2015 THIRD QUARTER & NINE MONTHS RESULTS

Third Quarter Key Points

· E&P production up 26% at 716 kboed; full year guidance increased to 680-700 kboed

· 45 cargoes delivered from QCLNG in the nine months to end September; Train 2 commissioning in progress

· FPSO 6 onstream; Brazil net production reached 175 kboed in October

· Upstream EBITDA down 22% to $1 087 million; lower commodity prices partially offset by higher volumes,increased oil in mix and higher liquefaction contribution

· LNG Shipping & Marketing EBITDA down 65% to $213 million; higher volumes more than offset by lower sales prices

· Business Performance EPS down 63% to 8.2 cents; Total EPS down to (3.0) cents due to non-cash foreign exchange impacts on tax balances

· Unconditional anti-trust approval for Shell offer received from European Commission; two of the five pre-conditions now satisfied

BG Group's Chief Executive, Helge Lund said:

"Our teams delivered another strong operational performance in the third quarter. In our Upstream business, we maintained positive momentum in our growth projects in Australia and Brazil, and we continued to improve reliability and efficiency in our base assets. We are now increasing our full year guidance for production to 680-700 kboed. Our LNG operations had a robust operating performance, despite challenging market conditions, and we have maintained our EBITDA guidance for 2015.

"We are on track to deliver our promised operating and capital cost savings for 2015 and are adding new low cash cost volumes through Australia and Brazil. These actions will help mitigate the impact of lower commodity prices on our financial results.

"We continue to work with Shell on integration planning and to secure the necessary regulatory approvals ahead of the shareholder vote. The transaction remains on track to complete in early 2016."

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 14) and notes 1 to 3 (pages 22 to 25). Unless otherwise stated, the results discussed in this release relate to BG Group's Business Performance.

b) Including share of post-tax results from joint ventures and associates.

Business Review - Group

a) For a definition see the Glossary on page 35.

b) Profit before tax for the quarter excluding joint ventures and associates was $280 million (2014 $1 190 million) giving an effective tax rate of 17.5% (2014 40.4%) and for the nine months was $1 649 million (2014 $4 935 million) giving an effective tax rate of 32.0% (2014 40.3%). 

Third quarter

Revenue and other operating income decreased 9% to $4 147 million, reflecting a significant fall in realised sales prices impacting both the Upstream and LNG Shipping & Marketing segments. The impact of lower prices was partly offset by higher volumes in both segments, with E&P production volumes up 26% and LNG delivered volumes up 76%.

EBITDA decreased 37% to $1 244 million. In the Upstream segment, EBITDA fell 22% to $1 087 million primarily reflecting the lower revenues partly offset by the increased contribution from liquefaction following the start of QCLNG operations. In the LNG Shipping & Marketing segment, EBITDA fell 65% to $213 million as margins reduced primarily as a consequence of lower sales prices. The increased loss in the Other activities segment reflects the intra-group elimination of profit associated with equity LNG cargoes in transit, following the ramp-up of operations at QCLNG.

Business Review - Group continued

Third quarter continued

EBIT decreased by $899 million to $384 million, reflecting the reduced EBITDA and higher DD&A charges primarily as a result of increased E&P production and the start-up of QCLNG.

Net finance costs of $55 million included foreign exchange gains of $48 million (2014 net finance costs of $43 million included realised foreign exchange hedge gains of $24 million and other foreign exchange losses of $29 million). Excluding the impact of foreign exchange, net finance costs increased by $65 million to $103 million, reflecting the reduction in the amount of interest on borrowings that can be capitalised against assets under construction following the start-up of QCLNG.

The tax charge for the quarter reduced to $49 million. This reflects the lower profit before tax and the year-to-date impact of a reduction in the Group's estimated 2015 full year effective tax rate (excluding BG Group's share of joint ventures and associates' results and tax) to 32.0%, from previous guidance of 35%. In the current low commodity price environment, the full year rate remains sensitive to movements in the Group's profits by jurisdiction, but is currently expected to outturn in the range 30-35%. 

Group earnings of $280 million and EPS of 8.2 cents both decreased 63%, with the reduction in EBIT only partially offset by the reduction in the Group's effective tax rate.

Net cash flow from operating activities decreased by $394 million as a result of lower Business Performance EBIT, partly offset by lower tax payments.

Capital investment on a cash basis was 32% lower at $1 532 million and was entirely in the Upstream segment, consisting of $1 358 million on development and other activities, and $174 million on exploration. The development spend was concentrated primarily in Brazil ($687 million) and Australia ($292 million).

Free cash flow improved by $224 million to a $705 million outflow, reflecting a $710 million reduction in capital investment, partly offset by the $394 million decrease in net cash flow from operating activities.

Nine months

Revenue and other operating income decreased 20% to $12 119 million, reflecting a significant fall in realised sales prices impacting both the Upstream and LNG Shipping & Marketing segments. The impact of lower prices was partly offset by weather-related gains in North America in the LNG Shipping & Marketing segment and higher volumes in both segments, with E&P production volumes up 15% and LNG delivered volumes up 48%.

EBITDA decreased 43% to $4 207 million. In the Upstream segment, EBITDA fell 41% to $3 095 million primarily reflecting the lower revenues, partly offset by the increased liquefaction contribution from QCLNG. In the LNG Shipping & Marketing segment, EBITDA fell 44% to $1 184 million as margins reduced through a combination of lower sales prices and a greater proportion of relatively lower margin spot cargoes. The EBITDA loss reported in Other activities increased to $72 million, reflecting the intra-group elimination of profit associated with equity LNG cargoes in transit.

EBIT decreased by $3 256 million to $1 956 million, reflecting the reduction in EBITDA and higher DD&A charges, which resulted from higher E&P production volumes and the start-up of QCLNG.

Net finance costs of $154 million included foreign exchange gains of $27 million (2014 net finance costs of $101 million included realised foreign exchange hedge gains of $41 million and other foreign exchange losses of $25 million). Excluding the impact of foreign exchange, net finance costs increased by $64 million to $181 million primarily reflecting the reduction in the amount of interest on borrowings that can be capitalised.

The tax charge for the nine months reduced to $528 million and reflects the lower profit before tax and the reduction in the Group's estimated 2015 full year effective tax rate (excluding BG Group's share of joint ventures and associates' results and tax) to 32.0% (2014 40.3%).

Group earnings of $1 274 million and EPS of 37.3 cents both decreased 59%, with the reduction in EBIT only partially offset by the reduction in the Group's effective tax rate.

Net cash flow from operating activities decreased by $2 995 million as a result of lower Business Performance EBIT and a working capital cash outflow, offset by lower tax payments.

Capital investment on a cash basis was 34% lower at $4 655 million and was entirely in the Upstream segment, consisting of $4 185 million on development and other activities, and $470 million on exploration. The development spend was concentrated primarily in Brazil ($1 951 million) and Australia ($988 million).

Business Review - Group continued

Nine months continued

Free cash flow worsened by $777 million to a $2 060 million outflow, primarily reflecting the decrease in net cash flow from operating activities, partly offset by the lower capital investment. The total cash inflow for the nine months was$969 million, including $4 597 million gross proceeds from the disposal of the QCLNG pipeline.

Net debt of $9 584 million fell by $1 514 million as a result of the QCLNG pipeline disposal, and gearing remained broadly flat at 24.5%. Return on average capital employed reduced to 4.8%, reflecting the lower Business Performance results.

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

Third quarter

Total earnings for the third quarter of 2015 were a loss of $101 million (loss of 3.0 cents per share) and included a post-tax loss of $381 million in respect of disposals, re-measurements and impairments primarily as a result of a $344 million net charge reflecting the impact of foreign exchange movements on deferred and current tax balances, especially in Brazil and Australia, resulting from the appreciation of the US Dollar. Total earnings in the third quarter of 2014 were $1 510 million (44.3 cents per share) and included a post-tax gain of $751 million in respect of disposals, re-measurements and impairments, of which $771 million was a gain arising from the disposal of the Central Area Transmission System (CATS) gas pipeline in the UK.

Nine months

Total earnings for the nine months of 2015 were $2 357 million (69.1 cents per share) and included a post-tax gain of $1 083 million in respect of disposals, re-measurements and impairments primarily associated with the $1 650 million gain on sale of the QCLNG pipeline, partially offset by a $708 million net charge reflecting the impact of foreign exchange movements on deferred and current tax balances, especially in Brazil and Australia. Total earnings for the nine months of 2014 were $3 979 million (116.8 cents per share) and included a post-tax gain of $859 million in respect of disposals, re-measurements and impairments, of which $771 million was a gain arising from the disposal of the CATS gas pipeline in the UK, and $170 million was a gain arising from the sale of six LNG vessels.

For further information see Presentation of Non-GAAP measures (page 14) and notes 1 to 3 (pages 22 to 25).

Recommended cash and share offer for BG Group plc by Royal Dutch Shell plc

On 8 April, the Boards of Royal Dutch Shell plc (Shell) and BG Group plc announced that they had reached agreement on the terms of a recommended cash and share offer to be made by Shell for the entire issued and to be issued share capital of BG Group plc.

Under the terms of the Combination, which will be subject to certain pre-conditions and conditions, BG Group plc shareholders will be entitled to receive, for each BG Group plc share, 383 pence in cash and 0.4454 Shell B Shares.

Please refer to the Rule 2.7 announcement at www.bg-group.com/shelloffer for further details.

Anti-trust regulatory clearance for the transaction was received from the European Commission in September. Together with the Brazilian Conselho Administrativo de Defesa Econômica (CADE) approval, which was received in July, this means that two of the five pre-conditions in relation to the Combination have been satisfied.

In September, the Australian Competition and Consumer Commission (ACCC) published a Statement of Issues seeking further information and views on the proposed transaction.

The transaction is expected to complete in early 2016.

Third quarter business highlights

Overview

E&P production was 716 thousand barrels of oil equivalent per day (kboed), up 26% from the third quarter of 2014. Growth in the third quarter was driven by Australia, Brazil and Norway. Volumes in Australia almost trebled to 98 kboed and in Brazil, almost doubled to 158 kboed. In Norway, Knarr continued to ramp up, producing 13 kboed in the quarter. This growth was partially offset by the expected decline in Egypt, down 12 kboed to 43 kboed. The Group's performance in the third quarter was ahead of the guidance provided at the second quarter as a result of FPSO 6 coming onstream ahead of schedule and better than expected uptime across the Santos Basin; certain shutdowns rescheduled into the fourth quarter; and better operating efficiency across a number of assets.

The LNG Shipping & Marketing segment delivered 75 cargoes (4.8 million tonnes) in the quarter, 31 more cargoes than the third quarter of 2014 (2.1 million additional tonnes). Increased supply was driven by 25 cargoes from QCLNG and six additional spot cargoes. Of the 75 cargoes (2014 44), 54 were supplied to Asian markets (2014 33). The Group delivered its first ever cargoes to Egypt and Pakistan during the quarter.

Australia

QCLNG Train 1 has been running at plateau. Train 2 commenced operations in July and commissioning is progressing, ahead of the start of commercial operations. In the third quarter, a total of 27 cargoes were produced across both trains, making a total of 52 since the start of 2015. During the third quarter, 25 cargoes were delivered to customers.

E&P production in Australia has continued to ramp-up according to plan, achieving its highest level in a single day of around 118 kboed in October and averaging 98 kboed for the quarter, net to BG Group. During the quarter, less than 20% of the gas supplied to QCLNG was from third-party gas contracts, in line with expectations during the ramp-phase.

The integrated project remains on track to reach plateau production in mid-2016.

Brazil

In October, BG Group achieved record net production from the Santos Basin, reaching 175 kboed. Across the Santos Basin, BG Group has 23 wells in production which are flowing at an average rate of 27 kbopd (gross).

In the quarter, gross production from FPSO 4 (Cidade de Ilhabela) has averaged 86 kbopd with three producer wells and one injector well and FPSO 5 (Cidade de Mangaratiba) has averaged 127 kbopd from four producer and four injector wells. Plateau production from these FPSOs is expected during the fourth quarter.

In July, the 150 kbopd Cidade de Itaguaí (FPSO 6) for Iracema North started up and currently has two producer wells connected, and has been producing at rates of 61 kbopd. Final integration works on FPSO 7 continue in the Brasa shipyard in Brazil, while FPSO 8 is currently en route from China and is expected to arrive at Brasa in the coming weeks for final integration works. Integration works continue on FPSO 9 in Singapore. FPSOs 7 to 9 are all due onstream in 2016.

Third quarter business highlights continued

Brazil continued

For all replicant FPSOs, the consortium continues to closely monitor developments, including any potential impacts of the Lava Jato investigation, establishing and implementing mitigation plans where necessary.

In April 2015, Petrobras issued its final audited 2014 financial statements which included a write-off in respect of overpayments on the acquisition of property, plant and equipment incorrectly capitalised according to testimony obtained as part of the Lava Jato investigations. The impact of this write-off on BG Group's various interests remains unknown.

Egypt

At the end of the third quarter, the amount owed by the Egyptian government was $1.1 billion, with $0.9 billion overdue. Discussions continue with the Egyptian government regarding potential future gas development programmes, subject to the negotiation of a higher domestic gas price and resolution of the outstanding receivables.

Thailand

In the third quarter, first gas was achieved from the first two Greater Bongkot South Phase 4C wellhead platforms. The remaining platform is due onstream in the first quarter of 2016.

Trinidad and Tobago

During the quarter, BG Group has revised downwards its proved and probable reserves in Trinidad and Tobago. This revision follows the start-up of the Starfish field in December 2014 where production has been lower than anticipated with only one development well now on production, and at the Dolphin field where decline rates have been higher than expected.

Canada

In September, BG Group acquired three non-operated positions offshore Newfoundland with equity stakes of 10% in blocks EL1125 and EL1126, and 25% in block EL1123. A first well is expected to be drilled in EL1123 later this year.

USA

In August, the Lake Charles LNG project received its Final Environmental Impact Statement from the Federal Energy Regulatory Commission (FERC), a key regulatory milestone for the three-train, 15 mtpa liquefaction project in Louisiana. FERC authorisation for Lake Charles LNG, the last major regulatory hurdle, is expected in November.

2015 outlook

BG Group has increased its outlook for 2015 E&P production volumes to 680 - 700 kboed, excluding any changes to the portfolio. This reflects the strong operational performance to date and the reduced duration of planned shutdowns in the second half of the year. In the fourth quarter, the Group expects continued growth in Brazil and Australia to be partly offset by a number of planned shutdowns and the continued expected decline in Egypt.

LNG Shipping & Marketing EBITDA guidance remains in the range of $1.3 - 1.5 billion for 2015 based on mid-October forward commodity price curves, with an expected outturn around the middle of the range (see page 31 for further details). Supply volumes are still expected to be slightly lower than 2014, excluding the purchase of spot cargoes and the impact of new volumes from QCLNG. As previously disclosed, the majority of the contribution from QCLNG will be reported in the Upstream segment of the business.

With cash capital expenditure of $4.7 billion in the first nine months of the year, 2015 will be significantly lower than 2014, as projects complete and the Group reacts to a lower oil price environment. Capital expenditure on a cash basis is now expected to be around 30% lower than 2014 at around $6.5 billion.

In the current low commodity price environment, the Group's 2015 full year effective tax rate, excluding BG Group's share of joint ventures and associates' results and tax, remains sensitive to movements in the Group's profits by jurisdiction, but is now expected to outturn in the range 30 - 35%.

The Group's 2015 cost and efficiency programme is progressing well, with the emphasis on lifting, organisation and infrastructure cost savings, and remains on track to deliver at least the $300 million target savings for 2015.

BG Group's sensitivity to a $1 per barrel movement in the oil price is still expected to be between $60 - 70 million at an earnings level and between $70 - 80 million on post-tax operating cash flow, both on an annualised basis for 2015 only.

Upstream

a) Margins calculated on the basis of E&P EBIT or EBITDA before exploration charge, based on E&P production volumes. Additional operating and financial data is given on page 33.

Upstream continued

a) Excludes fuel gas.

Upstream continued

Third quarter

E&P production volumes increased 26% reflecting the ramp-up in Brazil, Australia and Norway, partly offset by lower production in Egypt.

Revenue and other operating income decreased 8% to $2 640 million, reflecting significantly lower commodity prices, partly offset by higher volumes and an improved product mix with additional oil, primarily from Brazil.

E&P EBITDA before exploration was 36% lower at $1 022 million, primarily reflecting the decrease in revenue. Lifting costs increased 20% to $559 million following the ramp-up of production in Brazil and Australia. Operating costs increased 3% to $930 million as the increase in lifting costs was partly offset by a 15% fall in Royalties and other operating costs, reflecting lower commodity prices. Other E&P costs increased 18% to $326 million as a result of higher Brazil oil shipping costs, as well as net foreign exchange losses on certain working capital balances in Brazil as a result of the devaluation of the Brazilian Real.

E&P DD&A increased 20% to $738 million, as the impact of higher production volumes was partly offset by favourable changes in the mix of fields.

The Group's average realised oil price decreased 48% to $54.23 per barrel, the liquids price decreased 47% to $41.94 per barrel, and the gas price per produced therm decreased 34% to 34.33 cents, reflecting reductions in market prices. As a result, unit revenues reduced $18.64 per boe to $34.27 per boe.

Unit operating expenditure decreased to $14.11 per boe (2014 $17.21 per boe), mainly due to a reduction in royalty costs per boe reflecting the lower commodity prices. Lifting costs per boe also decreased slightly as a result of the overall increase in production volumes, combined with changes in the mix of producing fields. Other E&P unit costs decreased to $4.95 per boe (2014 $5.28 per boe). 

Consequently, the Group's unit E&P EBITDA margin was $14.95 per boe lower at $15.51 per boe.

The unit DD&A charge decreased to $11.20 per boe (2014 $11.72 per boe) as a result of changes in the production mix, with lower production from higher rate fields in the UK and increased production from lower rate fields in Brazil and Australia. This was partially offset by an increased rate in Trinidad and Tobago following reserves revisions.

The E&P EBIT margin was $14.43 per boe lower at $4.31 per boe.

The exploration charge of $119 million decreased 49%, due to lower well write-off costs and reduced seismic activities. Gross exploration expenditure was marginally lower at $300 million and included spend in Trinidad and Tobago ($84 million), Canada ($74 million), the UK ($39 million) and Australia ($15 million). 

Liquefaction EBITDA increased $156 million to $184 million, reflecting the first full quarter of commercial operations at QCLNG Train 1 and common facilities following the first commercial cargo delivery date (FCDD), partially offset by a small loss for the first quarter of operations at Train 2 due to lower initial tariffs charged to the E&P businesses prior to FCDD. The positive contribution from QCLNG was partly offset by lower volumes and prices at Atlantic LNG.

Capital investment on a cash basis of $1 532 million consisted of $1 358 million on development and other activities, and $174 million on exploration. The development spend was concentrated primarily on projects in Brazil ($687 million) and Australia ($292 million), together with investments in Tunisia ($60 million), Kazakhstan ($59 million) and the UK ($54 million).

Nine months

Production volumes increased 15% primarily as a result of the ramp-up in Brazil, Australia and Norway, partly offset by lower production in the UK and Egypt.

Revenue and other operating income decreased 23% to $7 209 million, reflecting significantly lower commodity prices, partly offset by higher volumes and an improved product mix with additional oil, particularly from Brazil.

E&P EBITDA before exploration was 42% lower at $3 236 million, reflecting the decrease in revenue and higher lifting costs, partially offset by lower royalties and Other E&P costs. Lifting costs increased 16% to $1 586 million, reflecting the ramp-up of production in Brazil and Australia. Royalty and other operating costs decreased 10% following the lower commodity prices. Other E&P costs decreased 21% to $637 million, including the impacts in Brazil of movements in the volume of oil held in stock, with around 6.5 mmboe of oil in stock at the end of the quarter. Other E&P costs in 2014 also included the elimination of profit associated with the Lula and Iara extended well tests.

Upstream continued

Nine months continued

E&P DD&A increased 2% to $1 907 million, reflecting the higher production volumes, partly offset by favourable changes in the mix of fields and the effect of impairments recorded in 2014.

The Group's average realised oil price decreased 48% to $55.99 per barrel, the liquids price decreased 46% to $46.41 per barrel and the gas price per produced therm decreased 26% to 37.62 cents, reflecting lower market prices. As a result, unit revenues reduced $20.30 per boe to $34.71 per boe.

Unit operating expenditure decreased to $14.28 per boe (2014 $15.74 per boe), as higher lifting costs per boe were more than offset by lower royalties per boe. Lifting costs were adversely impacted by the shut-ins and planned asset integrity programme in the UK in the first quarter, and the ramp-up of production in Brazil and Australia. Lower commodity prices led to a decrease in royalty costs, although this was partly offset by an increased proportion of production from royalty paying fields, principally in Brazil. Other E&P unit costs decreased to $3.40 per boe (2014 $4.92 per boe) due to the impacts in Brazil of the timing of oil liftings and eliminations of profit on oil sales from extended well tests in 2014.

Consequently, the Group's unit E&P EBITDA margin was $17.13 per boe lower at $17.28 per boe.

The unit DD&A charge decreased to $10.18 per boe (2014 $11.44 per boe) as a result of a change in the mix of production, with lower production from higher rate fields in the UK and increased production from lower rate fields in Brazil and Australia.

The E&P EBIT margin was $15.87 per boe lower at $7.10 per boe.

The exploration charge decreased 24% to $391 million primarily as a result of reduced seismic activities. Gross exploration expenditure decreased 20% to $730 million and included spend in Trinidad and Tobago ($195 million), the UK ($104 million), Australia ($102 million) and Canada ($74 million).

Liquefaction EBITDA increased $112 million to $250 million, with the start of production from QCLNG partly offset by Egyptian LNG, with no cargoes lifted in 2015, and lower prices and volumes at Atlantic LNG.

Capital investment on a cash basis of $4 655 million consisted of $4 185 million on development and other activities, and $470 million on exploration. The development spend was concentrated primarily on projects in Brazil ($1 951 million) and Australia ($988 million), together with investments in the UK ($241 million), Kazakhstan ($178 million), Tunisia ($146 million), Trinidad and Tobago ($137 million) and Egypt ($108 million).

LNG Shipping & Marketing

Additional operating and financial data is given on page 33.

LNG Shipping & Marketing continued

Third quarter

Delivered volumes increased 76% with 25 cargoes from QCLNG and six additional spot cargoes. The total number of cargoes from the Group's Atlantic Basin supply contracts remained unchanged.

Revenue and other operating income was up 11%, as the benefit of higher delivered volumes was partially offset by lower LNG sales prices.

LNG Shipping & Marketing EBITDA decreased 65% to $213 million, reflecting lower margins primarily as a result of the fall in sales prices. In addition, the majority of EBITDA associated with new supply from QCLNG is recorded in the Upstream segment.

LNG Shipping & Marketing EBITDA unit margin fell 80% to $45 per tonne.

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

DD&A decreased 19% to $26 million following the sale and leaseback of six LNG vessels in 2014 and two further vessels in the first quarter of 2015.

LNG Shipping & Marketing EBIT decreased to $187 million, as the fall in EBITDA was partially offset by the lower DD&A charges.

LNG Shipping & Marketing continued

Nine months

Delivered volumes increased 48% with 45 cargoes from QCLNG and 18 additional spot cargoes, partially offset by three fewer cargoes from the Group's Atlantic Basin supply contracts.

Revenue and other operating income was down 4% as a result of lower LNG sales prices, partially offset by the higher delivered volumes and weather-related gains in the Group's North American gas marketing business due to particularly cold weather in the first quarter of 2015.

LNG Shipping & Marketing EBITDA decreased 44% to $1 184 million, reflecting lower margins primarily as a result of the fall in sales prices combined with a greater proportion of relatively lower margin spot cargoes. The majority of EBITDA associated with new supply from QCLNG is recorded in the Upstream segment.

LNG Shipping & Marketing EBITDA unit margin fell 62% to $97 per tonne.

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

DD&A decreased 26% to $81 million following the sale and leaseback of six LNG vessels during 2014 and two further vessels in the first quarter of 2015.

LNG Shipping & Marketing EBIT decreased to $1 103 million, as the fall in EBITDA was partially offset by the lower DD&A charges.

Presentation of Non-GAAP measures

Legal Notice

Consolidated Income Statement

Third Quarter

a) See Presentation of Non-GAAP measures (page 14) for an explanation of results excluding disposals, certain re-measurements and impairments.

The notes on pages 22 to 30 form an integral part of these condensed financial statements.

Consolidated Income Statement

Nine Months

a) See Presentation of Non-GAAP measures (page 14) for an explanation of results excluding disposals, certain re-measurements and impairments.

The notes on pages 22 to 30 form an integral part of these condensed financial statements.

For information on dividends paid in the period, see note 7 (page 29).

Consolidated Statement of Comprehensive Income

a) Income tax relating to hedge adjustments is a $110 million credit for the quarter (2014 $121 million credit) and a $104 million credit for the nine months (2014 $43 million credit).

b) Income tax relating to the re-measurement of defined benefit pension obligations is a $16 million charge for the quarter (2014 $1 million credit) and a $9 million charge for the nine months (2014 $2 million credit).

The notes on pages 22 to 30 form an integral part of these condensed financial statements.

Consolidated Balance Sheet

a) The BG Pension Scheme is now in surplus following receipt of proceeds from the disposal of LNG vessels during the first quarter of 2015.

b) Assets and liabilities classified as held for sale at 31 December 2014 includes QCLNG Pipeline Pty in Australia and two LNG ships.

The notes on pages 22 to 30 form an integral part of these condensed financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 22 to 30 form an integral part of these condensed financial statements.

Consolidated Cash Flow Statement

The cash flows above are inclusive of discontinued operations.

a) Includes profit/(loss) before tax from discontinued operations for the quarter of $nil (2014 $nil) and for the nine months of $6 million (2014 $9 million).

The notes on pages 22 to 30 form an integral part of these condensed financial statements.

Notes

1. Basis of preparation

These results, approved by the Board on 29 October 2015, are the condensed financial statements ('the financial statements') of BG Group plc for the quarter ended and the nine months ended 30 September 2015. 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 2014 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 2014 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 2014.

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.

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 23), 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.

2. Disposals, re-measurements and impairments

Third quarter and nine months: Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a credit of $17 million for the quarter (2014 $391 million credit), of which a credit of $21 million (2014 $70 million credit) represents non-cash mark-to-market movements on certain gas contracts. For the nine months, a charge of $101 million in respect of re-measurements is included (2014 $386 million credit), of which a charge of $18 million represents non-cash mark-to-market movements on certain gas contracts (2014 $170 million credit). 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 $4 million charge for the quarter (2014 $216 million credit) and a net $83 million charge for the nine months (2014 $111 million credit) representing unrealised mark-to-market movements associated with economic hedges.

Other operating income in 2014 for the quarter and nine months also includes a $105 million credit in respect of final settlement of a legacy treaty dispute relating to investments formerly held by the Group.

Third quarter and nine months: Operating costs

Operating costs comprise restructuring costs of $4 million pre-tax ($3 million post-tax) for the quarter and $19 million pre-tax (post-tax $15 million) for the nine months. Restructuring costs of $79 million were incurred in 2014 (post-tax $65 million).

Third quarter and nine months: Disposals of non-current assets

The nine months include a pre-tax gain of $2 538 million (post-tax $1 650 million) following the disposal of the QCLNG pipeline, of which a pre-tax gain of $6 million (post-tax $6 million) arose in the third quarter. The first quarter of 2015 included a pre-tax loss of $15 million (post-tax $10 million) in respect of the sale of two LNG vessels.

In 2014, the third quarter included a pre and post-tax gain of $771 million in respect of the disposal of the Central Area Transmission System (CATS) gas pipeline in the UK and a pre and post-tax charge of $22 million as a result of the relinquishment of an exploration licence in Australia. The second quarter of 2014 included a pre-tax gain of $216 million (post-tax $170 million) in respect of the sale of six LNG vessels, which were previously held as finance leases and have subsequently been leased back under operating leases.

Other disposals in 2015 resulted in a pre-tax charge to the income statement of $9 million (2014: $nil) in the quarter (post-tax $6 million, 2014 $nil) and a pre-tax charge of $23 million (2014 $3 million) for the nine months (post-tax $14 million, 2014 $2 million).

2. Disposals, re-measurements and impairments continued

Third quarter and nine months: Impairments

In 2014, the third quarter included a pre-tax charge of $44 million (post-tax $27 million) and the nine months included a pre-tax charge of $84 million (post-tax $11 million gain) following the impairment of certain E&P assets.

Third quarter and nine months: Other

Other disposals in 2015 resulted in a pre-tax charge of $20 million (2014 $2 million) in the third quarter (post-tax $18 million, 2014 $3 million) and a pre-tax charge of $22 million (2014 $42 million) in the nine months(post-tax $24 million, 2014 $37 million).

Third quarter and nine months: Share of post-tax results from joint ventures and associates

In the second quarter of 2015, a pre and post-tax charge of $5 million was recognised, being the Group's share of a write-off of assets under construction in Brazil following the bankruptcy of a contractor. In the first quarter of 2015, a pre and post-tax charge of $40 million was recognised, being the Group's share of an impairment charge recognised by a joint venture entity.

Third quarter and nine months: Net finance income/(costs)

Re-measurements presented in net finance income/(costs) include net foreign exchange movements on the associated borrowings and certain intercompany balances, offset by mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk. In addition, re-measurements include $8 million charge (2014 $34 million charge) in the third quarter and $15 million charge in the nine months (2014 $3 million charge) relating to derivatives partially hedging the Group's Brazilian Real and Australian Dollar foreign exchange exposure that do not qualify for hedge accounting under IAS 39.

Taxation

The third quarter of 2015 included a net taxation charge of $518 million. This comprised a net charge of $344 million related to changes in deferred tax arising from the retranslation of the Group's tax bases, especially in Brazil and Australia, partly offset by a current tax credit in relation to foreign exchange losses on intra-Group lending, both due to the appreciation of the US Dollar, and $174 million relating to disposals, re-measurements and impairments.

The nine months of 2015 included a net taxation charge of $1 255 million. This comprised a charge of $912 million relating to disposals, re-measurements and impairments, primarily associated with the disposal of the QCLNG pipeline; a net charge of $708 million reflecting the impact of foreign exchange movements on deferred and current tax balances; and a $365 million credit relating to the revision of deferred tax balances as at 1 January 2015 due to changes in UK North Sea taxation rates.

3. Segmental analysis