FORM 6-K

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Report of Foreign Issuer
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

March 17, 2003

BG Group plc
(Name of Registrant)

100 Thames Valley Park Drive
Reading RG6 1PT
ENGLAND
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F         Form 40-F

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes         No

Enclosure: BG Group plc’s Annual Report and Accounts 2002 for the fiscal year ended December 31, 2002.

BG Group Annual Report and Accounts 2002

	CONTENTS
2	Chairman’s and	54	Group Executive Committee	129	Shareholder Information
	Chief Executive’s Statement	57	Directors’ Report	130	Additional Shareholder
4	Financial Calendar 2003	60	Remuneration Report		Information
5	Business Review	70	Auditors’ Report	137	Cross-Reference to Form 20-F
12	Country Reviews	71	Principal Accounting Policies	138	Index
27	Governance and Risk	74	Accounts	139	Glossary
34	Corporate Responsibility	117	Supplementary Information –	140	Definitions
38	Operating and Financial		Gas and Oil
	Review	122	Five Year Financial Summary
52	Board of Directors	128	Historical Production

BG IS AN INTEGRATED GAS MAJOR: OUR FOCUS IS ON UNDERSTANDING, BUILDING AND SUPPLYING NATURAL GAS MARKETS AROUND THE WORLD.

BG Group plc is a public limited company listed on the
London and New York Stock Exchanges and registered
in England. This is the report and accounts for the
year ended 31 December 2002. It complies with UK
regulations and incorporates the annual report on
Form 20-F for the Securities and Exchange Commission
to meet US regulations.

2	BG GROUP PLC 2002	SIR RICHARD GIORDANO, CHAIRMAN (LEFT)
		FRANK CHAPMAN, CHIEF EXECUTIVE
		CHAIRMAN’S AND CHIEF EXECUTIVE’S STATEMENT

We are pleased to report that our second full year of operation as the new BG Group has seen continuing success. This has been a year of strong growth: an excellent performance in a difficult business environment.

Political and economic turbulence has characterised many of the markets and regions in which we operate. The slowdown in the global economy, with particular macroeconomic deterioration in some areas, has affected the demand for energy in the short term. Against this background our integrated gas major strategy continues to deliver strong growth. BG’s success is based on core strengths across the gas chain from reservoir to burner tip. We have an outstanding ability to find and develop gas reserves at very competitive costs. We have a proven track record in developing and serving gas markets in many parts of the world. We are confident that this strategy and these skills will enable us to continue to deliver profitable growth and to provide exceptional shareholder value.

BUSINESS PERFORMANCE*
In our second full year of business as the new BG Group, we delivered another strong set of results. Operating profits increased by 7% whilst underlying operating profit increased by 13% at constant upstream prices. As a result of the unanticipated and abruptly imposed North Sea tax surcharge, earnings fell by 9%. Excluding the £95 million tax surcharge, earnings per share would have been 11% higher than in 2001.

As a result of strong growth and the transformation of our cost base, our total operating profit has grown by a compound average rate of 41% per annum since 1997. This growth has been achieved across our upstream and downstream segments.

The Group continued to generate strong operating cashflows and, notwithstanding a substantial capital investment programme of £1.5 billion, we ended the year with gearing of only 23%.

In accordance with our existing dividend policy, your Board is recommending a final dividend of 1.55 pence per ordinary share, making a full year total of 3.1 pence.

* Excluding exceptional items

BUSINESS HIGHLIGHTS
The majority of our projects, required to double our energy growth between 1999 and the end of 2003, have been delivered. The four principal projects to be completed in 2003, the Scarab Saffron fields offshore Egypt, the Ballylumford power station upgrade in the UK, Atlantic LNG Train 3 in Trinidad and the Karachaganak field development in Kazakhstan, remain on schedule. Our businesses continue to perform well and we are strongly placed to deliver our 2003 targets for production and for return on average capital employed.

During 2002, BG increased its proved gas and oil reserves by 31% through commercialisation of discoveries, reserves upgrades and acquisitions. Over the last 12 months, we completed 25 exploration and appraisal wells, of which 18 were successful (72% success rate). Particular appraisal successes have been Buzzard in UK waters and Sienna in the Nile Delta. Over the past five years our annual average success rate in exploration and appraisal wells has been 71%.

Today, we have an outstanding hydrocarbon resource base: 8.7 billion barrels of oil equivalent, of which more than 4.6 billion barrels are proved and probable reserves. This represents over 64 years of potential production at 2002 production rates. Our reserves replacement ratio in 2002 was 433%. Over the past five years, BG’s organic reserves replacement ratio has averaged over 290% while our proved and probable reserves have increased at a compound annual growth rate of 17%. We have an excellent record in translating these finds into economic projects; this resource base therefore provides BG with an exceptional platform for profitable growth for many years to come.

External benchmarking studies showed BG’s Exploration and Production business (E&P) as a top quartile performer in three

BG GROUP PLC 2002 3

	FINANCIAL HIGHLIGHTS
	BG – CONTINUING OPERATIONS	2002		2001
	Turnover (£m)(i) (ii)	2 610		2 508
	Total operating profit (£m)(ii)	888		833
	Earnings (£m)(ii)	424		465
	Earnings per share (p)(ii)	12.0		13.3
	Cash inflow from normal operating activities (£m)(iii)	1 015		837
	Capital investment (£m)	1 510		1 079
	Net borrowings (£m)	(1 002	)	(538	)
	Net assets (£m)	3 348		3 530
(i)	Purchased gas sales have been presented net. There is no impact on operating profit – see note 1, page 81
(ii)	Excluding exceptional items – see note 5, page 90
(iii)	Excluding one-off items – see note 28(A)(c), page 110

year average finding and development costs, annual unit operating costs and reserves replacement. We have driven unit lifting costs down by 50% since 1997. Unit operating costs have fallen by 34% over the same period, with the gains we have made on lifting costs being partially offset by the effect of portfolio changes and higher oil prices. With our finding and development cost target for 2003 of $3.20 per barrel of oil equivalent (boe) and a target for unit operating costs of $2.75 per boe, we aim to achieve an industry leading, full-cycle cost of less than $6 per boe.

Liquefied Natural Gas (LNG) is another of our core activities. Our skills in this segment of the gas chain enable us to move our gas reserves long distances to markets with unsatisfied demand for natural gas. In 2002, we saw the start of Atlantic Train 2 in Trinidad and Tobago and good progress with Train 3. There were major advances on Egyptian LNG and a good performance in the first year of operation of the US subsidiary which manages the LNG importation business based in the Lake Charles terminal off the Gulf of Mexico. In November 2002, we also received from the Italian Government and Port authorities approval to construct and operate a new LNG importation terminal in Brindisi off the south-east coast of Italy.

Access to markets is also achieved through Transmission and Distribution (T&D). During the year, our T&D throughput increased by 4% and we added over 1 400 km of new gas distribution network. We revised our 2003 and 2006 T&D volume targets to reflect adverse economic conditions in Argentina and the delayed power market growth in Brazil and the greater than anticipated availability of high sulphur fuel oil.

Power Generation (Power), a key part of building markets, is an important element of our integrated strategy. Gas-fired power generation provides important base loads to pull gas through to developing markets. We have consciously designed our Power business to minimise exposure to merchant risk with our revenues anchored by power purchase agreements based on plant availability and operating cost performance. This year saw a 19% increase in profits from Power and we achieved our 2003 power capacity target ahead of schedule.

We also explore opportunities to create new businesses, particularly where these exploit synergies with our distribution activities and enhance existing assets. We are developing new businesses in three market segments: natural gas vehicles, domestic combined heat and power, and telecommunications networks.

STRATEGY
Our essential strategy and direction continue unchanged: strong growth and good returns from an integrated and internationally diversified energy business with the emphasis clearly on gas; developing reserves, building and accessing markets; and participating in the mid-stream enabling businesses. Our high performing E&P business is and will remain the centre of gravity of BG. Given our competitive strengths, LNG is rich in value-adding opportunities and we will continue to emphasise this area, capitalising on success in the Atlantic and Mediterranean basins. The focus in distribution will be, for the present, the improvement of returns from this segment. Meanwhile, we will continue efforts to expand our strongly performing Power segment. Power generation is and, we believe, will continue to be a major source of growth in the demand for natural gas.

BG AT WORK
BG’s skills across the value chain are central to the realisation of our strategy. It is in the execution of our projects that BG truly excels and this depends on having the right people. We would like to take this opportunity to pay tribute to what they have achieved during 2002.

Our successes in the past few years in exploiting opportunities throughout the gas chain have demonstrated the depth of our skills and expertise.The entries in the 2002 Chairman’s Awards (for excellence in health, safety and environment) and the inaugural Chief Executive’s Technology Innovation Awards have epitomised the strength of BG’s skills and the pride our staff take in their work.

Underpinning these competencies is a performance culture, which is now the hallmark of BG.We are creating an environment

4 BG GROUP PLC 2002

FINANCIAL CALENDAR
Annual General Meeting	22 April 2003
Ex-dividend date for 2002
final dividend	19 March 2003
Record date for 2002
final dividend	21 March 2003
Payment of 2002 final dividend
Shareholders	2 May 2003
ADR holders	12 May 2003
Financial year end	31 December 2003
CHAIRMAN'S AND CHIEF EXECUTIVE’S STATEMENT

where every individual in the organisation has a clear sense of their contribution to Group goals and a real desire to take personal responsibility to search for improved solutions.

OPERATING RESPONSIBLY
Our Statement of Business Principles has been reviewed by the Board. It continues to provide a firm foundation of values and operating principles.

We remain strongly committed to the health, safety and security of our employees and of all those affected by our operations. Over the last few years, we have made great strides in improving safety. We had an injury rate of 0.7 per million hours worked this year, continuing the downward trend from previous years (0.9 in 2001, 1.2 in 2000). However, despite our efforts, we deeply regret that there were two contractor fatalities at our Karachaganak project in Kazakhstan in 2002. Any fatality is unacceptable. We therefore make considerable efforts to identify and share lessons learnt with our partners and contractors.

Although gas is a relatively clean and efficient fuel, we place our responsibility to minimise the impact of our operations on the environment at the core of our business planning. We operate within a company-wide environmental management system to minimise environmental impacts. We have made a commitment that all major activities where we have a controlling interest will achieve external certification of their environmental management systems. During 2002, BG assets in Bolivia, Brazil, Northern Ireland and Egypt achieved ISO 14001.

We recognise that our ‘licence to operate’ depends in part on the value we can return to the communities among whom we develop our projects. As well as community investment projects managed through the BG Foundation with its theme of skills transfer, we aim to develop awareness of how our businesses can support social and economic development in the communities.

With respect to governance, we are witnessing the emergence of new standards. BG Group is already well positioned to meet these new requirements. Our governance system, in which your Board is closely engaged, is based on our clear and strongly held Business Principles. We have robust processes to identify

and manage risk at asset, regional and Group levels. We will continue to maintain the highest standards of governance throughout the Group, based on our absolute commitment to integrity and high ethical standards in all our operations.

We made two changes to your Board of Directors during the year. In August, Ashley Almanza was appointed Chief Financial Officer and Executive Director on the Board. Ashley, who has held a number of senior finance positions with the Group over the last nine years, succeeds Andrew Bonfield. We would like to thank Andrew for the commitment and leadership he brought to the Company in his time with us. In September, Sir Robert Wilson, currently chairman of Rio Tinto plc and non-executive director of Diageo plc, was appointed non-executive Director.

We would also like to thank our shareholders. Many of you have been with us for some time and have witnessed the Group’s remarkable transformation from a national utility to a major player in the world’s liberalising energy markets.

THE FUTURE
Your Company’s goal is to deliver top quartile shareholder returns as measured against the performance of our energy industry peers. We have already established an enviable track record. With the continuing support of our shareholders and our people, we are well positioned to seize the wealth of opportunities in the global market.

6 BG GROUP PLC 2002

	BG IS AN INTEGRATED GAS COMPANY WITH ACTIVITIES ACROSS THE WHOLE RANGE OF GAS OPERATIONS, FROM THE RESERVOIR TO THE FINAL CONSUMER.
BUSINESS REVIEW

		BG HIGHLIGHTS 2002
>		Total operating profit* up 7%
>		Underlying total operating profit* growth of 13% at constant upstream gas and oil prices
>		E&P volume up 25%
>		Proved reserves replacement ratio 433%
>		Finding and development costs $3.20 per boe
>		Invested £1.5 billion
>		Acquired E&P assets in India
>		Kashagan declared commercial
>		Production commenced at Atlantic LNG Train 2 and NCMA
	*	Excluding exceptional items – see note 5, page 90

STRATEGY
We focus on understanding, building and supplying natural gas markets. Our high performing Exploration and Production (E&P) business, which finds and develops reserves, remains the centre of gravity of our activities. The increasingly opportunity-rich Liquefied Natural Gas (LNG) segment, together with Transmission and Distribution (T&D) and Power, form our downstream activities and give us a complete range of skills across the gas chain.

OVERVIEW
BG is an international business and is currently active in some 20 countries across five continents. We believe that our combination of skills and experience across the gas chain and our geographical diversity are key to the creation of shareholder value.

In a world where gas is abundant, affordable and the cleanest of fossil fuels, it is increasingly becoming the fuel of choice. Worldwide demand for gas grew by over 2.5% per annum over the 20 years from 1980 to 2000. Forecasts in the Energy Information Administration’s International Energy Outlook 2002 indicate that the growth in demand for natural gas to 2020 will be substantially stronger than for other major sources of energy. This growth is forecast to be particularly strong in developing countries. BG expects this, together with the continuing liberalisation of gas markets around the world, to continue

to generate valuable opportunities for companies such as BG that are experts in gas.

We have four major business segments: E&P; LNG; T&D; and Power. Further details about these segments are on pages 7-10. Our Other activities segment includes New Business, which develops opportunities that complement our core businesses, and certain corporate functions.

The principal portfolio changes in 2002 were the acquisition of exploration and production assets in India and the exchange of North Sea assets with BP. In February 2002, we completed a $350 million (£247 million) acquisition of a 30% interest in the Panna/Mukta oil and gas fields and the Tapti gas field, off the west coast of India. This acquisition established India as a core geographic area for BG. The North Sea exchange represented a significant consolidation of our United Kingdom Continental Shelf (UKCS) portfolio in a transaction which is believed to be one of the largest asset exchanges in the recent history of the North Sea (further details on page 14). We also increased our interest in the North Caspian PSA, which includes the large Kashagan field, and were awarded a 100% interest in seven exploration licences off the eastern coast of Spain.

In 2001, the main divestments were the Storage segment and a partial interest in the Phoenix Natural Gas distribution business.

Please see information regarding certain forward-looking statements on page 130 of this report.

BG GROUP PLC 2002 7

BUSINESS REVIEW

A number of assets, principally Transco, were demerged to Lattice Group in October 2000. The sale of our interest in Dynegy Inc. was the main disposal in 2000.

BUSINESS SEGMENTS

Exploration and Production (E&P)
This segment comprises exploration, development, production and marketing of hydrocarbons with a focus on gas.

• 2002 production performance: 373 000 boed – an increase of 25% on 2001

• 2003 production target: 440 000 boed

• 2006 production target: 530 000 boed

The chart above shows that, during the period from 2000 to 2002, approximately 70% of our E&P production was gas.

External benchmarking studies, based on 2001 data, showed BG as a top quartile performer in three year average finding and development costs, annual unit operating costs and reserve replacement. Our goal is to maintain this top quartile performance and we will continue to use benchmarking studies to monitor our performance relative to our peers.

E&P’s worldwide finding and development costs (including the acquisition of unproved properties) were $3.20 per boe in 2002, based upon changes in proved reserves excluding purchases, sales and production. Over the last three years, worldwide finding and development costs averaged $3.22 per boe. The annual unit operating costs in 2002 increased slightly from 2001’s $2.96 per boe to $3.12 per boe, reflecting the impact of oil price related service costs and an increase in tariff costs, predominantly because of transportation and processing fees on production from the Jade and Blake fields (which began production in February 2002 and June 2001 respectively).

Our 2003 E&P cost targets are $3.20 per boe for finding and development costs, and $2.75 per boe for operating expenditure. Both these targets assume normalised oil prices as set out in the Risk Factors section on pages 32 and 33. The operating cost target was revised in November 2002 from the $2.40 per boe set in 1999 primarily to reflect the higher royalty and tariff costs associated with our subsequent Bolivian and Indian acquisitions and changes to our production mix. The change in mix is principally due to greater than originally planned volumes from the UK which, although a strong contributor to profits, is a higher unit cost area.

	E&P HIGHLIGHTS 2002
>	E&P volume up 25%
>	Unit finding and development costs of $3.20 per boe
>	Proved reserves replacement ratio of 433%
>	72% exploration and appraisal success rate
>	Proved reserves of 1 919 mmboe, up 31%
>	Proved and probable reserves of 4 623 mmboe, up 11%
>	NCMA commenced production in Trinidad

KEY E&P ASSETS OPERATING IN 2002
Armada	United Kingdom
Blake Area	United Kingdom
Bongkot	Thailand
CATS	United Kingdom
Dolphin	Trinidad and Tobago
Easington Catchment Area	United Kingdom
Elgin/Franklin	United Kingdom
Everest	United Kingdom
J-Block Area	United Kingdom
Karachaganak	Kazakhstan
Lomond	United Kingdom
Miskar	Tunisia
NCMA	Trinidad and Tobago
Panna/Mukta and Tapti	India
Rosetta	Egypt

	LNG HIGHLIGHTS 2002
>	New LNG importation capacity service at Lake Charles, USA
>	Atlantic LNG (ALNG) Train 2 production commenced
>	Egyptian LNG (ELNG) Train 1 Sale and Purchase Agreement signed and construction commenced
>	ALNG Train 4 FEED completed
>	Early works started on ALNG Train 4 and ELNG Train 2
>	Approval received to construct Brindisi LNG importation terminal in Italy
	KEY LNG ASSETS OPERATING IN 2002
	Atlantic LNG Trains 1 and 2	Trinidad and Tobago
	LNG vessels	Various
	Lake Charles	USA

In 2002, proved reserves increased by 31% to 1 919 mmboe from 1 466 mmboe in 2001, after production of 136 mmboe, acquisition of 111 mmboe and disposal of 26 mmboe.

Proved reserves upgrades from existing fields and from projects that received sanction during the year accounted for 504 mmboe. The principal fields that contributed to these reserves were in Egypt, Kazakhstan and the UK.

The industry-leading proved reserves replacement ratio in 2002 was 433% (264% in 2001). Over the last three years, BG’s proved reserves replacement ratio averaged 333%.

The chart above shows the proved and probable reserves for the last three years. Year end proved and probable reserves increased in 2002 by 11% to 4 623 mmboe from 4 149 mmboe in 2001. The principal increases came from fields in Egypt, Kazakhstan and India.

During 2002, the key assets to start production were the Hibiscus field within the North Coast Marine Area (NCMA) development in Trinidad, Jade and the second phase of the Easington Catchment Area (ECA) fields in the UKCS.

Twenty-five exploration and appraisal (E&A) wells were completed during 2002, 18 of which were successful, resulting in a 72% success ratio. When considered along with our performance in 2001 (71%) and 2000 (100%), this demonstrates a consistently strong level of achievement.

Between 1998 and 2002, BG has achieved a 71% annual average success rate in exploration and appraisal wells. This success flows from our technical expertise and an active portfolio management system, which aims to ensure that only those projects of the highest quality receive funding.

The principal exploration successes were the Kalamkas discovery in the Caspian Sea, the Solar discovery in Egypt’s West Delta Deep Marine Concession (WDDM) and the Panda discovery offshore Italy.

Appraisal operations were completed on the Buzzard oil field in the northern North Sea, one of the largest oil discoveries in the UK North Sea in the last ten years. During the year, activities continued on the appraisal of the Sapphire and Sienna fields in Egypt and on the Kashagan field in the Caspian Sea.

Liquefied Natural Gas (LNG)
This segment combines the development and use of LNG import and export facilities with the purchase, shipment and sale of LNG and regasified natural gas.

• 2002 production performance: 1.1 mtpa – an increase of 38% on 2001

• 2003 production target: 2.3 mtpa

• 2006 production target: 6 mtpa

Our 2003 target was revised from 1.9 mtpa in November 2002 to reflect both increased equity from that assumed when our target was set in 1999 and from improved operational performance

BG GROUP PLC 2002 9

BUSINESS REVIEW

at Atlantic LNG (ALNG) in Trinidad and Tobago.

Our experience of the LNG export sector, gained from the ALNG export project, gives BG a strong position in the fast-track development and operation of LNG export facilities. During 2002, ALNG Train 2 came into operation, while construction continued on ALNG Train 3 and began on ELNG Train 1.

The skills that enabled the rapid commercialisation of ALNG Trains 1, 2 and 3, together with ELNG Train 1, are now being applied to ALNG Train 4 and ELNG Train 2. First production from ELNG Trains 1 and 2 is anticipated in the third quarter of 2005 and mid-2006 respectively. First production from ALNG Train 4 is expected in 2006 and, in Indonesia, first production from the new Tangguh LNG export project is due in 2007.

We also seek to deliver our equity gas reserves and those of others to attractive markets. In the USA, BG LNG Services, LLC, has contracted for all the uncommitted capacity service, including that of the forthcoming expansion at the Lake Charles importation terminal, for 22 years from 1 January 2002. During 2002, we used this capacity service to process 44 LNG cargoes into this key market.

BG has plans for new LNG importation terminals. In Italy, we are developing a new terminal at Brindisi, one of the four cornerstones of our Atlantic Basin LNG strategy, and in India we are pursuing a new LNG importation project at the port of Pipavav in Gujarat State.

As well as owning two LNG vessels which are committed on a long-term basis to a third party, we currently have long-term charters over four additional vessels. One is currently being used to deliver ALNG Train 2 volumes to the USA and the other three are either sub-chartered on variable term contracts or used to transport LNG for BG’s account. We also entered into two short-term charters in 2002.

To add to its fleet, BG has agreed to a long-term charter for a new LNG vessel from the second half of 2003. In addition, we have agreed to a sale and lease-back arrangement for the new 138 000 cubic metre LNG vessel ordered in 2001, which is due to enter service in the second quarter of 2004. We have also secured options for the purchase of further new LNG vessels which, if exercised, would provide for the delivery of up to five additional vessels between late 2005 and 2006. BG released the option for a sixth vessel in early 2003.

Transmission and Distribution (T&D)
This segment comprises the development, ownership and operation of major gas pipelines and distribution networks, and the supply of gas through these to the end customer.

• 2002 throughput performance: 11.0 bcma – an increase of 4% on 2001

• 2003 throughput target: 11.7 bcma

• 2006 throughput target: 14.0 bcma

The 2003 and 2006 T&D throughput targets were revised in November 2002.

	T&D HIGHLIGHTS 2002
>	Distribution assets supply gas to 2.7 million consumers worldwide
>	Added over 1 400 km of new gas distribution network
>	Comgas volume increased 31%

KEY T&D ASSETS OPERATING IN 2002
Bolivia-
Brazil pipeline	Bolivia/Brazil
Comgas	Brazil
Gujarat Gas	India
Interconnector	United Kingdom

10 BG GROUP PLC 2002

                BUSINESS REVIEW

	POWER HIGHLIGHTS 2002
>	2.5 GW power capacity target for 2003 achieved in 2002
>	San Lorenzo entered commercial operations
>	New 2006 capacity target of 2.7 GW

KEY POWER ASSETS OPERATING
IN 2002
Premier Power
(Ballylumford)	United Kingdom
Seabank Power
Phases 1 and 2	United Kingdom
San Lorenzo	Philippines
Santa Rita	Philippines

The revision principally reflected the adverse economic conditions in Argentina and the effects in Brazil of the slower than anticipated development of a thermal power market and higher than anticipated supplies of high sulphur fuel oil, which competes in some market segments with natural gas. Despite this, Comgas, Brazil’s largest distribution company, in which BG has a 60.05% interest, grew its annual volume by 31%.

Good performance was achieved in a number of our smaller distribution assets.

Most of our T&D assets have penetrated only part of their potential natural gas markets. In the future, we intend to focus upon returns from these assets through continued operational excellence and expansion.

An agreement in December 2002 with Petrobras extended our capability to deliver our Bolivian gas to Comgas until 2011. BG is the only company, other than Petrobras, to achieve this level of integration.

Power
This segment comprises the development, ownership and operation of natural gas-fired power generation plants.

• 2002 power capacity: 2.5 GW – an increase of 9% on 2001

• 2003 power capacity target: 2.5 GW

• 2006 power capacity target: 2.7 GW

We have already reached our 2003 power capacity target with the start of operations at the San Lorenzo power station in the Philippines, and based upon progress towards developing the Barca power project in Tunisia, we have added a 2006 target (see chart above).

This segment is a strong and reliable contributor to BG’s profits and offers attractive rates of return.

All our power stations are gas-fired and have long-term Power Purchase Agreements, under which payment is based largely on availability, not the actual level of output.

With the anticipated replacement in the second quarter of 2003 of 600 MW of existing capacity with CCGT at Ballylumford, in excess of 80% of our capacity will be highly efficient CCGT units.

New Business
We are currently developing new businesses in three market areas which exploit synergies with our existing activities. Our aim is to grow these into profitable businesses which complement our core businesses.

Natural Gas Vehicles: Iqara Gas Natural, a BG subsidiary, provides compression services to the natural gas vehicle (NGV) market in São Paulo, Brazil. In India, both Gujarat Gas and Mahanagar Gas have Compressed Natural Gas stations serving the NGV market.

BG GROUP PLC 2002 11

OPERATING RESULTS
The table below shows the turnover and total operating profit/(loss) excluding exceptional items for BG’s continuing operations(a)(d)
			GROUP TURNOVER (b)				TOTAL OPERATING PROFIT/(LOSS) (c)
	2002 £m		2001 £m		2000 £m		2002 £m		2001 £m		2000 £m
Exploration and Production	1 555		1 283		1 188		731		606		513
Liquefied Natural Gas	309		81		31		8		29		25
Transmission and Distribution	541		834		766		50		119		78
Power Generation	189		192		183		124		104		102
Storage(e)	–		75		77		–		21		3
Other activities	66		90		54		(25	)	(46	)	(33	)
Less: intra-group sales	(50	)	(47	)	(27	)
	2 610		2 508		2 272		888		833		688
Geographical analysis
UK	1 310		1 246		1 069		565		489		297
Americas	793		786		725		56		113		107
Rest of world	507		476		478		267		231		284
	2 610		2 508		2 272		888		833		688

(a)	For information on exceptional items, see note 5, page 90.
(b)	Gas trading activity within the Exploration and Production segment has been re-presented on a net basis, see note 1, page 81.
(c)	Total operating profit/(loss) includes BG’s share of operating profits less losses in joint ventures and associated undertakings.
(d)	For information regarding discontinued operations, see the five year summaries on page 122.
(e)	In November 2001, BG disposed of the assets comprising the Storage segment.

Domestic Combined Heat and Power (DCHP): BG is developing combined heat and power generators for use in domestic and small commercial premises. In January 2002, agreement was reached between MicroGen, BG’s DCHP business, and Rinnai of Japan, a leading boiler and water heater manufacturer, to finalise development of MicroGen units. A product launch in the UK is scheduled for 2004. Telecommunications Networks: During 2002, we increased the customer base of Iqara Broadband, our telecommunications subsidiary in India, to around 6 000 customers in Surat and the neighbouring city of Vadodara in Gujarat State. We are looking at other opportunities and are currently launching similar businesses in Mumbai and elsewhere in Gujarat State, with the first customers in both regions signed up in early 2003. We will also be launching a telecommunications network service in São Paulo, in 2003.

CAPITAL INVESTMENT
Major E&P projects incurring capital investment in 2002 included the acquisition of assets in India, additional equity in the Kashagan field, continued progress on Phase 2 of Karachaganak and the WDDM, NCMA, and ECA fields. Within the other business segments, expenditure was incurred mainly on the ALNG expansion, Comgas’ transmission and distribution networks and the Premier Power CCGT plant. Total capital investment in the year was £1.5 billion.

Our capital investment for 2003 is expected to be about £0.8 billion. Anticipated major projects include: continued development of Karachaganak, WDDM, the ALNG and ELNG projects and the Comgas network.

Despite the planned £5.6 billion investment between 1999 and 2003, gearing is expected to remain below 25%.

Key risks and assumptions
The key risks and assumptions surrounding the 2003 and 2006 targets are set out in the Risk Factors section on pages 32 and 33.

12 BG GROUP PLC 2002

BG GROUP PLC 2002 13

14 BG GROUP PLC 2002

BG HAS ACTIVITIES IN SOME 20 COUNTRIES ACROSS FIVE CONTINENTS. OUR SIX CORE GEOGRAPHIC AREAS ARE UK, TRINIDAD AND TOBAGO, THE SOUTHERN CONE OF SOUTH AMERICA, EGYPT, KAZAKHSTAN AND INDIA. IN ADDITION, WE HAVE ACTIVITIES IN NORTH AMERICA, THE ASIA PACIFIC REGION AND OTHER PARTS OF THE MEDITERRANEAN BASIN.

COUNTRY REVIEWS

UNITED KINGDOM – CORE AREA
In the upstream segment, we have a major exploration and production business on the UKCS with interests in more than 30 fields. We sell our UKCS gas on a wholesale basis, under both long- and short-term contracts, and are currently producing approximately 8% of the UK’s total gas supply.

Our downstream businesses include power generation, an equity interest in the UK-Continent Interconnector pipeline and participation in Northern Ireland’s natural gas industry. Our Storage segment and related assets were sold in November 2001.

Upstream
BG-operated fields on the UKCS include the Armada complex and the South West Seymour field in the central North Sea, the Blake Area in the Outer Moray Firth and some of the Easington Catchment Area (ECA) fields in the southern North Sea. We also hold a majority interest in the Central Area Transmission System (CATS) offshore pipeline, plus interests in a number of non-operated fields.

In May 2002, BG and BP signed what is believed to be one of the largest asset exchanges in the recent history of the UK North Sea, significantly consolidating our asset base, particularly in the Moray Firth. Under the terms of the deal, we acquired BP’s interest in the Atlantic and Glenelg discoveries, increased our stake in the Neptune and Elgin/Franklin fields and associated infrastructure, and

acquired interests in three exploration blocks in exchange for various BG interests including the Brae Area fields and £21.5 million in cash.

We continued to rationalise our UK portfolio by disposing of our 60% equity in the southern North Sea block 47/15b, containing the Rose gas discovery. It was sold for £7.32 million and in addition we acquired a further 1.5% interest in the BG-operated Armada complex, increasing our total Armada equity to 46.77%. Completion of this transaction is expected in the first quarter of 2003.

Armada and South West Seymour
We have a 46.77% interest in, and are the operator of, the Armada fields (Fleming, Drake and Hawkins) which cover over 57 sq km and span five exploration blocks. The estimated original gross reserves were 1.2 tcf and 62 mmbbl of condensate and natural gas liquids. First gas was produced in October 1997. A Phase 2 drilling programme, designed to extend the field’s plateau and increase its life to 2010, began in December 2001 and the three well programme is now complete. Gas is exported via the CATS pipeline to Teesside and liquids are transported through the Forties pipeline system to Cruden Bay. Following the expiry of our field-dedicated gas sales contracts in September 2002, our equity gas from Armada is now sold on medium- or short-term contracts or on the spot market.

BG also operates the South West Seymour field (BG 57%), which lies to the east of the Armada fields. The field was discovered in October 2002 and was drilled following the Armada Phase 2 drilling programme, benefiting from logistical and operational synergies to deliver the project on time and under budget. First production from South West Seymour is scheduled for March 2003 following minor modifications to the Armada platform to accommodate the additional production. Our equity gas and liquids from the field will be sold on a similar basis to our Armada production.

Blake Area
BG operates the Blake Area (BG 44%). The first phase, focusing on the Blake Channel development, comprises a sub-sea tie-back to the adjacent Ross field infrastructure. First oil production from the Blake Channel commenced in June 2001, just 18 months after project sanction and approximately 10% under budget. Estimated original gross reserves were 70 mmboe. In November 2002, we received DTI approval to develop Blake Flank, an extension of the Blake Channel. Estimated original gross reserves are 20 mmboe, and first oil production from Blake Flank is targeted for the third quarter of 2003.

ECA Phase 1 and Juno
The BG-operated Neptune and Mercury gas fields in the southern North Sea have been in production since December 1999, having been developed as the first phase

DRILLING ACTIVITIES	BG GROUP PLC 2002	15
CONTINUED IN THE NORTH
SEA DURING 2002 (LEFT).

COUNTRY REVIEWS

of the ECA project and exporting production via BP’s Cleeton/Dimlington system. As part of our asset exchange with BP, we acquired an additional 18% interest in Neptune, giving us an increased holding of 79%. Our share of Mercury remains at 73.33%.

ECA Phase 2, the Juno project, consists of the BG-operated Minerva and Apollo gas fields (BG 65%) and the BP-operated Wollaston and Whittle gas fields (BG 30.77%). First gas from Juno was achieved on 31 December 2002 with the flow of gas from the Whittle field. The Wollaston and Minerva fields came on-stream in the following week, and first gas from the Apollo field is expected in April 2003. The BG-operated Artemis gas discovery is currently being evaluated.

In the UKCS 20th Licensing Round in 2002, BG was awarded a licence for block 47/3h (BG-operated, 65%) adjacent to the Juno development in the southern North Sea.

Everest and Lomond
Production from the Everest and Lomond fields in the central North Sea (BG holds interests of 57.79% and 61.11% respectively) started in May 1993. Estimated original gross reserves were 320 mmboe. Gas from these fields is exported via the CATS pipeline, with the majority sold to Teesside Power Limited under a long-term sales contract. Produced liquids are transported through the Forties pipeline system.

J-Block Area
BG holds a 30.50% interest in the Judy and Joanne fields which commenced production in 1996. During 2002, a three well drilling programme was successful in proving additional reserves and increasing the fields’ production rates. Gas from the J-Block Area is transported via the CATS pipeline and liquids are transported via the Norpipe system to Teesside.

We also hold a 35% interest in the high pressure/high temperature Jade gas condensate field which commenced production in February 2002. A four well development programme was completed on the field in 2002 and during the drilling programme the Jade Deep discovery was made in an underlying reservoir. It has been developed with the fourth Jade development well. Oil and gas from the Jade field flows to the nearby Judy platform for processing and onward export. In the third quarter of 2002 the Jade field reached its expected plateau rate and the overall production rate from the J-Block Area fields has now reached a peak of over 450 mmscfd of gas and 70 000 bopd.

Elgin/Franklin
BG increased its interest in the Elgin/Franklin fields to 14.11% during 2002 as part of the asset exchange with BP (see page 14). These high pressure/high temperature gas condensate fields began production in 2001 with estimated original gross reserves of 711 mmboe.

Elgin/Franklin gas is exported, via the Shearwater Elgin Area (SEAL) pipeline (BG 7.86%) to onshore gas processing facilities at Bacton in Norfolk. Fourteen Elgin/Franklin wells have been drilled and a gross peak production rate of over 150 000 barrels of condensate per day and 550 mmscfd of gas has been achieved.

As part of the BP asset exchange, we also acquired an interest in the Glenelg field, a potential Elgin/Franklin satellite, by acquiring BP’s 14.70% interest in Blocks 29/4d and 29/4f.

Buzzard
The Buzzard oil discovery was announced in June 2001. The discovery was made in an area covered by two adjacent licences. In one we hold a 19.99% interest and in the other a 29.41% interest. A six well appraisal programme was completed in June 2002 and recoverable reserves are estimated to be in excess of 400 mmboe, making it one of the largest oil discoveries in the UK North Sea in the past ten years. A new 3D seismic survey was completed in August 2002, and development planning is under way with sanction anticipated by mid-2003.

Atlantic and Cromarty
As part of the asset exchange with BP (see page 14), BG acquired a 75% stake in, and operatorship of, the Atlantic gas discovery in the Outer Moray Firth. It is expected to be developed together with the adjacent Cromarty gas discovery (BG 10%). Pre-sanction study work is continuing, examining the best options

16 BG GROUP PLC 2002

BLEO HOLM FLOATING PRODUCTION, STORAGE AND OFFLOADING VESSEL, UK (BELOW).
HIBISCUS PRODUCTION PLATFORM, NCMA (RIGHT), AND ATLANTIC LNG TRAINS 1, 2 AND 3, TRINIDAD AND TOBAGO (FAR RIGHT).

COUNTRY REVIEWS

for developing the fields. Depending on the option chosen, first production is expected to start in late 2005 or 2006. Through the BP asset exchange we also acquired operatorship and a 41.67% equity in two adjacent blocks (14/26b and 14/27a) which have the potential for further gas discoveries that could be tied back to the Atlantic field.

Central Area Transmission System (CATS)
We have a 51.18% interest in the CATS pipeline that transports gas from the Everest, Lomond, Andrew, Armada, Judy, Joanne, Jade, Erskine and Banff fields, and the fields in the Eastern Trough Area Project (ETAP) to Teesside. The 404 km long, 36" diameter pipe has an approximate peak gas capacity of 1 700 mmscfd. Onshore, CATS consists of two plants providing processing facilities to the Armada, Everest, Lomond, Erskine, ETAP and Banff fields. The first plant became operational in 1997 and the second came on-stream in 1998.

SEAL and SILK
BG has a 7.86% interest in the Shearwater Elgin Area pipeline (SEAL) which was completed in 2000 to export gas to Bacton from the Elgin/Franklin and Shearwater fields. Our interest was increased from 6.88% as part of the BP asset exchange. This pipeline began exporting gas from the Elgin field in May 2001. We also have a 15.98% interest in the SEAL Interconnector Link (SILK) pipeline that provides direct access from SEAL into the UK-Continent Interconnector pipeline.

Downstream
BG has a 25% interest in Interconnector (UK) Limited, the company that owns the interconnector pipeline linking the UK and Continental European gas transmission systems. The pipeline first became operational in October 1998 and can transport up to 20 bcm per year of gas from Bacton in the UK to Zeebrugge in Belgium, and 8.5 bcm per year in the opposite direction. BG and some of the other partners have committed to increase the reverse flow capacity to 16.5 bcm per year with effect from December 2005. Although the majority of our capacity has been sublet on medium- and long-term contracts, we retain some capacity for shorter-term sales of both capacity and gas. This allows us to market capacity and gas in the UK and Continental Europe, particularly at emerging hubs such as Zeebrugge.

Premier Transmission Limited (BG 50%) owns and operates the Scotland to Northern Ireland pipeline (SNIP) and was granted a 35 year minimum term licence to transport gas to Northern Ireland in 1996. The pipeline first came into operation in October 1996 and the maximum daily pipeline capacity is currently 8 mmcmd.

BG has a 51% stake in Phoenix Natural Gas Limited (Phoenix), the only natural gas distributor in Northern Ireland. Phoenix was awarded a licence in September 1996, granting it 20 years’ exclusivity for the transportation of gas in the licence area and exclusive rights of

supply for eight years to small customers. As at 31 December 2002, Phoenix had approximately 45 000 domestic customers and 5 000 industrial and commercial customers in the Greater Belfast area.

Premier Power Limited (BG 100%) owns and operates the 1 067 MW Ballylumford power station that underpinned the development of the SNIP. A new 600 MW combined cycle gas turbine (CCGT) power plant is expected to commence full commercial operations in the second quarter of 2003. This new plant will replace some of the existing ageing and less efficient generating capacity at Ballylumford. Currently, 833 MW of the full 1 067 MW capacity is generating power, with some older capacity available either as back-up or for when additional markets are developed.

The 1 130 MW Seabank CCGT power station near Bristol is owned and operated by Seabank Power Limited, a 50:50 joint venture between BG 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. With an initial gross efficiency of over 57% compared with about 35% efficiency for conventional coal- or oil-fired generation, Seabank is one of the UK’s most efficient power stations. BG sells its UKCS gas on a wholesale basis at the entry to the UK’s National Transmission System (NTS) and ships gas through the NTS to sell at the National Balancing Point under long-,

BG GROUP PLC 2002 17

medium- and short-term contracts with approximately 30% of our UK 2002 production sold on a day-to-day basis into the spot market. Our UK gas marketing activity is specifically focused on obtaining best value for our upstream production, and we further optimise our portfolio through the use of rented storage.

FAROE ISLANDS
BG has a 39.96% interest in the Faroes Partnership, which drilled its first offshore well, close to the boundary with the UK, in November 2001. We chose not to participate in the well beyond commitment depth for technical reasons. In 2002, a well was drilled on the adjacent UK P1029 licence (BG 23.60%) to appraise the Faroes well. New 3D seismic data was acquired in 2002 and, together with the well results, will be evaluated to enable future drilling decisions to be made.

TRINIDAD AND TOBAGO – CORE AREA
We have been operating in Trinidad and Tobago since 1989 and we continue to build on our position as a major gas player by developing and producing gas reserves off the east and north coasts for sale in local markets and for LNG exports.

East Coast Marine Area (ECMA)
The BG-operated Dolphin gas field (BG 50%) started production in March 1996. The platform is 52 miles off the east coast of Trinidad in Block 6(b). Original gross reserves are estimated at 2.6 tcf.

The Dolphin field is contracted to supply up to 275 mmscfd of gas to the National Gas Company of Trinidad and Tobago under a 20 year supply contract.

In 2002, BG and partner ChevronTexaco received approval from the Ministry of Energy and Energy Industries for the development of the Dolphin Deep and Starfish fields in adjacent Block 5(a) and Block E. We have a 50% interest in both blocks. Reserves from these discoveries are to be produced through the upgraded Dolphin facilities via sub-sea completions and pipelines to supply gas to Atlantic LNG (ALNG). These completions are expected to be the deepest sub-sea developments in Trinidad and Tobago waters to date.

ECMA is scheduled to supply 80 mmscfd to ALNG Train 3 from mid-2005.

In April 2002, BG and partners signed a PSC with the Government of Trinidad and Tobago for Block 3(a). The 614 sq km block is 40 km off the east coast of Trinidad in water depths of 100-300 feet. The block (BG 30%) is adjacent to Block 2(c), where BHP and partners have recently made significant gas and oil discoveries.

Under the Block 3(a) PSC terms, BG and partners have agreed to acquire 300 sq km of 3D seismic data and embark on a six well exploratory drilling programme.

North Coast Marine Area (NCMA)
We have a 45.88% interest in the NCMA Unit Area, which is 40 km off the north coast of Trinidad. The NCMA production

area includes three gas fields, Hibiscus, Poinsettia and Chaconia, with aggregated estimated original gross reserves of 2.4 tcf.

These three fields are being developed in up to four phases to supply gas to ALNG.

The Hibiscus production and drilling platform, currently the tallest and heaviest in Trinidad and Tobago, was successfully installed in September 2001. The 107 km, 24" pipeline from NCMA to ALNG has a capacity of 400 mmscfd.

NCMA is contracted to supply 240 mmscfd to ALNG Train 2 for 20 years, 125 mmscfd to ALNG Train 3 for two years and then 45 mmscfd for 18 years.

Development drilling operations began in late 2001 and seven Phase 1 and Phase 2 wells are scheduled to be completed on Hibiscus and Chaconia by the third quarter of 2003. Production began at the Hibiscus field in August 2002.

Phase 3 of the development involves the drilling of up to seven sub-sea wells, five on Poinsettia and one each on Hibiscus and Chaconia, with production scheduled to begin in 2009. A possible Phase 4 would involve the installation of compression facilities on the Hibiscus platform.

Atlantic LNG (ALNG)
The ALNG export facility is located at Point Fortin, on the south-west coast of Trinidad.

The first train of the ALNG liquefaction facility (BG 26%) came on-stream in 1999 and supplies markets in the USA, Spain and Puerto Rico.

18 BG GROUP PLC 2002

LAKE CHARLES LNG IMPORTATION TERMINAL, LOUISIANA, USA (LEFT AND FAR LEFT).
BG IS THE OPERATOR OF THE LOS SURIS FIELD, BOLIVIA (RIGHT).

ALNG Train 2 began operation in August 2002 with initial cargoes taken to the Lake Charles importation terminal. ALNG Train 3 is under construction and is expected to commence operation in the second quarter of 2003. BG has a 32.50% interest in both Trains 2 and 3. The BG-operated NCMA fields will supply 50% of the gas for Train 2 and 25% of the initial gas for Train 3.

LNG to be produced from gas supplied by BG and our upstream partners to Trains 2 and 3 has been sold under long-term contracts for import into the Elba Island LNG terminal in Georgia, USA. These LNG deliveries will start in the second quarter of 2003.

Trains 1 and 2 have capacities of 3.1 mtpa and 3.4 mtpa respectively, whilst Train 3 will also have a capacity of 3.4 mtpa.

A FEED study for the construction of a fourth ALNG train, with a capacity of 5.2 mtpa, was completed in February 2002. Early construction work is under way prior to commencement of the EPC contract. Negotiations continue between ALNG shareholders and the Government of Trinidad and Tobago to sanction the project, and it is anticipated that Train 4 will begin operations in 2006. Total production at ALNG would, as a consequence, rise to over 15 mtpa.

USA
In 2002, the first year of LNG operations in the USA, our subsidiary BG LNG

Services, LLC, received and processed 44 LNG cargoes through the Lake Charles LNG importation terminal in Louisiana. We have established a downstream marketing group based in Houston that optimises our LNG sales position and in 2002 we purchased and processed LNG from a wide range of sources including Qatar, Oman, Algeria and Nigeria in addition to the initial volumes from ALNG Train 2 in Trinidad and Tobago.

BG has a service agreement to utilise the available capacity at the Lake Charles terminal for 22 years from 1 January 2002. The terminal is well located for access to 15 major inter-state natural gas pipelines and currently has the capacity to receive, store, vaporise and deliver an average daily send-out of 630 mmscfd of gas, with a total storage capacity of 6.3 bcf. We can also utilise the terminal peaking capacity service and achieved a peak send-out rate in excess of 950 mmscfd in 2002. From 2006, the capacity is planned to expand to an average daily send-out of 1 200 mmscfd with total storage capacity of 9 bcf.

The Terminalling Service Agreement provides for BG LNG Services, LLC, to utilise approximately 80% of the capacity service of the Lake Charles terminal from 1 January 2002 to 31 August 2005, whilst the remaining capacity is committed to a third party. From 1 September 2005, BG will have the right to 100% of the capacity service, including the planned expansion.

SOUTHERN CONE OF SOUTH AMERICA – CORE AREA
BG has a significant position throughout the gas chain in the natural gas market in South America’s Southern Cone. Although this has been a difficult year in macroeconomic terms, we remain active in Argentina, Bolivia, Brazil and Uruguay and participate in two major gas distribution businesses in the region: Companhia de Gas de São Paulo (Comgas) in São Paulo, and MetroGAS S.A. (MetroGAS) in Buenos Aires, the largest gas distribution companies in Brazil and Argentina respectively. Both Comgas and MetroGAS are regulated entities. BG is also pursuing new business ventures in the region, including telecommunications opportunities in the São Paulo region and providing compression services to the natural gas vehicle market in São Paulo.

ARGENTINA
BG has been active in the Argentine energy market for more than a decade, holding a diversified portfolio of upstream and downstream assets. In the upstream segment, we previously held a number of exploration blocks, the last of which was relinquished towards the end of 2002. Our most significant asset in Argentina is MetroGAS in which we have a 45.11% stake. Inevitably, Argentina’s deteriorating economic and regulatory environment has had a negative impact on MetroGAS. The Argentine Government has imposed a number of economic and political measures (as described below) which may restrict BG’s ability to exercise

BG GROUP PLC 2002 19

COUNTRY REVIEWS

its control over MetroGAS and management is monitoring this situation closely.

MetroGAS sales were £134 million in 2002 compared to £470 million in 2001 and £485 million in 2000. The decrease was mainly because of the dramatic devaluation of the Argentine Peso and the pesification of tariffs (the translation of prices then fixed in US$ into pesos at a 1:1 exchange rate). Volumes delivered decreased by 11.3% in 2002, mainly due to the economic recession and higher hydroelectricity availability leading to the displacement of gas-fired power demand.

MetroGAS is regulated by the Argentine national gas regulatory body ENARGAS, and was granted a licence in 1992 for 35 years, extendable for a further ten years. MetroGAS has exclusive gas distribution and supply rights in its licence area for customers consuming less than a certain volume of gas and can pass through to customers the price of purchased gas and transportation services. Its distribution margin is also regulated by ENARGAS. In January 2002, MetroGAS’s tariffs were pesified and the US Producer Price Index mechanism was abolished.

Also in January 2002, the Government of Argentina issued the Public Emergency and Exchange Regime Reform Law in response to the economic crisis. This resulted in profound changes to previously existing economic relationships. All aspects of the Argentine financial

crisis, including the pesification and freezing of tariffs, the amendment of the Convertibility Law, the massive devaluation, the political environment and the demise of the banking system, have contributed to the deterioration of the financial and operating health of all Argentine public service companies, including MetroGAS. During 2002, all licensed public service providers entered into a re-negotiation process with the government that should result in new terms for such licences and concessions. On 25 March 2002, MetroGAS announced that it had suspended principal and interest payments on all its financial indebtedness. Despite this, MetroGAS made some partial interest payments to all financial creditors on a pro-rata basis during 2002 (see page 45 for further details). To mitigate the impact of the crisis on MetroGAS’ cash position, MetroGAS has also reduced its capital investment programme to a level that is consistent with maintaining business continuity, safe operations and the quality of gas supplies, and with meeting the Argentine Basic Licence Rules.

BOLIVIA
With estimated equity gas reserves in excess of four tcf, BG is the second largest holder of reserves in Bolivia, including eight large exploration/exploitation blocks. We hold equity in Itau and Margarita, two of the largest discovered gas fields in the country, and have been producing from our 100% owned and

operated fields in the Los Suris and La Vertiente licences since their purchase in December 1999.

Our activities in Bolivia, combined with our interests in the Bolivia-Brazil pipeline and Comgas, establish a platform from which we can supply gas into the Brazilian market. In December 2002, we announced that we had extended our existing gas sales agreement with Comgas with a contract to supply up to 0.65 mmcmd of our equity gas during the period 2003 to 2011.

We have a 37.50% equity interest in the Margarita gas condensate field. Initial production is planned for mid-2004, with gas supplied to the Brazilian market through the existing YPFB-Petrobras gas sales contract. Future gas production is planned to be sold to the west coast of North America via the Pacific LNG consortium, comprising the partners in the Margarita field. This would involve transporting gas across the Andes for processing at an LNG plant on the Pacific coast and onward export to Mexico for regasification, and from there to the USA. The Bolivian Government is currently assessing the gas export route to the coast.

Recent pressure measurements prove that the Itau (BG 25%) and San Alberto fields are connected. BG, along with its partners in Itau, are continuing to lobby the Bolivian Government and the San Alberto field operator to establish a framework for unitisation or gas balancing.

20 BG GROUP PLC 2002

COUNTRY REVIEWS

BG plans to drill the Mistol oil exploration well in 2003 on its 100% operated Block XX Tarija East.

BRAZIL
In addition to our controlling interest in Comgas, we own one third of BBPP Holdings Limited, which was selected by the Brazilian state energy company, Petrobras, as its partner in Transportadora Brasileira Gasoduto Bolivia Brasil S.A. (TBG). TBG developed the Bolivia-Brazil pipeline’s Brazilian section.

Comgas (BG 60.05%) continued to show volume growth in 2002, and the total sales increased to £293 million (£257 million in 2001; £195 million in 2000) despite the effect of the devaluation of the Brazilian Real. During the year, Comgas connected almost 33 000 new residential and commercial customers, 65 new industrial customers, 2 new co-generation and power generation stations, and 94 Natural Gas Vehicle stations. At the year end, Comgas had approximately 378 000 customers (345 000 in 2001; 329 000 in 2000).

Comgas’ concession area is the industrial heartland of Brazil, and in the São Paulo region natural gas represented 3.5% of the energy matrix in 2001 (2.6% in 2000). The Comgas concession is a 30 year franchise lasting to 2029, with the potential for an additional 20 years. The concession is regulated by Comissão de Serviços Públicos de Energia de Estado de São Paulo (CSPE), a São Paulo state regulatory body. Comgas has exclusivity

throughout its concession area in gas transportation, and in gas supply to residential and commercial customers, for the length of the concession. Comgas can pass through to customers the price of purchased gas and transportation services. Its distribution margins are adjusted by CSPE according to an IGPM – X price cap methodology, where IGPM is a Brazilian inflation index and X is an efficiency factor. The methodology is subject to review every five years and Comgas is working with CSPE towards a final determination.

In transmission, we hold an 8.10% interest in the Bolivia-Brazil pipeline (BBP). Current pipeline capacity is 17 mmcmd and a total capacity of 30 mmcmd is scheduled for the second quarter of 2003. BG began using BBP capacity to sell its equity gas from Bolivia to Comgas in Brazil in September 2001, being the first Bolivian gas supplier other than Petrobras to supply the Brazilian market directly. In December 2002, BG and Petrobras signed an agreement to assign part of Petrobras’ firm capacity in the TBG portion of the BBP to BG. This is the first time such capacity has been assigned and has allowed us to extend our existing gas sales agreement with Comgas.

Under Brazilian regulations,TBG as operator of transportation pipelines is required to offer to third parties firm transportation capacity derived from the expansion of such pipelines through an open season process. In November 2001, BG made a formal Expression of Interest

in taking new expansion transmission capacity in the TBG. However, the timetable for the open season process has been delayed because of the slowdown in investment in gas-fired power generation in Brazil.

In the upstream E&P sector, BG holds an interest in the BM-S-9, 10 and 11 blocks in the Santos Basin offshore São Paulo. At present, a large 3D seismic survey, which was completed in July 2002, is being interpreted. This work is planned to be completed in 2003, when the results can be fully assessed.

URUGUAY
BG has a 40% stake in, and is technical operator of, the Gasoducto Cruz del Sur (Southern Cross pipeline) consortium which, in 1999, was awarded the concession to construct and operate a gas transmission system linking markets in Uruguay with Argentina for the first time. First gas flowed through the cross-border pipeline in November 2002 and the pipeline supplies Montevideo and markets along its route. Through our holding in Dinarel S.A., BG has a 25.50% interest in Gas Link S.A., a 40 km gas pipeline connecting the Southern Cross pipeline with the Argentine transportation network, which was completed in April 2002.

EGYPT – CORE AREA
In 2002, we made significant progress towards development of upstream projects to supply gas to the domestic

BG GROUP PLC 2002 21

COMGAS CONTINUES TO SHOW

BOTH CUSTOMER AND VOLUME

GROWTH, BRAZIL (LEFT).

EQUIPMENT FOR THE SUB-SEA

PRODUCTION IN THE SCARAB

SAFFRON FIELDS, EGYPT (RIGHT).

market and for export. Downstream, BG achieved several key milestones towards implementing the Egyptian LNG (ELNG) project with the conclusion of core agreements and the start of construction work.

Between 1997 and the end of 2001, we invested $440 million in our Egyptian operations and plan to invest a further $770 million between 2002 and 2006, primarily to realise gas export projects.

In 2002, our exploration programme in West Delta Deep Marine Concession (WDDM), in which we have a 50% interest, led to a new discovery in January on the Solar prospect. Two appraisal wells drilled in early 2002, Sapphire-4 and Sienna-2, confirmed sufficient reserves to underpin a two-train ELNG project. Since 1997, BG has drilled 24 exploration and appraisal wells in the Rosetta (BG 40%) and WDDM Concessions, 22 of which have been successful. This represents a 92% success rate overall and 100% in WDDM.

To maximise further the exploration potential of WDDM, we are reviewing the results from a 3D seismic survey covering approximately 1 200 sq km, which was conducted in August 2002.

Rosetta Concession
The BG-operated Rosetta field proved to be a flexible and reliable source of gas for the domestic market in 2002. The field, which started production in January 2001, has performed above expectations and has been able to produce above the DCQ during periods of high demand. During

2002, production averaged 243.2 mmscfd, with a peak rate of 335 mmscfd.

The second phase will be developed as an unmanned minimum facilities wellhead platform tied back to the existing Rosetta platform. The project is expected to enter FEED in March 2003 and sanction is anticipated by mid-2003 with first gas scheduled for the fourth quarter of 2005.

West Delta Deep Marine Concession (WDDM)
First gas production from the Scarab Saffron fields within WDDM is expected in March 2003. In December 2002, BG and its WDDM partners agreed revisions to the planned DCQ. The initial DCQ will be 440 mmscfd until the end of 2003. On 1 January 2004, the DCQ will rise to 586 mmscfd for one year and will rise again on 1 January 2005 to 626 mmscfd. On 1 January 2006, the DCQ will revert to 533 mmscfd unless three months have elapsed since the first shipment from ELNG, in which case, the DCQ will rise an additional 100 mmscfd to 633 mmscfd for a period of seven years. The Scarab Saffron fields are larger and in deeper water (in excess of 700 metres) than any other gas fields so far developed in Egypt and are the first to be developed using sub-sea technology. The eight Phase 1 development wells were completed on schedule in November 2002. The Scarab Saffron development has been designed to allow for the integration of the Simian Sienna fields to maximise synergies and reduce costs.

The Simian Sienna fields will supply the gas to ELNG Train 1. Like the Scarab Saffron project, they will use sub-sea completion technology but because of the greater distance from the shore, the project will utilise a shallow water controls platform to reduce controls system risks and maintain plant availability.The FEED for the development was completed in May 2002. Responses to the tender for the Engineering Procurement Installation and Commissioning contract were received in December 2002, with award expected in the first quarter of 2003. Offshore construction is likely to start in 2004, with production scheduled to commence in mid-2005.

In March 2002, the Egyptian People’s Assembly ratified amendments to the WDDM Concession Agreement to allow gas exports. BG and its partners are therefore the first, and currently the only, upstream players in Egypt with a definitive export agreement allowing the export of gas from a development within a concession area.

The amendments to the Agreement also introduced a floor and ceiling price to domestic gas sales. At Brent oil prices of below $10/bbl, the floor price payable for domestic gas is $1.50/mmbtu and a ceiling price of $2.65/mmbtu applies when Brent oil is above $20/bbl. This pricing arrangement was adopted simultaneously for the Rosetta Concession, and has been applied retrospectively from the start of Rosetta production in January 2001.

22 BG GROUP PLC 2002

GROUND WORK COMMENCED

ON ELNG TRAIN 1, EGYPT (RIGHT).

THE MISKAR FIELD CURRENTLY

PROVIDES APPROXIMATELY 60%

OF TUNISIA’S DOMESTIC CURRENT

DEMAND (FAR RIGHT).

COUNTRY REVIEWS

Egyptian LNG (ELNG)
The ELNG project passed several key milestones in 2002. In October, the LNG Sale and Purchase Agreement was signed between BG, its WDDM partners and Gaz de France for the sale of the entire output of the 3.6 mtpa first train (BG 35.50%) to Gaz de France. This followed a Heads of Terms agreement in January. Train 1 is scheduled to start production during the third quarter of 2005. In parallel to the commercial framework, construction of Train 1 and the common facilities started with the early works programme in May 2002 and the full EPC contract with Bechtel was signed in September 2002. BG and its partners also made progress in securing project finance of $1.15 billion for the construction of Train 1 and common facilities with the announcement in January 2003 of the appointment of 12 international banks as International Mandated Lead Arrangers and the signing of an agreement with three Egyptian banks.

The Egyptian LNG Company (BG 35.50%) will own both the LNG site and common facilities, such as storage tanks and jetty. Separate companies will own the individual trains. The ownership of future train companies may differ from the shareholding of the Train 1 company (BG 35.50%). An operating company, in which BG has a 35.50% interest, will undertake operation of all trains.

Also in January 2003, BG and its partners authorised the start of the early works programme of the Train 2 EPC contract.

Train 2 is expected to start production in mid-2006, about nine months after the start-up of Train 1.

Nile Valley Gas Company (NVGC)
BG has a 37.50% interest in NVGC which holds a 25 year franchise to develop the gas market in Upper Egypt. NVGC has contracted more than 16 000 domestic customers and signed up a number of major industrial users, including cement manufacturers and glass factories. A review of options for the company is under way.

SPAIN
In 2002, BG was awarded seven exploration licences in the western Mediterranean, offshore Spain.

The Spanish Government awarded BG a total area of 6 500 sq km. BG holds 100% equity in all seven new licences and has committed to a £20 million exploration programme over the next three years.

A 2 500 sq km 3D seismic acquisition programme, the largest survey acquired in Spanish waters, was completed in July 2002. Exploration drilling is expected to begin towards the end of 2003.

Any gas discoveries could be developed for the Spanish domestic market.

TUNISIA
BG is the largest producer of gas in Tunisia, providing approximately 60% of the current domestic demand from the Miskar field. We are committed to further exploration activity in the country and to investing $450 million between 2000 and 2009 in various projects.

BG has a 100% interest and is operator of the Gulf of Gabes Miskar concession, which contains the Miskar field.

BG has a long-term gas sales contract with the Tunisian state electricity and gas company, Société Tunisienne de l’Electricité et du Gaz (STEG), which gives BG the right to supply over 230 mmscfd from Miskar.

Miskar gas is processed at the onshore Hannibal Terminal, 21 km south of Sfax. A further upgrade of the processing facilities is scheduled for completion in 2003.

We drilled three infill wells on the Miskar field in 2002 and have signed manufacturing and installation contracts for gas compression equipment to be installed on the Miskar platform. This equipment is expected to be operational in 2004.

BG is operator and joint permit holder with Enterprise Tunisienne d’Activités Pétroliéres (ETAP), the Tunisian state-owned petroleum company, of the Amilcar exploration permit, which includes the Hasdrubal gas condensate discovery.

We drilled our first well on this discovery in 1997 and, during 2002, drilled a further appraisal well, which confirmed the south-west extension of the Hasdrubal field and the presence of an oil rim. Studies are being conducted to evaluate the optimal development to recover this oil as well as the gas and condensate.

BG GROUP PLC 2002 23

	COUNTRY REVIEWS

Negotiations continue on the development of the Barca power station. An Environmental Impact Assessment has been approved by the Tunisian Government. The plant could commence operations in 2006 using unprocessed gas reserves from BG’s offshore interests, including Miskar, Hasdrubal and the Jugurtha field, which was discovered in 1982. An appraisal well is due to be completed on Jugurtha in March 2003.

ITALY
BG is developing a focused interest in the E&P, LNG and Power segments within the fast growing Italian gas market. BG’s upstream activities are concentrated in the Sicily Channel and the Po Valley in north-western Italy. In April 2002, we announced a gas discovery on the Panda prospect in the Sicily Channel, in which BG has a 37.50% interest. An appraisal programme began with a well, which started in December 2002, and a 3D seismic survey is planned for later in 2003.

A three year onshore exploration programme is expected to commence in the Po Valley in 2003, subject to the granting of environmental approvals. The first well is scheduled to be drilled on the high pressure/high temperature Cascina Favorita-1 prospect, located around 40 km to the south-west of Milan.

In November 2002, planning and environmental approval was granted for the construction and operation of a 6 mtpa LNG regasification facility at

Brindisi on the south-east coast of Italy. A Memorandum of Understanding (MoU) was signed in February 2003 with Enel, for the sale of 50% of the project. Two further MoUs have been signed to explore options for BG to supply LNG and gas to Enel. The 3 mtpa first phase is scheduled to be sanctioned by the end of 2003, with first imports into the Italian market expected to commence in 2007. Brindisi is strategically located to receive LNG from the Mediterranean Basin and the Gulf States.

BG is a 32% partner in Serene SpA, a joint venture company, which owns and operates approximately 400 MW of power and steam co-generation at five power stations adjacent to Fiat Auto factories.

ISRAEL AND AREAS OF PALESTINIAN AUTHORITY
BG’s involvement in the region’s emerging gas industry will increasingly focus on commercialisation opportunities, particularly for gas from our discoveries offshore Gaza.

Areas of Palestinian Authority
In the second half of 2000, BG discovered potentially commercial gas reserves at the Gaza Marine-1 and 2 wells. Future development is likely to be via sub-sea wells and a pipeline to an onshore processing terminal.

Exploration efforts are continuing within the Gaza Marine licence to maximise the potential of the existing discoveries. New 2D seismic, covering 375 sq km, was acquired in late 2002 over near-shore

areas and is currently being processed. It is also planned to drill a further well in 2003.

Israel
Since early 2001, we have rationalised our exploration assets in Israel. We withdrew from four deep-water Gal C concessions in 2001 and in early 2002 sold our 35% interest in the offshore Med Ashdod licence. The Med Yavne lease was reduced in 2002 to an area of 52.3 sq km around gas discoveries made in 1999. It is currently proposed to drill a well on the Tamar prospect in 2003 in the Matan (Gal B concession) offshore exploration block. A decision on whether to drill or relinquish our interest in, and operatorship of, the Matan and Michal (Gal A concession) offshore exploration blocks will be taken in 2003.

We continue to negotiate for the sale of gas from offshore Gaza to major power and industrial users.

KAZAKHSTAN – CORE AREA
BG has been active in Kazakhstan for over a decade. We are joint operator of, and a 32.50% interest holder in, the giant Karachaganak gas condensate field in north-west Kazakhstan. We are also a partner in the North Caspian Sea Production Sharing Agreement (PSA), which includes the giant Kashagan field and the Kalamkas discovery of October 2002.

BG is a 2% shareholder in the Caspian Pipeline Consortium (CPC). The CPC pipeline links reserves in western

24 BG GROUP PLC 2002

COUNTRY REVIEWS

Kazakhstan to the Black Sea, thus enabling Kazakhstan’s liquid production to access world markets. The pipeline has been operational since October 2001.

Karachaganak
In November 1997, BG, Agip, Lukoil and Texaco (now ChevronTexaco) signed a Final Production Sharing Agreement relating to the Karachaganak field, which originally commenced production in 1984.

Gas and condensate is produced from the existing facilities in the field and currently all this production is sold into the Russian market. In 2002, BG and its partners enhanced the existing facilities and this allowed new daily, monthly and annual production records to be set during the year. Over 19 000 tonnes of condensate were produced during one day in October (over 144 000 bopd gross) and over 5.1 million tonnes were produced during the year (an average of over 106 000 bopd gross).

The main focus, however, is the Phase 2 project. This involves the development of new production and gas injection facilities, the workover of around 100 wells and the construction of a new oil export pipeline to connect to the CPC line at Atyrau. In addition, extensive support facilities are being constructed at the field to provide power, water, logistics support and accommodation. Phase 2 will allow the majority of liquids produced in the field to be exported to world markets. The gas produced will be sold into the Russian market or reinjected into the reservoir.

Substantial progress was made on Phase 2 during 2002: the commissioning of the gas injection facilities began and the liquids processing facilities are now far advanced; 24 wells were worked over bringing the total completed to 96; the connecting pipeline to Atyrau was laid; and the 120 MW power station is now providing power for field activities with surplus power going into the local grid. At the end of 2002, the Phase 2 project was over 90% complete and on target for first oil exports via CPC in the third quarter of 2003.

On completion of the new facilities, the field is expected to produce more than 10 mtpa (200 000 bpd) of liquids and up to 7 bcm of sales gas per annum (700 mmscfd).

North Caspian
In May 2002, we increased our interest in the North Caspian Production Sharing Agreement (PSA) from 14.29% to 16.67%. BG and partners increased their stakes after BP and Statoil sold their interests in the PSA.

In June 2002, the Kashagan field was declared to be commercial, with gross reserves under a natural depletion mode of 7-9 billion barrels of oil. Secondary recovery methods such as gas injection could increase this to 13 billion barrels of oil. The field is currently being appraised via a five well programme utilising two rigs, and a FEED is currently under way.

In December 2002, the development plan for the first phase of the Kashagan

development was submitted to the Kazakhstan Government for approval. In October 2002, the North Caspian Sea partners announced that an exploration well drilled on the Kalamkas prospect discovered hydrocarbons. The well, approximately 90 km south-west of Kashagan, flowed at 2 300 bopd of 29-35 degrees API oil on test. The partners are currently evaluating the results. During 2003, the partners intend to drill three further exploration prospects.

INDIA – CORE AREA
The purchase of exploration and production assets in February 2002 established India as our sixth core geographic area.

BG is a major investor in the Indian gas market where gas demand is expected to grow from today’s level of 5 300 mmscfd to about 13 700 mmscfd in 2025.

Panna/Mukta and Tapti
In February 2002, we completed the $350 million (£247 million) acquisition of a 30% interest in the Tapti gas field and the Panna/Mukta oil and gas fields, and a 62.64% interest in the CB-OS/1 exploration licence.

In 2002, production from the Tapti and Panna/Mukta fields averaged about 20 000 boepd net to BG. All gas produced from the fields is sold to the Gas Authority of India Limited (GAIL), whilst oil from the Panna/Mukta complex is bought by the Indian Oil Corporation Limited.

BG GROUP PLC 2002 25

SUBSTANTIAL PROGRESS WAS MADE ON PHASE 2 OF THE KARACHAGANAK FIELD, KAZAKHSTAN (LEFT). MAHANAGAR GAS CONTINUES TO SHOW SIGNIFICANT GROWTH IN CNG VOLUMES, INDIA (RIGHT). GUJARAT GAS IS INDIA’S LARGEST PRIVATE GAS DISTRIBUTION COMPANY (FAR RIGHT).

We currently operate these assets and are in discussion with partners regarding future operatorship arrangements.

Since the acquisition, we have completed a FEED study for a fourth wellhead platform on Tapti, with first gas expected during 2004, and we have developed an infill drilling programme which is expected to enhance oil recovery from Panna. Both these projects are subject to partner and government approvals.

Beyond this, there are opportunities for additional wells and processing facilities on these fields to increase production.

Gujarat Gas Company Limited (GGCL)
We have a 65.12% controlling interest in GGCL, India’s largest private gas distribution company.

By the end of 2002, GGCL was serving approximately 140 000 domestic, 1 800 commercial and 450 industrial customers. In addition, it provided refuelling services for over 1 100 natural gas vehicles (NGV).

GGCL has secured a portion of the new gas supplies produced from the offshore Lakshmi field which commenced delivery in November 2002. This should enable GGCL to market an additional volume of up to 1.27 mmscmd on both a long-term and spot basis. GGCL also provides a transportation service to third parties which amounted to 301 mmscm in 2002. GGCL’s total volume throughput was 781 mmscm, an increase of 77% on the previous year.

Mahanagar Gas Limited (MGL)
We also have a 49.75% interest in the MGL distribution joint venture with GAIL and the Government of Maharashtra. By the end of 2002, MGL had connected around 150 000 domestic, 460 commercial and 38 industrial customers. In addition, it serviced approximately 60 000 NGVs from 45 CNG stations. MGL gas sales volume for 2002 was 206 mmscm, an increase of 47% on the previous year.

LNG
BG is the sole promoter of an LNG importation and regasification terminal at the port of Pipavav in the State of Gujarat to supplement the region’s domestic gas supplies. The Pipavav terminal would initially handle 2.65 mtpa of LNG, with first deliveries potentially in 2007.

New Business
Iqara Broadband, a BG subsidiary, is operational in Surat and Vadodara, and provides high-speed broadband internet connections, internet telephony and virtual private networks, via a hybrid fibre coaxial telecommunications network. At the end of 2002, 6 000 residential and commercial customers were served by Iqara Broadband. Similar projects are being developed in Mumbai and in Gujarat State.

INDONESIA
Our Indonesian activities are focused on developing and marketing our gas reserves within the Muturi PSC in conjunction with the Tangguh LNG project.

We have a 50% operated interest in the Muturi PSC in Irian Jaya, 3 000 km east of Jakarta which, following the final statutory relinquishment submitted in August 2002, covers an area of 1 346 sq km. The onshore northern part of the Muturi PSC contains the Mogoi Deep gas discovery, drilled by BG in 1996. The super giant Vorwata gas field, discovered in 1997, straddles the boundary of the offshore southern part of the Muturi PSC and the adjacent BP-operated Berau PSC.

In July 1997, BG and ARCO (now BP) agreed to collaborate on the supply of gas to the proposed Tangguh LNG export project, using reserves from the Wiriagar, Berau and Muturi PSCs. An independent assessment by consultants DeGolyer and MacNaughton certified proved and probable reserves from the three PSCs of 18.3 tcf, of which 12.1 tcf are in the Vorwata field.

In the early part of 2002, the invitation to tender for the construction of the proposed LNG plant was released to bidders.

In September 2002, the Tangguh partners announced the sale of 2.6 mtpa of LNG under a 25 year contract to the proposed Fujian importation terminal in China. The marketing of the remainder of Tangguh’s capacity continues with the intention of sanctioning the project in 2003. First production is scheduled to begin in 2007.

On 19 December 2002, BG and its partners in the Tangguh LNG project signed the Tangguh Joint Venture

26 BG GROUP PLC 2002

	IN THE PHILIPPINES, THE SANTA RITA POWER STATION (RIGHT) HAS NOW BEEN JOINED BY THE SAN LORENZO POWER STATION IN FULL COMMERCIAL OPERATIONS.
COUNTRY REVIEWS

Agreement (TJVA) superseding the previously signed Collaboration Agreement. The TJVA is subject to endorsement by the Government of Indonesia. It provides for the unitisation of the Muturi, Berau and Wiriagar PSCs and defines how the partners will work together to further develop and manage Tangguh. Under the TJVA, BG has a 10.73% interest in the project, with the opportunity to increase this equity interest if reserves in Mogoi are independently certified by 2006.

THAILAND
We have a 22.22% interest in the offshore Bongkot field, in the Gulf of Thailand, which currently supplies around one fifth of Thailand’s total gas demand.

The Bongkot field commenced production in 1993 and contained estimated original gross reserves of 3.3 tcf of gas and 62 mmbbls of liquids. Current contracted daily gas quantity is 550 mmscfd.

The Bongkot field development presently consists of a central complex for gas gathering, processing, export and accommodation, and 148 wells drilled from 12 wellhead platforms.

A new 400 000 bbl floating condensate storage and offloading vessel (FSO) has recently been constructed and became operational in January 2003.

BG also has a 50% interest in, and is the operator of, three exploration blocks (Blocks 7, 8 and 9), located in the Gulf of Thailand in disputed waters between

Thailand and Cambodia. Discussions between the Governments of Thailand and Cambodia are continuing following the signing in 2001 of a Memorandum of Understanding to conclude an agreement for the joint development of the hydrocarbons in a Joint Development Area, including Blocks 7, 8 and 9.

PHILIPPINES
BG continues to play an important role in the development of the Philippines natural gas market through participation in gas-to-power projects.

We have interests in two gas-fired power projects in the Philippines – the Santa Rita and San Lorenzo power stations.

First Gas Power Corporation, a 100% subsidiary of First Gas Holdings Corporation, in which BG has a 40% stake, owns the 1 000 MW Santa Rita power station. On 1 January 2002, the plant switched from liquid fuel to run on natural gas from the Shell/Texaco Malampaya field. Electricity generated at Santa Rita is sold to the Manila Electric Company (Meralco) under a 25 year agreement, which expires in 2025.

In October 2002, the San Lorenzo power station, at Batangas City, began full commercial operations, also selling power to Meralco under a Power Purchase Agreement which expires in 2027. BG has a 40% interest in FGP Corp. which is the owner and developer of this twin-turbine 500 MW power station.

OTHER AREAS
BG also has a downstream interest in the Malaysian energy sector. We were the co-developer and have a 20% interest in Genting Sanyen Power, a 720 MW gas-fired power station in Kuala Langot near Kuala Lumpur International Airport.

The regional headquarters of BG in Asia Pacific are in Singapore and provide leadership and expertise in the fields of commerce, finance, law, tax and project development to support projects and investments in the region.

BG GROUP PLC 2002 27

GOVERNANCE AND RISK

CORPORATE GOVERNANCE
Corporate governance is the system by which companies are directed and controlled. UK listed companies are required to include a statement on corporate governance in their annual reports. This statement must include a narrative on how the principles of the Combined Code have been applied and whether or not a company has complied throughout the year with all the provisions set out in the Combined Code. The Combined Code is appended to the Listing Rules of the UK Listing Authority.

The Company is committed to achieving and maintaining high standards of corporate governance throughout the Group and to integrity and high ethical standards in all its business dealings. The Board continually reviews developments in corporate governance. The following statement sets out how BG Group plc implements corporate governance.

Statement of compliance with the provisions of the Combined Code
The Directors consider that the Company has complied throughout the financial period with the provisions set out in Section 1 of the Combined Code.

The Board of Directors
The Board leads and maintains full and effective control over all wholly-owned companies and all activities where BG has a controlling shareholding. Where it has a minority interest, BG encourages and helps its partners to establish such controls.The current Directors’ biographies,

on page 53, demonstrate that the Board possesses the necessary range of backgrounds, qualities and experience to lead the Company.

BG Group plc has separate posts of Chairman and Chief Executive. The Board consists of three Executive Directors (the Chief Executive, the Deputy Chief Executive and the Chief Financial Officer) and ten non-executive Directors, including the Chairman and Deputy Chairman. The Deputy Chairman also acts as the Senior Independent Director. All Directors are subject to election by shareholders at the first opportunity after their appointment by the Board and to re-election by shareholders every three years. Attendance by all Directors is expected at all Board meetings and at the Annual General Meeting except in special circumstances. The Board is supplied with high quality and timely information to enable it to discharge its duties.

The Board meets regularly throughout the year, including, in 2002, eight formal Board meetings. The Board has a schedule of matters specifically reserved to it for decision, including matters of key strategic importance, Group financial policy and material acquisitions and disposals. In addition, the Board focuses each year on BG’s strategy at an off-site Planning Conference and Directors participate in various briefing visits both in the UK and overseas.

All the Directors have access to the advice and services of the Company

28 BG GROUP PLC 2002

THE COMPANY IS COMMITTED TO ACHIEVING HIGH STANDARDS
OF CORPORATE GOVERNANCE THROUGHOUT THE GROUP AND
TO INTEGRITY AND HIGH ETHICAL STANDARDS IN ALL ITS
BUSINESS DEALINGS.

GOVERNANCE AND RISK

Secretary. If necessary, Directors are free to take independent professional advice as to Board decisions at BG’s expense. The Company Secretary ensures that Board procedures are followed and that applicable rules and regulations are complied with. The Company Secretary may be removed only with the approval of the Board.

Appropriate training and briefing is provided to all Directors on appointment to the Board, taking into account their individual qualifications and experience, and training is also available to meet their individual needs. The Board also recognises the value of regularly identifying its own strengths and weaknesses and in 2002 introduced a Board evaluation exercise which it intends to repeat annually.

The Board considers that all Directors bring an independent judgment to the Board’s deliberations in respect of strategy, performance, resources, key appointments and standards of conduct. All the non-executive Directors are considered by the Board to be independent of management and free from any business or other relationship which could interfere with the exercise of their independent judgment.

Committees
The Board has delegated authority to the following committees on specific matters. All the committees have formal terms of reference or, in the case of the Audit Committee, a written charter, approved by the Board. The membership of each of the committees is shown on page 53.

Group Executive Committee
Chairman: Frank Chapman
The Board delegates authority for the day-to-day management of the Company’s business to the Group Executive Committee (GEC) which meets monthly. The minutes of these meetings are circulated to all non-executive Directors. The membership of this committee comprises the three Executive Directors and all the senior managers whose details are shown on page 55.

The GEC focuses on four key areas – strategy, Group performance, people and organisation – and has in turn delegated specific authority to six smaller sub-committees:

• Investment Committee

• Exploration Committee

• Business Development Committee

• Health, Safety, Security and Environment Committee

• Policy and Risk Committee

• Energy Trading Risk Management Committee

Chairman’s Committee
Chairman: Sir Richard Giordano
The Chairman’s Committee comprises the Chairman, the Deputy Chairman and all the Executive Directors. It advises and assists the Chairman in the preparation for Board meetings so that the Board has

issues and proposals requiring Board resolution and approval presented to it in a timely and efficient fashion. With the exception of those matters reserved specifically for the Board, the Chairman’s Committee also acts on behalf of the Board between scheduled meetings when, in exceptional circumstances, it is not possible or practicable to convene a meeting of the Board.

Audit Committee
Chairman: Lord Sharman
The Audit Committee comprises all the non-executive Directors and reviews the management of key risks facing the Company, the effectiveness of internal controls, compliance, financial and accounting policies and practices, the form and content of financial reports and statements and general matters which may be brought to the attention of the Company by its auditors. In addition, the committee reviews the scope and results of audit and its cost-effectiveness, as well as the performance of the auditors and the scope and cost of non-audit services provided to the Company. The committee meets at least four times a year.

The Audit Committee meets the membership requirements of the Combined Code in the UK and the Blue Ribbon Report in the US. The Blue Ribbon Report is a New York Stock Exchange publication which makes recommendations on improving the effectiveness of corporate audit committees.

BG GROUP PLC 2002 29

THE BOARD HAS OVERALL RESPONSIBILITY FOR THE GROUP’S
SYSTEM OF INTERNAL CONTROL AND FOR REVIEWING ITS
EFFECTIVENESS, WHILST THE ROLE OF MANAGEMENT IS TO
IMPLEMENT BOARD POLICIES ON RISK AND CONTROL.

GOVERNANCE AND RISK

The Audit Committee reviews its charter each year and recommends any necessary changes to the Board. A copy of the current charter, which was adopted by the Committee and approved by the Board in November 2002, is set out on page 31.

Finance Committee
Chairman: Sir Richard Giordano
The Finance Committee comprises the Chairman, the Chief Financial Officer, the Chief Executive and the Deputy Chief Executive and considers financing and treasury decisions concerning the Group, including the giving of guarantees and indemnities. The committee normally meets four times a year.

Nominations Committee
Chairman: Sir Richard Giordano
The Nominations Committee comprises the Chairman, the Chief Executive and two non-executive Directors. It oversees and recommends to the Board all appointments of Directors and the Company Secretary and reviews succession planning for the Board. The committee meets at least once a year and otherwise as required.

Remuneration Committee
Chairman: Elwyn Eilledge
The Remuneration Committee consists exclusively of non-executive Directors. It has responsibility for setting, reviewing and recommending to the Board the Company’s overall remuneration policy and strategy and for setting, reviewing and approving the remuneration of the Executive Directors.

Further information about the Remuneration Committee is contained in the Directors’ Report on remuneration on pages 60 to 69.

Relationship with shareholders and Annual General Meeting
The Company recognises the importance of maintaining a purposeful relationship with its shareholders and uses the Annual General Meeting (AGM) as an opportunity to communicate with its shareholders. Full details of the AGM are set out in the Notice of AGM on pages 19 to 21 of the Annual Review.

BG has an annual Investor Relations Programme and maintains a dialogue with its institutional shareholders in this country and overseas. In order to facilitate this dialogue, regular meetings are held with institutional shareholders following the announcement of quarterly and annual results.

Internal Control
The system of internal control is designed to manage, rather than eliminate, the risk of failure to achieve business objectives. In pursuing these objectives, internal controls can provide only reasonable and not absolute assurance against material misstatement or loss. The Board has established key policies and has carried out a specific assessment of the Group’s system of internal control for the purpose of this report.

The Company, as required by the Listing Rules, has complied with the Combined Code provisions on internal control by establishing the procedures necessary to implement the guidance issued by the Internal Control working party of the Institute of Chartered Accountants in England and Wales in September 1999 (the Turnbull Committee Report) and by reporting in accordance with that guidance.

The processes used by the Board to review the effectiveness of the system of internal control include the following:

• The Audit Committee reviews the effectiveness of internal financial, operational, compliance and risk management controls. Significant issues are referred to the Board for consideration.

• The Company has an Internal Audit department and its scope of work, authority and resources are reviewed annually by the Audit Committee.

• The Finance Committee considers financing decisions concerning the Group, including the giving of guarantees and indemnities, and monitors policy and control mechanisms for managing treasury risk.

Statement on Disclosure Controls and Procedures
BG Group shares are listed on the London Stock Exchange and its American Depository Shares are listed on the New York Stock Exchange. As a result of the US Sarbanes-Oxley Act of 2002, BG Group is obliged to make statements with regard to its disclosure controls and procedures.

30 BG GROUP PLC 2002

THE CHIEF EXECUTIVE AND THE CHIEF FINANCIAL OFFICER HAVE
EVALUATED THE EFFECTIVENESS OF THE GROUP’S DISCLOSURE
CONTROLS AND PROCEDURES AND HAVE CONCLUDED THAT SUCH
CONTROLS AND PROCEDURES WERE EFFECTIVE.

GOVERNANCE AND RISK

In accordance with these obligations, the Chief Executive and the Chief Financial Officer have evaluated the effectiveness of the Group’s disclosure controls and procedures (as defined under Rule 13a-14(c) of the US Securities Exchange Act 1934) within 90 days of the date of this Annual Report and Accounts. Based on this evaluation they have concluded that, as of such date, such controls and procedures were effective to ensure that material information relating to the Group would be made known to them by others within the Group. There were no significant changes (including corrective actions with regard to significant deficiencies and material weaknesses) in the Group’s internal controls or in other factors that could materially affect these controls after the date the Chief Executive and Chief Financial Officer completed their evaluation.

Risk Management
There is a continuous process for identifying, evaluating and managing the significant risks faced by the Company. This was in place during 2002 and up to the date of approval of this Annual Report and Accounts. The process is embedded in the business, with risk assessment and evaluation incorporated into the key business processes including strategy and business planning, investment appraisal, performance management and health, safety, security and environmental management processes. This process is reviewed annually by the Audit Committee on behalf of the Board.

During the year the Audit Committee:

• reviews the external and internal audit work plans;

• considers reports from management and internal and external audit on the system of internal control and material control weaknesses;

• requests, receives and reviews reports from management on actions taken to address risk areas identified by management and/or the internal audit process;

• receives and reviews an annual report on the changes since the last annual assessment in the nature and potential impact of significant risks and the internal controls in place to manage them.

At the year end, before producing this statement on internal controls in the Annual Report and Accounts, the Board, through the Chief Executive, asks each member of the Group Executive Committee to complete a Letter of Assurance confirming compliance with the Internal Control Framework which consists of the Group’s policies, procedures and processes. Each member of the Group Executive Committee asks all the senior managers in their area of responsibility to complete similar Letters of Assurance. This cascading process is designed to provide assurance that policies, procedures and processes are being effectively implemented. The output of this process is a register of any identified gaps and proposed measures that will be taken to address the gaps.

The register is presented to the Chief Executive and, for separate consideration, to the Head of Audit. The Chief Executive and Audit Committee are both satisfied that there are no material gaps in the implementation of the internal control framework.

BG GROUP PLC 2002 31

AUDIT COMMITTEE CHARTER

Purpose The Audit Committee is established as a committee of the Board. The purpose of the Audit Committee is to assist the Board of Directors of the Company in fulfilling its responsibilities in respect of:
–	overseeing the Group’s financial reporting process, including the internal control structure and procedures for financial reporting and monitoring the integrity of the Group’s financial statements
–	the manner in which the Group’s management ensures and monitors the adequacy of financial, operational and compliance internal controls and risk management processes designed to manage significant risk exposures
–	the selection, compensation, independence and performance of the Group’s external auditors
–	the independence and performance of the Group’s internal auditors.
Composition and meetings The Audit Committee shall comprise not less than three non-executive Directors. All members of the Committee shall be independent, that is free from any other relationship that, in the opinion of the Board, may interfere with the exercise of their independent judgement. All members of the Committee shall have financial literacy and contribute other expertise relevant to the Group. At least one member of the Committee shall be a financial expert. The Board of Directors shall appoint a Chairman from among the members from time to time. The Company Secretary or his/her nominee shall be the Secretary to the Committee. The Committee shall meet not less than four times per annum and more frequently as circumstances require. The external auditors or internal auditor may request a meeting if they consider that one is necessary. A quorum of the Committee shall be three members. Non-executive Directors who are not members of the Committee shall be entitled to attend all meetings. The Group’s senior management, internal auditor and representatives of the external auditors shall be available to attend when required. The Chairman of the Committee shall attend the AGM and be prepared to respond to any shareholder questions on the Committee’s activities. The Committee shall meet at least twice each year with only the external and internal auditors present. Authority and Responsibilities The Audit Committee has full authority to investigate all matters that fall within this Charter. The Audit Committee is accountable to the Board and shall not be entitled to sub-delegate all or any of the powers and authority delegated to it. In discharging its responsibilities, the Audit Committee shall have unrestricted access to the Company’s management, books and records and shall be entitled to receive such information as it requires from any employee. All employees shall be directed to co-operate with any request made by the Audit Committee. The Board and external auditors are accountable to shareholders. The Audit Committee, as a committee of the Board, is responsible for selecting the external auditors for recommendation to the Board and appointment by the shareholders. The Audit Committee is directly responsible for the compensation and oversight of the external auditors. It is the responsibility of the management of the Group to prepare financial statements in accordance with generally accepted accounting principles (GAAP) and of the Group’s external auditors to audit those financial statements. The Audit Committee’s responsibility is one of oversight and, in carrying out its responsibilities, the Audit Committee itself is not providing any expert or other special assurance as to the Group’s or Company’s financial statements. The Committee shall:
–	Review the adequacy of this Charter annually, reporting any proposed changes to the Board for review and approval.
–	Review and approve the external auditors’planned audit scope and findings from their interim and final audits, including the management letter and response.
–	Review with management and the external auditors, reporting the results of the review to the Board:
	•	the Group’s financial statements, together with any schedule of unadjusted differences arising from the audit;
	•	all the Group’s critical accounting policies and practices used, including their application and quality;

	•	material judgements and compliance with accounting standards, alternative treatments of financial information within GAAP that have been discussed with management, the effect of the alternative treatments on the disclosed information and the auditors’ preferred treatment;
	•	material written communications with management relating to the audit;
	•	stock exchange and media releases in respect of any published results and any financial matters brought to the attention of the Company by the auditors;
	•	compliance with stock exchange listing rules and relevant legislation.
–	Discuss with management, the external auditors and the internal auditors significant business risk exposures and the processes established to identify, monitor, control and report such exposures. Consider reports prepared by Internal Audit, the external auditors, the Chairman of the Policy & Risk Committee, and others as the Committee may request, on the operation of internal controls within the Group, any significant risk management failures and management’s responses.
–	As a part of the above review of business risk and internal control, annually evaluate the design and effectiveness of:
	•	the internal control structure and procedures of the Group for the purposes of financial reporting; and
	•	disclosure controls and procedures designed to ensure that information disclosed by the Group is properly accumulated and communicated to senior management to allow appropriate discussions regarding disclosure to take place,
	•	recommending the results of this assessment to the Board.
–	Oversee the functioning of Internal Audit, reviewing its strategic focus, activities and plans, staff numbers and qualifications and budget. Approve, as a Committee, the appointment or removal of the Head of Group Audit.
–	Apply the BG Group “Policy on the effectiveness and independence of external auditors”, (the “Policy”), as approved by the Committee from time to time, including, inter alia:
	•	selecting the external auditors for recommendation to the Board and appointment by shareholders and agreeing their fees and other compensation
	•	pre-approving audit and non-audit services to be provided by the external auditors
	•	reviewing annually the performance of the external auditors, including the cost effectiveness of the audit, and reporting to the Board the results of that review and completing a more detailed review of auditor effectiveness at least every 5 years, including consideration of whether to tender the audit
	•	considering any questions of resignation or removal of the external auditors
	•	receiving from the external auditors a formal written statement that discloses all relationships between the auditors and the Group, as set out in the Policy, and reports on: the performance of non-audit activities; rotation of audit partners and staff; auditor relationships; employment of former auditors; and includes the confirmation of auditor independence. The Committee will review and discuss with the external auditors any relationships or services that may impact on the independence and objectivity of the external auditors and take, or recommend that the Board takes, appropriate action to ensure their independence
	•	resolving disagreements between management and the external auditors regarding financial reporting for the purpose of issuing the audit report.
–	Establish and oversee procedures for the receipt, retention of information about and treatment of complaints relating to financial matters.
–	Set out in an annual report to the Board, inter alia, that it has reviewed the scope of the annual audit, the independence of the auditors in accordance with the Policy and is satisfied that the integrity of the audit has not been compromised. The Committee will also recommend whether a report should be given to shareholders.
–	Regularly report to the Board of Directors its conclusions with respect to the matters that the Audit Committee has considered.
–	Consider any other matters, as may be delegated from time to time by the Board.
The Audit Committee is authorised to obtain, and determine the fees for, outside legal or other independent professional advice and to secure the attendance of outsiders with relevant experience and expertise, as it considers necessary.

32 BG GROUP PLC 2002

LAKE CHARLES LNG IMPORTATION TERMINAL, LOUISIANA, USA (RIGHT).

SCARAB SAFFRON CONSTRUCTION WORK NEARING COMPLETION, IDKU, EGYPT (FAR RIGHT)

GOVERNANCE AND RISK

RISK FACTORS

Our risk management process focuses on identifying and managing the key risks to our business.

The key risks to our business are:

Delivery of the Group’s business targets
The Group’s 2003 and 2006 business targets, which are described in the Business Review section, and financial targets, which are described in the Operating and Financial Review of this Annual Report and Accounts, and our long-term growth potential are the focus of significant attention especially in the areas of:

• execution of major capital intensive projects on time and within budget;

• commercialisation of projects; and

• long-term energy growth including the reserves/resource base growth to support this.

Project development and execution are subject to technical, commercial and economic risks. Technical risks in upstream activities include uncertainties in estimating reserves, future production volumes and the costs of upstream activities, including drilling. Technical risks in downstream activities include the timely completion of projects under construction, security of supply, unscheduled outages, electricity transmission system or gas pipeline system constraints and reliable application of new technologies to operations.

Commercial risks are dependent on the Group’s ability to enter into, restructure or re-contract advantageous long-term commercial agreements. BG Group generally participates in business activities with several co-venturers and operating agreements provide for liabilities to be borne by co-venturers according to their interests. However, government licences generally require joint and several liability of all co-venturers.

Economic risks include credit risk, commodity price expectations, price indexation of gas contracts to oil-based and other indices, the levy of royalties and taxes on hydrocarbon production, exchange rates and inflation rates. The most significant economic risks are large fluctuations in the following:

• commodity prices, being the risk of a significant fluctuation in oil and/or gas prices;

• exchange rates, in particular the US$:UK£;

• US/UK inflation; and

• UK corporation tax.

The Group’s targets are based on the assumptions that: Brent oil prices will be $16 per barrel real (base 2000) until end 2003 and $17 per barrel nominal thereafter; US$:UK£ exchange rate will be $1.55:£1; US/UK inflation rates will be 2.5% per annum; the UK corporation tax rate will be 30%, except UK upstream which will be 40% from 2002 onwards; and UK uncontracted gas prices will be 22 pence

per therm in 2001, 18 pence per therm in 2002 and 17 pence per therm thereafter.

Significant variations in these factors from those assumed may have a material impact on the Group’s ability to deliver its business targets.

Country risks
Group companies, joint ventures and associates operate in countries and regions throughout the world that are subject to significantly differing political, economic and market conditions. BG’s operations are subject to the jurisdiction of numerous governmental agencies in the countries in which its assets are located, with respect to regulatory and environmental matters. Generally, many of the countries in which the Group does, and expects to do, business have recently developed, or are in the process of developing, new regulatory and legal structures to accommodate private and foreign owned businesses. These regulatory and legal structures and their interpretation and application by administrative agencies are relatively new and sometimes under-developed. Many detailed rules and procedures are yet to be issued. The interpretation of existing rules can also be expected to change over time, making the business environment in which the Group operates less predictable.

Specific country risks that may have a material impact on our business include:

• political and economic instability;

BG GROUP PLC 2002 33

GOVERNANCE AND RISK

• government intervention in licence awards;

• regulatory, taxation and legal structure changes;

• the control of field developments and transportation infrastructure;

• the receipt of permits and consents;

• cancellation of contractual rights; and

• expropriation of assets.

The Group seeks to maintain a diverse portfolio of investments in different countries in order to spread its exposure to country risk.

Competition
Across the world, there is strong competition in the energy sector. Numerous companies compete in the sector, many of them internationally, but no single company dominates globally.

The Group’s projects compete with other forms of energy available to customers, primarily on the basis of price paid by the end user. Policies and measures at the international and national level to tackle climate change will increasingly affect the business conditions, presenting risks and opportunities to the Group. Changes in the usage of alternative sources of energy or in the relative cost of gas vis-à-vis alternative energy sources such as fuel oil, liquefied petroleum gas or hydroelectric power, may have a material impact on the Group’s ability to maintain existing market positions or gain new market positions.

Protecting the Group’s reputation
The Group’s reputation is crucial to business success. The Statement of Business Principles guides actions and decisions by providing a common code of ethics for all employees.

We seek to ensure that third party contractors, agents and representatives are retained on terms consistent with the Business Principles. Non-compliance with the Business Principles could impact on our reputation in the marketplace and thereby materially affect our business.

Health, Safety, Security and Environment
The Group recognises that the protection of the health and safety of its employees and others affected by its operations, the security of physical and intellectual assets and the protection of the natural environment are essential elements in delivering business performance.

The Group has identified key risks in these areas and has implemented internal control systems to manage them.

Risk mitigation strategies are employed to reduce further the Group’s exposure to these risks. Failure to maintain and improve our performance in the areas of health, safety, security and environment could result in damage to, or destruction of, facilities and injury to persons, each of which could have a material effect on the Group’s business.

Insurance
A comprehensive insurance programme is maintained to protect against significant losses and, as is consistent with good energy industry practice, includes cover for physical damage, removal of debris, control of wells, redrill, pollution and employer’s and third party liabilities.

The programme incorporates the use of the Group’s captive insurance subsidiary and is subject to certain limits, deductibles, terms and conditions. However, some of the major consequences of the risks involved in BG Group’s activities cannot, or may not, be reasonably and economically insured against.

Attracting and retaining human resources (HR)
We are developing comprehensive human resource plans addressing medium- to longer-term needs as an integral part of our business plans. They will reconcile the demand for and planned supply of people with the range of capabilities and experience required. Global HR policies are aimed at maximising employee commitment and retention and are refined to be relevant locally. Failure to attract and retain people with the right capabilities and experience could have a material effect on our business.

  34 BG GROUP PLC 2002

    CORPORATE RESPONSIBILITY

BUSINESS PRINCIPLES
BG’s Statement of Business Principles sets out the fundamental values and principles within which we operate as we drive to create shareholder value. Our commitment is to the welfare of our employees and to the stakeholders and communities we serve.

The Statement was first published in 1998 and is reviewed by the Board annually. The most recent review of the Business Principles took account of external developments in corporate social responsibility and new legal requirements that followed the series of corporate collapses in the USA. In February 2003, the Board also approved recommendations to incorporate clauses on fraud, theft and security. In parallel, we reviewed the associated policies (see below) that support implementation of the Business Principles and underpin our high level of commitment to corporate social responsibility.

The Business Principles are understood throughout the Company. Translations have been distributed at local levels in appropriate languages. They are a formal part of our dealings with partners and suppliers. The Business Principles establish a code of ethics for the Company and apply to every Director, officer and employee of the Group.

Our inclusion in a number of external ethical indices including the Dow Jones Sustainability Indexes is public recognition of our social and environmental performance.

Underpinning the Business Principles there are eight key Group Policies which state performance expectations and detail the Group’s corporate principles and codes of practice. These Policies cover:

• Personal Conduct;

• Human Resources;

• Governance;

• Human Rights;

• Communications;

• Health, Safety and Environment;

• Security; and

• Corporate Conduct.

The Statement of Business Principles and the associated Group Policies will be available on our website www.bg-group.com. Our 2002 Social and Environmental Report provides further information on our policies and activities in this area.

There is a continuing and widening debate about the constituent elements of corporate social responsibility and about how to measure and define corporate obligations to the communities within which companies operate. BG recognises the importance of these

BG GROUP PLC 2002 35

THROUGH THE CHAIRMAN’S AWARDS, WE CONTINUE TO
RECOGNISE EXEMPLARY PERFORMANCE AND INNOVATION
WITHIN BG, JOINT VENTURES AND CONTRACTORS. THE ANNUAL
AWARDS, SPONSORED BY THE CHAIRMAN AND NON-EXECUTIVE
DIRECTORS, REWARD EXCELLENCE AND ENCOURAGE THE
SHARING OF BEST PRACTICE IN HEALTH, SAFETY, ENVIRONMENT,
COMMUNITY DEVELOPMENT AND PEOPLE’S PERFORMANCE.

CORPORATE RESPONSIBILITY

debates and participates in them. We are confident that our commitment to our Business Principles will remain a strong foundation for our approach to the evolving dimensions of corporate social responsibility.

HEALTH, SAFETY, SECURITY AND ENVIRONMENT
We believe that the protection of the health and safety of our employees and all those affected by our business and the protection of the environment and security of our assets are critical to our overall success. Our aim is to raise our practice to world standards in all countries in which we operate. Our approach to delivering good performance in these areas is based on the principle of continuous performance improvement.

Our continuous improvement process is driven by strong management commitment and employee involvement and is enabled by a number of tools including our Health, Safety, Security and Environment Management System and Directives and the 14-Point Profile. The 14-Point Profile provides the framework to develop asset specific and business-wide Performance Improvement Plans. Contractors and partners have adopted our 14-Point Profile tool during 2002, notably in Kazakhstan, Egypt, India and LNG Shipping, to assess and improve their performance.

Challenging stretch targets are then derived and cascaded down through the

organisation via performance contracts as an integral part of our business performance ethic. Performance is assured through monthly reports on health, safety, security and environment to the Group Executive Committee and quarterly reports to the Board.

Health
Our assets continued to make steady progress with health risk assessments during 2002. Approximately 32% of assets already report having completed their first health risk assessment programme. Remaining assets are intending to complete these assessments during 2003.

Reported figures for occupational illness remain low, but a study is planned for 2003 to establish whether these are a true reflection of the current position or if there is an element of under-reporting.

In 2002, our health strategy for BG was revised and re-issued to reflect organisational changes. Emphasis has been directed to promotion and development of occupational health in the assets, within the company-wide framework.

A co-ordinated wellness programme has been run from our Head Office with different monthly topics. A substantial programme was created for the European Week for Safety and Health in October 2002. Assets are now being encouraged and assisted with health promotion programmes of their own.

Safety
Our drive to deliver superior safety performance was sustained in 2002, with a reduction in the frequency of lost time injuries (staff and contractors) per million man-hours worked frequency (LTIF) to 0.7 compared to 0.9 LTIF in 2001; this is a 72% improvement since 1999.

Our goal for safety management is that no harm is suffered by employees or contractors, or by those associated with our activities. We continue the drive to protect the safety of our employees and contractors. We deeply regret the two contractor fatalities in Kazakhstan during 2002. Thorough investigations of these incidents have led to changes in methods of work and implementation of specific solutions to avoid recurrence. The lessons learnt were shared across BG and with our partners and contractors.

New initiatives are being developed and implemented by our assets and skill centres to help achieve a step change in our safety performance. These include the update of the 14-Point Profile tool and the carrying out of climate surveys to establish the maturity of our assets in relation to safety awareness and to prepare for the introduction of behavioural-based programmes.

Security
The protection of our employees and assets is integral to our business.

Our security policy has been revised to incorporate our commitment to the UK/US Voluntary Principles for Security

LOOKING OUT FROM THE NORTH

COAST OF TRINIDAD TOWARDS THE

HIBISCUS PLATFORM (LEFT). SAFETY

IS TAKEN SERIOUSLY IN ALL OUR

EGYPTIAN OPERATIONS.

and Human Rights. We evaluate the risks of operating in varied conditions worldwide.

During 2002, economic instability in South America and tension both in the Middle East and between India and Pakistan provided security challenges. Effective risk assessment and good mitigation processes allowed our businesses to continue whilst minimising losses of revenue.

We monitor closely the continuing threat of world terrorism and the potential for conflict around the world, aided by advice from governments and by interaction with others in the oil and gas sector.

Environment
Our core business, the production, supply and distribution of gas, has a potential net beneficial impact on the environment because gas is a relatively low carbon and clean fuel, capable of high efficiencies. However, our activities also have the capacity to produce negative environmental impacts. We operate within a company-wide environmental management system to minimise negative effects. Recognising the advantages of independent assurance of the systems, we have made a commitment that all major controlled activities will achieve external certification of their environmental management systems. During 2002, certification to ISO 14001 was received by: BG Bolivia; Comgas, Brazil; Phoenix

Natural Gas, Northern Ireland; the Rosetta field, Egypt; and the Hibiscus development, Trinidad and Tobago.

Climate change is a major environmental issue for BG. New developments allow gas to displace higher carbon fuels with a net reduction in greenhouse gas emissions. During 2002, we increased capacity to supply gas by commissioning Atlantic LNG Train 2 and expansion of the transmission and distribution networks in South America, India and Northern Ireland to new customers. Direct emissions from BG-operated facilities during 2002 were 5.7m tonnes CO₂ equivalent, a 6% decrease on 2001. Greenhouse gas emissions will present both a financial liability and opportunity as policies to control emissions, including emissions trading, are introduced. To reflect the financial significance of emissions, we have collected greenhouse emission data on an equity share basis from operated and non-operated activities.

Conservation of biodiversity and access to sensitive areas present a challenge to extractive companies. We have developed a pilot Biodiversity Action Plan in Egypt and are working with partners to minimise impacts in sensitive environments in the North Caspian, Bolivia and Indonesia. We have adopted the environmental position to go beyond compliance, seeking to meet internationally accepted good practice. Managing local environmental impacts, including air emissions and water

pollutants, in line with this position will minimise impacts and maintain good relations with local communities and regulators, so reducing the risks to operations and projects.

HUMAN RESOURCES MANAGEMENT
BG people are a critical part of the BG proposition, a key source of competitive advantage. We employ 4 606 people around the world, 3 884 of whom work outside the UK and 3 599 of whom are non-UK nationals.

Building and continuously developing a high-calibre, multinational workforce is essential to the continued growth of the Company and success of our integrated gas major strategy.

We have put in place a range of cohesive HR policies and programmes, designed to engage our people with the aims of the business, the needs of our customers, the interests of shareholders and the well-being of the cultures and communities in which we operate.

We are committed to developing the BG culture, where the power of diversity, collaborative working, creativity and a strong sense of individual discipline and responsibility are valued as key factors in the delivery of our performance. More specifically, our people agenda commits us to:

• attracting and retaining the best people, helping them to realise their potential;

BG GROUP PLC 2002 37

CORPORATE RESPONSIBILITY

• encouraging the development of leadership capability throughout the organisation;

• aligning individual performance with the aims of the business and the interests of shareholders; and

• providing a supportive working environment.

During 2002, we developed the DOING framework, which underpins all our HR policies and practices. DOING – which stands for delivering, outperforming, integrating, networking and growing – is designed to create a BG ‘mindset’, ways of thinking and behaving that will help to deliver our business goals and create shareholder value. The DOING ethos is at the heart of our appraisal, development and reward programmes.

We have also put a number of processes in place to develop a genuinely international management team and create opportunities for local managers in all the countries in which we operate to realise their potential. Such programmes enable BG to benefit from access to a worldwide pool of employees who are able to combine knowledge of local culture and business with the BG mindset.

During the year, we invested in the development of a Group-wide leadership programme, with a particular focus on doing new things in new ways. By developing leadership capability throughout the organisation, we will be able to take advantage of the

opportunities that the gas market is currently generating and is predicted to generate in the future.

Key elements of this leadership programme include formal leadership training, mentoring and coaching initiatives. In 2003, we will be supplementing this with a formal modular-based management development programme targeted at our growing core assets.

COMMUNITY INVOLVEMENT
We recognise that as an international company we have responsibilities to contribute to the communities where we do business. We make voluntary and contractual contributions to communities, sponsor local groups and run employee involvement programmes. We also undertake social impact assessments, develop community relationships and contribute to sustainable development.

BG’s voluntary and contractual contributions to social projects in 2002 totalled £6.5 million, which is quantified by the London Benchmarking Group model (www.lbg-online.net).

Social and Economic Impact
The social and economic impacts of oil and gas exploration and development activities can be substantial. We recognise that understanding the potential social impacts of our activities will become increasingly complex as our operations grow globally and can be located near remote and vulnerable communities.

Community Investment
We seek to support social and economic development in the communities where we operate. The (non-charitable) BG Foundation was formed in 1998 to develop and manage our community investment programme. The BG Foundation provides structured funding for community initiatives that support our skills transfer theme and are aligned to BG’s business objectives.

The BG Energy Challenge has now raised over £1 million since its inception in 1996. The 2002 event brought together 23 teams from the oil and gas sector, raising £156 500 for the international humanitarian charity, CARE International UK.

We offer various employee involvement programmes. The matched funding scheme, CareShare, allows employees to increase the money they raise up to a maximum of £250 per person per year. In 2002, the CareShare scheme contributed a further £7 651 to £23 018 raised by 34 employees benefiting 27 charitable causes. UK payroll employees use our payroll-giving scheme and contribute a monthly average of £45 from pre-tax salary to charities of their choice.

38 BG GROUP PLC 2002

  OPERATING RESULTS

	GROUP TURNOVER (a)						TOTAL OPERATING PROFIT/(LOSS) (b)
	2002 £m		2001 £m		2000 £m		2002 £m		2001 £m		2000 £m
Continuing operations
Excluding exceptional items
Exploration and Production	1 555		1 283		1 188		731		606		513
Liquefied Natural Gas	309		81		31		8		29		25
Transmission and Distribution	541		834		766		50		119		78
Power Generation	189		192		183		124		104		102
Storage (c)	–		75		77		–		21		3
Other activities	66		90		54		(25	)	(46	)	(33	)
Less: intra-group sales	(50	)	(47	)	(27	)
	2 610		2 508		2 272		888		833		688
Exceptional items (d)	–		34		–		–		34		(314	)
	2 610		2 542		2 272		888		867		374
Discontinued operations (e)
Transco	–		–		2 361		–		–		698
Other activities	–		–		165		–		–		65
Less: intra-group sales	–		–		(99	)
	–		–		2 427		–		–		763
Total	2 610		2 542		4 699		888		867		1 137

(a)	Gas trading activity within the E&P segment has been re-presented on a net basis, see note 1, page 81.
(b)	Total operating profit/(loss) includes BG’s share of operating profits less losses in joint ventures and associated undertakings.
(c)	In November 2001, BG disposed of the assets comprising the Storage segment.
(d)	For further information on exceptional items, see note 5, page 90.
(e)	Includes exceptional demerger related costs of £43 million in 2000.

OPERATING AND FINANCIAL REVIEW

INTRODUCTION
This Operating and Financial Review focuses on the continuing operations of BG. Sections discussing the consolidated results, including the results of discontinued operations in 2000, can be found on page 46 onwards. There were no discontinued operations in 2002 or 2001. A five year summary of the financial results of BG’s continuing operations is set out on page 126.

The continuing operations of BG comprise: Exploration and Production (E&P), Liquefied Natural Gas (LNG), Transmission and Distribution (T&D), Power Generation (Power) and Other activities. In November 2001, BG disposed of the assets comprising the Storage segment.

Discontinued operations in 2000 comprise those activities demerged to Lattice, including Transco and BG’s property, leasing, technology and energy services businesses.

This Operating and Financial Review should be read in conjunction with the consolidated Financial Statements and related notes included elsewhere in this report.

OPERATING RESULTS – CONTINUING OPERATIONS EXCLUDING EXCEPTIONAL ITEMS
BG’s turnover in 2002 was £2 610 million compared to £2 508 million in 2001 (2000 £2 272 million) – an increase of 4%. Total operating profit in 2002 was £888 million compared with £833 million in 2001 and £688 million in 2000. This represents increases of 7% and 21% respectively. Excluding the impact of changes in upstream gas and oil prices, total operating profit would have increased by 13% in 2002 and by 22% in 2001.

BG’s post-tax return on average capital employed (ROACE) was 10.9% (2001 13.4%; 2000 12.8%). Excluding the impact of the North Sea tax surcharge (see ‘Taxation – continuing operations’, below), ROACE in 2002 was 13.2%.

BG’s 2002 results were impacted by a number of factors including gas and oil commodity prices and foreign exchange rates (in particular the Argentine Peso, Brazilian Real and US$ movements against Sterling). BG’s exposure to oil prices is partly mitigated by the predominance of gas in its portfolio. A significant part of BG’s upstream

Please see information regarding certain forward-looking statements on page 130 of this report.

BG GROUP PLC 2002 39

EXPLORATION AND PRODUCTION
	2002	2001	2000
Production volumes (mmboe)
– oil	22.5	13.4	9.9
– liquids	19.4	14.7	14.9
– gas	94.2	80.7	77.7
	136.1	108.8	102.5
Average realised
– oil price per barrel (£/$)	16.67/24.86	16.63/23.97	18.42/28.07
– liquids price per barrel (£/$)	7.96/11.87	9.43/13.60	11.32/17.25
– UK gas price per produced therm (p)	15.91	16.85	15.06
– international gas price per produced therm (p)	12.49	13.62	11.92
– overall gas price per produced therm (p)	14.26	15.48	13.84
Lifting costs per boe (£/$)	1.04/1.55	1.05/1.51	1.12/1.70
Operating expenditure per boe (£/$)	2.09/3.12	2.05/2.96	2.09/3.19
Development expenditure (£m)	704	585	464
Gross exploration expenditure (£m)
– capitalised exploration expenditure	274	77	85
– other exploration expenditure	65	59	54
	339	136	139
Lifting costs represent operating expenditure excluding royalties, tariffs and insurance.

activity is conducted through gas contracts that are not directly linked to short-term movements in the oil price. The Argentine Peso, Brazilian Real and US$ all weakened over the course of the year. BG’s results will continue to reflect the impact of these, and other, market factors.

E&P
E&P’s turnover increased by 21% to £1 555 million from £1 283 million in 2001 and £1 188 million in 2000. The 2002 increase was underpinned by 25% higher production (£328 million), offset by lower realised prices (£49 million). The 2001 increase was due mainly to higher production (£93 million) and favourable US$ exchange rate movements (£22 million).

Production volumes rose by 25% (27.3 mmboe) to 136.1 mmboe, contributing £328 million to the increase in turnover in 2002 relative to 2001. This growth included new production from the Jade (3.9 mmboe), Panna/Mukta (3.8 mmboe), Tapti (2.6 mmboe) and North Coast Marine Area (NCMA) (1.9 mmboe) fields, higher production from fields which started during 2001 – Elgin/Franklin (5.8 mmboe) and Blake (3.4 mmboe) – together with greater production from existing fields, Karachaganak (6.7 mmboe)

and La Vertiente in Bolivia (2.7 mmboe). Excluding the Indian fields (Panna/Mukta and Tapti) acquired in early 2002, production rose by 19%.

In 2001, production volumes rose to 108.8 mmboe, an increase of 6.3 mmboe (6%), compared to 2000, resulting in a £93 million growth in turnover. Production increases were delivered mainly by fields within the UKCS (Blake (3.4 mmboe), Elgin/Franklin (3.5 mmboe) and Easington Catchment Area (ECA) (3.1 mmboe)), together with the Rosetta field in Egypt (2.4 mmboe). All of these fields, with the exception of the ECA fields, commenced production during 2001. These increases were partially offset by lower production at the Everest and Lomond fields (2.3 mmboe) and the J-Block fields (1.4 mmboe) in the UKCS and the Karachaganak field (1.7 mmboe).

Whilst oil prices in 2002 were broadly in line with 2001, gas price realisations were affected by low UK spot prices, and there was a consequential reduction in take from certain supply contracts as customers switched to purchase spot market gas at lower prices.

Prices for the majority of BG’s UK gas contracts are reset annually on 1 October. For the year beginning 1 October 2002,

average prices are expected to be around 12% lower than the 2001/2002 gas year. This compares to an increase of 9% in 2001.

Average realised overseas gas prices fell during 2002 because of a change in mix and the time lag effect of oil price movements reflected in certain contracts. Average realised overseas gas prices rose in 2001.

Total operating profit in 2002 increased by £125 million (21%) to £731 million (2001 £606 million; 2000 £513 million). The increase in 2002 reflected strong production growth of 25%, partially offset by the impact of lower realised gas prices. Excluding the impact of price changes, operating profit in 2002 would have increased by 29%. The improvement in 2001 was mainly the result of higher production volumes.

Unit lifting costs were £1.04 per boe in 2002 compared to £1.05 per boe in 2001. Unit operating costs were £2.09 per boe in 2002 against £2.05 per boe in 2001, reflecting the impact of an increase in tariff costs, principally from transportation and processing fees on production from the Jade and Blake fields (which started production in February 2002 and June 2001 respectively). Prolonged periods of firm oil prices typically create cost pressure on oil

40 BG GROUP PLC 2002

OPERATING AND FINANCIAL REVIEW

services and it is estimated that this, together with the impact of prices on royalties and tariffs, has contributed around 25 US cents per boe to unit operating costs compared with BG’s cost target assumption.

Unit lifting costs in 2001 fell by 6% compared with 2000 to £1.05 (a fall of 9% excluding the impact of the US$) reflecting lower costs and higher volumes. Unit operating costs were £2.09 per boe in 2000.

Of the 25 exploration and appraisal wells completed in 2002, 18 were successful, representing a success rate of 72% (2001 success rate of 71% with 14 wells completed). Well write-off costs were £12 million (2001 £13 million). In 2000, BG’s exploration and appraisal drilling programme achieved an industry leading 100% success rate and consequently there were no well write-off costs in the year.

LNG
LNG’s turnover more than tripled in 2002 to £309 million (2001 £81 million; 2000 £31 million). LNG shipping and marketing activity accounted for the majority of the increased turnover in all three years (including the Lake Charles activity from 1 January 2002).

Total operating profit of £8 million in 2002 was £21 million lower than in 2001 (£29 million; 2000 £25 million). The decrease in 2002 reflected lower profits from shipping and marketing which, following a profit of £22 million in 2001,

broke even during the year. This was mainly because of lower US gas prices in the first half of 2002 and the cost of establishing the new shipping and marketing business at Lake Charles. The Lake Charles business performed well for its first year of operation with 44 cargoes received and processed and a further six cargoes delivered to other destinations to take advantage of market opportunities.

The segment results included the contribution from BG’s share of the operating profit of Atlantic LNG (ALNG), an associated undertaking (2002 £29 million; 2001 £30 million; 2000 £30 million) which exports LNG to the USA and Europe. The ALNG Train 1 2002 profit reflected a 5% increase in volumes, offset by lower prices. ALNG Train 2 commenced production, in start-up phase, in the third quarter of 2002.

In 2001, the £4 million increase in profit came from growth in shipping and marketing activity (an increase from £13 million to £22 million) offset by higher business development expense (a £5 million increase in costs to £23 million). ALNG’s 2001 profit, compared to 2000, reflected higher volumes and commodity prices, offset by increased commodity costs.

T&D
T&D’s turnover in 2002 was £541 million compared to £834 million in 2001 and £766 million in 2000. Turnover in 2002 included the impact of the devaluation

of the Argentine Peso (£292 million) and the Brazilian Real (£84 million).

Excluding MetroGAS, T&D’s turnover was £407 million in 2002 (2001 £364 million; 2000 £281 million). The increase in 2002 reflects a 14% increase in Comgas’ turnover where a 31% rise in volumes was offset by the exchange impact of the Brazilian Real referred to earlier. Higher transmission volumes led to a 76% increase in volumes at Gujarat Gas in 2002.

The higher turnover in 2001 compared to 2000 mainly reflects a 32% increase in Comgas’ turnover from higher volumes (up 33%) following the expansion of its distribution network and increased power generation demand. Excluding the impact of the weaker Brazilian Real, Comgas’ turnover increased by 50%. Gujarat Gas’ volumes increased by 27% in 2001.

MetroGAS’ 2002 turnover fell because of the devaluation of the Argentine Peso and the effects of the country’s adverse economic and regulatory environment. In 2001, MetroGAS’ turnover fell by 3% mainly as a result of higher rainfall leading to the displacement of gas-produced power by hydroelectric power. Demand in the final quarter of the year also began to see the adverse impact of deteriorating macroeconomic conditions in Argentina.

Total operating profit including BG’s share of profits in joint ventures and associated undertakings in 2002 was

BG GROUP PLC 2002 41

OPERATING AND FINANCIAL REVIEW

£50 million (2001 £119 million; 2000 £78 million). The result in 2002 reflected strong growth at Comgas, offset by the foreign exchange impact of the weakening Brazilian Real and of the Argentine Peso on the results of MetroGAS. The increase in 2001 reflected improved performance across the segment, most notably at Comgas, Phoenix Natural Gas (Phoenix) and the Bolivia-Brazil pipeline. In addition, business development and overhead costs were lower than in 2000.

Comgas continued to see an increase in Sterling reported profit with operating profit up 88% to £32 million (2001 £17 million; 2000 £4 million loss). The increase in 2002 reflected strong volume growth and gross profit improvement, offset by the significant impact of the Brazilian Real depreciation. Excluding the impact of the weaker Brazilian Real, Comgas’ underlying operating profit increased by £24 million (141%) in 2002 compared to 2001 and by £31 million in 2001 compared to 2000.

The £72 million fall in profit from MetroGAS, to £3 million (2001 £75 million; 2000 £74 million), reflected the impact of the Argentine Peso devaluation, and the country’s adverse economic and regulatory environment. The small increase in the 2001 profit compared to 2000 reflected higher prices and lower costs offset by lower volumes (7% lower).

The Argentine Government has imposed a number of economic and political measures (as described on page 19) which may restrict BG’s ability to exercise its control over MetroGAS and management is monitoring this situation closely.

T&D’s share of profits in joint ventures and associated undertakings was £33 million (2001 £29 million; 2000 £24 million). The increases in both 2002 and 2001 were mainly attributable to Mahanagar Gas in India and to the Bolivia-Brazil pipeline.

Power
Power’s turnover was £189 million in 2002 compared with £192 million in 2001 and £183 million in 2000. Turnover in all three years was mainly attributable to Premier Power in the UK.

Total operating profit of £124 million (2001 £104 million; 2000 £102 million) included BG’s share of profits in joint ventures and associated undertakings of £93 million (2001 £81 million; 2000 £73 million) – attributable to the power plants at Seabank (in the UK), Santa Rita and San Lorenzo (in the Philippines), Serene (in Italy) and Genting Sanyen (in Malaysia).

The 19% increase in total operating profit in 2002 reflected increased profitability across the segment. At Premier Power, profit increases were driven by a reduction in costs following the planned closure of an existing unit during the year and one-off credits amounting to around £4 million. The San Lorenzo power

station entered into full commercial operation on 1 October and was the main contributor to the increase in BG’s share of the operating profit in joint ventures and associated undertakings.

The 2% increase in total operating profit in 2001 reflected the commencement of full commercial operations at Seabank (Phase 2 commissioned in January 2001) and Santa Rita (fully operational in August 2000), together with the receipt of lower cost reimbursements on the Santa Rita and San Lorenzo projects.

Storage
On 28 November 2001, BG disposed of BG Storage Limited (BG Storage). Further details of the sale are given in ‘Exceptional items – profit/(loss) on disposals – continuing operations’, below.

Storage’s turnover up to the date of disposal in 2001 was £75 million, compared with £77 million in 2000. Turnover in 2001 benefited from higher capacity and commodity sales at the Rough storage facility, offshore UK.

Operating profit to the date of disposal was £21 million compared to £3 million in 2000. Increased profits in 2001 reflected a lower depreciation charge (following a £200 million impairment of assets in mid-2000) and lower decommissioning costs.

Other activities
Other activities comprise New Business development expenditure, certain corporate costs and activities relating to certain long-term gas contracts.

42 BG GROUP PLC 2002

PROFIT FOR THE YEAR: CONTINUING OPERATIONS
			2002						2001						2000
	Total £m		Exceptional items £m		Business performance £m	(a)	Total £m		Exceptional items £m		Business performance £m	(a)	Total £m		Exceptional items £m		Business performance £m	(a)
Total operating profit	888		–		888		867		34		833		374		(314	)	688
Profit/(loss) on disposal of fixed assets	(14	)	(14	)	–		98		98		–		280		280		–
Interest	(80	)	–		(80	)	(63	)	17		(80	)	(80	)	–		(80	)
Tax	(374	)	–		(374	)	(287	)	(28	)	(259	)	(114	)	63		(177	)
Minority interest	(10	)	–		(10	)	(29	)	–		(29	)	(19	)	–		(19	)
Earnings	410		(14	)	424		586		121		465		441		29		412
Earnings per share	11.6	p	(0.4	)p	12.0	p	16.7	p	3.4	p	13.3	p	12.7	p	0.9	p	11.8	p
(a) Business performance represents continuing operations excluding exceptional items. For further information on exceptional items, see note 5, page 90.

OPERATING AND FINANCIAL REVIEW

The total operating loss in 2002 was £25 million compared to £46 million in 2001 and £33 million in 2000. The 2002 loss was due principally to New Business expense partially offset by the release of a provision on certain long-term gas contracts no longer required. The operating loss in 2001 arose mainly as a result of an increased corporate provision for bad debts in the fourth quarter of £20 million and higher levels of expenditure on New Business compared to 2000. These 2001 increases were partially offset by a £7 million operating profit on certain long-term gas contracts, prior to their disposal, and the release of that portion of the provision no longer required in respect of these contracts (£13 million). The loss in 2000 arose mainly on New Business expense and activity under certain long-term gas contracts.

EXCEPTIONAL ITEMS – OPERATING RESULTS – CONTINUING OPERATIONS
There were no exceptional operating items in 2002.

In 2001, the House of Lords ruled in favour of the Central Area Transmission System (CATS) partners (BG’s share 51.18%) in their dispute with Teesside Gas Transportation Limited (an Enron Corp. subsidiary). This gave rise to income of £34 million in the E&P segment which is presented as an exceptional item within turnover. See ‘Litigation’, below, for further information.

In 2000, Premier Power incurred exceptional charges of £29 million relating to restructuring costs incurred following the conclusion of all agreements necessary to proceed with its CCGT project. This charge was included within the Power segment.

In 2000, the carrying value of the Rough offshore storage facility was impaired by £200 million in the light of trading conditions during 2000 and following a review of the longer term prospects of the business. This was treated as an exceptional operating charge in Storage’s results.

The total operating loss of Other activities in 2000 included an £85 million exceptional charge in respect of demerger related costs. An analysis of these costs is set out in note 5, page 90.

EXCEPTIONAL ITEMS – PROFIT/(LOSS) ON DISPOSALS – CONTINUING OPERATIONS
Profits/(losses) on the disposal of fixed assets and investments are reported as exceptional items.

In 2002, the loss on disposal of fixed assets and investments of £14 million (2001 £98 million profit; 2000 £280 million profit) included the £7 million loss on disposal of BG’s 100% investment in Iqara EcoFuels Limited and a loss of £2 million relating to the disposal of part of the Rose field.

The 2001 profit included the disposal of BG Storage and associated assets and a 24.5% share in Phoenix. BG Storage

provided gas storage services in Great Britain and its assets included the Rough offshore storage facility, salt cavities in Hornsea and an interest in processing facilities at Easington. The associated assets sold included the remaining interest in the processing facilities at Easington, the Amethyst gas processing condensate transport agreement and BG’s interest in the offshore York discovery. The sale of BG Storage generated proceeds of £421 million which gave rise to a profit of £78 million. The sale of part of BG’s interest in Phoenix, the Northern Ireland natural gas distribution company, reduced BG’s interest in Phoenix to 51% and realised a £21 million profit.

Profits in 2000 included £305 million on the sale of BG’s share of Dynegy Inc., an associated undertaking.

INTEREST – CONTINUING OPERATIONS
BG’s net interest payable was £80 million compared to £63 million in 2001 and £80 million in 2000. The 2001 charge of £63 million included a £17 million receipt in respect of the House of Lords judgment in favour of the CATS partners (see ‘Litigation’, below). Excluding this 2001 exceptional receipt, the 2002 interest charge was in line with 2001, reflecting a higher level of borrowings offset by lower interest rates and lower unwinding charges on discounted provisions. The underlying 2001 charge was in line with 2000, reflecting higher levels of borrowings offset by a lower charge in respect of discounted provisions

BG GROUP PLC 2002 43

OPERATING AND FINANCIAL REVIEW

following the assignment of certain long-term gas contracts in 2001.

The interest charge also includes BG’s share in the interest charge of joint ventures and associated undertakings, which was £36 million in 2002 compared to £40 million in 2001 and £35 million in 2000.

TAXATION – CONTINUING OPERATIONS
BG’s tax charge for 2002 before exceptional items was £374 million (2001 £259 million; 2000 £177 million). This incorporates the changes enacted in the Finance Act 2002, including a 10% surcharge on North Sea profits. This rate change had the effect of increasing the current year charge by £44 million and gave rise to a further £51 million charge relating to opening UK deferred tax balances. Excluding both this change relating to opening balances and exceptional items, BG’s effective tax rate for 2002 was 40% (2001 34.5%; 2000 29.1%). Excluding the change relating to opening balances and including exceptional items, BG’s tax charge was £323 million (2001 £287 million; 2000 £114 million), representing an effective tax rate of 40.7% (2001 31.8%; 2000 20%).

EARNINGS AND EARNINGS PER SHARE –CONTINUING OPERATIONS EXCLUDING EXCEPTIONAL ITEMS
Earnings (earnings per share) were £424 million (12.0 pence) in 2002 compared to £465 million (13.3 pence) in 2001 and £412 million (11.8 pence) in 2000.

Excluding the effect of the North Sea tax surcharge (£95 million) described above, 2002 earnings per share would have been 14.7 pence.

CAPITAL INVESTMENT – CONTINUING OPERATIONS
Capital investment of £1 510 million (2001 £1 079 million; 2000 £883 million) included the acquisition of the entire share capital of BG Exploration and Production India Limited (formerly named Enron Oil and Gas India Limited) for £247 million. The total comprised expenditure on intangible and tangible fixed assets of £1 178 million (2001 £927 million; 2000 £717 million) and on fixed asset investments of £332 million (2001 £152 million; 2000 £166 million).

E&P’s capital investment (including capitalised exploration expenditure) was £1 238 million (2001 £671 million; 2000 £549 million). This included the acquisition of BG Exploration and Production India Limited, referred to above. This company’s assets include 30% interests in the Tapti gas field and the Panna/Mukta oil and gas fields.

Gross exploration expenditure incurred during 2002 was £339 million (2001 £136 million; 2000 £139 million) of which £274 million was capitalised (2001 £77 million; 2000 £85 million). The £274 million in 2002 included payments in respect of the exercise of pre-emption rights and the continuing exploration and appraisal programme at Kashagan.

Development expenditure totalled £704 million compared with £585 million in 2001 and £464 million in 2000.

Development expenditure in 2002 was primarily in respect of the Karachaganak, West Delta Deep Marine Concession (WDDM), ECA, Miskar, NCMA, Armada and Jade fields. Development expenditure in 2001 was focused on the Karachaganak, WDDM, Elgin/Franklin and NCMA fields and in 2000 was mainly on the Karachaganak, Blake, Elgin/Franklin, Everest, Lomond and Rosetta fields.

LNG’s capital investment in 2002 was £117 million compared to £104 million in 2001 and £67 million in 2000. Expenditure in each year related mainly to the expansion of ALNG, and in 2002 also related to the development of Egyptian LNG.

T&D’s capital investment amounted to £81 million (2001 £170 million; 2000 £117 million). Expenditure in both 2002 and 2001 was incurred mainly on the expansion of the transmission and distribution networks at Comgas. Capital investment in 2000 included the expansion of Comgas’ and MetroGAS’ distribution networks.

Capital investment for Power in 2002 of £50 million (2001 £122 million; 2000 £135 million) was mostly related to the Premier Power CCGT project, as was the 2001 expenditure. Capital investment in 2000 related mainly to Seabank and the Premier Power CCGT project.

44 BG GROUP PLC 2002

OPERATING AND FINANCIAL REVIEW

Capital investment of approximately £0.8 billion is projected for 2003. BG proposes to meet this expenditure from both the operating cash flows of the business and, as appropriate, the money and capital markets, including existing lines of credit.

FINANCIAL TARGETS
BG’s targeted financial framework is:

• ROACE of 10-11% in 2003 and 13% in 2006, based on an oil price of $16 real (base 2000) until the end of 2003 and then $17 (nominal) per barrel;

• Capital investment of £5.6 billion for the period 1999 to 2003 and £3 billion for the period 2004 to 2006;

• Gearing ratio (net debt as a percentage of total shareholders’ funds plus net debt) of less than 25%.

The ROACE targets set in 1999 (in respect of 2003) and 2001 (in respect of 2006) were revised during the year from original values of 13% and 14% respectively. The former was reduced to reflect the impact of higher investment due to the exercise of Kashagan pre-emption rights, the purchase of Indian upstream assets and updated spending plans, whilst the effects of the increased UK corporation tax and the economic situation in South America impacted both targets.

The key risks and assumptions surrounding the 2003 and 2006 targets are set out in the Risk Factors section on pages 32 and 33.

CASH FLOW – CONTINUING OPERATIONS
Cash flow from normal operating activities (excluding significant one-off items, see note 28, page 110) in 2002 was higher than 2001 at £1 015 million (2001 £837 million; 2000 £844 million). Including the one-off items arising in 2001 and 2000, cash flow from operating activities in 2002 of £1 015 million compared to £666 million in 2001 and £1 078 million in 2000.

The one-off items comprised the assignment of certain long-term gas contracts (2001 £184 million outflow), the House of Lords judgment in favour of the CATS partners (2001 £34 million inflow), the demerger of Lattice (2001 £21 million outflow; 2000 £56 million inflow) and deferred income on the Premier Power CCGT project (2000 £178 million inflow).

Dividends from joint ventures and associated undertakings amounted to £68 million in 2002, compared to £75 million in 2001 and £28 million in 2000. The increase in 2002 and 2001 compared to 2000 was mainly due to dividends from Santa Rita and Seabank. Dividends were received from ALNG in all three years.

Returns on investments and servicing of finance accounted for a net cash outflow of £32 million in 2002 (2001 £40 million; 2000 £30 million outflow (excluding £129 million in respect of dividends received from Lattice)). This includes a £4 million outflow (2001 £18 million; 2000 £16 million) in respect of dividends

paid to minority shareholders. 2001 also included a £17 million interest receipt arising from the House of Lords judgment in favour of the CATS partners.

Tax of £240 million was paid in 2002 compared to £261 million in 2001 and £200 million in 2000. The reduction in 2002 reflects the increased capital allowances available following the enactment of the Finance Act 2002. The increase in 2001 reflected the transition to new arrangements for the payment of UK corporation tax, introduced by the Inland Revenue in 1999.

Payments to acquire fixed assets and investments amounted to £1 386 million in 2002, £989 million in 2001 and £844 million in 2000. Payments in 2002 included £247 million in respect of the purchase of the entire share capital of BG Exploration and Production India Limited (offset by £57 million cash acquired in this acquisition) and the purchase of pre-emption rights on Kashagan.

Receipts in respect of the disposal of fixed assets and investments were £7 million in 2002 (2001 £466 million; 2000 £524 million). Receipts in 2001 included £421 million in respect of the sale of BG Storage and associated assets and £49 million on the disposal of a 24.5% share in Phoenix. These 2001 receipts were offset by £14 million cash held by BG Storage at the time of the disposal. Receipts in 2000 included £466 million from the sale of BG’s interest in Dynegy Inc.

BG GROUP PLC 2002 45

OPERATING AND FINANCIAL REVIEW

NET BORROWINGS – CONTINUING OPERATIONS
Net borrowings (comprising cash, current asset investments, short- and long-term borrowings) increased to £1 002 million as at 31 December 2002 from £538 million as at 31 December 2001 (£360 million as at 31 December 2000). The increase in both 2002 and 2001 was mainly due to capital investment, together with, in 2001 only, the payment for the assignment of certain long-term contracts and working capital movements, offset by the cash receipts on disposal of fixed assets, discussed above.

As at 31 December 2002, BG’s share of net borrowings in joint ventures and associated undertakings amounted to approximately £700 million (2001 approximately £600 million), including BG shareholder loans of approximately £320 million (2001 approximately £150 million). These net borrowings are included in BG’s share of the net assets in joint ventures and associated undertakings which are consolidated in BG’s accounts (see note 12, page 95). Of the net borrowings excluding BG shareholder loans, £100 million is guaranteed by BG.

BG shareholders’ funds as at 31 December 2002 were £3 324 million compared with £3 406 million at the beginning of the year. The change incorporates currency translation adjustments of £385 million (see movement in BG shareholders’

funds, page 78). The gearing ratio was 23.0% (31 December 2001 13.2%).

Details of the maturity, currency and interest rate profile of the Group’s borrowings as at 31 December 2002 are shown in notes 17 to 20, page 98 and details of the Group’s current asset investments as at 31 December 2002 are shown in note 16, page 97.

BG’s principal borrowing entities are BG Energy Holdings Limited (BGEH), BG Energy Capital plc (BGEC), BG Energy Finance Inc. (BGEF), MetroGAS, Gas Argentino S.A. (Gas Argentino), Comgas and Gujarat Gas. The borrowings of BGEC and BGEF are guaranteed by BGEH. The borrowings of MetroGAS, Gas Argentino, Comgas and Gujarat Gas are non-recourse to the other members of the Group.

BGEH is the Group’s principal credit rated entity, with long-term credit ratings of A-from Fitch, A3 from Moody’s and A- from Standard & Poor’s. BGEH has short-term credit ratings of F-2 from Fitch, P-2 from Moody’s and A-2 from Standard & Poor’s.

As at 31 December 2002, BGEF had a $1.0 billion US Commercial Paper Programme, which was unutilised. BGEC had a $1.0 billion Eurocommercial Paper Programme, of which $913 million was unutilised and a $2.0 billion Euro Medium Term Note Programme, of which $1.208 billion was unutilised. BGEH had aggregate committed multicurrency revolving borrowing facilities of $1.072 billion, of which $552 million

matures in 2003 and $520 million matures in 2005. These facilities were undrawn.

In addition, at 31 December 2002, BGEH had uncommitted multicurrency borrowing facilities of £635 million, of which £515 million was unutilised.

There are no restrictions on the application of funds in any of the borrowing facilities of BGEH, BGEC or BGEF.

Comgas had committed borrowing facilities of Brazilian Reals (BRL) 632 million (£113 million), of which BRL 194 million (£35 million) was unutilised, and uncommitted borrowing facilities of BRL 759 million (£136 million), of which BRL 501 million (£90 million) was unutilised.

MetroGAS announced on 25 March 2002 that it had suspended payment of principal and interest on all its financial indebtedness of $419 million. On 23 July 2002 and 22 October 2002, it announced its intention to make extraordinary payments on certain accrued interest amounts and as a result is now current with interest accrued up until 30 September 2002. MetroGAS is currently developing a comprehensive plan to restructure all its financial obligations, although progress is constrained by the pace of the utility tariff renegotiation process in Argentina.

Gas Argentino has also suspended debt service on its borrowings of $70 million.

46 BG GROUP PLC 2002

PROFIT FOR THE YEAR
	2002	(a)	2001	(a)			2000
							Discontinued		Continuing
					Total		operations		operations
	£m		£m		£m		£m		£m
Consolidated results
Total operating profit	888		867		1 137		763		374
Profit/(loss) on disposal of fixed assets	(14	)	98		276		(4	)	280
Interest	(80	)	(63	)	(459	)	(379	)	(80	)
Tax	(374	)	(287	)	(281	)	(167	)	(114	)
Minority interest	(10	)	(29	)	(19	)	–		(19	)
Earnings	410		586		654		213		441
Earnings excluding exceptional items	424		465		664		252		412
(a) There were no discontinued operations in 2002 or 2001.

OPERATING AND FINANCIAL REVIEW

All the borrowings of MetroGAS and Gas Argentino are non-recourse to BG and management has no plans to provide financial support to these subsidiaries.

The borrowing facilities of MetroGAS and Gas Argentino contain certain financial covenants, and some of the borrowings of MetroGAS and Comgas have restrictions as to their use, being linked to capital projects.

Gujarat Gas has uncommitted borrowing facilities of Indian Rupees (INR) 880 million (£12 million), of which INR 392 million (£5 million) was unutilised.

The distribution of the profits of MetroGAS and Comgas is restricted under local legislation. Details of these restrictions are shown in note 30, page 116. Distribution of the profits of BG’s other subsidiary undertakings is not materially restricted.

Except for the working capital of MetroGAS and Gas Argentino, BG’s working capital is considered to be sufficient to meet current requirements.

DIVIDEND
At demerger the Board stated its intention to maintain the dividend level in real terms. This will enable an appropriate portion of future earnings to be retained for investment in the attractive opportunities expected to be available to the Group.

The Directors have proposed a final dividend of 1.55 pence per ordinary share to be paid on 2 May 2003 (12 May 2003 in respect of American Depositary Shares (ADSs)). This brings the total dividend for the year to 3.1 pence compared to 3.0 pence in 2001 and 2.9 pence in 2000 (on a pro forma basis). The total dividend in respect of 2000, including discontinued operations, was 6.4 pence.

DEMERGER IN 2000
In December 1999, BG completed its restructuring and refinancing which involved the separation of its regulated and unregulated businesses.

In October 2000, the Company’s shareholders approved the demerger of certain businesses to Lattice. On demerger, shareholders received one Lattice Group plc share for each BG Group plc share held. This demerger separated BG’s two principal businesses, BG International and Transco, with the former remaining within BG. All activities demerged to Lattice are presented in these accounts as discontinued operations.

A discussion of the consolidated results, including the contribution of discontinued operations, is presented below. As there were no discontinued operations in 2002 or 2001, there is no discussion of the 2002 results in comparison to the 2001 results.

CONSOLIDATED RESULTS – INCLUDING DISCONTINUED OPERATIONS
This section should be read together with the results of continuing operations discussed above.

Consolidated turnover in 2001 was £2 542 million compared to £4 699 million in 2000. Consolidated total operating profit (including exceptional items), was £867 million in 2001 and £1 137 million in 2000.

During 2000, BG made sales in respect of the transportation of gas of around £1.5 billion to British Gas Trading Limited, a subsidiary of Centrica plc.

OPERATING RESULTS – INCLUDING DISCONTINUED OPERATIONS
The operating results of business segments within continuing operations are discussed earlier in this review. Discussed below are the results of operations discontinued in 2000.

Transco
Transco was demerged to Lattice effective on 23 October 2000. Transco’s turnover was £2 361 million in 2000 to the date of demerger. Operating costs of £1 663 million in 2000 included £50 million in respect of potential liabilities under the network code (dealing with transportation arrangements) and other shipper issues, £41 million of exceptional demerger costs and additional replacement expenditure of £30 million.

BG GROUP PLC 2002 47

OPERATING AND FINANCIAL REVIEW

Transco’s operating profit in 2000 was £698 million.

Other activities (discontinued operations)
Other activities relate to those businesses other than Transco that were demerged to Lattice in 2000. Total operating profit generated in 2000 was £65 million, including a £76 million pension credit.

INTEREST – CONSOLIDATED RESULTS –INCLUDING DISCONTINUED OPERATIONS
The consolidated net interest charge in 2001 was £63 million compared to £459 million in 2000. The lower charge in 2001 reflects the inclusion of discontinued operations in 2000.

TAXATION – CONSOLIDATED RESULTS –INCLUDING DISCONTINUED OPERATIONS
BG adopted FRS 19 in 2001 and, accordingly, restated the tax charge for previous years. The consolidated tax charge for 2001 was £287 million (2000 £281 million). The consolidated historical cost effective tax rate was 31.8% in 2001 and 26.2% in 2000.

EARNINGS AND EARNINGS PER SHARE –CONSOLIDATED RESULTS – INCLUDING DISCONTINUED OPERATIONS
Consolidated earnings in 2001 were £586 million compared to £654 million in 2000. The fall in 2001 was primarily due to discontinued operations being included only up to the effective date of demerger, 23 October 2000.

BG’s consolidated earnings per ordinary share were 16.7 pence in 2001 and 18.8 pence in 2000. Earnings per share excluding exceptional items were 13.3 pence in 2001 and 19.1 pence in 2000.

CAPITAL INVESTMENT – CONSOLIDATED RESULTS – INCLUDING DISCONTINUED OPERATIONS
In 2001, BG’s total capital investment was £1 079 million. This related to continuing operations only and is discussed earlier in this review.

In 2000, BG’s total capital investment was £1 514 million, comprising investment in tangible and intangible fixed assets of £1 278 million and additions to fixed asset investments of £236 million.

Transco’s capital investment in 2000 was £482 million. The expenditure was incurred in respect of the National Transmission System and the expansion of high pressure systems.

CASH FLOW – CONSOLIDATED RESULTS –INCLUDING DISCONTINUED OPERATIONS
Consolidated cash inflow from operating activities was £666 million in 2001 compared to £2 642 million in 2000. The fall in 2001 was mainly due to the inclusion of discontinued operations in 2000. Payments to acquire fixed assets and investments amounted to £989 million in 2001 (2000 £1 384 million).

NET BORROWINGS – CONSOLIDATED RESULTS – INCLUDING DISCONTINUED OPERATIONS
Net borrowings as at 31 December 2001 were £538 million (2000 £360 million). Net borrowings of the businesses demerged to Lattice amounted to £5 621 million as at the date of demerger.

TREASURY POLICY
The Group’s principal Treasury risks are those risks associated with refinancing, interest rates, foreign exchange and counterparty credit. These risks are all managed in accordance with policies approved by the Finance Committee. The use of derivative financial instruments is controlled by policy guidelines set by the Board. The Group’s principal Treasury policies are summarised below.

Refinancing risk
Refinancing risk is managed principally by limiting the amount of borrowings maturing within any specific period. The maturity profile of the Group’s borrowings appears in note 17, page 98.

Interest rate risk
Interest rate risk is managed by the use of fixed- and floating-rate borrowing, and interest rate derivatives.

The Group’s principal interest rate risk management policy is to seek to minimise total financing costs (i.e. interest costs plus changes in the market value of debt) subject to upper and lower limits on the ratio of fixed-rate to floating-rate obligations.

48 BG GROUP PLC 2002

OPERATING AND FINANCIAL REVIEW

In the case of the borrowings of BGEH (including borrowings guaranteed by BGEH), such borrowings must generally be between 25% and 50% fixed rate.

Foreign exchange risk
US dollars
A substantial proportion of the Group’s business activity is conducted in US$, and the Group holds substantial dollar-denominated assets. The Group mitigates its exposure to the US$ by borrowing in, or swapping borrowings into, US$ up to a maximum of 100% of the book value of US$ denominated assets.

The foreign exchange policy does not require US$ denominated transactions to be hedged, although the Group may hedge certain exposures with the authorisation of the Finance Committee.

Details of transaction hedge amounts appear in note 20, page 100.

Other currencies
The Group’s net balance sheet exposure to foreign currencies other than the US$ principally comprises exposure to the Argentine Peso, Brazilian Real and Indian Rupee. These net exposures are managed on a case-by-case basis with the objective of protecting economic value subject to practicality and cost considerations.

Subsidiary undertakings which borrow on a stand-alone basis are generally required to borrow in, or swap borrowings into, their functional

currency of operation or a proxy for the functional currency.

The Group mitigates its exposure to transactions in currencies other than the US$ or Sterling by hedging certain expected cash flows into Sterling or US$.

Counterparty risk
Treasury counterparty risk arises principally from the investment of surplus funds, from cash balances held in bank accounts, and from the use of derivative instruments. Such risk is controlled through credit limits (principally credit rating-based) and monitoring procedures.

Derivative financial instruments held for purposes other than trading
As part of its business operations, the Group is exposed to risks arising from fluctuations in interest rates and exchange rates. The Group uses off-balance sheet derivative financial instruments (derivatives) in order to manage exposures of this type. The Group enters into interest rate swaps or forward rate agreements to manage the composition of floating and fixed rate debt, and so hedge interest rate exposure.

The Group enters into foreign exchange contracts to hedge commercial transactions, and enters into foreign currency swaps to adjust the currency composition of its assets and liabilities in order to hedge its exposure to exchange rate movements. Certain agreements are combined foreign currency and interest

swap transactions. Such agreements are shown as cross-currency swaps.

The Group’s policy is not to use interest rate and exchange rate derivatives for speculative purposes. Derivatives can, to varying degrees, carry both counterparty and market risk.

Valuation and sensitivity analysis
The Group calculates the fair value of medium- and long-term debt and derivative instruments by discounting all future cash flows by the market yield curve at the balance sheet date. In the case of instruments with optionality, the Black’s variation of the Black-Scholes model is used to calculate fair value.

The Group utilises a sensitivity analysis technique to evaluate the effect that changes in relevant rates or prices will have on the market value of debt and derivative instruments. As at 31 December 2002, the potential change in the fair value of the aggregation of medium-and long-term debt and exchange rate and interest rate derivative instruments was £10 million, assuming a 10% change in the level of interest rates (2001 £1 million). The potential change in the fair value of the above, assuming a 10% change in exchange rates, was £103 million (2001 £58 million).

COMMODITY RISK
The Group’s results are sensitive to US$ denominated crude oil prices. Crude oil prices are volatile, depending on shifts

BG GROUP PLC 2002 49

COMMITMENTS AND CONTINGENCIES
as at 31 December 2002			Payment due:
	Total £m	Within 1 year £m	1-3 years £m	4-5 years £m	Over 5 years £m
Commitments
Capital commitments	430	430	–	–	–
Operating lease commitments	476	56	104	102	214
Finance lease commitments	218	2	12	13	191
Future well costs	21	21	–	–	–
Other financial commitments	1 324	32	71	136	1 085
	2 469	541	187	251	1 490
Contingencies
Loan guarantees	856
Other (mainly the provision of indemnities)	2 483
	5 808

OPERATING AND FINANCIAL REVIEW

in world supply and demand, OPEC (Organization of the Petroleum Exporting Countries) policies and the general economic and political climate. The Group’s exposure to oil prices is partly mitigated by the predominance of gas in its portfolio, much of which is sold under long-term contracts. In 2002, substantially all upstream revenues had some degree of indexation to oil prices. Most of this was on a time lagged basis.

The Group does not, as a matter of course, hedge all commodity prices, but may hedge certain gas and oil revenue streams from time to time. The Group uses forward commodity contracts, including forward, derivative and option contracts, to partially offset the exposure of certain of its forecast oil and gas revenues to commodity price variations. The Group also has a small commodity trading operation. The fair value of the Group’s commodity derivative contracts is calculated using forward price curves for the relevant commodity. As at 31 December 2002, the potential change in the fair value of the aggregation of outstanding commodity derivative contracts was £9 million (2001 £3 million) assuming a 10% change in the forward price curve.

COMMITMENTS AND CONTINGENCIES
BG’s commitments and contingencies are summarised in the table above. BG proposes to meet its commitments from both the operating cash flows of the business and from the money and capital

markets, including existing lines of credit. As at 31 December 2002, BG and its joint ventures and associated undertakings had undertaken commitments for capital expenditure of £430 million, principally concerning investment in the exploration and appraisal programme and LNG export facilities. Other financial commitments as at 31 December 2002 and 2001 comprised a 22 year contract for a capacity service at Lake Charles. The increase in this commitment relates to the planned expansion of the capacity service of the terminal. Other contingencies mainly include the provision of indemnities to third parties in respect of the Company and its subsidiary undertakings, in the normal course of business. Further details can be found in note 25, page 104.

LITIGATION
During 1999, the London Court of Appeal heard the appeal by Teesside Gas Transportation Limited (an Enron Corp. subsidiary) (TGTL) against the judgment of June 1997 in favour of the CATS partners. BG has an ownership share (51.18%) in CATS. The Court of Appeal found in partial favour of the appeal, resulting in the CATS partners being ordered to pay a sum to TGTL, of which BG’s share was £34 million plus £12 million interest. In 2001, the House of Lords overturned the Court of Appeal’s 1999 decision, giving rise to income of £34 million and £17 million interest receivable. The resulting tax impact is a £15 million charge, leading to a net

£36 million increase in earnings. For details of other legal proceedings, see note 25, page 104.

APPLICATION OF CRITICAL ACCOUNTING POLICIES
The following paragraphs identify those critical accounting policies which rely on complex or subjective decisions or assessments by management. These should be read in conjunction with BG’s Principal Accounting Policies which are discussed on pages 71 to 73.

Exploration expenditure
BG accounts for exploration expenditure under the ‘successful efforts’ method. The success or failure of each exploration effort is judged on a well-by-well basis as each potential hydrocarbon structure is identified and tested. Certain expenditure, such as licence acquisition and drilling costs, is capitalised within intangible assets pending determination of whether or not proved reserves have been discovered. A review is carried out at least annually and any unsuccessful expenditure is written off to the profit and loss account. Costs that relate directly to the discovery and development of specific gas and oil reserves are capitalised and depreciated over the useful economic lives of those reserves. Certain expenditure that is general in nature, such as geological and geophysical exploration costs, is written off directly to the profit and loss account.

An alternative policy would be the ‘full cost’ method under which all costs

50 BG GROUP PLC 2002

OPERATING AND FINANCIAL REVIEW

associated with exploring for and developing gas and oil reserves within a cost pool are capitalised and written off against income from subsequent production. Whilst the reported profits under each method will be the same over the total life of the entity, profits are generally recognised earlier under the full cost method.

Depreciation
Exploration and production assets are depreciated using the unit of production method based on the proved developed reserves of those fields, except that a basis of total proved reserves is used for acquired interests and facilities. The measurement of reserves involves judgment and reserve estimates are reviewed and, where relevant, updated quarterly.

Under the UK Statement of Recommended Practice (SORP) entitled ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’, commercial reserves are recommended as the basis for calculating depreciation. This definition permits the inclusion of probable as well as proven reserves. This option is subject to a higher degree of estimation than that used by BG.

Decommissioning
Decommissioning provisions are recognised in the accounts at the net present value of the future expenditure required to settle the Group’s decommissioning obligations.

The discount implicit in recognising the decommissioning liability is unwound over the life of the provision and is included in the profit and loss account as a financial item, within the net interest charge. Where a provision gives access to future economic benefits, an asset is recognised and depreciated in accordance with BG’s depreciation policy referred to earlier.

The measurement of decommissioning provisions involves the use of estimates and assumptions such as the discount rate used to determine the net present value of the liability. The estimated cost of decommissioning is based on engineering estimates and reports from independent advisors. In addition, the payment dates of expected decommissioning costs are uncertain and are based on economic assumptions surrounding the useful economic lives of the fields concerned. Management reviews the assumptions used in the calculation of expected costs on an annual basis.

Impairments
Impairment reviews compare the carrying value of an income generating unit with its recoverable amount. The recoverable amount is the higher of the net realisable value and the estimated value in use. Value in use is based on the net present value of expected future pre-tax cash flows. Impairment reviews impact all operating segments.

BG uses assumptions that are consistent with its base case business plan to determine the net present value of future cash flows for use in impairment reviews. Particular assumptions which impact the calculations are gas and oil prices, foreign exchange rates and discount rates.

Presentation of gas trading activity
As part of managing its gas supply portfolio within the UK gas market, BG undertakes gas trading activities (i.e. the purchase and re-sale of third-party gas). In view of the nature of these activities, BG believes a net presentation of the operating results is most appropriate (see note 1, page 81).

US GAAP – derivative instruments and hedging activity
Under US GAAP, BG recognises all derivatives as either assets or liabilities on the balance sheet and measures them at fair value. BG uses derivative instruments to manage the risk of fluctuations in commodity prices, interest rates and foreign currencies. The fair value of these instruments is determined based on quoted market prices for the same or similar instruments. If a quoted market price is not available, the fair value is determined based on the present value of estimated future cash flows using a risk adjusted discount rate.

The main assumption used in the calculation of the fair value of commodity contracts relates to gas prices. This is used in the estimation of future cash

BG GROUP PLC 2002 51

OPERATING AND FINANCIAL REVIEW

flows. These prices are consistent with the Group’s base case business plan as used in the impairment reviews.

RELATED PARTY TRANSACTIONS
BG provides goods and services to and receives goods and services from its joint ventures and associated undertakings. In the year ended 31 December 2002, BG incurred charges of £71 million (2001 £28 million; 2000 not material) and, in turn, charged £29 million (2001 £2 million; 2000 not material) under these arrangements. In addition, BG provides financing to some of these parties by way of loans. As at 31 December 2002, loans of £336 million (2001 £259 million; 2000 £164 million) were due from joint ventures and associated undertakings. These loans are accounted for as part of BG’s investment in joint ventures and associated undertakings and disclosed in note 12, page 95. Interest of £19 million (2001 £18 million; 2000 £13 million) was charged on these loans during the year at interest rates of between 4.06% and 9.95% (2001 4.84% and 9.25%). The maximum debt outstanding during the year was £336 million (2001 £260 million; 2000 £175 million).

MetroGAS received charges relating to trading transactions of £8 million (2001 £27 million) from another shareholder during 2002. As at 31 December 2002, MetroGAS owed £1 million to this party (2001 £2 million).

During the year there were also a number of transactions between the Company and its subsidiary undertakings which are eliminated on consolidation and therefore not disclosed.

RESEARCH AND DEVELOPMENT
Investment on research and development is made to enable BG to continuously build and develop its core competencies in gas chain technologies. In this way, BG maintains its ability to leverage superior value from its ongoing business operations and new opportunities. BG pursues a policy of identifying best in class research groups through an integrated programme of maintaining an awareness of new and emerging technologies and working with partners of choice to leverage our technology investment in joint industry projects.The strategic aim of this approach is that we can become the fastest and smartest implementor of new technology. Consolidated investment on research and development in 2002 was £11 million (2001 £13 million; 2000 £34 million).

THE EURO
On 1 January 2002, 12 European countries replaced their national currency with the Euro. The UK may adopt the Euro as its national currency at a later date.

BG does not expect the Euro to lead to any significant operational disruptions or to impose costs which could materially affect liquidity or capital resources.

US GAAP RECONCILIATION
The differences between UK and US GAAP are set out in note 29, page 112. The differences include accounting for goodwill, pension costs, derivative instruments and deferred tax. Under Financial Accounting Standard (FAS) 133, BG’s derivative instruments are marked-to-market. BG uses derivative instruments to manage the risk of fluctuations in commodity prices, interest rates and foreign currencies. There are a number of issues pending before the Financial Accounting Standards Board which may have a material impact on the application of FAS 133. BG’s results under US GAAP are expected to continue to see some volatility due to the requirement of FAS 133 to mark-to-market a number of instruments and contracts at a point in time.

52 BG GROUP PLC 2002

BOARD OF DIRECTORS

BG GROUP PLC 2002 53

1 Sir Richard Giordano KBE (68)
Chairman and Non-Executive Director

Sir Richard Giordano was appointed Chairman of British Gas plc in January 1994, having been a non-executive Director since December 1993. He is non-executive deputy chairman of Rio Tinto plc and a non-executive director of US-based Georgia-Pacific Corporation Inc. After working as a lawyer with Shearman & Sterling, the international law firm based in the US, he was chairman and chief executive of BOC Group plc from 1985 to 1991 and chairman from 1994 to 1996. He has also previously served on the boards of National Power plc and Reuters plc and has been non-executive deputy chairman of Grand Metropolitan plc. He is a trustee of Carnegie Endowment for International Peace. (ii), (iii), (iv), (v), (vi)

2 Frank Chapman (49)
Chief Executive

Frank Chapman was appointed Chief Executive with effect from 23 October 2000, having been appointed to the Board of BG plc in February 1997. He joined British Gas plc in November 1996. He has had an international exploration and production career spanning some 27 years and, prior to joining British Gas plc, spent 18 years with Shell and four years with BP. (i), (ii), (iv), (v)

3 Ashley Almanza (39)
Chief Financial Officer

Ashley Almanza was appointed Chief Financial Officer in August 2002. He joined British Gas plc in 1993 as a Finance Manager in the Exploration and Production division. Over the following years, he held a number of Corporate and Business Unit roles including Finance Director of BG International Downstream and Deputy Finance Director of BG International. During this time, he also worked on the successive Group demergers. He acted as Group Finance Director from October 2000 to January 2001 before he was appointed Group Financial Controller. Prior to joining British Gas plc he trained as a chartered accountant, working in South Africa and London. (i), (ii), (iv)

4 Peter Backhouse (51)
Non-Executive Director

Peter Backhouse was appointed to the Board as a non-executive Director in July 2000. He was formerly executive vice president, refining and marketing at BP Amoco plc. Previous roles at BP included deputy chief executive of BP Oil and chief executive of BP Oil Europe. He has gained considerable gas experience in international LNG and in UK natural gas as head of BP’s UK gas marketing business. He is also a member of the Advisory Board of Carlyle/Riverstone Energy Partners, a US private equity fund. (iii), (vi)

5 David Benson (64)
Non-Executive Director

David Benson was appointed to the Board of British Gas plc as a non-executive Director in October 1988. He is a senior advisor to Fleming Family and Partners and is also chairman of Charter European Trust. He is a non-executive director of Daniel Thwaites plc, Murray International Trust plc and the US-based Rouse Company and Dover Corporation. He is also chairman of the Trustees of the COIF Charity Funds. He started his career with Shell before he joined Kleinwort Benson with which he has been associated for nearly 40 years. (iii), (vi)

6 Sir John Coles GCMG (65)
Non-Executive Director

Sir John Coles was appointed to the Board of BG plc as a non-executive Director in March 1998. He had a 37 year career with the Foreign and Commonwealth Office (the FCO) and retired as Permanent Under-Secretary of State in the FCO and Head of the Diplomatic Service in November 1997. He is a trustee of the Imperial War Museum and chairman of Sight Savers International. (iii), (vi)

7 Paul Collins (66)
Non-Executive Director

Paul Collins was appointed to the Board as a non-executive Director with effect from 23 October 2000. He retired in September 2000 as a vice chairman and member of the management committee of Citigroup Inc. Previously, he was a vice chairman (since 1988) and director (since 1985) of Citicorp and its principal subsidiary, Citibank. He joined Citicorp in 1961. He is a director of Kimberly-Clark Corporation and Genuity Corporation and a director and vice chairman of Nokia Corporation. He is also a trustee of the University of Wisconsin Foundation and the Glyndebourne Arts Trust, and is a member of the Advisory Board of Welsh, Carson, Anderson & Stowe, a US private equity firm. (iii), (vi)

8 Elwyn Eilledge CBE (67)
Non-Executive Director

Elwyn Eilledge was appointed to the Board of BG plc as a non-executive Director in February 1997. He is also chairman of the Financial Reporting Advisory Board to the Treasury and former chairman of BTR plc. He was previously chairman of Ernst and Young International Limited, the chartered accountants, with which he worked for nearly 30 years. (iii), (v), (vi)

9 William Friedrich (54)
Deputy Chief Executive and General Counsel

William Friedrich was appointed Deputy Chief Executive with effect from 23 October 2000. He joined British Gas plc in December 1995 as General Counsel after a 20 year career with Shearman & Sterling, where he became a partner in 1983. Whilst with the firm, he practised as a general corporate lawyer, working mainly on international transactions, and ultimately headed the firm’s worldwide project development and project finance practice. (i), (ii), (iv)

10 Keith Mackrell (70)
Deputy Chairman and Senior Independent Non-Executive Director

Keith Mackrell was appointed Deputy Chairman with effect from 23 October 2000, having been appointed to the Board of British Gas plc as a non-executive Director in June 1994. The Board nominated him Senior Independent Director with effect from 1 January 2001. He is also a non-executive director of Govett Asian Recovery Trust plc and other companies. He is a governor of the London School of Economics and chairman of Enterprise LSE. He is a former director of Shell International Petroleum Company Limited with which he had a career spanning 35 years.
(ii), (iii), (vi)

11 Dame Stella Rimington DCB (67)
Non-Executive Director

Dame Stella Rimington was appointed to the Board of BG plc as a non-executive Director in February 1997. She had a career with the Security Service spanning 27 years. She was the first woman Director General of MI5 and the first person to hold the post to have her name made public. She is also a non-executive director of Marks and Spencer plc. (iii), (v), (vi)

12 Lord Sharman (60)
Non-Executive Director

Lord Sharman was appointed to the Board as a non-executive Director with effect from 23 October 2000. He is currently non-executive chairman of Aegis Group plc and non-executive director of Reed Elsevier plc. A chartered accountant, he was chairman of KPMG International from 1997 to 1999, having been a senior partner since 1994. (iii), (vi)

13 Sir Robert Wilson KCMG (59)
Non-Executive Director

Sir Robert Wilson was appointed to the Board as a non-executive Director in September 2002. He has been chairman of Rio Tinto plc since 1997 and prior to that was chief executive between 1991 and 1997. He is also a non-executive director of Diageo plc and The Economist Newspaper Limited. (iii)

Membership of committees
(i)	Group Executive
(ii)	Chairman’s Committee
(iii)	Audit
(iv)	Finance
(v)	Nominations
(vi)	Remuneration

54 BG GROUP PLC 2002

GROUP EXECUTIVE COMMITTEE

BG GROUP PLC 2002 55

The Group Executive Committee has primary authority for the day-to-day management of the Group’s operations within limits set by the Board of Directors. It is chaired by the Chief Executive and membership comprises the other Executive Directors and those senior managers whose details are set out below.

1 Frank Chapman
Chief Executive

See page 53 for biographical details.

2 Ashley Almanza
Chief Financial Officer

See page 53 for biographical details.

3 William Friedrich
Deputy Chief Executive and General Counsel

See page 53 for biographical details.

4 Charles Bland (53)
Executive Vice President Policy & Corporate Affairs

Charles Bland joined BG plc in 1999. He is responsible for government and public affairs, brand and marketing, communications and community affairs. He was appointed to his current position in September 2002 having previously been President, BG Kazakhstan, and Vice President, Government Affairs. Before joining BG he worked in UK government, holding various posts in the Ministry of Defence.

5 Peter Duffy (41)
Executive Vice President Human Resources

Peter Duffy joined BG Group plc in 2001, when he was appointed to his current position with responsibility for all matters relating to human resources strategy and policy. He has extensive international human resource management experience, particularly in the area of organisation development, performance and change management. He previously worked for TRW Inc., LucasVarity plc, and British Aerospace plc.

6 Martin Houston (45)
Executive Vice President & Managing Director Atlantic, Europe and Mediterranean Basin

Martin Houston joined British Gas plc in 1983 and was appointed Executive Vice President upon demerger in October 2000. Prior to that he held a number of technical and commercial posts predominantly with an international focus. He played a leading role in the development of the LNG industry in Trinidad and was chairman of Atlantic LNG from 1996 to 2000. His most recent positions have included President and General Manager of BG Trinidad and Tobago, Director of LNG and Vice President of Strategy and Portfolio Development. He is a fellow of the Geological Society of London.

7 David McManus (49)
Executive Vice President Skill Centres

David McManus joined BG Group plc in 2000 and was appointed Executive Vice President upon demerger in October 2000 with responsibility for the Eastern Hemisphere. He was appointed to his current position in January 2003 and is now responsible for all matters relating to petroleum engineering, project engineering management, procurement and commercial and operational functions. He was previously president of ARCO Europe and managing director of ARCO UK Limited. Prior to working at ARCO, he acquired extensive technical and commercial experience in various roles with Ultramar, Lasmo and Shell.

8 Emma Nichol (38)
Company Secretary

Emma Nichol joined BG plc in 1997 and has responsibility for all matters relating to the Board, its committees and governance and risk management. She was appointed Company Secretary upon demerger in October 2000. Her previous role was as Deputy General Counsel. She formerly worked at Clifford Chance and National Power plc.

9 Dave Roberts (42)
Executive Vice President & Managing Director Eastern Hemisphere

Dave Roberts joined BG Group plc in January 2003 when he was appointed to his current position, with responsibility for the Group’s activities in India, South East Asia, the Middle East and Kazakhstan. He was previously adviser to Chevron Texaco’s vice chairman and director of strategy management for Texaco’s worldwide upstream business. He has extensive experience in surface and sub-surface engineering and technical leadership, operations and general management.

10 Sean Sutcliffe (39)
Executive Vice President & Managing Director New Businesses

Sean Sutcliffe joined British Gas plc in 1990 and was appointed Executive Vice President upon demerger in October 2000. In addition to his responsibility for new businesses, he is also responsible for strategic development, mergers and acquisitions, technology and exploration activity. Previously, he worked in strategic and operational roles across the gas chain, both in the UK and internationally. Before joining BG, he worked for VSEL Consortium plc, primarily in engineering consultancy.

11 Rick Waddell (43)
Executive Vice President & Managing Director South America

Rick Waddell joined BG Group plc in March 2002 when he was appointed to his current position. Based in Sâo Paulo, he is responsible for all upstream and downstream activities in the Southern Cone, including Comgas in Sâo Paulo and MetroGAS in Buenos Aires. He is a former senior vice president of Enron Corporation for Latin America and was regional logistics manager for South America with Wal-Mart International.

12 Jon Wormley (54)
Executive Vice President & Managing Director UK Region

Jon Wormley joined British Gas plc in 1992 and was appointed to his current position upon demerger in October 2000. Prior to that he was Finance Director, BG International, and held executive responsibility for Comgas in Sâo Paulo. He is a Certified Public Accountant – Texas, USA. He received his BSBA degree from the University of Tulsa, Oklahoma in 1970. He has worked in the oil and gas industry since 1971, beginning his career with Phillips Petroleum Company in the USA. He held various senior level financial positions with Phillips both in and outside the USA.

CONTENTS
57	Directors’ Report
60	Remuneration Report
70	Auditors’ Report
71	Principal Accounting Policies
74	Consolidated Profit and Loss Account
76	Consolidated Statement of Total Recognised Gains and Losses
77	Balance Sheets
78	Movement in BG Shareholders’ Funds

79	Consolidated Cash Flow Statement
79	Reconciliation of Net Borrowings
80	Analysis of Cash Flow Movement
81	Notes to the Accounts
117	Supplementary Information
	– Gas and Oil
122	Five Year Financial Summary
126	Five Year Financial Summary (continuing operations only)
128	Historical Production
129	Shareholder Information
130	Additional Shareholder Information
137	Cross-Reference to Form 20-F
138	Index
139	Glossary
140	Definitions

BG GROUP PLC 2002 57

DIRECTORS’ REPORT

The Directors present their report and the audited accounts for the financial year ended 31 December 2002. A statement by the Directors on corporate governance is on page 27. A report by the Directors on remuneration is on pages 60 to 69.

PRINCIPAL ACTIVITIES
BG is an integrated gas company with activities across the whole range of gas operations, from exploration to the final consumer.

Exploration and Production (E&P)
E&P comprises exploration, development, production and marketing of hydrocarbons with a focus on gas. At 31 December 2002, BG had 1 919 mmboe of proved and 4 623 mmboe of proved and probable reserves.

Liquefied Natural Gas (LNG)
The LNG business combines the development and use of LNG import and export facilities with the purchase, shipping and sale of LNG and regasified natural gas.

Transmission and Distribution (T&D)
T&D develops, owns and operates major pipelines and distribution networks, and supplies gas through these to the end customer.

Power Generation
BG develops, owns and operates natural gas-fired power generation plants around the world.

The Business Review (pages 5 to 11) and Operating and Financial Review (pages 38 to 51) give a report on the Group’s performance during the past year, its prospects and research and development activities.

RESULTS AND DIVIDEND
The profit on ordinary activities before taxation was £794m compared with £902m in 2001. A final dividend of 1.55p per ordinary share is proposed (1.50p for 2001), making a total dividend for the year of 3.1p (3.0p in 2001). £300m (2001 £481m) has been transferred to reserves from the profit and loss account. The results are dealt with fully in the Financial Statements (pages 74 to 116) and in the Operating and Financial Review (pages 38 to 51).

SIGNIFICANT EVENTS SUBSEQUENT TO 31 DECEMBER 2002
There have been no significant events affecting the Company or its subsidiaries which have occurred since the end of the financial year.

SUBSTANTIAL SHAREHOLDERS
At 20 February 2003, the Company had received the following notifications of holdings of 3% or more of the issued share capital of the Company:

The Capital Group Companies, Inc.	279 910 423 ordinary shares	7.93%
Legal and General Group plc	116 458 766 ordinary shares	3.29%

SHARE CAPITAL
The Company was given authority at the 2002 Annual General Meeting to make market purchases of up to 352 870 087 of its own ordinary 10p shares at a maximum price per share of 105% of the middle market price. This authority will expire at the 2003 Annual General Meeting and similar approval from shareholders will be sought at that meeting to renew the authority for a further year. No market purchases of ordinary shares were made in 2002.

Details of shares issued during the year are shown in note 24 to the accounts (page 103).

DIRECTORS AND OFFICERS
The names of the current Directors and their biographical details are given on page 53. Ashley Almanza was appointed to the Board as Chief Financial Officer and as an Executive Director on 1 August 2002. Andrew Bonfield relinquished his responsibilities as Executive Director, Finance from 1 August 2002 and resigned as a Director on 16 August 2002. Sir Robert Wilson was appointed to the Board as a non-executive Director on 19 September 2002.

Any person appointed as a Director by the Board must retire at the first Annual General Meeting (AGM) after their appointment and seek re-election by shareholders. Ashley Almanza and Sir Robert Wilson will therefore be seeking election by shareholders at the 2003 AGM. In addition, Directors are subject to re-election by shareholders every three years. Sir Richard Giordano, Frank Chapman, David Benson, Sir John Coles, Elwyn Eilledge, Keith Mackrell and Dame Stella Rimington were all elected at the 2000 AGM and will seek re-election by shareholders at the 2003 AGM.

Details of the Directors’ service contracts, emoluments and share interests can be found in the Remuneration Report on pages 60 to 69.

The executive officers of the Company at 31 December 2002 (being those members of the Group Executive Committee who are not Directors) and their biographical details are given on page 55.

The aggregate remuneration of the executive officers in 2002 (including Erika Coghlan up to 6 September 2002 when she left the Company) was £2 550 287 (2001 £1 677 556) and aggregate pension contributions were £31 606 (2001 £23 362). At 20 February 2003, executive officers had the following aggregate beneficial interests in the Company’s shares: ordinary shares 138 092; employee profit sharing schemes 21 284; long term incentive schemes 1 870 848 (notional allocation). This notional allocation includes the full allocation made in October 1999. The performance period ended on 30 September 2002. BG’s performance meant that 46% of the original allocation was put into trust on behalf of participating executive officers. (The remainder of the 1999 allocation has lapsed.)

58 BG GROUP PLC 2002

DIRECTORS’ REPORT continued

Under the Sharesave Scheme at 20 February 2003, executive officers held options over a total of 39 178 ordinary shares at exercise prices of £2.29 or £2.26 per share, exercisable between March 2004 and April 2007; under the Company Share Option Scheme they held options over a total of 1 876 530 ordinary shares at an exercise price of £2.685, £2.5634, £2.5925, £3.08 or £2.5175 per share, exercisable between November 2003 and September 2012. At 20 February 2003, none of the executive officers held shares under the Executive Share Option Scheme. A description of the Company’s employee share schemes, other than the Executive Share Option Scheme (under which no grants have been made since 1994), is given on pages 60 to 64.

EMPLOYEES
The Group had 4 606 employees worldwide at 31 December 2002, of which 3 884 were based outside the UK. There are well-established and effective arrangements for communication of the Company’s results and significant business issues for employees of the Company and its wholly-owned subsidiaries through electronic mail and the Company’s intranet and in-house publications, as well as videos and briefing meetings at each business location. When necessary, consultation with employee and Trade Union representatives also takes place.

The Group takes a positive approach to equality and diversity and encourages its partners to do likewise. By tapping into the talent and skills available in all groups and communities in the countries in which it operates, the Group underpins the lasting success of its enterprise. The Group achieves this by using appropriate recruitment and selection techniques, ensuring equality of employment opportunity and equal access to development opportunities.

The Group is also committed to providing a work environment free from harassment and discrimination and remains committed to fair treatment of people with disabilities in relation to job applications, training, promotion and career development. Every effort is made to find appropriate alternative jobs for those who are unable to continue in their existing job because of disability. As with the approach to equality and diversity, the Group encourages its partners to have a similar approach to these issues where Group policies are not able to be directly implemented.

Employees of the Company and wholly-owned UK subsidiaries are encouraged to become shareholders in the Company. The majority hold ordinary shares under the Company Employee Profit Sharing Scheme, and a significant number are members of its Sharesave Scheme and the Share Incentive Plan (SIP).

COMMUNITY INVOLVEMENT
During the year, the Group donated £1m in the UK, as well as supporting projects in the overseas countries in which BG operates. No donations were made in the UK for political purposes and it is BG’s policy not to make political donations generally. For further information on BG Group’s community involvement, see page 37.

SUPPLIERS
The Group aims to pay all its creditors promptly. It is the Group’s policy to agree the payment terms at the start of business with each supplier, ensure that suppliers are aware of the terms of payment, and pay in accordance with contractual and other legal obligations.

The Group had 24 days’ purchases outstanding at 31 December 2002 based on the average daily amount invoiced by suppliers during the year.

AUDIT COMMITTEE
The Audit Committee has reviewed and discussed with management and the external auditors the Group’s audited financial statements for the year ended 31 December 2002 and has recommended to the Board of Directors that the financial statements be included in this Annual Report and Accounts.

ANNUAL GENERAL MEETING
The Annual General Meeting (AGM) will be held at 2.00 p.m. on Tuesday, 22 April 2003 at the International Convention Centre, Birmingham. For shareholders, a Notice of AGM, which includes an explanation of the proposed resolutions, is included in the Annual Review which is enclosed with this document.

A summary of the business carried out at the AGM will be published on the Company’s website.

AUDITORS
Following the conversion of our auditors PricewaterhouseCoopers, to a Limited Liability Partnership (LLP) from 1 January 2003, PricewaterhouseCoopers resigned on 13 February 2003 and the Directors appointed its successor, PricewaterhouseCoopers LLP, as auditors. A resolution to reappoint PricewaterhouseCoopers LLP as auditors to the Company will be proposed at the Annual General Meeting.

GOING CONCERN
The accounts have been prepared on the going concern basis since the Directors are satisfied that the Group’s and Company’s activities are sustainable for the foreseeable future.

STATEMENT OF DIRECTORS’ RESPONSIBILITIES FOR PREPARING THE FINANCIAL STATEMENTS
The Directors are required by the Companies Act 1985 to prepare financial statements for each financial year which give a true and fair view of the state of affairs of the Company and of the Group at the end of the financial year and of the profit or loss of the Company and the Group for the financial year. The Company is also required to prepare financial statements for US shareholders in accordance with the requirements of the US Securities and Exchange Commission.

The Directors consider that in preparing the Financial Statements on pages 74 to 116, the Company has used appropriate accounting policies, consistently applied and supported by reasonable and prudent judgments and estimates and all applicable accounting standards have been followed. The Company has complied with UK and US disclosure requirements in this report in order to present a consistent picture to all shareholders.

BG GROUP PLC 2002 59

The Directors have responsibility for ensuring that the Company keeps accounting records which disclose with reasonable accuracy the financial position of the Company and of the Group and which enable them to ensure that the Financial Statements comply with the Companies Act 1985.

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

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

The Directors confirm that the Audit Committee continues to review the adequacy of the system of internal control adopted by the Group.

A copy of the Financial Statements of the Company is placed on the BG Group website. The maintenance and integrity of the BG Group website is the responsibility of the Directors. The work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the Financial Statements since they were initially presented on the website.

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

By order of the Board
Emma Nichol

Company Secretary

21 February 2003

Registered office:
100 Thames Valley Park Drive
Reading
Berkshire
RG6 1PT
Registered in England No. 3690065

60 BG GROUP PLC 2002

REMUNERATION REPORT

Introduction
This report is made by the Board on the recommendation of the Remuneration Committee. The first part of the report provides details of BG Group’s remuneration policy. The second part provides details of the remuneration, service contracts and share interests of all the Directors for the year ended 31 December 2002. The Directors confirm that this report has been drawn up in accordance with Schedule B of the Combined Code.

Responsibility for reviewing Group remuneration strategy and policy, recommending any changes and approving individual remuneration packages for Executive Directors rests with the Remuneration Committee. The Committee consists exclusively of independent non-executive Directors and meets on at least four occasions each year. The members are: Peter Backhouse, David Benson, Sir John Coles, Paul Collins, Elwyn Eilledge (Committee Chairman), Sir Richard Giordano, Keith Mackrell, Dame Stella Rimington and Lord Sharman; Emma Nichol, Company Secretary, attends as secretary to the Committee. Frank Chapman, Chief Executive, Peter Duffy, Executive Vice President Human Resources, and Cathy Aldwinckle, Head of Compensation and Benefits, attend these meetings as required and provide information and advice to the Committee to enable it to make informed decisions. The Remuneration Committee also meets without management and receives information and independent executive remuneration advice from an external consultancy firm, Towers Perrin⁽ⁱ⁾, whose appointment was approved by the Remuneration Committee.

During 2001, the Remuneration Committee reviewed BG’s global remuneration strategy and proposed some changes, principally to our long-term incentive schemes. Those changes were approved by shareholders at the 2002 Annual General Meeting and have since been implemented⁽ⁱⁱ⁾. Other than as detailed on page 63, no changes are proposed to the remuneration policy this year. The Committee will review the policy on a regular basis and recommend changes as and when appropriate in forthcoming years.

REMUNERATION POLICY
BG needs to be able to employ and retain international employees of the highest calibre with the necessary skills, capabilities and experience to execute its business strategy and thereby deliver strong growth. The catchment area for recruitment is increasingly outside the UK and the required talent is scarce.

The overriding objectives of our remuneration policy are to enable the recruitment and retention of this limited executive resource and to reinforce our strong performance ethic.

Accordingly, the central premise of our remuneration policy is that, whilst reward arrangements should be market competitive, employees should look to performance related incentives rather than base salaries to achieve above average reward.

To implement our policy, we have a well-developed, company-wide performance management system and we operate three complementary performance related incentive schemes for executives. The three schemes are the Annual Incentive Scheme (AIS), the Long Term Incentive Scheme (LTIS) and the Company Share Option Scheme (CSOS). These schemes form a significant proportion of the total reward package for executives.

The AIS is designed to focus executives on the business priorities for the financial year and to reinforce our individual performance culture. The aim of the LTIS is to motivate participants to maximise total shareholder return (TSR)^{(iii )}as measured against a comparator group of international oil and gas companies over a period of three years. The CSOS aims to drive real earnings growth over the long term, the mechanism used for measuring this being published earnings per share (EPS)^(iv) growth relative to the growth in the retail price index, excluding mortgage interest repayments (RPIX). Further details of the AIS, the LTIS and the CSOS can be found on pages 61 to 63.

The varying performance periods and performance conditions of the three schemes combine and complement each other to enable the measurement and reward of both short- and long-term performance and of absolute (AIS), sustained (CSOS) and comparative (LTIS) financial performance. The Remuneration Committee considers that this combination of performance measures aligns executives’ interests with those of shareholders and establishes a clear link between pay and performance.

Components of Remuneration
The current remuneration package for Executive Directors comprises performance related and non-performance related components. The performance related components are the performance related incentive schemes referred to above and the non-performance related components are base salary, taxable benefits and pension entitlements. In addition, the Executive Directors are eligible to participate in the Company’s all-employee share schemes. Pay and employment conditions elsewhere in the Group and the provisions of Schedule A to the Combined Code have been taken into account in determining the remuneration packages for Executive Directors.

The proportion of each Executive Director’s total remuneration that is performance related is significant even for target (which is based on budget) performance. For stretch (significantly above budget) performance, the amount of remuneration payable is higher as is the proportion that is performance related. New legislation (the Directors’ Remuneration Report Regulations 2002) requires us to explain the relative importance of those elements of remuneration which are, and those which are not, performance related. In fulfilling this requirement, we have had to make a number of assumptions, including what the Company’s share price growth will be over the next three years and what our total shareholder return will be relative to that of a comparator group of companies. Based on such assumptions, the average proportion of remuneration that is performance related for target performance is approximately 45% for Executive Directors. For stretch performance, the average is about 75%.

(i)	Towers Perrin also provides some general compensation and benefits advice and information to some of our overseas activities and is responsible for the administration of some of our share schemes.
(ii)	Details of these changes can be found on pages 52-55 in the Company’s 2001 Annual Report and Accounts.
(iii)	TSR is defined as the return on investment obtained from holding a company’s shares over a period. It includes dividends paid, the change in the capital value of the shares and other payments to, or by, shareholders within the period.
(iv)	EPS is calculated by dividing the earnings for the financial year (excluding exceptional items) by the weighted average number of ordinary shares in issue and ranking for dividend during the year.

BG GROUP PLC 2002 61

Base Salaries
Executive Directors’ salaries are reviewed each year on 1 April and this review takes into account individual performance and market competitiveness. Pensionable salary is derived from base salary only.

In line with our remuneration policy, the Remuneration Committee benchmarks Executive Directors’ salaries against a comparator group. Given BG’s international presence and position roughly in the middle of the FTSE 50, the Remuneration Committee considered it appropriate to reference Executive Directors’ base salaries for the 1 April 2002 salary review against the median of the FTSE 50. We will use the same comparator group for the 1 April 2003 salary review.

Annual Incentive Scheme
The Company operates a cash-based Annual Incentive Scheme (AIS), which provides an incentive opportunity in the range of 0% to 100% of base salary.

At the start of the incentive year (1 January), based on the Company’s business priorities, the Remuneration Committee sets both the performance measures and the targets. These targets ensure that incentives at the higher end of the range are payable only for demonstrably superior Company and individual performance.

For the Executive Directors and other members of the Group Executive Committee, the financial performance measure for the 2002 incentive year was EPS, adjusted to take into account the volatility of upstream commodity prices. For the 2003 incentive year, the Remuneration Committee has agreed that the financial performance measures for Executive Directors and other members of the Group Executive Committee will be EPS (again adjusted for commodity prices) and return on average capital employed (ROACE)⁽ⁱ⁾.

When determining incentive payments, the Remuneration Committee considers health, safety and environmental performance in addition to absolute and underlying financial performance. When setting targets for 2002, the Remuneration Committee could not have foreseen the introduction of the North Sea tax surcharge. The Remuneration Committee therefore decided to exclude the adverse effects of the surcharge when it determined the 2002 AIS payments. Payments in respect of the 2002 incentive year will be made in April 2003 based on 2002 results. The payments are non-pensionable.

Long-Term Incentives – Estimated Present Value
During 2001, the Remuneration Committee sought external, independent advice from Towers Perrin to establish an objective measure to describe the value at the time of grant or allocation of long-term incentives which may, or may not, pay out in the future. This measure is referred to as the Estimated Present Value (EPV). The EPV takes account of the risk that all grants and allocations may be forfeited. This EPV is then used to determine the appropriate levels of face value CSOS grants and LTIS allocations.

The changes approved by shareholders last year enable the Remuneration Committee to make awards under both schemes, up to a maximum combined EPV of 175% of base salary each year. However, we stated the intention of the committee that long-term incentive grants in 2002 would not exceed a maximum combined EPV of 130% of base salary. The actual maximum combined EPV granted during 2002 was slightly less than 130%.

Each year, the Remuneration Committee decides on the appropriate blend of CSOS grants and LTIS allocations that will be made to Executive Directors within the maximum combined EPV. Awards will always be made under both schemes, with not less than one-third and not more than two-thirds of the total combined EPV being delivered by either scheme. When making this decision, the Remuneration Committee takes a number of factors into consideration including cost, the need to remain within scheme dilution limits and the performance conditions considered to be key to BG Group’s strategy at the time of the allocation or grant. For the 2002 awards, the Executive Directors received two-thirds of the total combined EPV through the LTIS and one-third through the CSOS.

Long Term Incentive Scheme (LTIS)
Currently, a limited number of high performing employees deemed to be making a significant contribution to the Company’s long-term TSR performance are allocated Company shares under the LTIS. This allocation marks the beginning of the performance period. The Company’s TSR performance against that of a comparator group over the three year period will determine what proportion of the allocated shares will be transferred into the ownership of the employee. The Remuneration Committee considers that measuring performance against a comparator group of companies ensures that executives are rewarded not solely based on BG Group’s performance but also relative to the performance of the other companies in the comparator group. The TSR performance is measured by the independent external corporate broker, Hoare Govett Limited, a subsidiary of ABN Amro Holding NV.

The LTIS comparator group for the 2002 allocation comprises 21 international oil and gas companies (including BG Group plc) of which 12 are headquartered in the USA, three in the UK and six elsewhere in Europe⁽ⁱⁱ⁾.

This group has been chosen because the Remuneration Committee believes that it comprises our major business competitors i.e. those companies against which BG is compared by shareholders.

(i)

Average capital employed consists of total shareholders’ funds plus net borrowings averaged between the start and end of year. ROACE represents total operating profit before exceptional items less BG’s share of net interest receivable and payable by joint ventures and associated undertakings and the interest charge relating to the unwinding of discount on provisions as a percentage of average capital employed.

(ii)

A different comparator group was used for the 1999, 2000 and 2001 allocations.

62 BG GROUP PLC 2002

REMUNERATION REPORT continued

The other companies in the comparator group are as follows:

Amerada Hess Corporation	El Paso Corporation	Repsol YPF SA
Anadarko Petroleum Corporation	ENI SpA	Royal Dutch Petroleum Co.
BP plc	ExxonMobil Corporation	Shell Transport & Trading Co. plc
Burlington Resources Inc.	Kerr McGee Corporation	Statoil ASA
ChevronTexaco Corporation	Marathon Oil Corporation	TotalFinaElf SA
ConocoPhillips Petroleum	Norsk Hydro ASA	Unocal Corporation
Duke Energy Corporation	Occidental Petroleum Corporation

For the 1999, 2000 and 2001 allocations, the Remuneration Committee set the following performance conditions:

– 100% of the allocated shares will be transferred only if upper quartile TSR performance is achieved;

– only 40% of the allocated shares will be transferred if median TSR performance is achieved. A proportion of between 40% and 100% of the allocated shares will be transferred for between median and upper quartile performance;

– where TSR performance is below the median, all of the allocated shares will be forfeited. There is no retest provision.

The performance conditions set by the Remuneration Committee for the 2002 allocation are more stringent than for previous allocations and are as follows:

– 100% of the allocated shares will be transferred only if ‘Number One’ TSR performance position is achieved;

– 75% of the allocated shares will be transferred if upper quartile TSR performance is achieved. A proportion of between 75% and 100% of the allocated shares will be transferred for between upper quartile and ‘Number One’ performance;

– only 30% of the allocated shares will be transferred if median TSR performance is achieved. A proportion of between 30% and 75% of the allocated shares will be transferred for between median and upper quartile performance;

– where TSR performance is below the median, all the allocated shares will be forfeited. There is no retest provision.

In the event of a change of control, vesting of shares under the LTIS is not automatic and would depend upon the extent to which the performance conditions had been met at the time.

An allocation of shares was made under the LTIS in October 1999 to UK payroll employees and overseas employees above a certain level of seniority. The performance period for the allocation ended on 30 September 2002. BG’s final position in the comparator group meant that 46% of the original allocation of shares was put into trust on behalf of participating employees. Subject to the rules of the LTIS, the shares will be transferred to those employees in October 2003.

Company Share Option Scheme (CSOS)
Approximately 1 200 employees are currently eligible to participate in the BG Group CSOS including UK payroll employees and overseas employees above a certain level of seniority.

The Company grants an option over its shares to each eligible employee and the option price is set at the fair market value at the time of the grant. As described below, the CSOS measures performance according to EPS growth relative to the growth in RPIX. The Remuneration Committee considers that the inclusion of an EPS performance measure ensures that executives only receive rewards when the Company has achieved sustained earnings growth during the performance period. To the extent that the performance target has been met three years from the date of grant, the option may be exercised (in whole or in part) at any time up to the expiry of ten years from the date of grant.

In 2002, the levels of grant made to individual employees were differentiated based on each individual’s performance to date and expectation of future contributions. For the 2002 grant, the Remuneration Committee set the following performance targets, which it considers to be particularly demanding. These targets also apply to the 2000 and the 2001 grants:

– for all of the option to become exercisable, the Company must achieve EPS growth over three years of RPIX plus 30%;

– only half of the option will be exercisable if EPS growth over three years is RPIX plus 15%. A proportion of between half and all of the option will be exercisable if the Company achieves EPS growth over three years of RPIX plus between 15 and 30%;

– if the Company’s EPS growth over three years is less than RPIX plus 15%, all the option will be forfeited.

Fixed point retesting is allowed in years four and five, in which EPS growth of RPIX plus 40% or plus 50% respectively must be achieved for all the option to become exercisable. This ensures that management is motivated to make the right decisions for the long-term growth of value without compromising the stretching performance conditions. At the end of year five, the option will be exercisable only to the extent that the performance conditions have been met.

In the event of a change of control, exercise of the option under the CSOS is not automatic and would depend upon the extent to which the performance conditions had been met at the time.

BG GROUP PLC 2002 63

Currently, grants to individuals under the CSOS are subject to a limit based on the aggregate of awards made within the preceding 12 month period. This is inconsistent with the individual limit contained in the LTIS, which is based on allocations made in a calendar year. This timing differential limits the Remuneration Committee’s flexibility when apportioning the combined EPV of awards appropriately between CSOS and LTIS on an annual basis.

It is therefore proposed to amend the CSOS to bring the grant basis into line with the LTIS, such that the limits on grants to individuals will be based on grants made in a calendar year for both schemes. Approval will be sought from shareholders at the 2003 Annual General Meeting to this amendment. This will ensure that the Remuneration Committee has the flexibility under each scheme to determine the appropriate blend of awards under CSOS and LTIS that may be made to Executive Directors. This is a technical, rather than substantive, amendment. It will not result in increased annual grants being made.

All-Employee Share Schemes
In order to encourage share ownership, the Company currently provides two all-employee share schemes for its UK employees, the Share Incentive Plan (SIP) and the Sharesave Scheme.

Share Incentive Plan (SIP)
The BG Group SIP is approved by the Inland Revenue. There are two parts to the SIP – the Partnership Shares Plan and the Free Shares Plan.

(i) Partnership Shares
Eligible employees are offered the opportunity to buy Company shares from pre-tax earnings as part of a regular share purchase plan. Shares are currently purchased every six months using employees’ accumulated deductions and placed in trust. The third Partnership Share purchase was made in October 2002. Sixty-one per cent of eligible employees participate in this plan, of which 66% are contributing the maximum of £125 per month.

(ii) Free Shares
A Free Shares award of 983 shares was made in May 2002 to all eligible employees in the UK based on BG’s performance during 2001. These shares will be held in trust for up to five years.

For 2002, the Board will allow awards of Free Shares in the Company to be made up to a value of £3 000 (the statutory limit) for each individual. All eligible employees will receive the same number of shares. This number will be determined based on the extent to which the Company has met the agreed profit targets for 2002.

Sharesave Scheme
The Company continued to operate the BG Group Sharesave Scheme in 2002. The scheme is approved by the Inland Revenue and provides for eligible employees to acquire the Company’s shares with the proceeds of a monthly savings contract. The contract period is three or five years. Eighty-one per cent of eligible employees currently participate in the Sharesave Scheme, contributing an average monthly payment of £207 (the maximum being £250).

Employee Profit Sharing Scheme
This scheme ceased to operate at the end of 2000. During 2002, shares allocated to participants in respect of the 1998 scheme were released and transferred into their names.

Shares held in respect of the 1999 and 2000 schemes will be released to eligible participants in 2003 and 2004 respectively.

Shareholding Guidelines
During 2002, shareholding guidelines were introduced for Executive Directors, Group Executive Committee members and certain other senior employees to encourage substantial long-term share ownership. These require that over a period of five years Executive Directors build up and then retain a holding of shares with a value equivalent to twice base salary. The required holding for other members of the Group Executive Committee is one-times base salary. The guidelines require that, in relation to 2002 and future LTIS allocations, vested shares (net of tax) should be retained by the individual until the required shareholding level is reached.

Service Contracts
The Executive Directors’ service contracts, including arrangements for early termination, are carefully considered by the Remuneration Committee and are designed to recruit, retain and motivate Directors of the quality required to manage the Company. The Remuneration Committee considers that a notice period of one year is appropriate.

The Executive Directors’ service contracts contain change of control provisions. Should the Directors’ employment be terminated within 12 months of a change of control, they are entitled to liquidated damages. The amount of liquidated damages is equal to one year’s then gross salary and a credit of one year’s pensionable service (less any deductions the employer is required to make), which the Remuneration Committee considers to be a genuine pre-estimate of loss. The Remuneration Committee considers that these clauses assist with recruitment and retention and that their inclusion is therefore in the best interests of shareholders.

Other than change of control clauses, the Executive Directors’ service contracts do not contain provisions for compensation in the event of early termination. When calculating termination payments, the Remuneration Committee takes into account a variety of factors including individual and Company performance, the obligation for the Director to mitigate his or her own loss (for example by gaining new employment), the Director’s age and length of service. Further details of the Executive Directors’ service contracts can be found on pages 65 and 66.

64	BG GROUP PLC 2002
REMUNERATION REPORT continued

Non-Executive Directors
The Board aims to recruit non-executive Directors of a high calibre with broad commercial, international or other relevant experience. Non-executive Directors are generally appointed for an initial three year period. The terms of their engagement are set out in a letter of appointment⁽ⁱ⁾. The initial appointment and any subsequent re-appointment is subject to election or re-election by shareholders. The letters of appointment do not contain notice periods or provision for termination payments.

Non-executive Directors are paid a basic fee⁽ⁱⁱ⁾. Additional fees are also payable, for example, for chairing a committee of the Board or acting as Deputy Chairman. The level of Directors’ fees is reviewed against market practice every two years, taking into account the required time commitment. The next review takes place this year.

Non-executive Directors are not eligible to participate in any of the Company’s share schemes, incentive schemes or pension schemes.

Performance Graph
The graph below shows BG Group’s total shareholder return performance since listing (calculated in accordance with the Directors’

Remuneration Report Regulations 2002) against the FTSE 100. We have chosen the FTSE 100 because this is a recognised broad equity market index of which BG is a member.

HISTORICAL TSR PERFORMANCE
Growth in the value of a hypothetical £100 holding over period since listing of BG Group plc on 13 December 1999

(i)	Sir Richard Giordano has an employment contract with the Company. Further details can be found on pages 65 and 66.
(ii)	Sir Richard Giordano receives a salary which takes into account his time commitment and contribution, particularly in relation to the Company’s international activities. His salary is reviewed annually on 1 April.

BG GROUP PLC 2002 65

The following section provides details of the remuneration, service contracts and share interests of all the Directors for the year ended 31 December 2002 and is audited information.

DIRECTORS’ REMUNERATION

Individual remuneration for the year to 31 December

	Salary/fees		Taxable benefits (i)		Bonus			Total
	2002	2001	2002	2001	2002		2001	2002	2001
	£	£	£	£	£		£	£	£
Sir Richard Giordano(ix)(xi)	443 750	375 000	46 623	74 483	–		–	490 373	449 483
Ashley Almanza(ii)(iii)(iv)(vi)	131 875	–	461	–	100 000		–	232 336	–
Frank Chapman(iv)(v)(vi)	537 998	486 372	34 347	25 453	550 000	245 000		1 122 345	756 825
William Friedrich(iv)(v)(vi)(vii)(xi)	517 248	481 872	57 867	43 540	461 120	242 500		1 036 235	767 912
Peter Backhouse(viii)	35 000	30 000	–	–	–		–	35 000	30 000
David Benson(viii)	35 000	30 000	–	–	–		–	35 000	30 000
Sir John Coles(viii)	35 000	30 000	–	–	–		–	35 000	30 000
Paul Collins(viii)	35 000	30 000	–	–	–		–	35 000	30 000
Elwyn Eilledge(viii)(x)	42 500	46 250	–	–	–		–	42 500	46 250
Keith Mackrell(viii)(xii)	85 000	80 000	–	–	–		–	85 000	80 000
Dame Stella Rimington(viii)	35 000	30 000	–	–	–		–	35 000	30 000
Lord Sharman(viii)	42 500	36 250	–	–	–		–	42 500	36 250
Sir Robert Wilson(iii)(viii)	9 917	–	–	–	–		–	9 917	–
Former Director
Andrew Bonfield(iv)(vi)(xiii)	249 665	369 006	16 525	18 400	–	190 000		266 190	577 406

(i)	Taxable benefits include items such as company car, fuel, driver, financial advice, medical and life insurance.
(ii)	Ashley Almanza was appointed as an Executive Director on 1 August 2002.
(iii)	Salary/fees, taxable benefits and bonus figures for 2002 relate to the period from the date of appointment as a Director.
(iv)	Bonus figures for 2001 represent payments under the BG Group Short Term Incentive Scheme in respect of 2001 which were made in March 2002. Bonus figures for 2002 represent payments under the Annual Incentive Scheme in respect of 2002 which will be made in April 2003.
(v)	The 2001 salary figure includes £6 372 in respect of the value of shares appropriated under the terms of the BG Group Employee Profit Sharing Scheme.
(vi)	With the exception of Ashley Almanza, salary figures for Executive Directors for 2002 include Free Shares to the value of £3 000 received under the BG Group Share Incentive Plan (SIP) in May 2002. In 2003, Ashley Almanza, Frank Chapman and William Friedrich will be entitled to receive up to a further £3 000 worth of Free Shares under the SIP.
(vii)	In October 2003, William Friedrich will be entitled to receive a maximum gross amount equivalent to the market value of 46 586 BG Group plc shares on 30 September 2003. This amount is derived from the performance criteria applicable to the Long Term Incentive Scheme for 1999. This entitlement was established at the time of his joining British Gas plc in December 1995 and prior to his appointment as an Executive Director of the Company.
(viii)	Each non-executive Director, other than Sir Richard Giordano, is paid a fee of £35 000 per annum. Each non-executive Director who chairs a committee of the Board receives an additional fee of £7 500 per annum.
(ix)	Sir Richard Giordano’s contract of employment provides that his salary will be reviewed annually on 1 April and increased by an amount which is at least in line with the Retail Price Index. For the duration of his Chairmanship, he is entitled to the use of a car and driver. He is also entitled to accident and private medical insurance upon terms agreed by the Board of the Company. The Company will also pay reasonable fees incurred by his tax advisers and this benefit will continue for two years following the cessation of his employment.
(x)	The 2001 fee figure includes a one-off bonus of £10 000 paid in recognition of contribution of time and effort in additional committee work.
(xi)	As US citizens, Sir Richard Giordano and William Friedrich are covered by long-term care insurance if they return to the USA. The value of the taxable benefit for 2002 is £6 871 for Sir Richard Giordano and £9 544 for William Friedrich.
(xii)	Keith Mackrell is non-executive Deputy Chairman of the Company, for which he receives £50 000 per annum in addition to his fee of £35 000 as a non-executive Director..
(xiii)	Remuneration paid until 16 August 2002, date of cessation as Director

DIRECTORS’ SERVICE CONTRACTS

EXECUTIVE DIRECTORS

Details of the employment contracts of the Executive Directors who served during the year are set out below.

				Compensation
				payable
	Contract	Unexpired	Notice	upon early
	date	term	period	termination (i)
Ashley Almanza	01.08.02	rolling 1yr	1yr	n/a
Frank Chapman	14.09.00	rolling 1yr	1yr	n/a
William Friedrich	14.09.00	rolling 1yr	1yr	n/a
		Contract
Former Executive Director		terminated
Andrew Bonfield*	05.01.01	16.08.02	1yr	n/a

* Resigned on 16 August 2002.

(i) Other than the change of control provisions, the Executive Directors’ employment contracts do not contain provisions for compensation payable upon early termination.

66 BG GROUP PLC 2002

REMUNERATION REPORT continued

Change of control
As described on page 63, the Executive Directors’ employment contracts contain change of control provisions.

For the purposes of these provisions, a change of control is deemed to occur if the Company becomes a subsidiary of another company; or if 50% or more of the voting rights of the Company or the right to appoint or remove the majority of the Board of the Company become vested in any individual or body or group of individuals or bodies acting in concert; or if all or substantially all of the business, assets and undertakings of the Company become owned by any person, firm or company (other than a subsidiary or associated company). A change of control is also deemed to occur if the whole of the issued capital of BG Energy Holdings Limited or a substantial part of the undertaking of that company (including its subsidiaries) is transferred to another company unless that transferee company is a subsidiary of the Company, or a company ultimately owned by substantially the same shareholders as are the ultimate owners of the Company. However, a change of control does not occur if (and, only if) through a process of reconstruction the Company becomes a subsidiary of another company owned by substantially the same shareholders, as are the shareholders of the Company.

The Executive Directors’ employment contracts provide that any payments made pursuant to these provisions will be made less any deductions the employer is required to make and shall be in full and final settlement of any claims the Executive Director may have against the employer or any associated company arising out of the termination of employment except for any personal injury claim, any claim in respect of accrued pension rights or statutory employment protection claims.

NON-EXECUTIVE DIRECTORS

				Compensation
				payable
	Contract	Notice	Unexpired	upon early
	date	period	term	termination (i)
Sir Richard Giordano(ii)	01.04.01	1yr	n/a	1yr salary
				and benefits in
				lieu of notice
Peter Backhouse	18.07.00	None	5 mths	n/a
David Benson	12.02.03	None	2 mths	n/a
Sir John Coles	12.02.03	None	2 mths	n/a
Paul Collins	18.07.00	None	5 mths	n/a
Elwyn Eilledge	12.02.03	None	2 mths	n/a
Keith Mackrell	12.02.03	None	2 mths	n/a
Dame Stella Rimington	12.02.03	None	2 mths	n/a
Lord Sharman	18.07.00	None	5 mths	n/a
Sir Robert Wilson	18.09.02	None	2yrs 7 mths	n/a

(i)

The terms of appointment for non-executive Directors, other than Sir Richard Giordano, do not contain any express contractual terms providing for compensation in the event of early termination of their appointment.

(ii)

Sir Richard Giordano has an employment contract with the Company which provides for a notice period of one year, or, at the Company’s discretion, payment in lieu of notice. In addition, upon termination of his employment (other than for gross misconduct), he will be entitled to payment equivalent to the cost of providing an office (with full time secretary and use of a car and driver) at a location of his choice for a period of five years.

BG GROUP PLC 2002 67

DIRECTORS’ INTERESTS IN SHARES UNDER THE NEW LONG TERM INCENTIVE SCHEME

	Notional	(i)					*
	allocations
	of shares		Notional	Notional	Notional	Notional		Notional	Notional
	made on		allocations	allocations	allocations	allocations		allocations	allocations
	1 Oct 1999		of shares	of shares	of shares	of shares		of shares	of shares
	(and subsequently		made on	made on	made on	as at		made on	as at
	reconstituted)		3 Nov 2000	1 Mar 2001	22 Nov 2001	1 Jan 2002		5 Sep 2002	31 Dec 2002
Ashley Almanza(ii)(iii)	12 086		7 570	–	29 848	49 504		274 272	323 776
Andrew Bonfield(iv)	–		–	141 322	175 037	316 359		–	–
Frank Chapman(ii)(iii)	164 306		181 700	–	225 706	571 712		611 286	1 182 998
William Friedrich(ii)(iii)	113 289		180 489	–	223 403	517 181		450 881	968 062
* Or at date of appointment (if later).

(i)	The October 1999 notional allocation was reconstituted after demerger using the average share prices of the first ten days of trading of the shares of the Company and Lattice Group plc immediately following demerger, as proportions of the aggregate of the two to produce the appropriate factors for adjustment. As a result, the initial allocation price was decreased from 376.46p to 245.73p and the initial allocation was increased by a factor of 1.532008 in the BG Group New Long Term Incentive Scheme. As a result of the performance criteria measured in October 2002, 46% of this notional allocation of shares is now subject to the one year retention period (the remainder of the allocation has lapsed). These shares will be transferred to the Executive Directors on 1 October 2003 when the retention period ends.
(ii)	The transfer of shares is dependent on the achievement of performance criteria at the end of a three year performance period followed by a further one year retention period, except for the awards made in September 2002, for which no retention period applies. The performance periods end in November 2003, November 2004 and September 2005 respectively for the notional allocations made in November 2000, November 2001 and September 2002.
(iii)	Dividends paid on shares held in trust may, at the discretion of the trustees, be reinvested in BG Group plc shares by the trustees and held on behalf of the Executive Directors until the normal release date of the respective allocations. On 23 December 2002, the trustees reinvested the interim dividend as follows: Ashley Almanza – 33 shares, Frank Chapman – 449 shares and William Friedrich – 309 shares.
(iv)	Andrew Bonfield ceased to be an Executive Director on 16 August 2002 following his resignation. As a result of his resignation, all his notional allocations lapsed immediately. The notional allocation of shares received by Andrew Bonfield in March 2001, following his appointment as Executive Director, was in line with the allocations made to the other Executive Directors in November 2000, following the demerger of Lattice Group plc. The allocation made to him in November 2001 was made partly under the terms of the BG Group New Long Term Incentive Scheme and partly as a special one-off allocation on identical terms. The latter was made following consultation with the Financial Services Authority and served to bring his allocation in line with the allocations of the other Executive Directors.

Market prices at the date of the awards were as follows: 3 November 2000 – 265.5p, 22 November 2001 – 261p, and 5 September 2002 – 251.75p. Market price at the date of the reinvestment of dividends was as follows: 23 December 2002 – 263p.

The performance conditions for the Scheme are set out on pages 61 to 62.

DIRECTORS’ INTERESTS IN ORDINARY SHARES
None of the Executive Directors hold options under the Executive Share Option Scheme and no grants have been made under that scheme since 1994.

OPTIONS
The number of share options held by the Directors under the BG Group Sharesave Scheme was as follows:

	Options as at 1 Jan 2002	*	Lapsed in year	Options as at 31 Dec 2002	Exercise price	Earliest normal exercise date	Expiry date
Ashley Almanza	4 230		–	4 230	£2.29	Mar 2004	Sep 2004
Andrew Bonfield(i)	7 466		7 466	–	–	–	–
Frank Chapman	4 286		–	4 286	£2.26	Nov 2004	May 2005
William Friedrich	7 368		–	7 368	£2.29	Mar 2006	Sep 2006

* Or at date of appointment (if later). No options were exercised or granted during the year.

(i) Andrew Bonfield ceased to be an Executive Director on 16 August 2002 following his resignation. As a result of his resignation all his options lapsed.

68	BG GROUP PLC 2002
	REMUNERATION REPORT continued

The number of share options held by the Directors under the BG Group Company Share Option Scheme was as follows:

	Options as at 1 Jan 2002	(i)	Options granted during the year	(ii)	Lapsed in year	Options as at 31 Dec 2002	Exercise price	Earliest normal exercise date	Expiry date
Ashley Almanza	33 519		–		–	33 519	£2.685	Nov 2003	Nov 2010
	50 557		–		–	50 557	£2.5634	Nov 2004	Nov 2011
	–		196 623		–	196 623	£2.5175	Sep 2005	Sep 2012
Andrew Bonfield(iii)	135 004		–		135 004	–	–	–	–
	296 481		–		296 481	–	–	–	–
Frank Chapman	167 597		–		–	167 597	£2.685	Nov 2003	Nov 2010
	382 304		–		–	382 304	£2.5634	Nov 2004	Nov 2011
	–		409 136		–	409 136	£2.5175	Sep 2005	Sep 2012
William Friedrich	166 480		–		–	166 480	£2.685	Nov 2003	Nov 2010
	378 403		–		–	378 403	£2.5634	Nov 2004	Nov 2011
	–		343 435		–	343 435	£2.5175	Sep 2005	Sep 2012

(i)	Or at date of appointment (if later). No options were exercised during the year.
(ii)	Or since date of appointment (if later).
(iii)	Andrew Bonfield ceased to be an Executive Director on 16 August 2002 following his resignation. As a result of his resignation all his options lapsed. The award of 135 004 share options in March 2001 was made following his appointment as Executive Director, Finance in January 2001. His award of 296 481 share options in November 2001 was made partly under the terms of the BG Group Company Share Option Scheme and partly as a special one-off award on identical terms. The latter was made following consultation with the Financial Services Authority and served to bring his awards in line with the awards of other Executive Directors in the same manner as under the BG Group New Long Term Incentive Scheme (see above).

The performance measure for the Scheme is set out on page 62.

The closing price of an ordinary share on 31 December 2002 was 268p. The range during the year was 313p (high) and 230.75p (low). These figures are derived from the Daily Official List of the London Stock Exchange.

ORDINARY SHARES
The Directors’ beneficial interests in ordinary shares of the Company at the end of the financial year were as follows:

	Beneficial interests ordinary shares (i)
	As at 1 Jan 2002	(ii)	As at 31 Dec 2002
Sir Richard Giordano(iii)	128 100		128 100
Ashley Almanza	20 472		20 760
Frank Chapman	220 055		221 326
William Friedrich(iv)	211 120		212 685
Peter Backhouse	20 500		20 500
David Benson	8 000		8 000
Sir John Coles	5 829		5 829
Paul Collins(v)	100 000		100 000
Elwyn Eilledge	9 443		9 443
Keith Mackrell	10 148		10 148
Dame Stella Rimington	3 751		3 751
Lord Sharman	1 956		1 956
Sir Robert Wilson	12 000		12 000

(i)	Beneficial interest including shares acquired pursuant to the BG Group Employee Profit Sharing Scheme and the BG Group Share Incentive Plan.
(ii)	Or at date of appointment (if later).
(iii)	Sir Richard Giordano holds 88 885 ordinary shares in the form of 17 777 American Depositary Receipts (ADRs). Each ADR represents five ordinary shares.
(iv)	William Friedrich holds 64 215 ordinary shares in the form of 12 843 ADRs.
(v)	Paul Collins’ holding is in the form of 20 000 ADRs.

OTHER INTERESTS
There have been no changes in the interests of the Directors in the share capital of the Company or any of its subsidiary undertakings between 1 January 2003 and 21 February 2003. As of 21 February 2003, the Directors’ interest in the share capital of the Company represents less than 1% of the issued share capital of the Company.

PENSIONS
All the Executive Directors were members of the BG Pension Scheme throughout the year. They are all subject to the earnings cap, which is a restriction on the amount of pay that can be used to calculate pensions payable from a UK tax approved pension scheme. The Company has agreed to increase their retirement benefits (including contingent death benefits) by means of an unapproved arrangement, the BG Supplementary Benefits Scheme, to at least the level which would otherwise have been provided had they not been subject to the earnings cap. Provision has been made in respect of the additional obligations for these post-retirement benefits.

BG GROUP PLC 2002 69

The arrangements for Frank Chapman and William Friedrich have not changed during the year. They provide an accrual of benefits designed to target a pension equivalent to two-thirds of their final 12 months’ salary on retirement from BG at age 60, inclusive of pension rights earned either in previous employments or previous pension arrangements. On appointment as an Executive Director with effect from 1 August 2002, Ashley Almanza’s pension arrangements were aligned with those of the other Executive Directors. Prior to that date he accrued benefits on the standard basis applicable to UK employees.

As for all members of the BG Pension Scheme, if the Company consents to retirement, no actuarial reduction is applied to pensions payable from age 55, provided 10 years’ service has been completed with the Group (which includes pensionable service transferred from previous employment). Pensions in payment are increased in line with retail price inflation. An adult dependant’s pension is payable on death in service, equal to two-thirds of that payable to the pension scheme member based on potential service to retirement age. On death in retirement an adult dependant’s pension is payable equal to two-thirds of the member’s pension prior to exchanging any of it for a cash lump sum.

Andrew Bonfield was entitled to pension arrangements on the same basis as the other Executive Directors. However, when he left the Company on 16 August 2002, he had completed less than two years’ pensionable service. A member leaving in such circumstances may request a transfer payment within a specific period but this opportunity was not taken up. He therefore received a refund of his own contributions and has no continuing entitlement to benefits under the BG Pension Scheme or the BG Supplementary Benefits Scheme.

Directors’ pension provisions were as follows:

	Directors’ contributions in year to 31 Dec 2002 £000	(i)	Age at 31 Dec 2002	Increase in pension in year to 31 Dec 2002£000 pa		(i) (iii)	Total accrued annual pension at 31 Dec 2002 £000 pa	Retirement age
				(a)	(b)
Ashley Almanza	4		39	7	7		28	60
Frank Chapman	15		49	57	55		210	60
William Friedrich	15		53	37	35		194	60

(a)	Actual increase.
(b)	Increase net of price inflation.

	Transfer value of accrued pension as at 31 Dec 2001	(ii)(iii)(iv)	Transfer value of accrued pension as at 31 Dec 2002	(iii)(iv)	Increase in transfer value over the year less Director’s own contributions	(i)(iii)
	£000		£000		£000
Ashley Almanza	174		240		62
Frank Chapman	1 896		2 667		756
William Friedrich	2 246		2 823		562

(i)	The figures for Ashley Almanza relate only to the period for which he has been an Executive Director i.e. from 1 August 2002.
(ii)	As at 1 August 2002 for Ashley Almanza.
(iii)	The increase in pension and transfer value for Frank Chapman (and also for William Friedrich) arises from the fact that his pensionable service has increased by one year and his pensionable salary has increased during the year, and not from any change to his pension promise. However, as at 31 December 2001 Frank Chapman’s pensionable salary was restricted by notional Inland Revenue limits. This resulted in a reduced accrued pension and transfer value at that date, but the limits did not impact on his 31 December 2002 pensionable salary. Consequently, his increase in accrued pension and transfer value over the year reflect not only a year of pension accrual but also the change from a pensionable salary which was limited to one which was not. If the effect of the latter is removed, his increase in accrued pension over the year is £33 000 and his increase in transfer value is £459 000.
(iv)	The transfer values shown at the end of 2001 and 2002 represent the value of each Executive Director’s accrued pension based on total service completed to the relevant date. The accrued pensions are the amounts that would have been paid if the Executive Director had left service at the relevant date. The transfer values have been calculated in accordance with guidance note ‘GN11’ issued by the Institute of Actuaries and Faculty of Actuaries.

EXTERNAL APPOINTMENTS
To broaden the experience of Executive Directors, it is Company policy to allow each of them to accept one external appointment as a non-executive director of another company, the fees for which would be retained by the individual Director.

By order of the Board
Elwyn Eilledge
Chairman of the Remuneration Committee

21 February 2003

Registered office:
100 Thames Valley Park Drive
Reading
Berkshire
RG6 1PT
Registered in England No. 3690065

70	BG GROUP PLC 2002
	INDEPENDENT AUDITORS’ REPORT TO THE MEMBERS OF BG GROUP PLC

We have audited the Financial Statements which comprise the profit and loss account, the balance sheet, the cash flow statement, the statement of total recognised gains and losses and the related notes which have been prepared under the historical cost convention and the accounting policies set out in the statement of accounting policies. We have also audited the disclosures required by Part 3 of Schedule 7A to the Companies Act 1985 contained in the Directors’ Remuneration Report (‘the auditable part’).

RESPECTIVE RESPONSIBILITIES OF DIRECTORS AND AUDITORS
The Directors’ responsibilities for preparing the Annual Report and Accounts, the Directors’ Remuneration Report and the Financial Statements and Form 20-F in accordance with applicable United Kingdom law and accounting standards and the requirements of the US Securities and Exchange Commission are set out in the statement of Directors’ responsibilities.

Our responsibility is to audit the Financial Statements and the auditable part of the Directors’ Remuneration Report in accordance with relevant legal and regulatory requirements and United Kingdom Auditing Standards issued by the Auditing Practices Board and the Listing Rules of the Financial Services Authority.

We report to you our opinion as to whether the Financial Statements give a true and fair view and whether the Financial Statements and the auditable part of the Directors’ Remuneration Report have been properly prepared in accordance with the Companies Act 1985. We also report to you if, in our opinion, the Directors’ Report is not consistent with the Financial Statements, if the Company has not kept proper accounting records, if we have not received all the information and explanations we require for our audit, or if information specified by law or the Listing Rules regarding directors’ remuneration and transactions is not disclosed.

We read the other information contained in the Annual Report and Accounts and Form 20-F and consider the implications for our report if we become aware of any apparent misstatements or material inconsistencies with the Financial Statements. The other information comprises only: the Directors’ Report, the unaudited part of the Directors’ Remuneration Report, the Chairman’s and Chief Executive’s Statement, the Operating and Financial Review and the Corporate Governance Statement.

We review whether the Corporate Governance Statement reflects the Company’s compliance with the seven provisions of the Combined Code specified for our review by the Listing Rules, and we report if it does not. We are not required to consider whether the Board’s statements on internal control cover all risks and controls, or to form an opinion on the effectiveness of the Group’s corporate governance procedures or its risk and control procedures.

BASIS OF AUDIT OPINION
We conducted our audit in accordance with Auditing Standards issued by the Auditing Practices Board in the UK and with Auditing Standards generally accepted in the US. An audit includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the Financial Statements and the auditable part of the Directors’ Remuneration Report. It also includes an assessment of the significant estimates and judgments made by the Directors in the preparation of the Financial Statements, and of whether the accounting policies are appropriate to the Company’s circumstances, consistently applied and adequately disclosed.

We planned and performed our audit so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the Financial Statements and the auditable part of the Directors’ Remuneration Report are free from material misstatement, whether caused by fraud or other irregularity or error. In forming our opinion we also evaluated the overall adequacy of the presentation of information in the Financial Statements.

UK OPINION
In our opinion, the Financial Statements give a true and fair view of the state of affairs of the Company and the Group at 31 December 2002 and of the profit and cash flows of the Group for the year then ended, and the Financial Statements have been properly prepared in accordance with the Companies Act 1985; those parts of the Directors’ Remuneration Report required by Part 3 of Schedule 7A to the Companies Act 1985 have been properly prepared in accordance with the Companies Act 1985.

US OPINION
In our opinion, the Financial Statements present fairly, in all material respects, the financial position of the Group at 31 December 2002 and 2001 and the results of its operations and cash flows for each of the three years to 31 December 2002 in conformity with accounting principles generally accepted in the UK.

Accounting principles generally accepted in the UK vary in certain significant respects from accounting principles generally accepted in the US. The application of the latter would have affected the determination of consolidated net income for each of the three years to the period ended 31 December 2002 and the consolidated shareholders’ funds at 31 December 2002 and 2001 as shown in the summary of differences between UK and US generally accepted accounting principles set out in the statement of accounting policies.

PricewaterhouseCoopers LLP
Chartered Accountants and Registered Auditors
1 Embankment Place
London WC2N 6RH 21 February 2003

BG GROUP PLC 2002	71
PRINCIPAL ACCOUNTING POLICIES

BASIS OF PREPARATION AND ACCOUNTING PRINCIPLES
The preparation of Financial Statements in conformity with generally accepted accounting principles requires management to make judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the Financial Statements and the reported revenues during the reporting period. Actual results could differ from these estimates.

The business activities demerged to Lattice in 2000 are presented in these accounts as discontinued operations.

These accounts have been prepared in accordance with applicable accounting standards, using historical cost principles for continuing operations and using historical cost principles modified through the revaluation of certain fixed assets for discontinued operations.

The accounting policies, where applicable, are materially in accordance with a Statement of Recommended Practice (SORP) issued by the Oil Industry Accounting Committee entitled ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’ although there are two areas where the accounting policies differ from the SORP. These are shown in the section on exploration expenditure (see below).

BASIS OF CONSOLIDATION
The accounts comprise a consolidation of the accounts of the Company and its subsidiary undertakings and incorporate the results of its share of joint ventures and associated undertakings.

The results of undertakings acquired or disposed of are consolidated from or to the date when control passes to or from the Company. Most of BG’s exploration and production activity is conducted through joint arrangements. BG accounts for its own share of the assets, liabilities and cash flows associated with these joint arrangements.

GOODWILL
On the acquisition of a subsidiary undertaking, joint venture or associated undertaking, fair values are attributed to the net assets acquired. Goodwill, which represents the difference between the purchase consideration and the fair value of the net assets acquired, is capitalised. Goodwill which has a limited useful economic life is amortised over an appropriate period on a straight-line basis not exceeding 20 years.

Goodwill eliminated against Group reserves prior to the implementation of Financial Reporting Standard (FRS) 10, ‘Goodwill and Intangible Assets’, has not been reinstated, but will be charged to the profit and loss account on any subsequent disposal of the net assets to which it is related.

When goodwill is denominated in a foreign currency, it is translated into Sterling in line with the Group’s accounting policy on foreign currencies (see below).

TANGIBLE FIXED ASSETS
All tangible fixed assets are carried at depreciated historical cost.

Additions represent extensions to, or significant increases in, the capacity of tangible fixed assets.

Contributions received towards the cost of tangible fixed assets (including government grants) are included in creditors as deferred income and credited to the profit and loss account over the life of the assets.

Interest charges on borrowings used to finance major capital projects are capitalised.

Depreciation
Freehold land is not depreciated. Other tangible fixed assets, except exploration and production assets, are depreciated on a straight-line basis at rates sufficient to write off the historical cost of individual assets over their estimated useful economic lives. The depreciation periods for the principal categories of assets are as follows:

Freehold and leasehold buildings	up to 50 years
Mains and services	up to 60 years
Plant and machinery	5 to 25 years
Meters	up to 20 years
Motor vehicles and office equipment	up to 10 years

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

Asset lives are kept under review and complete asset life reviews are regularly carried out.

72	BG GROUP PLC 2002
	PRINCIPAL ACCOUNTING POLICIES continued

IMPAIRMENT OF FIXED ASSETS
Any impairment of fixed assets is calculated as the difference between the carrying values of income generating units (including associated goodwill) and the estimated value in use at the date the impairment loss is recognised. Value in use represents the net present value of expected future cash flows discounted on a pre-tax basis.

Impairment of fixed assets is recognised in the profit and loss account within operating costs.

STOCKS
Stocks are stated at weighted average historical cost less provision for deterioration and obsolescence.

REVENUE RECOGNITION
Revenue recognition associated with exploration and production sales (natural gas, crude oil, petroleum and chemical products) is recorded when title passes to the customer.

Sales of liquefied natural gas (LNG) and associated products are recognised when the LNG passes the delivery point at the loading port or the tailgate of the regasification terminal. LNG shipping revenue is recognised over the period of the relevant contract.

Revenue from transportation and distribution activities is recognised in the same period in which the related volumes are delivered to the customer.

Power generation revenues are recognised on the availability status of the power station to produce at a given point in time. The costs of actual production are also passed through and recognised in revenue whenever power is generated.

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

EXPLORATION EXPENDITURE
The SORP (see basis of preparation and accounting principles, above) requires depreciation of licence acquisition costs on a straight-line basis. It also permits capitalisation of all costs incurred as intangible fixed assets. BG accounts for exploration expenditure under the successful efforts method and differs from the SORP as described below.

Exploration expenditure, including licence acquisition costs, is capitalised as an intangible fixed asset when incurred and certain expenditure, such as geological and geophysical exploration costs, is expensed. A review of each licence or field is carried out, at least annually, to ascertain whether proved reserves have been discovered. When proved reserves are determined the relevant expenditure, including licence acquisition costs, is transferred to tangible fixed assets and depreciated on a unit of production basis. Expenditure deemed to be unsuccessful is written off to the profit and loss account.

BG considers this application of the successful efforts method to be appropriate as it provides comparability with the Group’s peer group and because it treats licence acquisition costs in a manner which is consistent with the treatment of other exploration assets within intangible fixed assets.

DECOMMISSIONING COSTS
Provision is made for the net present value of the estimated cost of decommissioning at the end of the producing lives of fields. When this provision gives access to future economic benefits, an asset is recognised; otherwise the costs are charged to the profit and loss account. The unwinding of the discount on the provision is included in the profit and loss account as a financial item and is included within the net interest charge.

FOREIGN CURRENCIES
Assets and liabilities denominated in foreign currencies are translated into Sterling at closing rates of exchange or, where they are hedged using cross-currency swaps, at the swap rate. Trading results of overseas subsidiary undertakings, joint ventures and associated undertakings are translated into Sterling at average rates of exchange or, where hedged, at the contract rate of exchange. Differences resulting from the retranslation of the opening net assets and the results for the year are taken to reserves.

Exchange differences on monetary assets and liabilities are taken to the profit and loss account, except that exchange differences on foreign currency net borrowings used to finance foreign currency net investments are taken to reserves. All other exchange movements are dealt with through the profit and loss account.

DEFERRED TAX
Provision is made in full for the deferred tax arising on the difference between the accounting treatment and tax treatment for depreciation in respect of accelerated capital allowances and other timing differences. Provision for deferred petroleum revenue tax is shown net of allowable corporation tax relief (reflected in the deferred corporation tax balance) and is made in respect of applicable fields based on current forecasts.

BG GROUP PLC 2002 73

LEASES
Rentals under operating leases are charged to the profit and loss account as incurred.

FINANCIAL INSTRUMENTS
Derivative financial instruments utilised by the Group are interest rate swaps, foreign currency swaps, forward rate agreements, interest rate swaptions, tax equalisation swaps and forward exchange contracts.

A derivative financial instrument is considered to be used for hedging purposes when it alters the risk profile of an existing underlying exposure of the Group in line with the Group’s risk management policies. Derivatives used for hedging are accounted for on an accruals basis. During the year there were no interest rate or exchange rate derivatives used for trading purposes.

Termination payments made or received in respect of derivatives are spread over the shorter of the life of the original instrument or the life of the underlying exposure in cases where the underlying exposure continues to exist. Where the underlying exposure ceases to exist, any termination payments are taken to the profit and loss account.

Interest differentials on derivative instruments are recognised by adjusting the net interest charge. Premiums or discounts on derivative instruments are amortised over the shorter of the life of the instrument or the underlying exposure.

Currency swap agreements and forward exchange contracts are retranslated at the rates ruling in the agreements and contracts. Resulting gains or losses are offset against foreign exchange gains or losses on the related borrowings or, where the instrument is used to hedge a committed future transaction, are deferred until the transaction occurs.

PENSIONS
The cost of providing retirement pensions and related benefits is charged to the profit and loss account over the periods benefiting from the employees’ services. The regular pension cost, variations from the regular pension cost and interest are all charged within employee costs. The difference between the charge or credit to the profit and loss account and the contributions paid to the pension schemes in which the Group participates is shown as an increase or decrease in the provision. Deferred tax on this provision has been accounted for in full. The transitional disclosure requirements of FRS 17, ‘Retirement benefits’, are included within the pensions note (note 27, page 106).

RESEARCH AND DEVELOPMENT AND ADVERTISING EXPENDITURE
All research and development and advertising expenditure is written off as incurred.

74	BG GROUP PLC 2002
CONSOLIDATED PROFIT AND LOSS ACCOUNT

for the year ended 31 December		2002
				Exceptional		Business
		Total		items		performance
	Notes	£m		£m		£m
Turnover – Group and share of joint ventures		2 792		–		2 792
Less: share of joint ventures’ turnover		(182	)	–		(182	)
Group turnover	2, 5	2 610		–		2 610
Operating costs	3, 5	(1 877	)	–		(1 877	)
Group operating profit		733		–		733
Share of operating profits less losses in:
Joint ventures		83		–		83
Associated undertakings		72		–		72
Total operating profit	2	888		–		888
Loss on disposal of subsidiary and associated undertakings	5	(7	)	(7	)	–
Loss on disposal of other fixed assets	5	(7	)	(7	)	–
Profit on ordinary activities before interest	2	874		(14	)	888
Net interest	6	(80	)	–		(80	)
Profit on ordinary activities before taxation		794		(14	)	808
Tax on profit on ordinary activities	7	(374	)	–		(374	)
Profit on ordinary activities after taxation		420		(14	)	434
Minority shareholders’ interest		(10	)	–		(10	)
Profit for the financial year	2	410		(14	)	424
Dividends	8	(110	)	–		(110	)
Transfer to reserves	24	300		(14	)	314
Earnings per ordinary share:	9
Basic		11.6	p	(0.4	)p	12.0	p
Diluted		11.6	p	(0.4	)p	12.0	p

The accounting policies on pages 71 to 73 together with the notes on pages 81 to 116 form part of these accounts.

BG GROUP PLC 2002 75

for the year ended 31 December	2001						2000
			Exceptional		Business				Discontinued		Continuing
	Total		items		performance		Total		operations	(a)	operations
	£m		£m		£m		£m		£m		£m
Turnover – Group and share of joint ventures(b)	2 689		34		2 655		4 876		2 430		2 446
Less: share of joint ventures’ turnover	(147	)	–		(147	)	(177	)	(3	)	(174	)
Group turnover(b)	2 542		34		2 508		4 699		2 427		2 272
Operating costs(b)	(1 815)		–		(1 815)		(3 694)		(1 663)		(2 031)
Group operating profit	727		34		693		1005		764		241
Share of operating profits less losses in:
Joint ventures	68		–		68		58		(1	)	59
Associated undertakings	72		–		72		74		–		74
Total operating profit(c)	867		34		833		1137		763		374
Profit on disposal of subsidiary and associated undertakings	77		77		–		282		2		280
Profit/(loss) on disposal of other fixed assets	21		21		–		(6	)	(6	)	–
Profit on ordinary activities before interest	965		132		833		1413		759		654
Net interest	(63	)	17		(80	)	(459	)	(379	)	(80	)
Profit on ordinary activities before taxation	902		149		753		954		380		574
Tax on profit on ordinary activities	(287	)	(28	)	(259	)	(281	)	(167	)	(114	)
Profit on ordinary activities after taxation	615		121		494		673		213		460
Minority shareholders’ interest	(29	)	–		(29	)	(19	)	–		(19	)
Profit for the financial year	586		121		465		654		213		441
Dividends	(105	)	–		(105	)	(223	)	(122	)	(101	)
Transfer to reserves	481		121		360		431		91		340
Earnings per ordinary share:
Basic	16.7	p	3.4	p	13.3	p	18.8	p	6.1	p	12.7	p
Basic excluding exceptional items(d)							19.1	p	7.3	p	11.8	p
Diluted	16.7	p	3.4	p	13.3	p	18.8	p	6.1	p	12.7	p
Diluted excluding exceptional items(d)							19.1	p	7.3	p	11.8	p

In arriving at the 2000 figures above, net interest is the amount directly attributable to the actual net borrowings of continuing and discontinued operations. Tax charged is calculated based on the effective tax rates of continuing and discontinued operations.
(a)	Discontinued operations comprise the business activities demerged to Lattice effective on 23 October 2000 and include intra-group items which are not applicable post demerger (see note 1, page 81).
(b)	Gas trading activity has been re-presented on a net basis (see note 1, page 81).
(c)	Total operating profit for continuing operations in 2000 before exceptional items was £688m. An analysis of exceptional items is shown in note 5, page 90.
(d)	Earnings per ordinary share excluding exceptional items exclude the impact of profits and losses on disposals and the exceptional items disclosed in note 5, page 90, together with the associated tax impact.

The accounting policies on pages 71 to 73 together with the notes on pages 81 to 116 form part of these accounts.

76	BG GROUP PLC 2002
CONSOLIDATED STATEMENT OF TOTAL RECOGNISED GAINS AND LOSSES

for the year ended 31 December	2002		2001		2000
	£m		£m		£m
Profit for the financial year	410		586		654
Other recognised gains and losses:
Unrealised surplus on revaluation of tangible fixed assets(a)	–		–		164
Unrealised gain on transfer of assets to a joint venture(a)	–		–		6
Currency translation adjustments	(385	)	(233	)	45
	(385	)	(233	)	215
Total recognised gains and losses for the financial year	25		353		869

Cumulative currency translation losses taken to reserves amounted to £642m as at 31 December 2002 (2001 £257m; 2000 £24m). The movement in 2002 includes the impact of the retranslation of the Group’s net investments in MetroGAS S.A. (MetroGAS) of £83m (2001 £121m) and Companhia de Gas de São Paulo S.A. (Comgas) of £189m (2001 £97m) at the closing rate of exchange. In the case of MetroGAS, the rate prevailing on 11 January 2002 was used for the 2001 calculation.

(a) Relates to discontinued operations only (see note 1, page 81).

The accounting policies on pages 71 to 73 together with the notes on pages 81 to 116 form part of these accounts.

BG GROUP PLC 2002	77
BALANCE SHEETS

		The Group				The Company
as at 31 December		2002		2001		2002		2001
	Notes	£m		£m		£m		£m
Fixed assets
Intangible assets	10	812		798		–		–
Tangible assets	11	4 102		3 707		–		–
Investments in subsidiary undertakings	12					2 269		2 269
Investments in joint ventures:						–		–
Share of gross assets		655		639
Share of gross liabilities		(489	)	(494	)
	12	166		145
Loans	12	140		150
Investments in associated undertakings:						–		–
Share of net assets	12	231		245
Loans	12	196		109
Other investments	12	9		14		–		–
		5 656		5 168		2 269		2 269
Current assets
Stocks	14	105		98		–		–
Debtors: amounts falling due within one year	15	661		616		26		31
Debtors: amounts falling due after more than one year	15	93		125		16		16
		754		741		42		47
Investments	16	127		326		–		–
Cash at bank and in hand		141		92		7		4
		1 127		1 257		49		51
Creditors: amounts falling due within one year
Borrowings	17 to 20	(580	)	(493	)	–		–
Other creditors	21	(999	)	(847	)	(372	)	(266	)
		(1 579	)	(1 340)		(372	)	(266	)
Net current liabilities		(452	)	(83	)	(323	)	(215	)
Total assets less current liabilities		5 204		5 085		1 946		2 054
Creditors: amounts falling due after more than one year
Borrowings	17 to 20	(690	)	(463	)	–		–
Other creditors	21	(190	)	(228	)	–		–
		(880	)	(691	)	–		–
Provisions for liabilities and charges	22	(976	)	(864	)	(54	)	(52	)
		3 348		3 530		1 892		2 002
Capital and reserves
Called up equity share capital	23, 24	353		353		353		353
Share premium account	24	45		42		45		42
Other reserves	24	1 702		1 702		756		756
Profit and loss account	24	1 038		1 129		738		851
Joint ventures and associated undertakings	24	186		180
BG shareholders’ funds	24	3 324		3 406		1 892		2 002
Minority shareholders’ interest (a)		24		124
		3 348		3 530		1 892		2 002

All inter-company transactions are eliminated on consolidation. Commitments and contingencies are shown in note 25, page 104.

(a) Represents minority shareholders’ equity interest of £11m (2001 £98m) and minority shareholders’ non-equity interest of £13m (2001 £26m).

The accounts on pages 71 to 116 were approved by the Board and signed on its behalf on 21 February 2003 by:

Sir Richard Giordano, Chairman
Ashley Almanza, Chief Financial Officer

The accounting policies on pages 71 to 73 together with the notes on pages 81 to 116 form part of these accounts.

78	BG GROUP PLC 2002
MOVEMENT IN BG SHAREHOLDERS' FUNDS

	The Group						The Company
for the year ended 31 December	2002		2001		2000		2002		2001		2000
	£m		£m		£m		£m		£m		£m
Profit/(loss) for the financial year	410		586		654		(3	)	404		152
Dividends	(110	)	(105	)	(223	)	(110	)	(105	)	(223	)
	300		481		431		(113	)	299		(71	)
Issue of shares	3		–		44		3		–		44
Redemption of share capital	–		–		(4	)	–		–		(4	)
Termination of Sharesave Schemes	–		–		57		–		–		57
Other recognised gains and losses for the financial year (a)	(385	)	(233	)	215		–		–		–
Goodwill on disposal of associated undertaking	–		–		24		–		–		–
Dividend in specie (b)	–		–		(4 689	)	–		–		(824	)
Net movement in BG shareholders’ funds for the financial year	(82	)	248		(3 922	)	(110	)	299		(798	)
BG shareholders’ funds as at 1 January	3 406		3 158		7 080		2 002		1 703		2 501