deep concession was 

awarded in the third quarter of 2005 and 

covers 1 949 sq km in water depths of 

approximately 1 000-2 000 metres, 

adjacent to WDDM. The concession 

agreement was signed in July 2006, 

following ratification by the People’s 

Assembly. BG Group plans to acquire 

3D seismic in 2007 and drill the first 

well in 2008. 

UPSTREAM DEVELOPMENT 

AND PRODUCTION 

Rosetta 

Since Rosetta started production in 

January 2001, it has become a reliable 

component of the domestic supply 

network. In 2004, BG Group acquired 

a further 40% in Rosetta and produced 

above the DCQ in 2005. 

Phase 2 of the Rosetta development 

produced first gas on 15 April 2005. Under 

an amendment to the Rosetta GSA, the 

DCQ of gas production from Rosetta has 

risen to 345 mmscfd from the previous 

275 mmscfd. 

BG Group sanctioned the Rosetta Phase 3 

field development plan in the second 

quarter of 2006. 

Scarab Saffron 

Since delivering first gas in March 2003, 

Scarab Saffron has also proved a reliable 

supplier to the domestic market. 

On 1 January 2005, the DCQ rose to 

626 mmscfd. Up to 1 000 mmscfd has 

been processed through the Scarab 

Saffron facilities into the national grid, 

supplying both the domestic market and 

tolling through Damietta LNG. Under an 

agreement signed with EGAS in December 

2004, 225 mmscfd has been de-dedicated 

for five years from the domestic GSA and 

since February 2005 has been processed 

through the Damietta LNG plant for a 

tolling fee. BG Group and its WDDM partner 

Petronas lift the corresponding volume 

(1.4 mtpa) of LNG. BG Group lifted its first 

cargo from Damietta in March 2005. 

Scarab Saffron is the first deep water subsea 

development in Egypt. These facilities 

consist of eight sub-sea wells connected 

to a sub-sea manifold, in turn connected 

by 24-inch diameter and 36-inch diameter 

pipelines to an onshore processing 

terminal. Electrical and hydraulic lines 

connect the wells to the onshore control 

room. The fields are located approximately 

90 km from the shore and in water depths 

of more than 700 metres. 


The Simian and Sienna fields produced 

first gas on 15 April 2005 for supply to 

Egyptian LNG Train 1 at Idku. The Sapphire 

field produced first gas on 8 September 

2005 for supply to Egyptian LNG Train 2. 

The Simian, Sienna and Sapphire fields are 

located in WDDM approximately 120 km 

offshore Idku, near Alexandria, in the 

Mediterranean Sea. 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. 

In March 2002, the WDDM concession 

agreement was amended to allow gas 

exports from the concession. This 

followed the April 2001 signing of 

a LNG export agreement between 

BG Group, its partners and EGPC. 

In the second quarter of 2006, BG Group 

sanctioned the Phase 4 development 

of WDDM. 

DOWNSTREAM PROJECTS 

Egyptian LNG 

BG Group supplies Train 1 of Egyptian LNG 

with 565 mmscfd gas and supplies Train 2 

with 565 mmscfd gas from its Simian, 

Sienna and Sapphire fields in WDDM. 

The 3.6 mtpa output from Train 1 has been 

sold to Gaz de France under a 20 year sales 

and purchase agreement. BG Group entered 

into a contract with Gaz de France to 

purchase approximately two cargoes 

per month of LNG between July 2005 and 

the end of 2006. The first LNG cargo from 

Egyptian LNG Train 1 was lifted in May 2005, 

some three months ahead of schedule. 

The 3.6 mtpa output of Train 2 has been 

sold to BG Group under a 20 year

agreement. BG Group may deliver this 

output to its capacity at Lake Charles in 

the USA or divert to other markets. The 

first LNG cargo from Egyptian LNG Train 

2 was lifted in September 2005, some 

nine months ahead of schedule. 

The Egyptian LNG facilities, which include 

the common facilities such as storage 

tanks, loading jetty and utilities, are 

located in their own tax free zone at Idku. 

The plant produces a total of 7.2 mtpa 

LNG using the Phillips liquefaction 

technology. The total project cost of 

Trains 1 and 2 is around US$1.9 billion. 

Project financing of US$949 million 

was secured for Train 1 in April 2004 

and US$880 million was secured for 

Train 2 in July 2005. The latter includes 

US$320 million to repay the Train 1 Company 

for Train 2’s share of the common facilities. 

There is sufficient space at the Idku site 

for a further four LNG trains. BG Group 

is seeking reserves through its own 

exploration programme and partnerships 

with third parties to underpin Egyptian 

LNG Train 3. The Egyptian LNG project’s 

commercial structure has been designed 

to allow future expansion without the 

need to involve all existing partners and it 

is possible that third parties could supply 

gas to future Egyptian LNG trains. 

Egyptian LNG Company owns both the 

Egyptian LNG site and common facilities. 

Its sister company, Egyptian Operating 

Company for Natural Gas Liquefaction 

Projects (BG Group: 35.5%) (Opco), 

undertakes the operation of all trains. 

El Behera Natural Gas Liquefaction 

Company (BG Group: 35.5%) (Train 1 Co) 

owns Train 1. The ownership of further 

train companies will differ, for example, 

Idku Natural Gas Liquefaction Company 

(BG Group: 38%) (Train 2 Co) has a 

different ownership structure from 

Train 1 Co. 

Nile Valley Gas Company (NVGC) 

BG Group and its partners signed 

a 25 year franchise agreement covering 

Upper Egypt (the Nile Valley south of 

Cairo), forming NVGC in September 1998. 

Phase 1, costing £23 million in total, 

has involved extension of the gas 

transmission grid to Beni Suef and the 

construction of a distribution network to 

serve around 17 000 domestic customers 

and eight large industrial customers. 

Shareholders ELNG Holding, 

Opco and Train 1 Co (%) 


PETRONAS 35.5 

EGPC 12.0 

EGAS 12.0 

Gaz de France 5.0 

Shareholders Train 2 Co (%) 


PETRONAS 38 

EGPC 12 

EGAS 12 

27 

EGYPT

28 

ISRAEL AND AREAS OF PALESTINIAN AUTHORITY 


Israel and areas of Palestinian Authority 

Key dates 

1999 Acquired Med licences and 

offshore Gaza licence 

Or gas discovery 

2000 3D seismic data shot over 

offshore Gaza and Med licences 

Gaza Marine gas discovery 

2002 Additional 2D seismic shot over 

offshore Gaza licence 

2005 Relinquished Gal licences 

Partners Offshore Gaza (%) 

BG Group (operator) 

Consolidated Contractors 

90 

Company 10 


Offshore Gaza 

Gaza Marine 

EGYPT 

BG Group has been in Israel and areas 

of Palestinian Authority since 1996, 

with current activities focused upon 

the successful commercialisation of 

its offshore gas discoveries. 

ISRAEL 

Med Yavne lease 

BG Group is operator of the Med Yavne 

lease, which was reduced to an area of 

52.3 sq km around the Or gas discovery 

made in 1999. 

AREAS OF PALESTINIAN AUTHORITY 

Offshore Gaza 

BG Group is operator of an exploration 

licence covering the entire marine area 

offshore the Gaza Strip. Following 

acquisition of over 1 000 sq km of 3D 

seismic data, BG Group drilled two 

successful wells in the second half of 

2000 (Gaza Marine-1 and Gaza Marine-2). 

The first of these tested 37 mmscfd gas 

on a 48/64-inch choke with the flow rate 

constrained by testing equipment. The 

second well was not tested but confirmed 

a major gas discovery. In 2001, a technical 

review recommended a sub-sea 

development and pipeline to an onshore 

processing terminal. In May 2002, an 

outline Development Plan was approved 

by the Palestinian Authority. 

Or 

Med Yavne 

LEBANON 

ISRAEL 

GAZA 

During November and December 2002, 

BG Group acquired an additional 925 km 

of 2D seismic data over the area between 

the existing discoveries and the shore. 

BG Group holds 90% equity in the licence, 

which would be reduced to 60% if 

Consolidated Contractors Company and 

the Palestine Investment Fund exercise 

their options at development sanction. 

The Group is looking at options for 

commercialising the gas.


Algeria, Libya and Madagascar 

ALGERIA 

BG Group entered Algeria in August 2006, 

acquiring 49% and operatorship of the 

onshore Hassi Ba Hamou Perimeter, 

under a sales and purchase agreement 

with Gulf Keystone. 

The Hassi Ba Hamou Perimeter, in central 

Algeria, consists of the Hassi Ba Hamou 

gas discovery and five blocks (317b, 322b 3, 

347b, 348 and 349b), covering 

approximately 18 380 sq km. 

Following completion of the transaction, 

state oil and gas company Sonatrach 

will take a 25% interest in the PSC, leaving 

BG Group with 36.75% and Gulf Keystone 

with 38.25%. 

The forward work programme will include 

the acquisition of 2D and 3D seismic and 

six wells, including a minimum of three 

exploration wells in the initial prospecting 

phase to 2008. 

BG Group also signed a MoU with 

Sonatrach in March 2006, which provides 

a non-exclusive framework for discussions 

targeting the joint development of 

integrated gas chain projects. 

LIBYA 

In October 2005, BG Group was successful 

in the 2nd Libyan licensing round, entering 

one of the world’s major hydrocarbon 

provinces with a mix of largely unexplored 

acreage in both an established basin and 

a frontier area. 

BG Group will assume 100% ownership 

and operatorship of Area 123 (Blocks 1 

and 2) covering 4 900 sq km in Libya’s 

prolific onshore Sirt Basin. The work 

obligation involves acquiring seismic 

and an exploration well per block. 

BG Group was awarded a 50% nonoperated 

interest in Area 171, containing 

Blocks 1, 2, 3 and 4, covering approximately 

11 300 sq km onshore in the frontier Kufra 

Basin, with a commitment to acquire 

seismic and drill two exploration wells. 

MADAGASCAR 

In June 2006, BG Group acquired a 30% 

interest in the Majunga Offshore Profond 

exploration block in Madagascar under 

a farm-in agreement with Vanco. 

BG Group’s partners in the block are 

ExxonMobil (operator, 50%) and 

SK Corporation of Korea (20%). 

The block covers approximately 15 840 sq km 

in deep water (200-3 000 metres) off 

north-western Madagascar. Believed 

to be oil prone, it forms part of a largely 

unexplored frontier basin with significant 

potential. The forward work programme 

includes the drilling of an exploration well 

planned for 2007. 

MOROCCO 

TUNISIA 

ALGERIA 

ZAMBIA 

ALGERIA 

TANZANIA 

MOZAMBIQUE 

ZIMBABWE 

SOUTH 

AFRICA 

NIGER 

KENYA 

Hassi Ba Hamou 

TRIPOLI 

ALGIERS 

LIBYA 

CHAD 

Area 123 

Block 1 

Area 171 

Blocks 1,2,3,4 

Majunga Offshore Profond 

SEYCHELLES 

ANTANANARIVO 

MADAGASCAR 

TUNISIA 

Area 123 

Block 2 

LIBYA 

EGYPT 

29 

ALGERIA, LIBYA AND MADAGASCAR

30 

MAURITANIA 


Mauritania 


• Chinguetti commenced production 

in February 2006 

• Oil discovery on Labeidna-1, PSC B 

Key dates 

2004 Acquired interest in PSCs A & B 

2006 Chinguetti first oil in February 

Partners Chinguetti (%) 


Woodside (operator) 47.38 

Hardman 

Société Mauritanienne 

19.00 

des Hydrocarbures 12.00 

Premier 8.12 

ROC Oil 3.25 


Tiof 


Offshore Area B 

Deep Block 5 

Chinguetti Exclusive 

Exploitation 

Authorisation (EEA) 

Offshore Area B 

Deep Block 4 

Offshore Area A 

Block 3 

BG Group has a 13.084% interest in PSC A 

(covering Block 3 and shallow water 

Blocks 4 and 5), an 11.630% interest in 

PSC B (covering deep water Blocks 4 

and 5), and a 10.234% interest in the 

producing Chinguetti Exclusive Exploitation 

Authorisation (EEA). Both PSCs and the 

Chinguetti EEA are operated by Woodside. 

EXPLORATION 

Four oil discoveries (Chinguetti, Tiof, Tevet 

and Labeidna) have been made in PSC B, 

and a gas field (Banda) has been discovered 

in PSC A. Appraisal studies are ongoing on 

Tevet and Labeidna, and development 

studies have been initiated on Tiof. Three 

exploration wells are planned for 2006. 

UPSTREAM DEVELOPMENT 

AND PRODUCTION 

The Chinguetti oil field was discovered in 

2001. The development of the field was 

sanctioned in June 2004 and production 

started on 24 February 2006. The 

Government of Mauritania has exercised 

its right under the PSC B terms to take up 

a 12% interest in the Chinguetti EEA, giving 

BG Group a 10.234% interest in the EEA. 

The Chinguetti development consists of 

sub-sea completed wells tied back to a 

leased floating production, storage and 

offloading tanker. Associated gas disposal 

of 50 to 60 bcf is through a single gas 

injection well located over the undeveloped 

Banda gas field. 

MAURITANIA 


Block 5 


Block 4 

NOUAKCHOTT 

Banda 

Tevet 

Chinguetti 

Labeidna 

DAGANA 

The second phase of the development, 

to maintain production, is scheduled 

onstream in late 2006/early 2007.


Nigeria 


• Entered upstream through 

PSC on OPL 332 

• Olokola LNG project development 

agreement (PDA) signed and FEED let 

• Successful in May 2006 Nigerian 

licensing round 

Key dates 

2006 PSC signed on OPL 332 in January 

Olokola LNG Joint Venture 

PDA signed in February 

Contracted LNG deliveries 

from Nigeria LNG Train 4 

began in January 

MoU to buy LNG from Brass LNG 

signed in January 

Awarded licence OPL 286-DO in 

licensing round in May 

Co-venturers OPL 332 (%) 


Sahara Energy E&P Ltd 35 

NPDC 10 

Seven Energy Nigeria Limited 10 

ABEOKUTA 

PORTO 

NOVO 

LAGOS 

OPL 332 

IBADAN 

OKLNG 

ESCRAVOS 

OPL 286-DO 

AKURE 

BG Group commenced business 

development activities in Nigeria in 

mid-2004. Nigeria is considered to offer 

an excellent strategic fit with BG Group’s 

gas chain capability and Atlantic Basin 

position, and in the light of its 

hydrocarbon potential, offers the 

Group a considerable opportunity to 

grow a significant business position. 

LNG 

BG Group is planning a liquefaction plant 

at Olokola (OKLNG) on the south-western 

coast of Nigeria. In February 2006, 

BG Group signed a PDA, which forms 

the framework for the FEED phase, which 

has now commenced. The proposed 

project will comprise four LNG trains 

of approximately 5.5 mtpa each, with 

development envisaged in two phases 

of 11 mtpa capacity. BG Group will have 

a 13.5% share in the project. Nigerian 

National Petroleum Corporation (NNPC) 

and the international oil companies have 

the right to lift their equity share of LNG. 

Earlier in 2006, BG Group also announced 

a MoU with Nigeria’s Brass LNG, under 

which it expects to acquire up to 2.0 

mtpa LNG. The proposed deal will be 

for a 20 year term, with initial deliveries 

expected to start during 2011. These 

purchases complement the earlier signing 

of a 20 year sale and purchase agreement 

for 2.3 mtpa LNG from Nigeria LNG Trains 

4 and 5 located on Bonny Island. Deliveries 

from Train 4 commenced in January 2006 

(see LNG p.38). 

BENIN 

CITY 

NIGERIA 

BRASS LNG 

PORT 

HARCOURT 

NLNG 

CALABAR 

LUBA 

UPSTREAM 

In January 2006, BG Group signed a 

PSC for Block OPL 332 with the NNPC, 

which resulted in BG Group acquiring 

a 45% interest and operatorship of the 

deepwater block. The PSC followed a 

farm-in agreement with Sahara Energy 

Exploration and Production Limited 

(Sahara). OPL 332 is located in up to 

1 000 metres of water, approximately 

100 km south-east of Lagos. The other 

co-venturers are NPDC (a subsidiary 

of NNPC) and Seven Energy Limited. 

The work programme is expected to 

commence in late 2006 with the 

acquisition of 3D seismic followed 

by an exploration well in 2008. 

BG Group, with Sahara, was awarded 

Licence OPL 286-DO in the May 2006 

Nigerian Licensing Round. The licence is 

located in deep water (200-1 000 metres) 

offshore the western Niger Delta, 

approximately 250 km south-east of 

Lagos. BG Group will be the operator 

and will undertake a work programme, 

including one exploration well in the first 

five year phase. BG Group continues to 

evaluate further upstream opportunities. 

31 

NIGERIA

32 

TUNISIA 


Tunisia 


• Hasdrubal development plan 

approved by Tunisian government 

Key dates 

1989 Acquired Tenneco assets 

1996 Miskar field first production 

BG Group is the largest producer of gas 

in Tunisia, supplying approximately 50% 

of the domestic gas demand from the 

Miskar field. In addition, BG Group holds 

two exploration permits in the Gulf of 

Gabes with a combined surface area 

of 4 088 sq km. 

BG Group intends to undertake further 

exploration activity in Tunisia and to seek 

further investment opportunities utilising 

its gas chain expertise. 

MISKAR GAS FIELD 

Production from the offshore Gulf of 

Gabes Miskar production concession, 

which is 100% BG Group-owned and 

operated, commenced in June 1996. 

Gas from the field is processed at the 

BG Group Hannibal plant, located 21 km 

south of Sfax, and sold into the Tunisian 

gas system. BG Group has a Miskar gas 

sales contract with the Tunisian state 

electricity and gas company, Société 

Tunisienne de l’Electricité et du Gaz 

(STEG), which gives BG Group the right 

to supply up to 230 mmscfd on a longterm 

basis. The Miskar-7 appraisal well 

was spudded in December 2003 and 

completed in January 2004, which 

has proved up a further extension 

of the Miskar field. 

TUNISIA 

Hannibal 

TUNIS 

MISKAR INFILL WELLS 

BG Group is planning to drill six wells as 

part of the Miskar infill drilling campaign. 

The wells will be drilled in two phases, 

with three wells being completed in 

2006/2007 followed by a further three 

in 2008/2009. These wells are required 

to further extend the field plateau. 

MISKAR COMPRESSION 

BG Group commissioned offshore gas 

compression equipment on the Miskar 

platform in May 2005. 

AMILCAR PERMIT (INCLUDING 

HASDRUBAL DISCOVERY) 

BG Group is operator and joint permit 

holder with Entreprise Tunisienne 

d’Activités Pétrolières (ETAP), the Tunisian 

state owned petroleum company, of the 

Amilcar exploration permit, offshore Sfax 

in the Gulf of Gabes. BG Group drilled 

its first appraisal well, Hasdrubal-3, in 

June 1997, which flowed at 21 mmscfd. 

A further appraisal well, Hasdrubal-4, 

drilled in June 1998, flowed 4.6 mmscfd 

and 1 800 bopd from a single drill stem 

test. During 2002, BG Group drilled a 

further appraisal well, Hasdrubal-SW1, 

which tested light oil and confirmed the 

extension of the Hasdrubal field to the 

south-west. In December 2004, BG Group 

BIZERTE 

LA SKHIRA 

GULF OF GABES 

SOUSSE 

SFAX 

Amilcar 


Miskar 

Hasdrubal 

Ulysse A 

Ulysse B 

was granted an extension to the third 

renewal of the Amilcar permit, which 

now expires in December 2006. 

BG Group submitted a Hasdrubal plan 

of development which was approved by 

the Tunisian government in June 2006. 

ULYSSE PERMIT 

BG Group is operator and joint permit 

holder with ETAP of the Ulysse exploration 

permit, offshore Sfax in the Gulf of Gabes. 

BG Group acquired an approximate 

900 sq km extension to the Ulysse permit 

in August 2004. Two commitment wells 

are required by 2008. BG Group is 

currently interpreting a 3D seismic survey, 

which was shot over the permit in the 

summer of 2004, in order to determine 

a drilling programme.

North America and the Caribbean 

Canada and Alaska 


• Of 12 wells drilled in Canada in 2005, 

eight were successful 

• Acquired a 33.33% interest in 

849 858 hectares of land in the 

foothills area of Alaska’s North Slope. 

• Acquired a 40% interest in 

approximately 83 200 hectares in 

the Eastern North Slope of Alaska 

Key dates 

2004 Purchased El Paso Oil & Gas 

Canada Inc. 

2005 Awarded acreage in the 

Northwest Territories 

Acquired further acreage in 

Alberta and British Columbia 

2006 Entry into Alaska 

CANADA 

BG Group currently holds producing 

acreage in the following four core areas: 

• Bubbles, in the north-east part of the 

province of British Columbia (NEBC), 

is BG Group’s largest production 

asset in Canada with 57 wells. The 

gathering system includes 46 km of 

pipelines and four dehydration and 

compression facilities. 

• Ojay is in the south part of NEBC with 

six wells producing from Cretaceous 

sands through a single compression 

and dehydration facility. 

• Copton, located in western Alberta, 

produces from 18 wells in structured 

Cretaceous formations in the 

Canadian Deep Basin. This area has 

two gathering systems with over 59 km 

of pipelines and two compression and 

dehydration facilities. 

• Waterton is located in south-western 

Alberta. BG Group holds a 50% working 

interest in a producing Mississippian 

gas discovery made with Shell Canada 

in 2003. 

Current gas production is sold into the 

grid for the Canadian and US markets. 

The Company’s strategy is to continue 

developing the assets within its core 

areas, while also growing by investing 

in the acquisition and development of 

assets in new areas. 

EL 429/432 

YUKON 

TERRITORY 

Blocks EL 429/432 (net 110 196 hectares) 

in the Northwest Territories provided 

BG Group’s entry into the Central 

Mackenzie Valley. 

Since 2004, BG Group has continued to 

acquire further acreage in Alberta and 

British Columbia. 

ALASKA 

In February 2006, BG Group signed a 

Participation Agreement with Anadarko 

and Petro-Canada for a 33.33% interest in 

849 858 hectares of land in the Foothills 

area of the Alaskan North Slope. Each 

partner now owns a one third working 

interest in the acreage and Anadarko 

will serve as operator. 

Alaska’s North Slope has estimated 

discovered reserves in excess of 17 billion 

barrels of oil and 35 tcf gas. 

In April 2006, BG Group signed a further 

Exploration Agreement with Anadarko 

to acquire a 40% interest in 83 200 

hectares of land along Alaska’s Eastern 

North Slope. Anadarko will operate the 

acreage located on the coastal plain 

near to the Prudhoe Bay field, which 

has already produced over 10 billion 

barrels of oil. The Exploration Agreement 

became effective 17 April 2006. 

Bubbles 

BRITISH 

COLUMBIA 

Ojay 

Copton 

NORTHWEST 

TERRITORIES 

VANCOUVER 

FORT ST JOHN 

ALBERTA 

Waterton 

USA 

PRUDHOE BAY 

CALGARY 

Foothills Contract Area 

ALASKA 

ANCHORAGE 

BEAUFORT SEA 

ENS Contract Area 

CANADA 

TransAlaska Pipeline 

33 

CANADA AND ALASKA

34 

TRINIDAD AND TOBAGO 


Trinidad and Tobago 


• Atlantic LNG Train 4 start-up 

• Dolphin Deep onstream 

• Farmed out Block 3(a) interest 

Key dates 

1996 First Dolphin production 

1999 Atlantic LNG Train 1 

became operational 

2001 Hibiscus platform installed 

2002 Atlantic LNG Train 2 start-up 

2003 Atlantic LNG Train 3 start-up 

2004 Acquisition of Central Block 

2005 Manatee-1 discovery 

Atlantic LNG Train 4 start-up 

2006 Dolphin Deep onstream 

Partners Dolphin, Dolphin Deep 

and Starfish – ECMA (%) 


Chevron 50 

Poinsettia 

Chaconia 

Hibiscus 

Ixora 

Petrotrin Refinery Pointe-a-Pierre 

GULF OF 

PARIA 

Atlantic LNG 

POINT 

FORTIN 

VENEZUELA 

BG Group has been operating in Trinidad 

and Tobago since 1989, and continues 

to reinforce its position as a major gas 

player in the country. BG Group currently 

supplies gas to the domestic market and 

to Atlantic LNG primarily for export 

to North America. In December 2005, 

Atlantic LNG Train 4 started to produce 

LNG. BG Group and partner’s supply to 

this new train takes total forecasted 

operated production for the asset to 

around 900 mmscfd. 

EXPLORATION/APPRAISAL ACTIVITY 

In January 2005, BG Group and partner, 

Chevron, completed the Manatee-1 well 

in Block 6(d) in the East Coast Marine Area 

(ECMA), which indicated gross reserves of 

between 1.3 and 1.6 tcf. This was a significant 

gas discovery and emonstrated the 

extension of the Loran field from Venezuela 

into Block 6(d) in Trinidad and Tobago. BG 

Group and Chevron are evaluating future 

exploration drilling plans in their ECMA 

acreage which is held under several PSCs. 

On 21 March 2006, BG Group farmed out 

its 30% interest in Block 3(a) on the east 

coast of Trinidad to Kerr McGee. 

NCMA Unit Area 

CARIBBEAN SEA 

PORT OF SPAIN 

TRINIDAD 

PHOENIX PARK 

Central Block 

BEACHFIELD 


TOBAGO 

Block E 

ECMA 

Starfish 

Block 5(a) 

Dolphin Deep 

Dolphin 

Block 6(b) 

Loran/ 

Manatee 

Block 6(d) 

EAST COAST MARINE AREA 

The BG Group-operated Dolphin gas field, 

located 83 km off the east coast of 

Trinidad in Block 6(b), commenced 

production in March 1996. The Dolphin 

field is contracted to supply up to 

275 mmscfd gas to the National Gas 

Company of Trinidad and Tobago (NGC) 

under a 20 year supply contract. ECMA 

also supplies 80-100 mmscfd to Train 3 

and 120 mmscfd to Train 4. The gas is 

produced under a Combined Development 

Plan for Blocks 5(a), 6 and E fields. 

Reserves from the Dolphin Deep field 

are being produced through upgraded 

facilities on the Dolphin platform and a 

new gas receiving facility at Beachfield. 

The Dolphin Deep wells, which are the 

first sub-sea completions in Trinidad and 

Tobago, came onstream in July 2006. 

ECMA gas is being delivered to Atlantic LNG 

via two new pipelines – a new 95 km 

offshore 24-inch diameter pipeline bringing 

ECMA gas from the Dolphin platform to 

shore at Beachfield, and NGC’s new 76 km 

onshore 56-inch diameter Cross Island 

Pipeline (CIP) extending from Beachfield 

to the Atlatic LNG at Point Fortin.

NORTH COAST MARINE AREA (NCMA) 

The BG Group-operated NCMA 

development, located 40 km off the north 

coast of Trinidad, includes four gas fields: 

Hibiscus, Poinsettia, Chaconia and Ixora. 

In April 2000, a Unitisation Agreement 

was signed, and in December 2000 the 

Government of Trinidad and Tobago 

approved the development of the first 

three fields. These fields are being 

developed in up to four phases to supply 

gas to Atlantic LNG Trains 2, 3 and 4. 

The Hibiscus platform was successfully 

installed in September 2001, in a water 

depth of 150 metres together with a 

107 km, 24-inch diameter pipeline from 

NCMA to Atlantic LNG at Point Fortin. 

De-bottlenecking in September 2003 

increased capacity of the pipeline 

to 30% above the original design. 

The Ixora prospect was drilled and 

successfully completed in July 2003 

as part of drilling operations on the 

Hibiscus and Chaconia fields. 

Infill drilling and completion of the first 

sub-sea wells on the north coast of 

Trinidad has started with the H4 well in 

the south-western part of the Hibiscus 

field, which is due to start production in 

the third quarter of 2006. Further infill 

sub-sea wells will be drilled during 2006 

in Chaconia and Eastern Hibiscus as part 

of the Phase 3b of the NCMA development. 

Future NCMA developments include the 

development of the Poinsettia field as 

part of Phase 3c, and the installation 

of compression facilities on the 

Hibiscus platform. 

Deeper gas accumulations beneath 

the Poinsettia field were discovered 

by the Poinsettia-1a well in 2004. These 

discoveries are under evaluation and 

may require further appraisal, prior 

to their inclusion in the NCMA 

development programme. 

In August 2002, BG Group and its partners 

announced first gas production from the 

NCMA Hibiscus field into the newly 

commissioned Train 2. NCMA is contracted 

to supply 240 mmscfd gas to Train 2 for up 

to 20 years, in addition to 125 mmscfd to 

Train 3 for the first two years, reducing 

thereafter to 45 mmscfd. Production into 

Train 3 started in April 2003 and NCMA 

has consistently produced at rates over 

12% above the original DCQ for both Trains 

2 and 3. NCMA started to supply gas to 

Train 4 in December 2005. The Train 4 

supply contract is for approximately 80 

mmscfd. 

CENTRAL BLOCK 

Following the successful acquisition of 

Aventura’s share of the onshore Central 

Block in May 2004, BG Group holds a 65% 

interest and the operatorship of this 

111 sq km block. State-owned company 

Petrotrin holds the remaining 35% under 

an Exploration and Production Licence. 

The discoveries in the block include the 

currently producing Carapal Ridge field, 

as well as Baraka and Corosan. 

BG Group currently supplies 20 mmscfd 

gas and 500 bpd condensate to Petrotrin, 

for use in its refinery at Pointe-a-Pierre. 

Gas is transported via a 12 km 10-inch 

diameter pipeline that connects to the 

NGC network. Onshore and close to the 

CIP, Central Block also presents a relatively 

low cost opportunity for supply to Atlantic 

LNG. A new gas plant with a capacity of 

65 mmscfd is being constructed near the 

existing production site at Carapal Ridge. 

This increased capacity will supply up 

to 45 mmscfd for BG Group’s capacity 

in Atlantic LNG Train 4 from 2007. 

The terms of a new Exploration and 

Production Licence for Central Block 

have been agreed with the Government. 

A further exploration programme in Central 

Block is planned under these terms. 

ATLANTIC LNG 

The Atlantic LNG Company of Trinidad and 

Tobago, in which BG Group is a shareholder, 

constructed a US$1 billion LNG plant at 

Point Fortin, south-west Trinidad, which 

came into operation in April 1999. This first 

train produces 3.3 mtpa LNG, which is sold 

to markets in the north-east United States, 

Puerto Rico and Spain. Train 2 commenced 

production in August 2002 and Train 3 in 

April 2003, with the two trains producing 

on average a total of 7 mtpa. Combined 

construction cost for Train 2/3 was 

US$1.1 billion. With the arrival of Train 4 in 

December 2005, the total LNG production 

capacity for Atlantic LNG is over 15 mtpa. 

Government approval for the Train 4 

expansion project was received in June 

2003. Train 4, with 5.2 mtpa output from 

around 800 mmscfd gas supply, is one of 

the world’s largest liquefaction facilities, 

of which BG Group and upstream partners 

will supply 28.89%. 

Partners Hibiscus – NCMA (%) 


Petrotrin 19.50 

Eni 17.31 

PetroCanada 17.31 

Partners Central Block (%) 


Petrotrin 35 

35 

TRINIDAD AND TOBAGO

36 

TRINIDAD AND TOBAGO 


Trinidad and Tobago continued 

Shareholders Atlantic LNG 

Train 1 (%) 


BP 34 

Repsol 20 

Tractebel 10 

NGC 10 


Trains 2 and 3 (%) 


BP 42.5 

Repsol 25.0 


Train 4 (%) 


BP 37.78 

Repsol 22.22 

NGC 11.11 

Atlantic LNG Capacity 

Train mtpa* Gas supply** Start date 

1 3.1 – 1999 

2 3.4 50% 2002 

3 3.4 25% 2003 

4 5.2 28.89% 2005 

*Without any major de-bottlenecking, Trains 1, 2 and 3 have been able to operate at approximately 

3.3, 3.5 and 3.5 mtpa, respectively 

**BG Group and upstream partners 

The gross cost of the expansion was 

US$1.2 billion. The LNG produced from gas 

supplied to Trains 2 and 3 by BG Group and 

its partners is sold to BG Gas Marketing 

Ltd. (BGGM), a wholly owned BG Group 

subsidiary, following contract assignment 

by El Paso Merchant Energy under a longterm 

contract for import into the Elba 

Island LNG receiving terminal in Georgia, 

USA. LNG produced from the BG Group 

liquefaction capacity in Train 4 is sold free 

on board (FOB) under a long-term contract 

to BGGM for potential delivery into the 

US market via the Lake Charles import 

terminal in Louisiana. BG LNG Services 

(BGLS), a wholly owned subsidiary of BG 

Group has an agreement to utilise 100% of 

the available capacity at Lake Charles (see 

page 37). Train 4 is a fully integrated project 

for BG Group, involving the production and 

liquefaction of gas in Trinidad and Tobago, 

the shipping of LNG to Lake Charles in 

Louisiana and the subsequent regasification 

for onward sale into the US market. 

Further information on Atlantic LNG can be found on its website, www.atlanticlng.com


United States of America 


• MoU signed for 2.0 mtpa from 

Brass LNG, Nigeria 

• First cargoes lifted under Nigeria LNG 

and Egyptian LNG contracts 

• Lake Charles expansions completed 

• Agreements signed for enhancement 

of Lake Charles facility and expansion 

of Elba Island 

• BG Group selected to develop 

LNG terminal and supply Chile 

Key dates 

2002 22 year lease for Lake 

Charles capacity 

2003 LNG purchase agreements 

with Nigeria and Egypt 

Secured access to Elba terminal 

2004 LNG purchase agreement from 

Equatorial Guinea 

2006 Two planned expansions of 

Lake Charles increase capacity 

to 13.4 mtpa 

The United States gas market is becoming 

increasingly dependent on LNG imports to 

fill the growing gap between demand and 

local (US and Canadian) supply. BG is a 

leading player in the importation of LNG 

to the USA from both equity and thirdparty 

export projects and, in 2005, was 

responsible for 37% of LNG imports. 

BG, through its subsidiary companies has 

established this leading position through 

a combination of its capacity at the Lake 

Charles and Elba Island LNG receiving 

terminals, a portfolio of LNG supply 

contracts, its gas marketing capability, and 

its access to shipping. BG is in a strong 

position to build on both its supply and 

marketing positions in the USA through 

expansion of existing facilities and is 

pursuing new projects. 

LAKE CHARLES 

In May 2001, BG LNG Services (BGLS), 

a wholly-owned BG Group subsidiary, 

signed a 22 year LNG Terminalling Service 

Agreement to utilise the available capacity 

of the LNG import facility at Lake Charles, 

Louisiana, USA. 

The Agreement became effective on 

1 January 2002 and was extended in 

January 2004 to cover 100% of the 

available terminal capacity for the term 

of the Agreement. In 2002, the terminal 

had the capability to deliver an average 

daily send-out of 630 mmscfd gas on a 

sustainable basis and 1 bcfd on a peaking 

basis. The terminal has access to 15 major 

HOUSTON 

USA 

Lake Charles 

intrastate and interstate natural gas 

pipelines through the Trunkline Gas 

Pipeline system. 

The Lake Charles facility has undergone 

two expansions to increase sustainable 

baseload capacity to 1.8 bcfd (with 

peak capacity of 2.1 bcfd) completed 

in July 2006, and add a second unloading 

berth. All of the capacity of the 

expansions is committed to BGLS. 

BGLS has entered into a long-term 

agreement with Trunkline Gas Company 

to obtain pipeline capacity sufficient to 

meet its increasing throughput capability 

at Lake Charles from 1 April 2004 onwards. 

The agreement provides for the addition 

of new pipeline facilities and upgrades of 

existing facilities. The installation of 

the upgrades in July 2005 allows BGLS 

increased access to the US pipeline grid, 

providing enhanced access to diverse 

and liquid markets. 

In March 2006, BGLS signed an agreement 

with Trunkline LNG, the owner of the 

Lake Charles terminal, for upgrades 

to the facility including an ambient air 

vaporisation system and a natural gas 

liquids extraction plant to remove higher 

Btu products such as ethane and propane 

from the LNG. The new system will reduce 

fuel gas consumption, thus enhancing 

margins, as well as produce an additional 

revenue stream from NGL sales. As part 

of the agreement, Trunkline has also 

extended BGLS’s rights as the sole 

capacity holder by five years until 2028. 

CANADA 

GULF OF MEXICO 

JACKSONVILLE 

Elba Island 

BOSTON 

Providence 

Planned regas facility 

ELBA ISLAND 

During 2004, BGLS established itself as 

the new marketer of regasified LNG at 

Elba Island after taking over contracted 

capacity and long-term LNG supply from 

El Paso in late 2003. Additionally, BGLS 

entered a long-term transportation 

arrangement with Southern Natural Gas 

to construct the Cypress pipeline expansion 

of the Southern Natural Gas Pipeline 

running from Elba Island to Jacksonville, 

Florida. This pipeline extension will debottleneck 

BGLS’ access to the Southern 

Natural Gas Pipeline, when brought into 

service in May 2007, and connect Elba 

Island to the high value markets in Georgia 

and North Florida. 

During 2005, Southern Natural Gas, the 

terminal owner, announced that it will 

expand the terminal capacity to just over 

2 bcfd. BGLS agreed with Southern Natural 

Gas that it will, by 2012, increase its total 

capacity at the terminal to 1.17 bcfd. 

PROVIDENCE 

BGLS, in a joint initiative with KeySpan 

Corporation, the largest natural gas 

distributor in north-east USA, had 

proposed an upgrade of KeySpan’s existing 

LNG storage peak-shaving facility in 

Providence, Rhode Island, to allow marine 

deliveries. In April 2005, KeySpan filed a 

proposal with FERC. In July 2005, FERC 

issued an order denying authorisation of 

the project’s certificate under Section 3 

of the Natural Gas Act, citing concerns 

regarding the existing LNG tank, built 

37 

UNITED STATES OF AMERICA

38 

UNITED STATES OF AMERICA 


United States of America continued 

in 1974, and its non-compliance with 

current federal safety standards for new 

construction. KeySpan’s appeal of FERC’s 

order is currently pending. 

LNG SUPPLY 

BG Group is pursuing a number of options 

to create a diversified supply portfolio for 

its LNG regasification capacity. These 

options include buying LNG from thirdparties 

as well as from BG Group equity 

LNG liquefaction projects. The portfolio 

has a variety of contract tenures and 

comprises a mixture of FOB and carriage, 

insurance and freight (CIF) deals. 

On 13 October 2003, BGLS announced the 

signing of a 20 year sales and purchase 

agreement for 2.3 mtpa supplied from the 

Nigeria LNG (NLNG) Plus project (Trains 4 

and 5) on Bonny Island. The first cargo 

under this contract arrived at Lake Charles 

on 24 January 2006. Shipping for these 

purchases is supplied by NLNG. 

In June 2004, BG Gas Marketing (BGGM) 

entered into binding arrangements for the 

sale and purchase of 3.4 mtpa LNG for a 

period of 17 years commencing in 2007, 

from the LNG project being developed by 

Marathon Oil and its partners on Bioko 

Island, Equatorial Guinea. This purchase is 

on a FOB basis with BG Group supplying 

the shipping. 

In June 2005, BG Group announced 

an agreement with Gaz de France for 

the purchase of LNG at the rate of 

approximately two cargoes per month 

from July 2005 until the end of 2006. 

The volumes are diversions of cargoes 

originally purchased by Gaz de France 

from Egyptian LNG Train 1. The cargoes 

are planned for delivery to Lake Charles 

or Elba Island, but there is flexibility to 

deliver to other terminals. 

On 24 September 2003, BGGM executed 

sales and purchase agreements for 

deliveries of 3.6 mtpa LNG, starting in 

2006, representing the entire output of 

Egyptian LNG Train 2, in which BG Group is 

a partner. The purchase agreements cover 

the entire output of Egyptian LNG Train 2 

and provide for some volumes to be 

switched to BG Group’s Brindisi LNG 

regasification terminal in Italy, 

approximately three years after Train 2 

commercial operations start. BG Group 

started purchasing commissioning cargoes 

from Train 2 in 2005, with the first BG 

Group cargo loaded in September 2005. 

BGGM also signed a contract with 

Egyptian General Petroleum Corporation 

(EGPC), Egyptian Natural Gas Holding 

Company (EGAS) and Petronas on 

24 September 2004 for the export 

of natural gas via the SEGAS LNG plant 

located in Damietta, Egypt. The agreement 

allows BG Group and its Egyptian LNG 

partners to toll approximately 225 mmscfd 

gas through the plant for five years. BG 

Group lifted its first cargo in March 2005. 

BGGM has also agreed terms for the 

purchase of volumes from BG Group 

and its partners’ interests in Atlantic 

LNG Train 4, which commenced 

operations in late 2005. BG Group lifted 

its first commissioning cargo from 

the train on 28 January 2006. 

BG Group is participating in a joint project 

to develop a liquefaction plant in Olokola 

(OKLNG) on the south-western coast of 

Nigeria. BG Group will have a 13.5% share 

in the project and the LNG will be lifted 

by the project sponsors. OKLNG is likely 

to target US Gulf Coast markets and is 

scheduled to begin operation in 2010/2011. 

In January 2006, BGGM announced 

that it had entered into a MoU with 

Nigeria’s Brass LNG, under which it 

expects to acquire 2.0 mtpa LNG. The 

proposed deal will last for a 20 year 

term, with initial deliveries expected 

to start during 2011. It is planned that 

cargoes will be delivered on an ex-ship 

basis to Lake Charles, Louisiana and 

Elba Island, Georgia. 

DOWNSTREAM MARKETING 

BG Energy Merchants (BGEM) markets its 

regasified LNG from Lake Charles and Elba 

Island to multiple intermediary and end 

use customers via delivery through the US 

natural gas pipeline infrastructure. Sales 

are made under various short-, mediumand 

long-term arrangements. BGEM’s 

customers include leading gas and electric 

utilities, industrial and gas merchants. In 

2005, BGEM’s marketing activities in the 

USA accounted for 1.1% of total US natural 

gas consumption (source: EIA). 

SHIPPING 

BG Group has a long history in LNG 

shipping, having been involved in the 

development of both the prototype and 

first working LNG carriers in the industry. 

BG Group’s present activities in this area 

are primarily directed towards meeting 

the needs of BG Group projects. BG Group 

currently owns two 71 651 cubic metre 

LNG ships: the Methane Arctic and the 

Methane Polar. These vessels are on 

long-term charter to Gas Natural of Spain. 

BG Group has chartered five ships from 

Golar LNG under various forms of lease. 

These are the Golar Freeze, Khannur, Hilli, 

Gimi and Methane Princess. These ships 

have cargo capacities that range between 

125 000 and 138 000 cubic metres. 

In June 2004, BG Group took delivery 

of the Methane Kari Elin (138 000 cubic 

metres). In the first half of 2006, 

BG Group took delivery of two 145 000 

cubic metre ships: the Methane Rita 

Andrea and the Methane Lydon Volney. 

The Methane Jane Elizabeth is due for 

delivery in the second half of 2006 and 

a further four sister ships have been 

ordered for delivery in 2007. 

BG Group also continues to contract 

additional shipping as required on a 

short- and medium-term basis in order to 

capture additional business opportunities 

and maintain a balanced shipping position.

Statistical supplement 

CONTENTS 

40 Introduction and legal notices 

Social and environment data 

41 Environment 

41 Our People 

41 Society 

41 Conduct 

Group financial data 

42 Summarised BG Group 

annual results 

43 Summarised BG Group 

quarterly results 

44 Segmental analysis 

Exploration and Production 

45 Estimated net proved 

reserves of natural gas 


reserves of oil 


and probable reserves 

47 Operating statistics 

47 Drilling activity 

48 Field interests 

49 Licence and block interests 

LNG 

50 Facilities capacity 

50 Long term firm supply 

50 Cargoes 

51 Ships 

Transmission and Distribution 

51 Operating statistics 

Power 

51 Capacity 

Corporate information 

52 Principal acquisitions, 

commitments and divestments 

52 Credit ratings 

53 Issued share capital 

and dividend history 

53 Investor calendar 

Definitions and conversions 

54 Definitions 

IBC Energy conversion table 

39

40 

Introduction and legal notices 

INTRODUCTION 

Financial and operating statistics 

This financial and operating information 

includes extracts from BG Group plc’s 

Annual Report and Accounts 2005 

and Quarterly Results Statements. 

Reference to these reports will assist 

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. 

International Financial 

Reporting Standards 

BG Group plc has adopted International 

Financial Reporting Standards (IFRS) as 

its primary accounting basis for the year 

ending 31 December 2005. Re-statement 

of the 2003 and 2004 financial results 

and the principal accounting policies 

under IFRS are available in BG Group plc’s 

Annual Report and Accounts 2005. 

Business performance 

‘Business Performance’ excludes certain 

disposals and re-measurements and is 

presented as exclusion of these items 

provides readers with a clear and 

consistent presentation of the underlying 

operating performance of the Group’s 

ongoing business. 

Translation into US Dollars 

Some of BG Group’s financial figures 

in Sterling have been translated into 

US Dollars. The average rate for each 

year has been used when translating 

the income statement and cash flow 

statement. These translations should not 

be construed as representations that the 

Sterling amounts actually represent such 

US Dollar amounts or could be converted 

into US Dollars at the rate indicated or 

any other rate. 

LEGAL NOTICES 

Steps have been taken to verify the 

information contained in this Data Book 

and, unless otherwise indicated, is 

believed to be accurate as at 31 July 2006. 

However, neither BG Group plc nor any of 

its subsidiary undertakings, joint ventures 

or associated undertakings or their 

respective directors, partners, employees or 

agents make any representation, express or 

implied, or accepts any responsibility, with 

respect to the accuracy or completeness of 

the information in this document. Nothing 

in this document constitutes or shall be 

taken to constitute an offer, invitation 

or inducement to any person to invest in 

BG Group and no reliance should be placed 

on the information contained in it in 

connection with any investment decision. 

Forward looking information 

This Data Book includes ‘forward-looking 

information’ within the meaning of 

Section 27A of the US Securities Act 

of 1933, as amended, and Section 21E of 

the US Securities Exchange Act of 1934, 

as amended. Certain statements included 

in this Data Book, including without 

limitation, those concerning (a) strategies, 

outlook and growth opportunities, 

(b) positioning to deliver future plans 

and to realise potential for growth, 

(c) delivery of the performance required 

to meet the 2006 targets, (d) expectations 

regarding gas and oil prices, 

(e) development of new markets, 

(f) the development and commencement 

of commercial operations of new projects, 

(g) liquidity and capital resources, 

(h) gas demand growth, (i) plans for 

capital investment, (j) the economic 

outlook for the gas and oil industries, 

(k) regulation, (l) qualitative and 

quantitative disclosures about market 

risk and (m) statements preceded by 

‘expected’, ‘scheduled’, ‘targeted’, ‘planned’, 

‘proposed’, ‘intended’ or similar statements, 

contain certain forward-looking 

information concerning the Group’s 

operations, economic performance 

and financial condition. Although the 

Company believes that the expectations 

reflected in such forward-looking 

statements are reasonable, no assurance 

can be given that such expectations will 

prove to have been correct. Accordingly, 

results could differ materially from those 

set out in the forward-looking statements 

Details of disposals and re-measurements can be found on the BG Group website, www.bg-group.com 

The information contained in the Data Book can also be found on the BG Group website, www.bg-group.com 

This filing is also available on the website maintained by the SEC, www.sec.gov 

as a result of, among other factors, 

(a) changes in economic, market and 

competitive conditions, including gas 

and oil prices, (b) success in implementing 

business and operating initiatives, 

(c) changes in the regulatory 

environment and other government 

actions, including UK and international 

corporation tax rates, (d) a major recession 

or significant upheaval in the major 

markets in which the Group operates, 

(e) the failure to ensure the safe operation 

of the Group’s assets worldwide, 

(f) implementation risk, being the 

challenges associated with delivering 

capital intensive projects on time 

and on budget, including the need 

to retain and motivate staff, 

(g) commodity risk, being the risk of 

a significant fluctuation in gas and/or 

oil prices from those assumed, 

(h) fluctuations in exchange rates, 

in particular the US$/UK£ exchange 

rate being significantly different from 

that assumed, (i) risks encountered 

in the gas and oil exploration and 

production sector in general, (j) business 

risk management and (k) the 

Risk Factors included in BG Group plc’s 

Annual Report and Accounts 2005. 

BG Group undertakes no obligation to 

update any forward-looking statements. 

Cautionary note to US investors 

The United States Securities and Exchange 

Commission (SEC) permits oil and gas 

companies, in their filings with the SEC, 

to disclose only proved reserves that a 

company has demonstrated by actual 

production or conclusive formation tests 

to be economically and legally producible 

under existing economic and operation 

conditions. We use certain terms in this 

document such as ‘probable reserves’, 

that the SEC’s guidelines strictly prohibit 

us from including in filings with the SEC. 

US investors are urged to consider closely 

the disclosure in our Form 20-F, File 

No. 1-09337, available from us at 

BG Group, 100 Thames Valley Park Drive, 

Reading RG6 1PT. You may read and 

copy this information at the SEC’s public 

reference room, located at 450 Fifth Street 

NW, Washington D.C. 20549. Please call 

the SEC at 1-800-SEC-0330 for further 

information on the public reference room. 

This filing is also available on the website 

www.sec.gov maintained by the SEC.

Social and environment data 

ENVIRONMENT 

These represent 100% of the direct emissions, discharges and wastes from the activities shown below and 50% from our joint operated venture 

in Kazakhstan: 

• E&P operations where BG Group is designated as the ‘operator’; and 

• LNG, T&D and Power operations in which BG Group holds a total interest of over 50%. This includes MetroGAS S.A., which is controlled by BG Group 

(although BG Group’s direct shareholding is less than 50%). 

Emissions (tonnes) 

Electricity Distribution Total Total Total t/mmboe t/mmboe t/mmboe 

Venting Fugitive Flaring Fuel use generation losses 2005 2004 2003 2005 2004 2003 

Carbon dioxide 513 083 2 1 111 643 1 795 637 1 982 482 1 271 5 404 117 4 162 328 (1) 3 507 970 15 854 14 002 13 321 

Carbon monoxide 0 0 3 475 32 623 3 233 0 39 331 10 356 5 047 115 35 19 

Nitrogen oxides 0 0 781 8 382 2 522 0 11 685 11 767 (2) 7 497 34 40 (2) 28 

Sulphur dioxide 0 0 11 498 4 915 1 500 0 17 913 25 513 (2) 10 056 53 86 (2) 38 

Methane 4 931 842 5 460 270 255 36 669 48 427 47 139 (3) 52 056 (3) 142 159 (3) 198 (3) 

Volatile organic compounds 

Greenhouse gases (carbon 

5 521 156 1 429 204 70 3 087 10 467 9 636 7 906 31 32 30 

dioxide equivalent) 616 633 17 680 1 238 417 1 816 798 2 007 435 771 312 6 468 275 (4) 

5 242 001 (3) 4 601 150 (3) 

18 976 17 631 (3) 17 495 (3) 

Discharges to aqueous environments (tonnes) 

Waste for disposal (tonnes) 

Energy use (MWh) 

Oil in 

pr oc ess 

water 

OUR PEOPLE 

People 

People data refers to direct employees of BG Group and wholly owned subsidiaries. 

Oil on 

cuttings 

Oil 

spills 

Pr oc ess 

water 

Drill 

cuttings 

Total 

2005 

Total 

2004(5) 

Total 

2003 

202 567 9.4 3 738 986 27 855 3 767 619 3 068 125 2 704 480 

Metal General Hazardous Recycled 

Drill 

cuttings 

Total 

2005 

Total 

2004(6) 

Total 

2003 

1 838 3 666 3 709 964 12 294 21 508 43 159 33 907 

Total Total Total 

Gas Electricity Oil 2005 2004 2003 

7 514 539 37 497 1 130 244 8 682 281 5 634 718 3 841 183 

2005 2004 2003 

Employees worldwide (7) 5 363 5 175 4 596 

Employees based outside UK (7) 

4 000 3 912 3 551 

Employees working away from home country 440 452 316 

Women in management 11% 12% 12% 

Health and Safety 

Health and safety data refers to frequency per million hours worked. 

The safety statistics represent 100% of the data from the aforementioned operations plus the operations at Egyptian LNG and Nile Valley Gas Company, 

Egypt, in which BG Group holds an interest of less than 50% but BG Group employees hold senior management positions. 

2005 2004 2003 

Lost time injury frequency (LTIF) 0.5 0.6 0.7 

Total recordable case frequency (TRCF) 2.4 2.5 1.9 

Sickness absence 0.4 0.5 0.6 

Occupational related illness frequency (ORIF) 0.1 0.2 0.3 

CONDUCT 

2005 2004 2003 

Investigations of fraud allegations 6 – – 

Whistleblowing cases 7 2 0 

SOCIETY 

Social investment 

These represent 100% of contributions made by wholly owned BG Group businesses and proportional contributions (according to BG Group’s stake) made 

by operations and joint ventures where BG Group is a shareholder. 

2005 2004 2003 

Charitable gifts 1 064 441 855 432 848 985 

Community investment 1 508 691 843 804 738 759 

Commercial initiatives 808 014 1 530 500 1 197 254 

Management costs 260 357 264 978 248 757 

Sub-total voluntary contributions 3 641 503 3 494 714 3 033 755 

Contractual 3 503 761 5 661 765 3 086 196 

Total voluntary and contractual contributions 7 145 264 9 156 479 6 119 951 

(1) Reassessment of CO 2 loss from MetroGAS, reduced by 500 tonnes 

(2) Amended from 2004 CR Report to include fourth quarter figures from Ballylumford 

(3) Reflecting reassessment of methane leakage from MetroGAS distribution system 

(4) Based on revised data not available at the time of production of the BG Group 2005 Annual Report and Accounts, which quoted 6.4 million tonnes per annum 

(5) Recalculated to include cuttings figure of 1 592 tonnes from BG Trinidad and Tobago 

(6) Recalculated to exclude 32 033 tonnes of reinjected water misreported by KPO 

(7) Average numbers throughout 2005 

41

42 

(1) (2) 

Summarised BG Group annual results 

BUSINESS PERFORMANCE 

2005 2004 2003 

Dated Brent average $/bbl 54.52 38.26 28.84 

FX rate $/£ 1.83 1.82 1.63 

Henry Hub $/mmbtu 8.86 5.85 5.45 

BG Group E&P production (mmboe) 183.8 166.8 156.0 

Group revenue £ million 5 664 4 082 3 587 

Total operating profit 

Exploration and Production 1 942 1 204 959 

LNG 172 94 77 

Transmission and Distribution 211 134 116 

Power 113 121 129 

Other activities (3) (58) (31) (30) 

Total operating profit on ordinary activities 2 380 1 522 1 251 

Net interest (51) (70) (78) 

Profit on ordinary activities before taxation 2 329 1 452 1 173 

Tax on profit on ordinary activities (941) (582) (470) 

Profit on ordinary activities after taxation 1 388 870 703 

Minority shareholders’ interest (31) (28) (20) 

Earnings 1 357 842 683 

Earnings per ordinary share 38.3p 23.8p 19.4p 

Net cash flow from operating activities 1 606 1 582 1 444 

Net borrowings 253 (999) (721) 

Capital investment 1 516 1 894 1 054 

Capital investment excluding acquisitions 1 516 1 373 1 054 

ROACE after tax (%) 23.4 17.6 16.3 

Gearing (%) – 17.9 15.5 

(1) From 2005, information is prepared under IFRS. Information prior to 2005 is prepared under UK GAAP. 

For restatement under IFRS, please see the www.bg-group.com website 

(2) BG Group has applied IFRIC 4 from 1 January 2006. Comparative information has not been restated 

(3) Other activities include new business development expenditure and certain corporate costs

(1) (2) 

Summarised BG Group quarterly results 


Q2 


Q1 


Q4 

2005 

Q3 

2005 

Dated Brent assumption $/bbl 69.59 61.79 56.87 61.63 51.63 47.62 44.01 41.29 35.35 31.81 29.46 28.54 26.22 31.51 

FX rate $/£ 1.78 1.75 1.76 1.79 1.87 1.90 1.85 1.81 1.81 1.82 1.69 1.62 1.60 1.61 

Henry Hub $/mmbtu 6.54 8.98 12.97 8.49 6.73 6.27 6.26 5.44 6.09 5.61 5.07 4.88 5.61 6.24 

BG E&P production (mmboe) 55.6 55.8 54.3 41.2 44.6 43.7 45.0 39.7 41.2 40.9 41.3 38.4 39.1 37.2 

– oil volume (mmboe) 5.3 5.6 5.5 4.6 4.5 4.7 5.8 4.8 5.3 5.5 6.0 6.1 5.5 6.1 

– liquids volume (mmboe) 7.8 7.4 7.8 5.8 8.4 7.7 7.8 6.4 5.7 5.7 5.5 4.3 4.6 4.8 

– gas volume (mmboe) (3) 42.7 42.8 41.0 30.8 31.7 31.3 31.4 28.5 30.2 29.7 29.8 28.0 29.0 26.3 

BG avg UK gas price pence per produced therm 26.20 38.84 38.89 20.10 22.98 24.12 22.59 18.33 17.89 19.68 18.57 15.74 16.02 17.35 

BG avg Int’l gas price pence per produced therm 17.05 18.40 21.43 17.92 14.16 13.85 14.66 14.17 13.83 12.99 12.95 14.94 13.87 12.84 

Overall BG avg gas price pence per produced therm 19.09 23.69 26.11 18.42 16.81 17.48 17.55 15.71 15.40 15.97 15.30 15.29 14.86 15.21 

BG avg oil price $/bbl 69.76 62.53 58.55 63.02 52.36 48.24 45.58 42.80 36.17 32.56 29.13 28.92 25.58 32.82 

BG avg liquids price $/bbl 56.79 50.17 47.17 48.23 39.54 33.01 31.28 30.56 22.59 16.27 15.09 15.08 11.95 15.66 

Total operating profit including share of pre-tax operating 

results from joint ventures and associates 

£ million 

Exploration and Production 647 726 729 419 407 387 360 291 274 264 251 221 223 264 

LNG 34 138 79 51 15 27 21 37 19 15 17 29 21 10 

Transmission and Distribution 57 65 45 64 56 46 31 51 36 30 34 38 31 13 

Power 23 39 35 21 21 36 34 21 24 37 35 28 29 37 

Other activities (4) (9) (10) (30) (7) (8) (13) (11) (5) (6) (10) (10) (9) (5) (6) 

Total operating profit 752 958 858 548 491 483 435 395 347 336 327 307 299 318 

Net interest (14) 1 (13) (10) (10) (18) (20) (16) (15) (16) (13) (23) (20) (22) 

Profit before tax 738 959 845 538 481 465 415 379 332 320 314 284 279 296 

Tax on profit on ordinary activities (401) (384) (347) (215) (192) (187) (177) (151) (133) (128) (126) (114) (112) (118) 

Profit for the period 337 575 498 323 289 278 238 228 199 192 188 170 167 178 

Minority interest (12) (12) 6 (15) (14) (8) (2) (14) (7) (5) (5) (9) (7) 1 

Earnings (BG Group shareholders) (5) 325 563 504 308 275 270 236 214 192 187 183 161 160 179 

Earnings per ordinary share 9.3p 16.0p 14.2p 8.7p 7.8p 7.6p 6.7p 6.1p 5.4p 5.3p 5.2p 4.6p 4.5p 5.1p 

Net cash flow from operating activities 839 702 363 463 374 406 311 354 232 298 409 391 287 357 

Net (borrowings)/funds 14 183 253 (104) (50) (905) (999) (1 006) (954) (978) (721) (989) (1 038) (942) 

Capital investment 401 386 408 378 415 315 509 356 402 627 311 247 267 229 

Capital investment excluding acquisitions 401 386 408 378 386 315 389 356 292 367 311 247 267 229 

ADDITIONAL INFORMATION: EXPLORATION AND PRODUCTION 

Lifting costs ($/boe) $2.18 $2.08 $1.92 $2.54 $2.10 $2.18 $1.83 $2.20 $1.93 $1.60 $1.37 $1.49 $1.48 $1.60 

– lifting costs (£/boe) £1.21 £1.19 £1.09 £1.42 £1.13 £1.15 £0.99 £1.22 £1.07 £0.88 £0.81 £0.92 £0.92 £1.00 

Opex ($/boe) $3.72 $3.82 $3.85 $4.57 $3.82 $3.96 $3.60 $4.01 $3.78 $3.28 $2.95 $3.10 $2.97 $3.05 

– opex (£/boe) £2.07 £2.18 £2.19 £2.56 £2.04 £2.08 £1.95 £2.21 £2.09 £1.80 £1.75 £1.91 £1.85 £1.90 

Development expenditure (£ million) 160 131 188 166 174 155 195 151 125 139 134 114 122 116 

Gross exploration expenditure (£ million) 103 169 131 65 38 102 122 93 63 58 36 44 52 60 

– capitalised 66 136 89 34 15 87 92 75 50 45 30 30 48 48 

– other expenditure 37 33 42 31 23 15 30 18 13 13 6 14 4 12 

(1) 2005 information is prepared under IFRS. Information prior to 2005 is prepared under UK GAAP. For restatement under IFRS, please see www.bg-group.com 

(2) BG Group has applied IFRIC 4 from 1 January 2006. Comparative information has not been restated 

(3) Q1 2006 data includes fuel gas of 1.0 mmboe, Q2 2006 data includes fuel gas of 1.2 mmboe 

(4) Other activities include new business development expenditure and certain corporate costs 

(5) After prior period taxation of £76 million due to increase in North Sea taxation 

Q2 

2005 

Q1 

2005 

Q4 

2004 

Q3 

2004 

Q2 

2004 

Q1 

2004 

Q4 

2003 

Q3 

2003 

Q2 

2003 

Q1 

2003 

43

44 

Segmental analysis (1) 


Q2 Q1 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 

£ million 

Revenue and other 

operating income 

2006 2006 2005 2005 2005 2005 2005 2004 2004 2004 2004 2004 2003 2003 2003 2003 2003 

Exploration and Production 984 1 073 3 074 1 093 688 658 635 2 153 651 535 490 477 1 794 475 438 423 458 

LNG 548 653 1 631 771 404 236 220 1 098 296 336 276 190 945 186 362 264 133 

Transmission and Distribution 224 203 808 219 224 196 169 644 165 178 162 139 678 172 197 172 137 

Power 50 92 227 59 47 46 75 201 58 44 42 57 184 58 36 39 51 

Other activities (2) 2 3 15 5 4 4 2 8 2 3 2 1 3 1 2 – – 

Intra-group sales 

Revenue (excluding share 

(54) (52) (91) (49) (28) (7) (7) (22) (7) (7) (4) (4) (17) (5) (4) (7) (1) 

of joint ventures) 

Share of revenue in 

1 754 1 972 5 664 2 098 1 339 1 133 1 094 4 082 1 165 1 089 968 860 3 587 887 1 031 891 778 

joint ventures – – 256 – – – – 238 57 60 62 59 247 66 65 62 54 

OPERATING PROFIT 

Group operating profit before 

share of pre-tax results of 


Exploration and Production 647 726 1 942 729 419 407 387 1 204 364 295 278 267 959 251 221 223 264 

LNG 34 108 61 43 21 (9) 6 29 6 19 3 1 21 (4) 22 7 (4) 


Power 23 10 24 8 1 (1) 16 33 13 3 2 15 33 12 4 3 14 


Sub-total Group 

(9) (10) (58) (30) (7) (8) (13) (31) (11) (4) (6) (10) (30) (10) (9) (5) (6) 

operating profit 

Share of pre-tax results of 


752 888 2 138 784 488 435 431 1 329 404 344 298 283 1 057 271 266 249 271 

Exploration and Production – – – – – – – – – – – – – – – – – 

LNG 24 30 111 36 30 24 21 65 16 19 16 14 56 21 7 14 14 


Power 21 29 89 27 20 22 20 88 22 20 23 23 96 23 24 26 23 


Sub-total share of operating 

– – – – – – – – – – – – – – – – – 

profit in JVs and associates 56 70 242 74 60 56 52 193 47 49 50 47 194 56 41 50 47 

Total operating profit 808 958 2380 858 548 491 483 1 522 451 393 348 330 1 251 327 307 299 318 

(1) 2005 information is prepared under IFRS. Information prior to 2005 is prepared under UK GAAP. For restatement under IFRS please see the www.bg-group.com website 

(2) Other activities include new business development expenditure and certain corporate costs

Exploration and Production: Estimated net proved reserves of natural gas 

The allocation of the countries within these areas is: 

Atlantic Basin – Canada, Egypt, Trinidad and Tobago and the USA 

Asia and the Middle East – India, Kazakhstan, Thailand, Israel and areas of Palestinian Authority 

Rest of the world – Bolivia, Brazil, Italy, Mauritania, Norway, Spain, Tunisia and Venezuela. 

UK 

bcf 

Atlantic 

Basin 

bcf 

Asia and 

Middle East 

bcf 


Movement during the year: 

1 359 4 025 1 835 1 166 8 385 

Revisions of previous estimates (1) 50 317 579 99 1 045 

Extensions, discoveries and reclassifications 116 – – – 116 

Production (299) (175) (128) (76) (678) 

Purchase of reserves-in-place 7 – – – 7 

Sale of reserves-in-place (117) – – – (117) 

(243) 142 451 23 373 



1 116 4 167 2 286 1 189 8 758 

Revisions of previous estimates (1) 184 162 249 75 670 

Extensions, discoveries and reclassifications 8 – – – 8 

Production (269) (216) (149) (85) (719) 

Purchase of reserves-in-place – 359 – – 359 

Sale of reserves-in-place – – – – – 

(77) 305 100 (10) 318 



1 039 4 472 2 386 1 179 9 076 

Revisions of previous estimates (1) 297 392 402 209 1 300 

Extensions, discoveries and reclassifications 7 16 – 74 97 

Production (219) (332) (158) (96) (805) 

Purchase of reserves-in-place – – – – – 

Sale of reserves-in-place – (1) – – (1) 

85 75 244 187 591 

As at 31 December 2005 1 124 4 547 2 630 1 366 9 667 (2) 

Proved developed reserves of natural gas: 

As at 31 December 2002 1 194 834 545 720 3 293 

As at 31 December 2003 949 1 484 1 732 789 4 954 

As at 31 December 2004 867 1 393 2 038 665 4 963 

As at 31 December 2005 937 2 267 2 139 929 6 272 

(1) Includes effect of oil and gas price changes on PSCs 

(2) Estimates of proved natural gas reserves at 31 December 2005 include fuel gas of 534 bcf 

Rest of 

world 

bcf 

Total 

bcf 

45

46 

Exploration and Production: Estimated net proved reserves of oil 

‘Oil’ includes crude oil, condensate and natural gas liquids. 

UK 

mmbbl 

Atlantic 

Basin 

mmbbl 

Asia and 

Middle East 

mmbbl 

As at 31 December 2002 105.9 9.4 372.2 34.4 521.9 


Revisions of previous estimates (1) 5.7 0.5 85.8 (0.9) 91.1 

Extensions, discoveries and reclassifications 74.6 – – – 74.6 

Production (23.5) (0.1) (17.4) (2.0) (43.0) 

Purchase of reserves-in-place 0.3 – – – 0.3 

Sale of reserves-in-place (0.3) – – – (0.3) 

Rest of 

world 

mmbbl 

Total 

mmbbl 

56.8 0.4 68.4 (2.9) 122.7 

As at 31 December 2003 162.7 9.8 440.6 31.5 644.6 


Revisions of previous estimates (1) 21.7 – (3.1) 6.1 24.7 

Extensions, discoveries and reclassifications 1.3 – – 9.8 11.1 

Production (21.2) (0.3) (23.3) (2.2) (47.0) 

Purchase of reserves-in-place – 1.4 – – 1.4 


1.8 1.1 (26.4) 13.7 (9.8) 

As at 31 December 2004 164.5 10.9 414.2 45.2 634.8 


Revisions of previous estimates (1) 12.3 7.7 (46.9) 4.5 (22.4) 

Extensions, discoveries and reclassifications 1.5 – – 7.4 8.9 

Production (18.3) (0.5) (27.4) (2.8) (49.0) 

Purchase of reserves-in-place – – – – – 


(4.5) 7.2 (74.3) 9.1 (62.5) 

As at 31 December 2005 160.0 18.1 339.9 54.3 572.3 

Proved developed reserves of oil: 

As at 31 December 2002 99.0 0.1 290.9 16.1 406.1 

As at 31 December 2003 86.3 0.9 404.8 18.5 510.5 

As at 31 December 2004 87.1 1.6 382.3 20.4 491.4 

As at 31 December 2005 80.9 9.4 313.8 26.3 430.4 

(1) Includes effect of oil and gas price changes on PSCs 

Exploration and Production: Estimated net proved and probable reserves (1) 

DEVELOPMENT STATUS 


Fields in production 14 721 734 3 187 

Fields under development 294 137 186 

Fields awaiting development 255 4 47 

(1) Gas and oil reserves cannot be measured exactly since estimation of reserves involves subjective judgement. Therefore all estimates are subject to revision 

(2) Oil includes crude oil, condensate and natural gas liquids 

(3) Conversion rate of 6 bcf gas per mmboe 

Gas 

bcf 

Oil(2) 

mmbbl 

Total(3) 

mmboe

Exploration and Production: Operating statistics 

Production volumes (mmboe) 

Q2 


Q1 


Year 

2005 

Q4 

2005 

Q3 

2005 

Q2 

2005 

Q1 

2005 

– oil volume mmboe 5.3 5.6 19.3 5.5 4.6 4.5 4.7 21.4 5.8 4.8 5.3 5.5 23.7 6.0 6.1 5.5 6.1 

– liquids volume mmboe 7.6 7.4 29.7 7.8 5.8 8.4 7.7 25.6 7.8 6.4 5.7 5.7 19.2 5.5 4.3 4.6 4.8 

– gas volume mmboe (1) 42.7 42.8 134.8 41.0 30.8 31.7 31.3 119.8 31.4 28.5 30.2 29.7 113.1 29.8 28.0 29.0 26.3 

Prices 

BG Group avg UK gas price 

pence per produced therm 

BG Group avg Int’l gas price 

26.20 38.84 27.30 38.89 20.10 22.98 24.12 19.64 22.59 18.33 17.89 19.68 16.92 18.57 15.74 16.02 17.35 


Overall BG Group avg gas price 

17.05 18.40 17.27 21.43 17.92 14.16 13.85 13.95 14.66 14.17 13.83 12.99 13.67 12.95 14.94 13.87 12.84 


BG Group avg oil price 

19.09 23.69 20.15 26.11 18.42 16.81 17.48 16.18 17.55 15.71 15.40 15.97 15.16 15.30 15.29 14.86 15.21 

$ per barrel 

BG Group avg liquids price 

69.76 62.53 55.96 58.55 63.02 52.36 48.24 39.24 45.58 42.80 36.17 32.56 29.18 29.13 28.92 25.58 32.82 

$ per barrel 56.79 50.17 41.77 47.17 48.23 39.54 33.01 25.90 31.28 30.56 22.59 16.27 14.45 15.09 15.08 11.95 15.66 

Henry Hub $/mmbtu 

Unit costs 

6.54 7.75 8.86 12.22 9.82 7.03 6.37 5.85 6.26 5.44 6.08 5.62 5.45 5.07 4.88 5.61 6.24 

Lifting costs ($/boe) 2.18 2.08 2.17 1.92 2.54 2.10 2.18 1.88 1.83 2.20 1.93 1.60 1.48 1.37 1.49 1.48 1.60 

Lifting costs (£/boe) 1.21 1.19 1.19 1.09 1.42 1.13 1.15 1.03 0.99 1.22 1.07 0.88 0.91 0.81 0.92 0.92 1.00 

Opex ($/boe) 3.72 3.82 4.04 3.85 4.57 3.82 3.96 3.66 3.60 4.01 3.78 3.28 3.02 2.95 3.10 2.97 3.05 

Opex (£/boe) 

Finding and development costs 

2.07 2.18 2.21 2.19 2.56 2.04 2.08 2.01 1.95 2.21 2.09 1.80 1.85 1.75 1.91 1.85 1.90 

3 year rolling average ($/boe) (2) 7.07 (3) Reserve replacement 

3 year organic average reserve 

4.84 3.17 

replacement ratio (%) 152 (3) Investment 

Development expenditure 

248 304 

(£ million) 

Gross exploration expenditure 

160 131 683 188 166 174 155 610 195 151 125 139 486 134 114 122 116 

(£ million) 103 169 336 131 65 38 102 336 122 93 63 58 192 36 44 52 60 

– capitalised 66 136 225 89 34 15 87 262 92 75 50 45 156 30 30 48 48 

– other expenditure 37 33 111 42 31 23 15 74 30 18 13 13 36 6 14 4 12 

(1) From Q1 2006 includes fuel gas 

(2) The denominator uses the total net proved reserves changes over the three years excluding acquisitions, divestments and production 

(3) These figures are calculated on a SEC basis, which includes all reserves revisions and fuel gas and is calculated at year end prices 

Year 

2004 

Exploration and Production: Drilling activity 

WELL OPERATIONS 

Number of exploration and appraisal wells 2005 2004 2003 2002 2001 

Total 29 28 17 25 14 

Percentage successful (gross well basis) 48 64 71 72 71 

WELLS DRILLED IN 2005: ANALYSIS BY COUNTRY Exploration Appraisal 

Gross Net Gross Net 

Canada 12 10.50 – – 

Egypt 2 1.00 – – 

India – – 2 0.60 

Mauritania 3 0.36 2 0.23 

Trinidad and Tobago – – 1 0.50 

UK 3 0.80 1 0.41 

Norway 1 0.20 – – 

Italy 1 0.55 – – 

Spain 1 1.00 – – 

Total 23 14.41 6 1.74 

The gross figure is a total number of wells in which BG Group participated. 

The net figure is calculated by applying the licence working interest to each well and taking the sum of the fractional interests. 

In the case of farm-ins and farm-outs, the working interest will be that which applies after completion of the well and consequent re-arrangement of interest. 

Q4 

2004 

Q3 

2004 

Q2 

2004 

Q1 

2004 

Year 

2003 

Q4 

2003 

Q3 

2003 

Q2 

2003 

Q1 

2003 

47

48 

Exploration and Production: Field interests 

PRODUCING FIELDS (1) 

Gas production 

(net) bcf 

Oil and liquids production 

(net) ‘000s barrels 

Total production(2) 

(net) mmboe 

BG Group working 

interest (%) 2005 2004 2003 2005 2004 2003 2005 2004 2003 

UKCS Armada and SW Seymour (3) 46.77 and 57.00 38.1 59.2 62.1 1 880 2 910 3 038 8.2 12.8 13.4 

Blake (3) 44.00 0.8 1.7 1.7 4 088 4 997 5 532 4.2 5.3 5.8 

Easington Catchment Area (4) 30.77 and 79.00 51.3 69.5 71.2 204 249 249 8.8 11.8 12.0 

Elgin/Franklin 14.11 26.5 25.5 25.2 5 996 6 236 6 618 10.4 10.5 10.8 

Everest 58.31 25.1 30.9 34.6 720 988 1 226 4.9 6.1 7.0 

J-Block and Jade (5) 30.50 and 35.00 43.5 42.4 41.8 4 800 4 761 5 891 12.1 11.8 12.8 

Lomond 61.11 28.9 35.8 31.8 569 979 866 5.4 6.9 6.2 

Other 4.7 3.8 30.5 54 32 60 0.8 0.7 5.1 

UKCS sub-total 218.9 268.8 298.9 18 311 21 152 23 480 54.8 65.9 73.1 

International Bolivia (6) 37.50 and 100.00 30.7 21.6 14.2 1 063 517 396 6.2 4.1 2.9 

Canada Various 19.0 15.8 – 176 208 – 3.3 2.9 – 

Egypt (3) 50.00 and 80.00 209.9 84.7 50.5 259 89 39 35.3 14.2 8.5 

India (3),(7) 30.00 35.5 31.7 28.4 3 504 2 854 2 634 9.4 8.1 7.4 

Kazakhstan (8) 32.50 75.7 70.0 59.1 22 399 18 991 13 503 35.0 30.7 23.4 

Thailand (9) 22.22 47.0 47.6 40.6 1 440 1 501 1 282 9.3 9.5 8.0 

Trinidad (3) 45.88, 50.00 and 65.00 107.4 114.5 124.8 111 36 – 18.0 19.1 20.8 

Tunisia (3) 100.00 64.9 63.8 61.8 1 717 1 675 1 623 12.5 12.3 11.9 

International sub-total 590.1 449.7 379.4 30 669 25 871 19 477 129.0 100.9 82.9 

Total 809.0 718.5 678.3 48 980 47 023 42 957 183.8 166.8 156.0 

OTHER FIELDS AND DISCOVERIES WITH PROVED OR PROBABLE RESERVES: BG GROUP WORKING INTEREST (%) 

AS AT 31 DECEMBER 2005 (10) 

UKCS Atlantic (3) 75.00 

Cromarty 10.00 

Glenelg 14.70 

Buzzard 21.73 

Maria (3) 36.00 

NW Seymour (3) 57.00 

West Franklin 14.11 

Egypt Rashid-3, Rashid North, Soutt Sequoia (3) 80.00 

Serpent, near field satellites, North Sequoia, Saurus (3) 50.00 

Mauritania Tevet, Tiof 10.234 and 11.63 

Thailand Bongkot South 22.22 

Trinidad Starfish (3) 50.00 

Tunisia Hasdrubal (3),(11) 100.00 

(1) BG Group working interest at 31 December 2005 or when disposed of producing field 

(2) Conversion rate of 6 bcf gas per mmboe 

(3) Operated by BG Group at 31 December 2005 

(4) Easington Catchment Area project comprises the Apollo, Mercury, Minerva, Neptune and Wollaston and Whittle fields 

BG Group-operated except for Wollaston and Whittle 

(5) J-Block includes Judy and Joanne 

(6) Includes Margarita Early Production Facility and the BG Group-operated and 100% owned La Vertiente fields 

(7) Acquired 24 March 2004 

(8) Joint operated in partnership with Eni 

(9) Includes Ton Sak 

(10) Includes Central Block, acquired May 2004 

(11) Excludes North Caspian Sea PSA reserves, sold in April 2005 

(12) BG Group funds 100% of exploration costs, subject to up to 50% possible back-in from ETAP 

(13) Jointly operated with ONGC and Reliance Industries

Exploration and Production: Licence and block interests 

HELD AT 31 JULY 2006 

Country Interest Details 

Number 

of blocks 

BG Group- 

operated 


interest (%) 

Bolivia XVIII La Vertiente 1 1 100 

Caipipendi 1 0 37.5 

Block XX Tarija West 1 0 25 

Block XX Tarija East 2 2 100 

Charagua 1 0 20 

Block Los Suris 1 1 100 

Brazil BM-S-9 1 0 30 

BM-S-10 1 0 25 

BM-S-11 1 0 25 

BM-S-13 1 1 60 

BM-S-47 2 2 50 

BM-S-50 1 0 20 

BM-S-52 1 0 40 

BT-SF-2 6 0 50 

Canada i) Alberta Copton 126 106 Various 

Waterton 10 0 50 

AB Non-Core 66 26 Various 

ii) British Columbia Bubbles 201 197 Various 

Ojay 27 26 Various 

BC Non-Core 35 0 Various 

iii) Northwest Territories Central Mackenzie Valley 2 2 75 

Alaska Foothills 313 0 33.33 

Alaska Eastern North Slope 71 0 40 

China Block 53/16 1 1 100 

Block 64/11 1 1 100 

Egypt Rosetta (1) 1 1 80 

West Delta Deep Marine (2) 1 1 50 

El Manzala Offshore 1 1 100 

El Burg Offshore 1 1 70 

North Sidi Kerir Deep 1 1 50 

Faroe Islands (3) 001 5 0 39.96 

India (4) Mid and South Tapti 1 1 30 

Panna/Mukta 2 2 30 

Israel Med Yavne 1 1 35 

Italy Po Valley Permits (Italy Onshore) 7 5 Various 

Kazakhstan (3) Karachaganak 1 1 32.5 

Libya Sirte Block 123-1 1 1 100 

Sirte Block 123-2 1 1 100 

Kufra Block 171 4 0 50 

Madagascar Majunga Offshore Profond Block 1 0 30 

Mauritania Area A (5) 3 0 13.08 

Area B (6) (including Chinguetti) 3 0 Various 

Nigeria OPL332 1 0 45 

Norway (7) Southern North Sea 8 4 Various 

North Tampen 4 4 Various 

Mid-Norway 8 4 Various 

Barents Sea 3 1 Various 

Oman Block 60 1 1 100 

Areas of Palestinian Authority Gaza Marine (Offshore Gaza) 1 1 90 

Thailand 2/2539/49 1 0 22.22 

3/2515/7 1 0 22.22 

3/2549/71 1 0 22.22 

4/2515/8 (8) 3 1 50 

5/2515/9 1 0 22.22 

Trinidad Block 5 1 1 50 

Block 6 1 1 50 

Block E 1 1 50 

Central Block 1 1 65 

NCMA-1 1 1 57 

Tunisia Amilcar 1 1 50 

Miskar 1 1 100 

Ulysse 1 1 50 

United Kingdom (3) Southern North Sea 20 16 Various 

Central North Sea 67 33 Various 

(1) Rosetta Concession comprising 4 Development Leases (Rosetta Exploration Licence expired May 2003) 

(2) West Delta Deep Marine Concession comprising the Exploration Licence and 4 Development Leases 

(3) Includes part blocks 

(4) Jointly operated with ONGC and Reliance Industries 

(5) PSC A covering Block 3 and shallow water Blocks 4 and 5 

(6) PSC B covering deep water Blocks 4 and 5 

(7) Number of licences are indicated 

(8) Area is subject to dispute – Force Majeure 

49

50 

LNG Facilities capacity (mtpa) 

As at 31 July 2006 

EXPORT TERMINALS 

Train 

BG Group Equity/ 

Utilisation (%) 

Total Capacity 

(mtpa) Gross 


(mtpa) Net Status 

Atlantic LNG 1 26.00 3.1 0.806 Since April 1999 



Egyptian LNG 1 35.50 3.6 1.278 Since May 2005 

Egyptian LNG 2 38.00 3.6 1.368 Since September 2005 

Atlantic LNG 4 28.89 5.2 1.502 Since December 2005 

Total operating 7.164 

IMPORT TERMINALS 


(mtpa) Gross 

Lake Charles, USA 13.4 13.4 


(mtpa) Net Status 

100% since 1 January 2004 

Phase 2 expansion completed 

July 2006 

Elba Island, USA 3.3 (1) 3.3 (1) 100% since 1 January 2004 

Total operating 16.7 16.7 

Elba Cypress Pipeline de-bottlenecking 0.9 0.9 Anticipated Q2 2007 

Lake Charles IEP 3.1 3.1 Anticipated 2008 

Total planned expansions 4.0 4.0 

In development: 

Brindisi, Italy 6.0 4.8 (2) 

Anticipated end 2009 

Dragon LNG, Milford Haven, Wales 4.4 2.2 Anticipated end 2007 

Total in development 10.4 7.0 

(1) Of which 1.2 mtpa may be utilised by Marathon 

(2) BG Group has 80% access. The remaining 20% is for third-party access 

LNG: Long term firm supply (1) 

Firm Sup ply 

(mtpa) 

Commercial 

start-u p 

Atlantic LNG T2/3 2.1 2003 

Nigeria LNG 2.3 Q1 2006 

Egyptian LNG T2 (2) 3.5 Q2 2006 

Atlantic LNG T4 (3) 1.5 Q3 2006 

Equatorial Guinea 3.3 Q3 2007 

Total firm supply (4) 12.7 

(1) Assumes delivery into US East Coast 

(2) First cargo lifted in September 2005 

(3) First cargo lifted in January 2006 

(4) Excludes up to 1 mtpa of expected excess/de-bottlenecking volumes 

LNG Cargoes 

Q2 


Q1 


Year 

2005 

Q4 

2005 

Q3 

2005 

Q2 

2005 

Q1 

2005 

Actual Cargoes 

Lake Charles 23 2 36 11 8 9 8 59 8 23 16 12 99 20 30 27 22 

Elba Island 13 9 50 14 15 11 10 41 11 12 10 8 16 1 8 7 – 

Re-marketed 13 29 31 13 7 1 10 18 7 8 2 1 9 2 2 4 1 

Total 

Managed volumes (billion 

British thermal units) 

49 40 117 38 30 21 28 118 26 43 28 21 124 23 40 38 23 

Sales volumes 97 30 239 70 63 56 49 276 57 92 77 50 271 58 106 75 31 

Re-marketed 35 83 92 39 20 3 30 53 20 24 6 3 25 6 5 11 3 

Total managed volumes 132 113 331 109 83 59 79 329 77 116 83 53 296 64 111 86 34 

Year 

2004 

Q4 

2004 

Q3 

2004 

Q2 

2004 

Q1 

2004 

Year 

2003 

Q4 

2003 

Q3 

2003 

Q2 

2003 

Q1 

2003

LNG Ships 

As at 

31 July 

As at 31 Dec ember 

2006 2005 2004 2003 

Owned number of ships 2 2 2 2 

100% capacity 143 302 143 302 143 302 143 302 

Chartered (current) number of ships 7 7 4 4 

100% capacity 909 443 909 443 500 630 500 630 

Leased number of ships 3 1 – – 

Owned 

Quantity 

100% capacity 428 200 138 200 – – 

Gross 100 % 

capacity 

(cubic metres) Vessel name Comments 

Current 1 71 651 Methane Arctic Long-term charter to Gas Natural of Spain 

Current 1 71 651 Methane Polar Long-term charter to Gas Natural of Spain 

Time charter 

Current from Golar 1 125 856 Golar Freeze Operating between Atlantic LNG and USA 

Current from Golar 1 125 016 Khannur Long-term charter to Gas Natural of Spain 

Current from Golar 1 124 872 Hilli Operating between Atlantic LNG and USA 

Current from Golar 1 124 886 Gimi Operating between Atlantic LNG and USA 

Current from Golar 1 138 159 Methane Princess BG LNG delivery obligations 

Current from Shell 1 140 648 Granatina BG LNG delivery obligations 

Current from MISC 1 130 006 Empat BG LNG delivery obligations 

Lease 

Current 1 138 200 Methane Kari Elin BG LNG delivery obligations 

Current 1 145 000 Methane Rita Andrea BG LNG delivery obligations 

Current 1 145 000 Methane Jane Elizabeth BG LNG delivery obligations 

Current Total 12 1 480 945 

New-build orders 

Delivery Q3 2006 1 145 000 Methane Lydon Volney BG LNG delivery obligations 

Delivery 2007 4 145 000 TBA $620 million for 4 ships 

Transmission and Distribution 

As at 31 Dec ember 

2005 2004 2003 

THROUGHPUT (MILLION CUBIC METRES PER YEAR) 

Net to BG Group 

CUSTOMERS 

13 199 13 383 12 500 

Comgas 484 144 454 285 416 296 

MetroGAS 2 000 000 1 969 794 1 931 532 

Gujarat Gas 200 000 162 479 148 371 

Power 

CAPACITY 

Location Name 

BG Group Equity as at 

Operating Total (MW) 

Operating Net to 

BG Group (MW) 

31 July 2006 (%) 2005 2004 2003 2005 2004 2003 

Italy SERENE 33.68 386 386 386 130 130 124 

Malaysia Genting Sanyen Power (Kuala Langat) 20 760 760 734 152 152 147 

Philippines First Gas Power (San Lorenzo) 40 505 505 505 202 202 202 

Philippines First Gas Power (Santa Rita) 40 1 000 1 000 994 400 400 398 

UK Premier Power (Ballylumford) 100 1 316 1 316 1 316 1 316 1 316 1 316 

UK Seabank Power 50 1 130 1 130 1 130 565 565 565 

Total operational 5 097 5 097 5 065 2 765 2 765 2 752 

51

52 

Principal acquisitions, commitments and divestments 

ACQUISITIONS (TO 31 JULY 2006) 

Announced Details Completion £m 


2005 

none 

June Acquired remaining 50% in Brindisi LNG import terminal, Italy June 2005 29 

2004 

September Acquisition of further 40% stake in Rosetta, Egypt November 2004 120 

May Acquisition of exploration block offshore Brazil July 2004 13 

March Acquisition of DirectNet April 2004 5 

March Acquisition of Aventura Energy Inc May 2004 92 

February Acquisition of El Paso Oil and Gas Canada Inc March 2004 189 

February Acquisition of Mauritania Holdings B.V. March 2004 74 (1) 

(1) Includes $5.1 million contingencies 

COMMITMENTS (TO 31 JULY 2006) 



2004 

none 

April Exercised options to purchase four new LNG ships 2007 delivery 349 

2003 

December Acquired LNG supply, regas capacity and customers at Elba Island, Georgia, USA January 2004 72 (2) 

October Exercised options to purchase three new LNG ships Second half 2006 delivery 270 

(2) Of which $50 million is deferred and conditional 

DIVESTMENTS (TO 31 JULY 2006) 



2005 (3) 

none 

March Sale of entire 50% interest in Premier Transmission Ltd March 2005 26 

2004 

May 1.21% in Gas Authority of India Ltd January 2004 32 

2003 

December Sale of 50% interest in Muturi PSC and related 10.73% interest in the Tangguh LNG project, Indonesia May 2004 142 

November Sale of 51% interest in Phoenix Natural Gas December 2003 120 

April Sale of package of North Sea assets September 2003 72 

March Sale of entire 16.67% interest in the North Caspian PSA April 2005 936 

(3) In December 2005, on signing a Master Restructuring Agreement with the other shareholders and creditors of Gas Argentino S.A., parent company of MetroGAS S.A., BG Group 

ceased to control these companies and deconsolidated them from that date 

Credit Ratings (BG Energy Holdings Ltd.) 

BG Energy Holdings (BGEH) is rated by three major credit rating agencies: 

Rating agency Long-term rating Date assigned Outlook 

Fitch A August 2005 Stable 

Moody’s A2 August 2005 Stable 

Standard & Poor’s A- June 2002 Stable 

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

Corporate information 

TOTAL ISSUED ORDINARY SHARE CAPITAL 

2005 2004 2003 

Shares in issue at year end (millions) 3 549 3 536 3 530 

DIVIDEND DATA 

Payment Value Announcement Date Ex-dividend Date Record Date Payment Date UK Payment Date USA 

Final 1.45p 15 February 2001 25 April 2001 27 April 2001 8 June 2001 18 June 2001 

Interim 1.50p 26 July 2001 24 October 2001 26 October 2001 14 December 2001 24 December 2001 

Final 1.50p 21 February 2002 24 April 2002 26 April 2002 7 June 2002 17 June 2002 

Interim 1.55p 25 July 2002 23 October 2002 25 October 2002 13 December 2002 23 December 2002 

Final 1.55p 18 February 2003 19 March 2003 21 March 2003 2 May 2003 12 May 2003 

Interim 1.60p 28 July 2003 6 August 2003 8 August 2003 12 September 2003 19 September 2003 

Final 1.86p 17 February 2004 14 April 2004 16 April 2004 28 May 2004 7 June 2004 


Final 2.08p 15 February 2005 30 March 2005 1 April 2005 13 May 2005 20 May 2005 


Final 4.09p 8 February 2006 29 March 2006 31 March 2006 12 May 2006 19 May 2006 

Interim 3.00p 24 July 2006 9 August 2006 11 September 2006 15 September 2006 22 September 2006 

INVESTOR CALENDAR 

Event Type Date 


Q4 and Full Year 2005 Results and Strategy Presentation Presentation 8 February 2006 

2005 Final dividend Ex-dividend 29 March 2006 

2006 Annual General Meeting Meeting 28 April 2006 

Q1 2006 Results Announcement 3 May 2006 

2005 Final dividend Dividend Paid (UK) 12 May 2006 

Dividend Paid (USA ADR) 19 May 2006 

Q2 2006 Results Announcement 24 July 2006 

2006 Interim dividend Ex-dividend 9 August 2006 

2006 Interim dividend Dividend Paid (UK) 15 September 2006 

Dividend Paid (USA ADR) 22 September 2006 

Q3 2006 Results Announcement 3 November 2006 

2007 

Q4 and Full Year 2006 Results and Strategy Presentation Presentation February 

2006 Final dividend Ex-dividend April (1) 

2007 Annual General Meeting Meeting May (1) 

Q1 2007 Results Announcement May (1) 

2006 Final dividend Dividend Paid (UK) May (1) 

Dividend Paid (USA ADR) May (1) 

Q2 2007 Results Announcement July (1) 

2007 Interim dividend Ex-dividend August (1) 

2007 Interim dividend Dividend Paid (UK) September (1) 

Dividend Paid (USA ADR) September (1) 

Q3 2007 Results Announcement November (1) 

(1) Provisional dates. 

Registrars 

Lloyds TSB Registrars 

The Causeway, Worthing 

West Sussex 

BN99 6DA 

Tel: 0870 600 3951 

www.shareview.co.uk 

Email: bg@lloydstsb-registrars.co.uk 

Stock Exchange Information 

London Stock Exchange 

Ticker symbol: BG.L 

SEDOL number: 876289 

New York Stock Exchange 

Ticker symbol: BRG.N 

One ADR: 5 ordinary shares 

Cusip number: 55434203 

American Depositary Receipts 

ADR Depositary, JPMorgan Chase Bank 

JPMorgan Service Center, PO Box 3408, 

South Hackensack, NJ 07606-3408, USA 

+1 800 990 1135 (US toll-free) 

+1 201 680 6630 (outside USA) 

www.adr.com/shareholder 

Email: adr@jpmorgan.com 

53

54 

Definitions 

For the purpose of this document the following definitions apply: 

$ US dollar 

£ UK pounds sterling 

bbls Barrels 

bcf Billion cubic feet 

bcfpd Billion cubic feet per day 

bcm Billion cubic metres 

bcma Billion cubic metres per annum 

bcpd Barrels of condensate per day 

BG Group BG Group plc or any of its subsidiary undertakings, 

joint ventures or associated undertakings 

billion or bn One thousand million 

boe Barrels of oil equivalent 

boed Barrels of oil equivalent per day 

bopd Barrels of oil per day 

bpd Barrels per day 

Btu British thermal units 

CAGR Compound Average Growth Rate 

CCGT Combined Cycle Gas Turbine 

CNG Compressed Natural Gas 

cm Cubic metre 

DCQ Daily Contracted Quantity 

DTI Department of Trade and Industry 

EPC Engineering Procurement Construction 

FEED Front End Engineering Design 

GSA Gas Sales Agreement 

GW Gigawatts 

GWh Gigawatt hours 

HIIP Hydrocarbons Initially In Place 

HPHT High Pressure High Temperature 

km Kilometres 

mmbbls Million barrels 

mmboe Million barrels of oil equivalent 

mmbopd Million barrels of oil per day 

mmcmd Million cubic metres per day 

mmscm Million standard cubic metres 

mmscmd Million standard cubic metres per day 

mmscf Million standard cubic feet 

mmscfd Million standard cubic feet per day 

MoA Memorandum of Agreement 

MoU Memorandum of Understanding 

mtpa Million tonnes per annum 

MW Megawatt 

MWh Megawatt hours 

NGL Natural Gas Liquids 

NGV Natural Gas Vehicle 

normal bcm Billion cubic metre of gas at zero degrees Celsius 

and at an absolute pressure of 1.01325 bar 

PSC/PSA Production Sharing Contract/Production 

Sharing Agreement 

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 

PPA Power Purchasing Agreement 

sq km Square kilometres 

tcf Trillion cubic feet

Index 

Page 

E&P – FIELDS, BLOCKS, TERMINALS, 

CONCESSIONS AND LICENCES 

Alaska 

Foothills and Eastern North Slope 

Algeria 

33 

Hassi Ba Hamou Perimeter 

Bolivia 

29 

Block XX Tarija East 15 

Caipipendi 16 

Charagua 16 

Itau 16 

La Vertiente 15 

Los Suris 15 

Margarita 

Brazil 

15 

BM-S-9, 10, 11 and 13 17 

BM-S-47, 50, 52 17 

BT-SF-2 

Canada 

17 

Bubbles 33 

Copton 33 

Northwest Territories (EL 429 & 432) 33 

Ojay 33 

Waterton 

China 

33 

Blocks 64/11, 53/16 and 41/06 

Egypt 

21 

El Burg & El Manzala 26 

Mina and Silva 26 

North Sidi Kerir Deep 26 

Rosetta 26 

Scarab Saffron 26 


Solar, Serpent, Saurus, Sequoia and 

26 

Sienna-Up 26 

West Delta Deep Marine (WDDM) 

India 

25 

Panna/Mukta and Tapti 

Israel and areas of Palestinian Authority 

19 

Med Yavne 28 

Offshore Gaza 

Italy 

28 

Po Valley 

Kazakhstan 

11 

Karachaganak 

Libya 

12 

Area 123 and Area 171 29 

Norway 

Madagascar 

10 

Majunga Offshore Profond 

Mauritania 

29 

PSC A/B 

Nigeria 

30 

OPL 332 and OPL286-DO 31 

Page 

Oman 

Block 60 

Thailand 

24 

Bongkot 23 

Gulf of Thailand Blocks 7, 8 and 9 


23 

Block 5(a) 34 

Block 6(b) and 6(d) 34 

Block E 34 

Central Block 35 

Chaconia 35 

Dolphin and Dolphin Deep 34 

East Coast Marine Area (ECMA) 34 

Hibiscus 35 

Ixora 35 

Manatee-1 34 

North Coast Marine Area (NCMA) 35 

Poinsettia 35 

Starfish 

Tunisia 

34 

Amilcar 32 

Hasdrubal 32 

Miskar 32 

Ulysse 

UK and Faroe Islands 

32 

Amethyst 6 

Armada 6 

Apollo 7 

Atlantic/Cromarty 7 

Blake and Blake Flank 7 

Buzzard 9 

Drake 6 

Easington Catchment Area (ECA) 7 

Elgin/Franklin and Glenelg 8 

Everest and Lomond 8 

Faroe Islands Licence 001 9 

Fleming 6 

Hawkins 6 

J-Block, Jade, Judy/Joanne 8 

Maria 9 

Mercury, Minerva and Neptune 7 

SW Seymour and NW Seymour 6 

Whittle and Wollaston 

LNG LIQUEFACTION TERMINALS 

Egypt 

7 

Egyptian LNG Trains 1 and 2 

Nigeria 

26 

OKLNG 


31 

Atlantic LNG Trains 1, 2, 3 & 4 

LNG REGASIFICATION TERMINALS 

Italy 

35, 36 

Brindisi LNG 

UK 

11 

Dragon LNG 

USA 

5 

Elba Island 37 

Lake Charles 37 

Providence 37 

Page 

LNG SHIPPING 

Golar Freeze 38 

Gimi 38 

Hilli 38 

Khannur 38 

Methane Arctic, Jane Elizabeth, 

Kari Elin, Lydon Volney, Polar, Princess and 

Rita Andrea 38 

TRANSMISSION 

South America 

Bolivia – Brazil Pipeline 17 

Gas Link and Southern Cross Pipelines 14 

Kazakhstan 

Caspian Pipeline Consortium (CPC) 13 

UK 

CATS 9 

Interconnector UK 4 

SEAL and SILK 9 

DISTRIBUTION 

Argentina 

MetroGAS 14 

Brazil 

Comgas 18 

Egypt 

Nile Valley Gas Company (NVGC) 27 

India 

Gujarat Gas Company (GGCL) 20 

Mahanagar Gas (MGL) 20 

POWER 

Italy 

SERENE 11 

Malaysia 

Genting Sanyen 21 

Philippines 

San Lorenzo and Santa Rita 22 

UK 

Premier Power (Ballylumford) 4 

Seabank 4 

NEW BUSINESSES 

Brazil 

Iqara Energy Services 18 

Iqara Gas Natural 18 

UK 

Microgen 5 

Energy conversion table 

To Billion Billion Million Million 

cubic cubic barrels tonnes Trillion 

metres feet oil oil Million British 

gas gas equivalent equivalent tonnes thermal 

From bcm bcf mmboe mmtoe LNG units 

Multiply by 

Billion cubic 

metres gas bcm 

Billion cubic feet 

1 35.31 6.10 0.83 0.7 36.7 

gas bcf 

Million barrels 

oil equivalent 

0.028 1 0.17 0.024 0.020 1.04 

mmboe 

Million tonnes 

oil equivalent 

0.166 6 1 0.14 0.116 6.02 

mmtoe 

Million tonnes 

1.20 42.55 7.35 1 0.86 44.21 

LNG 

Trillion British 

1.41 49.74 8.59 1.17 1 51.69 

thermal units 0.027 0.96 0.17 0.023 0.019 1

Further information 

Further information on BG Group can be found in the 2005 Annual Report 

and Accounts, the 2005 Corporate Responsibility Report and on the 

www.bg-group.com website. 

Annual Report and 

Accounts 2005 

www.bg-group.com 

Corporate Responsibility 

Report 2005 

BG Group plc 

100 Thames Valley Park Drive 

Reading, Berkshire RG6 1PT 

www.bg-group.com 

Registered in England & Wales No. 3690065 

Designed and produced by Black Sun Plc. Printed by Butler and Tanner. 

This Data Book is printed on think 4 bright. This 

paper is produced from 100% ECF (Elemental 

Chlorine Free) pulp that is fully recyclable. It has FSC 

(Forest Stewardship Council) certification and has 

been manufactured within a mill which is registered 

under the British and international quality standard 

of BS EN ISO 9001-2000 and the environmental 

standard of BS EN ISO 14001-1996.

2006 Data Book (PDF) - BG Group

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