1st Quarter Results

First Quarter Key Points

· Business Performance EPS down 3% to 33.8 cents; Total EPS down 9% to 32.4 cents

· Net cash flow from operating activities up 6% to $2.4 billion

· E&P production volumes down 4% at 633 kboed

· LNG segment total operating profit down 7%; no BG Group cargoes from Egyptian LNG

· Egyptian domestic offtake exceeded contractual commitments; deteriorating reservoir performance

· Good progress in Australia and Brazil with key milestones delivered

· Group's exposure to commodity prices and foreign exchange rates 50 - 70% hedged in 2014

BG Group's interim Executive Chairman, Andrew Gould said:

"In the first quarter, we continued to make good progress with our key growth projects in Australia and Brazil. Group production volumes for the first quarter were consistent with our anticipated seasonal phasing, although production entitlement from Egypt was lower than expected as domestic offtake remains well above contractual commitments and reservoir performance deteriorates. As a result of the challenges in Egypt, the Group's 2014 production is now expected to be at the lower end of the guidance range."

a) 'Business Performance' excludes disposals, certain re-measurements and impairments and certain other exceptional items as exclusion of these items provides a clear and consistent presentation of the underlying operating performance of the Group's ongoing business. For further information see Presentation of Non-GAAP measures (page 12) and notes 1 to 3 (pages 19 to 21). Unless otherwise stated, the results discussed in this release relate to BG Group's Business Performance.

Business Review - Group

a) Includes capital investment relating to discontinued operations for the quarter of $nil (2013 $5 million).

b) Reflects net cash flow from operating activities, less net interest paid and capital investment on a cash basis, plus dividends from joint ventures and associates

and loan repayments.

c) For a definition see the Glossary on page 29.

Business Performance

First quarter

Revenue and other operating income increased 3% to $5 061 million. While E&P production volumes and LNG cargo deliveries were lower, revenues benefited from a significant increase in oil volumes, particularly from Brazil.

Total operating profit decreased 6% to $2 009 million, reflecting reductions in both the Upstream and LNG Shipping & Marketing segments. In Upstream, higher revenues were more than offset by higher operating costs. In LNG Shipping & Marketing, while average LNG margins were favourable, this was more than offset by the lower number of deliveries, with no BG Group cargoes from Egyptian LNG.

Net finance costs of $56 million included foreign exchange losses of $13 million (2013 net finance costs of $35 million included foreign exchange gains of $5 million).

The Group's effective tax rate (including BG Group's share of joint venture and associates' tax) was 41% for the quarter, lower than the rate of 44% for the first quarter of 2013 but in line with the full year rate for 2013.

Group earnings of $1 152 million and EPS of 33.8 cents both decreased 3% as the reduction in total operating profit and higher net finance costs were partially offset by the lower tax charge.

Free cash flow increased by $494 million from $(341) million to $153 million as a result of a working capital cash inflow due to lower LNG cargo receivables, and reduced capital investment, offset by higher taxes paid. Net debt was 2% lower at $10 410 million and gearing, at 23.6%, was broadly in line with last year.

Capital investment on a cash basis of $2 283 million was almost entirely in the Upstream segment ($2 271 million).This investment was concentrated primarily on the Group's key growth projects in Australia and Brazil. Further details are provided in the first quarter business highlights section and the Supplementary information: Operating and financial data section.

Total Results (including disposals, re-measurements and impairments)

First quarter

Total earnings for the first quarter of 2014 were $1 102 million (32.4 cents per share) and included a post-tax loss of $50 million in respect of disposals, re-measurements and impairments, primarily related to exceptional restructuring costs of $62 million. Total earnings in the first quarter of 2013 were $1 208 million (35.5 cents per share) and included a post-tax gain of $25 million in respect of disposals, re-measurements and impairments. For further information see Presentation of Non-GAAP measures (page 12) and notes 1 to 3 (pages 19 to 21).

First quarter business highlights

Australia 

In the Ruby Jo upstream development area, three of the six planned field compression stations (FCSs) started operating in the quarter, a fourth started up in April, with the two remaining FCSs expected to commence operations by the end of the second quarter. Importantly, operations at the central processing plant (CPP) started up in April. Drilling again exceeded expectations with 170 wells in the quarter.

At the LNG export facility, the first storage tank was successfully hydro tested and the plant remains on track to start commissioning the gas turbine generators in the second quarter. The QCLNG project is on schedule for first LNG in the fourth quarter of 2014, and within the project's Phase 1 $20.4 billion budget.

Brazil

Gross production from the three installed floating production, storage and offloading (FPSO) vessels in the Santos Basin exceeded 220 thousand barrels of oil equivalent per day (kboed) by the end of the quarter, following the February installation of a second well on FPSO 2 (Sapinhoá South), the first using a buoyancy supported riser (BSR) system. This well is currently producing around 35 thousand barrels of oil per day (kbopd). A third well was connected in April and is currently producing around 30 kbopd. In addition, a second BSR was installed in April. Plateau onFPSO 2 is expected mid-year from only four producing wells.

On FPSO 3 (Lula North East), a first BSR has been fully installed. The connection of new producing wells is imminent, with a second permanent well due in May. The second BSR is in position, with permanent tethering underway, in advance of additional well connections in the second half of 2014. Plateau on FPSO 3 is expected by the end of the year.

The operator expects to install FPSO 4 (Sapinhoá North) in the third quarter and FPSO 5 (Iracema South) by year end. Both vessels are in Brazil for the completion of topsides facilities, which include hydrocarbon processing capabilities. Both are on budget and around 90% complete. FPSO 6 (Iracema North), which is due onstream in the fourth quarter of 2015, is also on budget and around 60% complete.

In March, the installation licence for the deep water scope of the Cabiúnas gas pipeline was received. It is expected that the shallow water licence will be received in the second quarter of 2014.The pipeline represents the next major phase of gas export infrastructure.

The Iara ADR-1 appraisal well is currently undergoing drill stem testing. BG Group and its partners expect to start an extended well test (EWT) on Iara-4 in June ahead of Declaration of Commerciality (DoC) by the end of 2014.

Canada

In March, BG Group's pipeline partner, Spectra Energy Corp, submitted an Environmental Assessment Certificate Application to the British Columbia Environmental Assessment Office for the Westcoast Connector Gas Transmission Project. Further, BG Group received the final licence it requires from the National Energy Board to allow exports of up to 25 million tonnes per annum (mtpa) of LNG for 25 years from the date of first export.

In April, BG Group signed a non-binding Memorandum of Understanding (MoU) with China National Offshore Oil Corporation (CNOOC) in relation to the Prince Rupert LNG project.

Egypt

Production volumes in the first quarter of 66 kboed were 35% lower than in the fourth quarter of 2013 (102 kboed) as a result of deteriorating reservoir performance and the continuing high level of diversions to the domestic market, where the Group is entitled to a lower share of production. Consequently, volumes from Egyptian LNG were severely restricted, with no cargoes lifted by BG Group in the first quarter. One cargo is expected to be lifted by BG Group in the second quarter.

Looking forward, the strong likelihood of continued diversions to the domestic market, combined with further reservoir deterioration, means that the Group currently expects very limited cargoes to be lifted from Egyptian LNG for the foreseeable future. In the absence of concerted action from the Egyptian government, the future commercial operation of Egyptian LNG is increasingly at risk.

Due to a reduction in LNG exports and lower than expected direct payments from EGPC, the domestic receivables balance increased to $1.4 billion as at 31 March 2014, $0.7 billion of which is overdue. 

In the first quarter of 2014, Upstream and LNG activities in Egypt accounted for 10% of BG Group's production and around 5% of earnings from continuing operations. The book value of BG Group's investment in Egypt as at 31 March 2014, including receivables, was $2.7 billion, of which $0.2 billion relates to Egyptian LNG.

Phase 9a is on track to commence production in the third quarter of 2014. On plateau, Phase 9a will only temporarily offset reservoir decline. Release of funds for any further development is contingent upon an improvement in the investment climate including a significant improvement in the outstanding receivable position. Discussions with the Egyptian government are ongoing.

Results from the Notus high-pressure high-temperature discovery well proved gas in all targeted zones. These results are being assessed ahead of discussions with the government regarding possible development plans.

Kenya

In March, the Sunbird-1 exploration well intersected a gross hydrocarbon column of 44 metres in the Miocene reef, at1 584 metres subsea, in a water depth of 723 metres, offshore Kenya. Oil and gas samples have been recovered to surface and are being analysed.

Myanmar

In March, BG Group was awarded exploration acreage in the Rakhine Basin, offshore western Myanmar as part of the government's 2013 offshore bid round. The Group will operate two blocks, A4 and AD2 (45% and 55% equity respectively) and also secured non-operated acreage in blocks A7 and AD5 (45% equity in each).

BG Group and its partners have committed to a 3D seismic acquisition programme in each block, which is expected to begin in 2015, following an Environmental and Social Impact Assessment, with options beyond that for drilling. This award is in line with the Group's strategy to focus on securing prospective frontier acreage and enter, on average, one new basin each year.

Tanzania 

In April, BG Group and its partners in offshore blocks 1, 3 & 4 and the partners in block 2 signed a Heads of Agreement setting out how the companies will collaborate on development of a potential joint LNG project. Under the agreement, BG Group will be the lead developer during the pre-FEED phase. Joint project offices will be established inDar es Salaam and London.

Good progress has been made with the Tanzania Petroleum Development Corporation (TPDC) and the Tanzanian Ministry of Energy and Minerals on the preparatory work needed to progress the selection and acquisition of a site for the potential LNG project. The site announcement is expected in the second quarter of 2014.

Thailand 

In February, the Group achieved its first quarter milestone of gas from the Bongkot South Phase 4b project. This involved the installation and hook-up of four wellhead platforms, with gas from the project being exported via a new build spur line connected to existing infrastructure and condensate exported to the floating, storage and offloading vessel at Bongkot North.

USA

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

Portfolio management

In March, BG Group agreed to acquire an additional 25% interest in Block 5(c), offshore Trinidad and Tobago, taking its interest in the block to 100%. The transaction is subject to government approval.

In April, BG Group farmed down 25% of its interests in the BAR-M-215, 217, 252 and 254 blocks in the Barreirinhas Basin, offshore Brazil, to PTT Exploration and Production Public Company Limited (PTTEP). The transaction is subject to approval by the Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP).

Organisational restructuring

BG Group continues to drive productivity improvements in the business, including simplifying the organisation, as a key part of delivering the Group's long term strategy. During the quarter, the Group recognised an exceptional post-tax charge for restructuring costs of $62 million in relation to staff redundancies in the UK, Australia and Egypt.

Business outlook

The Group's 2014 production guidance remains unchanged at 590 - 630 kboed (at reference conditions), although production is now expected to be at the lower end of the range, given the issues in Egypt. The deterioration in Egypt will similarly impact 2015 production.

Group production will follow a marked seasonal profile in 2014. There is a significant amount of maintenance activity including planned shutdowns scheduled for the second and third quarters, particularly in the UK, which will lead to substantially lower production in those quarters. Production will rise in the fourth quarter as maintenance is completed and new developments are expected onstream.

In the LNG Shipping & Marketing segment, beyond one export cargo expected in the second quarter, the Group currently expects very limited cargoes from Egyptian LNG for the foreseeable future. In 2015, as previously reported, the planned gas development programme in Equatorial Guinea will result in fewer cargoes than in 2014. The majority of the contribution from QCLNG will be reported in the Upstream segment of the business.

The Group is reviewing its operational, investment and portfolio management plans and will not provide 2015 guidance until its full year results in February 2015.

Risk management for commodity prices and foreign exchange rates

Commodity prices

In 2014, the Group continues to execute a significant investment programme and expects to be cash flow negative for the year.

In order to reduce volatility of operating cash flow while this investment programme is being executed, BG Group has entered into Brent oil swaps at an average price of $106/bbl for the period of April through December 2014. After the effect of UK tax, these positions are expected to hedge more than 70% of the Group's 2014 earnings sensitivity to oil price movements for this period.

Commodity price hedges are accounted for in accordance with IAS 39, and will be recognised in the income statement. The hedges will be treated on a mark-to-market basis, so that for the intermediate quarters within 2014 the disposals, re-measurements and impairments section of the accounts will track the unrealised fair value of the hedges, before the final settlement is recognised in Business Performance.

BG Group will allocate the hedge impact across both Upstream and LNG Shipping & Marketing segments in accordance with the Group's expected Brent exposures. 

BG Group's policy is not to hedge commodity prices as a matter of course. However, from time to time it may elect to hedge certain revenue or cost streams.

Foreign exchange rates

The Group enters into currency exchange rate transactions to hedge certain currency cash flows and to adjust the currency composition of its assets and liabilities.

In 2014, BG Group entered into foreign exchange hedging instruments that are intended to reduce the Group's exposure to the Australian dollar and the Brazilian real for the period of April through December 2014 related to its capital investment for the year.

The Group has purchased forward Australian dollars covering approximately 50% of the expected sensitivity of the Group's underlying cash flow to the Australian dollar/US dollar exchange rate for the period of April through December 2014. The Group has also put in place costless collars to offset movements in the Brazilian real/US dollar exchange rate outside of cap and floor levels. These positions are expected to cover approximately 60% of the expected sensitivity of the Group's underlying cash flow to the Brazilian real/US dollar exchange rate for the period of April through December 2014.

Currency hedges are accounted for in accordance with IAS 39. To the extent that hedge accounting is achievable, the fair value of the currency instruments will be recorded in other comprehensive income, rather than the income statement, and the final settlement value of the hedges will be recognised as part of the underlying capital investment. Where hedge accounting rules cannot be applied, the mark-to-market value of the hedges will be treated similar to commodity hedges; the unrealised fair value movements will be tracked in the disposals, re-measurements and impairments section with the final settlement of the hedges recognised in Business Performance. It is expected that all of the Brazilian real costless collars and around one fifth of the Australian dollar forwards will achieve cash flow hedge accounting, with the remainder of the Australian dollar forwards being recorded with mark-to-market accounting through the income statement.

Upstream

a) Margins calculated on the basis of E&P operating profit before exploration charge.

Additional operating and financial data is given on page 26.

First quarter

Revenue and other operating income increased 6% to $3 252 million. While total production was 4% lower at 633 kboed, revenues benefited from a significant increase in oil volumes, particularly from Brazil. Production volumes were lower primarily as a result of Egypt (see Business Highlights section on page 4) with both reservoir deterioration and lower entitlement, due to the continuing high level of diversions to the domestic market. In addition, production from the USA was down, reflecting continued low levels of drilling activity and underlying decline. Lower volumes were partly offset by the ramp up of production at new developments, principally in Brazil, the UK and Bolivia.

The Group's 2014 production guidance remains unchanged at 590 - 630 kboed (at reference conditions), although production is now expected to be at the lower end of the range, given the issues in Egypt. Group production will follow a marked seasonal profile in 2014, with substantially lower volumes expected in the second and third quarters as a result of planned maintenance activity at certain key assets. Production is expected to rise in the fourth quarter as maintenance is completed and new developments are expected onstream.

The Group's average realised oil price decreased 1% to $108.95 per barrel, and the liquids price decreased 7% to $88.60 per barrel. The Group's average realised gas price increased 8% to 50.00 cents per therm. International gas price realisations were 9% higher than 2013 at 45.04 cents per therm reflecting a favourable change in the mix of fields, whilst the average realised UK gas price decreased 14% to 50.37 pence per therm reflecting lower spot prices.

E&P operating profit, before exploration, of $1 364 million was 5% lower, as the increase in revenue and other operating income was more than offset by higher operating costs. Unit operating expenditure increased to $14.72 per barrel of oil equivalent (boe), principally as a result of higher royalty and lifting costs from new developments in Brazil, higher royalties in Bolivia and higher lifting costs in the UK which included the impact of increased asset integrity activity.

The unit DD&A charge increased to $11.52 per boe as a result of new developments in the UK, partly offset by a reduced depreciation charge in Egypt and the USA following the recognition of impairments in the fourth quarter of 2013.

The E&P EBITDA unit margin was 15 cents higher at $35.45, reflecting an increase in revenue per boe primarily due to a significant rise in the share of oil in the portfolio and higher realised gas prices, offset by the higher unit operating costs. The E&P EBIT unit margin was 1% lower at $23.93 with the improvement in EBITDA margin being more than offset by the increase in unit DD&A charges.

The exploration charge of $161 million increased 52% as a result of higher well write-offs. Gross exploration expenditure of $285 million included Kenya ($51 million), Australia ($50 million), Brazil ($46 million), Uruguay ($30 million), Egypt ($29 million) and Tanzania ($28 million).

BG Group's share of operating profit from liquefaction activities decreased 11% to $94 million, primarily as a result of lower throughput at Egyptian LNG.

Business development costs of $22 million were incurred as the Group progressed potential integrated LNG projects in western Canada and Tanzania. These costs were more than offset by the reimbursement of previous business development expenditure from a partner.

Capital investment on a cash basis of $2 271 million included investment in Australia ($1 074 million), Brazil ($434 million), the UK ($150 million) and Egypt ($124 million).

LNG Shipping & Marketing

Additional operating and financial data is given on page 26.

First quarter

Revenue and other operating income was 4% lower, as an 18% reduction in delivered volumes was partly offset by favourable pricing and lower losses from the Group's historical LNG hedging programme which completed in the quarter. The new 2014 Brent oil hedges have not impacted the first quarter results.

Total operating profit decreased 7% to $692 million primarily as a result of lower delivered volumes, with no cargoes delivered from Egypt (2013: 10 cargoes). The impact of reduced volumes was partly offset by lower hedging losses and improved margins.

Average cargo margins improved as BG Group continued to benefit from strong global LNG demand and high Asian spot prices.

Business development costs and other costs include expenditure on the Lake Charles liquefaction project.

Presentation of Non-GAAP measures

Legal Notice

Consolidated Income Statement

First Quarter

a) See Presentation of Non-GAAP measures (page 12) for an explanation of results excluding disposals, certain re-measurements and impairments and presentation of

the results of joint ventures and associates.

b) Operating profit/(loss) is before share of results from joint ventures and associates.

c) Comprises earnings from continuing operations of $1 102 million (2013 $1 208 million) and from discontinued operations of $8 million (2013 $(1) million).

d) This measurement is shown by BG Group as it is used as a means of measuring the underlying performance of the business.

The notes on pages 19 to 25 form an integral part of these condensed financial statements.

Consolidated Statement of Comprehensive Income

a) Income tax relating to hedge adjustments is a $22 million charge for the quarter (2013 $170 million credit).

b) Income tax relating to the re-measurement of defined benefit pension obligations is a $7 million credit for the quarter (2013 $12 million credit).

The notes on pages 19 to 25 form an integral part of these condensed financial statements.

Consolidated Balance Sheet

The notes on pages 19 to 25 form an integral part of these condensed financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 19 to 25 form an integral part of these condensed financial statements.

Consolidated Cash Flow Statement

The cash flows above are inclusive of discontinued operations (see note 6, page 23)

a) Includes profit before tax from discontinued operations for the quarter of $9 million (2013 $5 million).

b) Includes profit on disposal of non-current assets and impairments of discontinued operations for the quarter of $nil (2013 $4m loss).

c) Cash and cash equivalents comprise cash and short-term liquid investments that are readily convertible to cash.

d) The balance at 31 March 2014 includes cash and cash equivalents of $6 344 million (31 March 2013 $4 300 million) and cash included within assets held for sale of $nil (31 March 2013 $87 million).

The notes on pages 19 to 25 form an integral part of these condensed financial statements.

Notes

1. Basis of preparation

These results, approved by the Board on 30 April 2014, are the condensed financial statements ('the financial statements') of BG Group plc for the quarter ended 31 March 2014 and are unaudited. The financial statements do not comprise statutory accounts within the meaning of Section 434 of the Companies Act 2006, and should be read in conjunction with the Annual Report and Accounts for the year ended 31 December 2013 which have been prepared in accordance with IFRS as adopted by the EU. The latest statutory accounts delivered to the registrar were for the year ended 31 December 2013 which were audited by Ernst & Young LLP and on which the Auditors' Report was unqualified and did not contain statements under Sections 498(2) or 498(3) of the Companies Act 2006. These financial statements have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the EU and the accounting policies, methods of computation and presentation as set out in the Annual Report and Accounts 2013, except as stated below.

The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amount of revenues, expenses, assets and liabilities at the date of the financial statements. If in the future such estimates and assumptions, which are based on management's best judgement at the date of the financial statements, deviate from the actual circumstances, the original estimates and assumptions will be modified as appropriate in the period in which the circumstances change.

A single amount is presented on the income statement for discontinued operations, comprising the post-tax results of these businesses and the post-tax profit or loss recognised on re-measurement to fair value less costs to sell and on disposal of the businesses.

Presentation of results

The presentation of BG Group's results separately identifies the effect of:

· The re-measurement of certain financial instruments; and

· Profits and losses on the disposal and impairment of non-current assets and businesses and certain other exceptional items.

These items, which are detailed in note 2 to the financial statements (page 20), are excluded from Business Performance in order to provide readers with a clear and consistent presentation of the underlying operating performance of the Group's ongoing businesses.

New accounting standards and interpretations

The IASB issued IFRS 11 'Joint Arrangements' in May 2011. The standard aims to provide a more substance-based reflection of joint arrangements in the financial statements by focusing on the rights and obligations of the arrangement rather than the legal form. The standard has been adopted by the Group for the year ended 31 December 2014 and has not had a material impact on the Group's financial statements.

A number of amendments to accounting standards issued by the IASB are applicable from 1 January 2014. They have not had a material impact on the Group's financial statements for the quarter ended 31 March 2014.

Changes in functional currency

Following a period of sustained growth and increased production performance, the cash flows and economic returns of the Group's Brazil upstream operations are now principally denominated in US dollars. From 1 January 2014, the functional currency of these operations changed from Brazilian real to US dollar in accordance with IAS 21.

2. Disposals, re-measurements and impairments

Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a credit of $79 million for the quarter (2013 $93 million credit), of which a credit of $77 million (2013 $6 million credit) represents non-cash mark-to-market movements on certain gas contracts. Whilst the activity surrounding these contracts involves the physical delivery of gas, the contracts fall within the scope of IAS 39 and meet the definition of a derivative instrument. In addition, re-measurements include a net $2 million credit for the quarter (2013 $87 million credit) representing unrealised mark-to-market movements associated with economic hedges, including a charge of $8 million associated with Brent oil swaps partially hedging the Group's exposure to commodity prices in 2014.

Operating costs

Operating costs includes a $75 million pre-tax charge (post-tax $62 million) relating to exceptional restructuring costs in the UK, Egypt and Australia.

Disposals of non-current assets and impairments

During the first quarter, disposals and impairments resulted in a pre-tax charge to the income statement of $45 million (post-tax $37 million). In the first quarter of 2013, disposals and impairments resulted in a pre and post-tax credit to the income statement of $10 million.

Net finance income

Re-measurements presented in net finance income include mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk, offset by foreign exchange movements on the associated borrowings and certain intercompany balances. In addition, re-measurements include a $13 million credit primarily associated with derivatives partially hedging the Group's Australian dollar foreign exchange exposure in its 2014 capex programme that do not qualify for hedge accounting under IAS 39.

3. Segmental analysis

a) External sales are attributable to segments as follows: Upstream $3 081 million (2013 $2 877 million), LNG Shipping & Marketing $1 896 million (2013 $2 032 million) and Other $2 million (2013 $1 million). Intra-group sales are attributable to segments as follows: Upstream $164 million (2013 $193 million) and LNG Shipping & Marketing$1 million (2013 $9 million).

b) Business Performance Other operating income is attributable to segments as follows: Upstream $7 million (2013 $2 million) and LNG Shipping & Marketing $75 million (2013 $5 million).

4. Net finance costs

a) In 2014, interest payable includes foreign exchange losses of $13 million (2013 interest receivable includes gains of $5 million).

b) Relates to the unwinding of the discount on provisions and amounts in respect of pension obligations which represent the unwinding of discount on the plans' net deficit.

c) Net finance income/(costs) on disposals, re-measurements and impairments for the quarter of $14 million (2013 $(68) million) is included in note 2 (page 20) and principally reflects mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk, partly offset by foreign exchange movements on certain borrowings.

d) Excludes the Group's share of net finance costs from joint ventures and associates for the quarter of $5 million (2013 $7 million).

5. Taxation

Business Performance taxation for the first quarter, including share of taxation from joint ventures and associates, is$801 million (2013 $929 million). The effective tax rate of 41% for the first quarter is based on the best estimate of the weighted average annual income tax rate expected for the full year (first quarter 2013 44%).

6. Discontinued operations

The post-tax profit of the businesses comprising discontinued operations for the quarter, including profits and losses on disposals and impairments, was $8 million (2013 $3 million).

7. Earnings per ordinary share - continuing operations

Basic earnings per share calculations in 2014 are based on the weighted average number of shares in issue of3 406 million for the quarter.

The earnings figure used to calculate diluted earnings per ordinary share is the same as that used to calculate earnings per ordinary share given above, divided by 3 423 million for the quarter, being the weighted average number of ordinary shares in issue during the period as adjusted for dilutive equity instruments.

8. Reconciliation of net borrowings(a) - First Quarter

As at 31 March 2014, BG Group's share of the net borrowings in joint ventures and associates amounted to approximately $0.7 billion, including BG Group shareholder loans of approximately $0.7 billion. These net borrowings are included in BG Group's share of the net assets in joint ventures and associates which are included inBG Group's accounts.

a) Net borrowings are defined on page 29.

Net borrowings comprise:

a) Finance lease receivable of $172 million (2013 $172 million) included within current and non-current trade and other receivables on the balance sheet.

Liquidity and Capital Resources - as at 31 March 2014

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

BGEH had a $4.0 billion US Commercial Paper Programme and a $2.0 billion Euro Commercial Paper Programme, both of which were unutilised. BGEH also had a $15.0 billion Euro Medium Term Note Programme, of which $9.0 billion was unutilised.

BGEH had aggregate undrawn committed revolving bank borrowing facilities of $5.22 billion, of which $2.18 billion expires in 2016 and $3.04 billion expires in 2017. Furthermore BGEH had $1.8 billion of undrawn credit facilities provided by an export credit agency, subject to the execution of agreed documentation.

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

9. Quarterly information: earnings and earnings per share

10. Commitments and contingencies

Details of the Group's commitments and contingent liabilities as at 31 December 2013 can be found in note 22,page 125 of the Annual Report and Accounts 2013. The Group's capital expenditure commitments have decreased by approximately $0.9 billion in the three month period to 31 March 2014, primarily due to progress on the Group's major growth projects. There have been no material changes to the Group's other commitments or contingent liabilities in the period.

11. Related party transactions

The Group provides goods and services to, and receives goods and services from, its joint ventures and associates. In addition, the Group provides financing to some of these parties by way of loans. Details of related party transactions for the year ended 31 December 2013 can be found in note 23, page 127 of the Annual Report and Accounts 2013. There have been no material changes in these relationships in the three month period to 31 March 2014. No related party transactions have taken place in the first three months of the current financial year that have materially affected the financial position or the performance of the Group during that period.

Supplementary information: Operating and financial data

Historical supplementary information is available on the BG Group plc website: www.bg-group.com

Glossary