3rd Quarter Results

Third Quarter Highlights

· Appointment of Helge Lund as Chief Executive

· E&P production down 2% at 569 kboed; decline in Egypt, partially offset by higher production in Brazil; no change to 2014 production guidance

· Upstream total operating profit at $746 million, down 36%; increased proportion of higher margin oil, more than offset by lower realised prices and higher costs

· LNG total operating profit at $576 million, down 4%; no change to 2014 LNG guidance

· Business Performance EPS down 29% to 22.3 cents; Total EPS up 22% to 44.3 cents

· Excellent flow rates in Brazil; BG Group net production exceeded 100 kboed in October

· QCLNG remains on track for first LNG in December; commenced mechanical testing of compressors

· $350 million equivalent received from Egyptian government in October; receivables down to $1.2 billion

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

"We have made good progress with our key projects in the quarter and delivered a solid set of results. Earlier this month, we appointed a new Chief Executive, Helge Lund. Helge's track record in building a world class exploration and production portfolio speaks for itself, and we believe we have the best person in the international oil and gas market to lead BG Group in its next phase of growth.

Our developments in Brazil and Australia are progressing well and, in the case of Brazil, beginning to have a material impact on our business. Reaching net production of over 100 kboed from our Brazil assets is a major achievement, and to do it so swiftly after first commercial production in 2010 reflects the quality and the scale of our interests there. In Australia, the Queensland Curtis LNG project is on target to export its first LNG cargo by the end of the year, which will add volumes and flexibility to the company's global LNG portfolio."

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.

Business Review - Group

a) Includes capital investment relating to discontinued operations for the quarter of $nil (2013 $nil) and for the nine months of $nil (2013 $10 million).

b) Reflects net cash flow from operating activities, less net interest paid and capital investment on a cash basis, plus dividends received and loan repayments.

c) For a definition see the Glossary on page 36.

Third quarter

Revenue and other operating income increased 4% to $4 581 million. This reflected a material increase in Brazil oil volumes which was largely offset by lower net production across other fields and lower commodity prices. Revenue in 2013 also included losses from the Group's legacy LNG hedging programme.

Total operating profit decreased 26% to $1 312 million. Brazil contributed strong growth in operating profit and E&P unit margins, with revenue growth outstripping the expected cost increases associated with the ramp up of production. This was more than offset by significant profit reductions in Kazakhstan as a result of revenue declines, and in the UK as a result of the higher cost of new developments and shutdowns. LNG Shipping & Marketing total operating profit was lower mainly due to the higher cost of spot cargo purchases.

Net finance costs of $47 million included realised foreign exchange hedge gains of $24 million and other foreign exchange losses of $29 million (2013 net finance costs of $63 million included foreign exchange losses of $24 million).

Group earnings of $759 million and EPS of 22.3 cents both decreased 29% primarily as a result of the reduction in total operating profit.

The Brent oil hedges entered into in the first quarter of 2014 have not materially impacted the third quarter results. Further details are given in the Risk management for commodity prices and foreign exchange rates section on page 7.

Business Review - Group continued

Third quarter continued

Net cash flow from operating activities of $1 238 million decreased by $113 million as a result of lower business performance operating profit, partly offset by higher working capital cash inflow. Free cash flow improved by $462 million to $(929) million primarily as a result of a $550 million reduction in capital investment. This reduction in capital investment is primarily related to Australia, with both a lower equity percentage and a lower capital run rate as the project approaches first LNG. Capital investment on a cash basis of $2 242 million was entirely in the Upstream segment and concentrated primarily on the Group's key growth projects in Australia and Brazil, together with investments in the UK and Norway. Further details are provided in the Third quarter business highlights section (see page 4) and the Supplementary information: Operating and financial data section (see page 33).

Nine months

Revenue and other operating income increased 11% to $15 143 million. Upstream revenues reflected a material increase in oil volumes from Brazil, partly offset by lower net production across other fields and lower liquids and UK gas prices. LNG revenue benefited from higher realised prices whilst revenue in 2013 included losses from the Group's legacy LNG hedge programme.

Total operating profit decreased 7% to $5 313 million. Brazil contributed strong growth in operating profit and E&P unit margins, with revenue growth outstripping the expected cost increases associated with the ramp up of production.LNG Shipping & Marketing total operating profits were also higher, reflecting favourable selling prices and higher volumes. However, these were more than offset by significant profit reductions in the UK as a result of the higher cost of new developments and shutdowns, and in Kazakhstan as a result of lower revenues.

Net finance costs of $113 million included realised foreign exchange hedge gains of $41 million and other foreign exchange losses of $25 million (2013 net finance costs of $124 million included foreign exchange losses of $1 million).

The tax charge for the nine months reflects the lower total operating profit and a lower expected effective tax rate for 2014 (including BG Group's share of joint ventures and associates' tax) of 40% compared to 42% in the prior year.

Group earnings of $3 120 million and EPS of 91.6 cents both decreased 4%, reflecting the reduction in total operating profit, partly offset by the decrease in net finance costs and the reduction in the Group's tax charge.

Net cash flow from operating activities of $5 723 million decreased marginally by $8 million as the lower business performance operating profit was offset by a higher working capital cash inflow. Free cash flow improved by $1 051 million to $(1 283) million, primarily reflecting a $1 031 million reduction in capital investment. This reduction in capital investment is primarily related to Australia, with both a lower equity percentage and a lower capital run rate as the project approaches first LNG. Capital investment on a cash basis of $7 001 million was almost entirely in the Upstream segment ($6 988 million) and concentrated primarily on the Group's key growth projects in Australia and Brazil. Further details are provided in the Supplementary information: Operating and financial data section(see page 33).

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

Third quarter

Total earnings for 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. Total earnings in the third quarter of 2013 were $1 230 million (36.2 cents per share) and included a post-tax gain of $160 million in respect of disposals, re-measurements and impairments.

Nine months

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. These gains were partly offset by exceptional restructuring costs of $65 million. Total earnings in the nine months of 2013 were $3 271 million (96.2 cents per share) and included a post-tax gain of $32 million in respect of disposals,re-measurements and impairments.

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

Third quarter business highlights

Overview

E&P production was 569 thousand barrels of oil equivalent per day (kboed), down 2% from the third quarter of 2013, as increased production from Brazil (+39 kboed) and the UK (+22 kboed) was more than offset by declines in Egypt (-57 kboed) and Kazakhstan (-13 kboed).

The LNG Shipping & Marketing segment supplied 44 cargoes (2.7 million tonnes) in the quarter, directly in line with the prior year; 33 of these cargoes were supplied to Asian markets (2013 32).

Australia

The QCLNG project, to deliver 8.5 million tonnes per annum (mtpa) of capacity, remains on schedule for first LNG in the fourth quarter of 2014 and within the Phase 1 budget of $20.4 billion.

In the Bellevue upstream development area, all three field compression stations (FCSs), along with the central processing plant (CPP) they supply, are now operational. Bellevue, in addition to Ruby Jo, Windibri and Kenya, completes the key supply infrastructure in the Surat Basin required for Train 1.

Around 2 300 coal seam gas (CSG) wells have been drilled as at the end of the third quarter, with around 1 300 CSG wells available for production or de-watering. Average flow rates continue to be in line with expectations.

In August, a new project labour agreement was signed, which ended the industrial dispute with the labour unions. Following this, at the LNG plant on Curtis Island, the gas turbine generators (GTGs) successfully provided permanent power for the facility and in October, mechanical testing for the compressors commenced. The introduction of hydrocarbons into purification front-end units is planned to occur in November with plant cool down planned for the end of November. There is limited remaining contingency in the schedule, but the Group currently expects the first LNG cargo to leave Curtis Island in December 2014.

As part of the commissioning process, the Group is ramping up gas production at the QCLNG project. In the third quarter, production at 34 kboed was 31% higher than the third quarter of 2013 and is planned to continue to ramp up in line with first LNG in December 2014. The increased production has short term implications for the domestic gas market. BG Group has several arrangements in place to manage ramp gas, which include storage and commercial agreements to supply domestic customers.

Brazil

Production from the Group's Santos Basin interests continues to grow. Average net production for the quarter was 81 kboed (2013 42 kboed), and in October, the Group achieved net stabilised production of more than 100 kboed.

The Cidade de Paraty (FPSO 3) on Lula North East reached its capacity of 120 thousand barrels of oil per day (kbopd) from only four producing wells, fewer than originally planned, as a result of higher than anticipated flow rates. Plateau production was achieved within 16 months from first oil, despite the delays associated with the buoyancy supported riser (BSR) system to hook up wells.

In October, first production from the Iracema development commenced. The first well at the 150 kbopd Cidade de Mangaratiba (FPSO 5) is producing around 10 kbopd during the commissioning of natural gas and reinjection systems, with total productive capacity of around 30 kbopd thereafter. Five producer wells have already been drilled for this FPSO.

The 150 kbopd Cidade de Ilhabela (FPSO 4) at Sapinhoá North has moved into position and is expected to commence production in the fourth quarter of 2014. Seven producer wells have already been drilled for this FPSO.

The 150 kbopd Cidade de Itaguai (FPSO 6) for Iracema North is around 75% complete at the end of the quarter.The operator expects first oil in the fourth quarter of 2015.

In BM-S-11, appraisal activity continues at Iara gathering data to help formulate the Declaration of Commerciality (DoC) which is due by the end of 2014. The extended well test (EWT) on the Iara-4 appraisal well continues with high average flow rates of around 30 kbopd. Testing will continue until December. Results from an Iara appraisal well, currently drilling in the north east of the block, are due in the fourth quarter. Data from these activities will help formulate the development plan for the Iara area which will be submitted in 2015, after the DoC.

Third quarter business highlights continued

Canada

BG Group continues to investigate the best way to advance the Prince Rupert LNG project. However, given current uncertainty about the size and number of North American projects, BG Group is taking a prudent approach to development in Canada by moderating future expenditure.

Egypt

E&P production was 55 kboed, 51% lower than the same period in 2013 and broadly in line with the second quarter of 2014. The reduction reflects deteriorating reservoir performance and the continued high proportion of diversions to the domestic market, where the Group is entitled to a lower share of production. Five of the Phase 9a wells are now onstream, however the nine well development will only temporarily offset underlying E&P production declines.

No LNG cargoes were lifted by BG Group in the third quarter. With declining upstream production and minimal gas supplies to Egyptian LNG, the Group continues to expect very limited cargoes to be lifted from Egyptian LNG for the foreseeable future.

In the third quarter of 2014, activities in Egypt accounted for 10% of BG Group's production and around 3% of earnings from continuing operations. The Group expects the earnings contribution from Egypt to continue to reduce over time.

At the end of the third quarter, the domestic receivables balance was in line with the previous quarter at $1.5 billion, with $1.4 billion overdue. As at 30 September 2014, the book value of BG Group's investment in Egypt including receivables was $3.0 billion, of which $0.2 billion relates to Egyptian LNG. In October, BG Group received a payment equivalent to $350 million from the Egyptian government, reducing the receivables balance to $1.2 billion.

Norway

The Knarr FPSO (63 kbopd gross capacity, BG Group 45% and operator) safely arrived in Norway in September and is due to be transferred to the field shortly. The Group's target for first production in the fourth quarter remains in place, but is subject to the receipt of Norwegian regulatory approvals, along with favourable weather conditions during subsequent mooring and well connection activities in the field. The project cost has increased to $1.2 billion (BG Group net) reflecting the expanded scope of works to accommodate the later development of the Knarr West discovery as well as higher costs in the sub-sea market.

Tanzania

In August, the Group completed a second drill-stem test (DST) on the Mzia discovery in Block 1. The DST included sustained gas production at a maximum flow rate of 101 million standard cubic feet per day (mmscfd). The results provide further support for a hub development to supply a potential onshore LNG project.

In October, the Kamba-1 exploration well in Block 4 resulted in a gas discovery at Kamba and successfully appraised the Fulusi extension of the Pweza reservoir. The Group is now focused on development engineering for the potential upstream and LNG project. The Kamba-1 well is the 11th discovery and the 16th consecutive successful well for BG Group in Tanzania. 

BG Group retains its 60% equity interest in, and is operator of, Blocks 1 and 4. BG Group has informed the government of its intended withdrawal from its 60% equity interest in Block 3 ($74 million exploration charge). The Papa-1 well, drilled in 2012, is the only gas discovery in Block 3. It is now estimated that BG Group's offshore Blocks 1 and 4 hold total gross recoverable resources of around 16 tcf, with further exploration upside.

Trinidad and Tobago

In August, the Ministry of Energy and Energy Affairs (MEEA) announced BG Group had successfully bid for the Trinidad and Tobago Deepwater Atlantic Area Blocks 3 and 7. The Group has 35% equity in both blocks.The award is subject to the finalisation of negotiation of the respective Production Sharing Contracts with the MEEA, which is expected to complete in the fourth quarter of 2014.

UK

The Everest shutdown commenced at the start of October, with the focus on asset integrity and safety critical maintenance. Storm damage to the flotel in early October required the vessel to be taken to shore for repairs.The maintenance is continuing using the personnel available on the platform, with the scope reduced accordingly. Those work items not completed during the coming weeks, will be deferred to a shutdown in 2015.

Third quarter business highlights continued

UK continued

BG Group is delaying a sanction decision on the high-pressure high-temperature Jackdaw project in the central North Sea, whilst the Group studies more economic and lower risk development solutions. These include a tie-back of the field to third-party infrastructure.

USA

BG Group continues to expect Federal Energy Regulatory Commission (FERC) approval for the Lake Charles LNG project in 2015. This 15 mtpa project will be financed and owned by Energy Transfer. However, BG Group will have effective control of the construction, development and operation of the project, together with a 25 year liquefaction capacity contract. If the project is licenced and sanctioned, BG Group expects that the legal entity which will own the Lake Charles liquefaction project will be fully consolidated in the Group's financial statements.

Portfolio Management

In July, BG Group announced the completion of the sale of its 62.78% equity interest in the Central Area Transmission System (CATS) gas pipeline in the UK North Sea. A post-tax profit on disposal of $771 million has been recorded in the third quarter results. In 2013, the CATS asset contributed $93 million to the Group's total operating profit. The sale does not impact BG Group's rights to capacity in CATS.

Board changes

In October, BG Group announced the appointment of Helge Lund as Chief Executive and as an Executive Director with effect from 2 March 2015. Andrew Gould, interim Executive Chairman, will return to the role of non-executive Chairman on the same date. 

Mr Lund will receive a conditional share award as part of his remuneration package on joining BG Group. This award is subject to prior approval at a specially convened general meeting of shareholders to be held on 15 December 2014.Mr Lund is not obliged to join BG Group if the share award is not approved.

Outlook

There is no change to any BG Group guidance for 2014.

2015 guidance will be provided at the Group's fourth quarter and full year results on 3 February 2015.

The Group's 2014 E&P production guidance remains at the lower end of the 590 - 630 kboed range. This reflects the previously disclosed issues in Egypt and the acceleration into 2014 of production sharing contract (PSC) effects in Kazakhstan following higher than reference condition oil prices.

The Group's outlook for 2014 unit operating expenditure and unit DD&A of $15.50 - 16.25 per boe and $12.25 - 13.00 per boe respectively, at reference conditions, remains unchanged.

In the LNG Shipping & Marketing segment, total operating profit guidance of $2.1 - 2.4 billion at reference conditions remains unchanged. The strong performance in the first three quarters of 2014 is not expected to continue into the fourth quarter, with lower delivered volumes and an adverse change in the Group's supply and sales mix.

In 2015, the Group continues to expect fewer cargoes from Equatorial Guinea given the operator's planned gas development programme. With lower contracted supplies from Equatorial Guinea and Egypt there will be fewer portfolio cargoes available for spot sales. However, the Group currently has sufficient flexibility within its LNG portfolio to ensure all customer commitments are met in 2015.

The Group's 2014 effective tax rate is expected to be 40%.

Risk management for commodity prices and foreign exchange rates 

Commodity prices

In the first quarter, BG Group entered into Brent oil swaps at an average price of $106 per barrel for the period of April through December 2014. The Brent oil price is $86 per barrel as at 27 October 2014.

In the third quarter, as a result of the fall in the Brent oil price, $22 million pre-tax realised gains and $213 million pre-tax unrealised gains were recognised. After the effect of UK tax, the forecast remaining positions are expected to hedge more than 70% of the Group's 2014 earnings sensitivity to oil price movements from October through December.

The hedge impact is allocated across both Upstream and LNG Shipping & Marketing segments in accordance with the Group's expected Brent exposures. In the third quarter, approximately 75% of the recorded realised hedge impact was in the Upstream segment, with the balance in the LNG Shipping & Marketing segment.

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 the first quarter, 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.

In the third quarter, $24 million pre-tax realised gains and $34 million pre-tax unrealised losses were recognised in the income statement with a further $8 million realised gains capitalised as assets under construction. For the period of October through December 2014, the Australian dollar forwards are expected to hedge approximately 50% of the forecast remaining sensitivity of the Group's underlying cash flow to the Australian dollar/US dollar exchange rate and the costless collars on the Brazilian real are expected to hedge approximately 60% of the forecast remaining sensitivity to the Brazilian real/US dollar exchange rate outside of the cap and floor levels.

Upstream

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

Additional operating and financial data is given on page 33.

Upstream continued

Third quarter

Production volumes decreased 2% reflecting reservoir decline and lower entitlement in Egypt, lower entitlement in Kazakhstan, shutdowns in the UK, including Buzzard, and declines in the USA. These reductions have been partially offset by the ramp up of projects in Brazil, new developments coming onstream in the UK and Bolivia and the ramp up in Australia as part of the commissioning process for Train 1 at QCLNG.

Revenue and other operating income increased 4% to $2 882 million. The revenue growth was driven mainly by a material increase in Brazil oil volumes. This was largely offset by: lower net production across other fields; lower oil, liquids and UK gas prices; and a lower revenue entitlement, including a prior period adjustment, in Kazakhstan to reflect lower cash distributions under the production sharing contract.

E&P operating profit, before exploration, of $926 million was down 24%. Brazil contributed strong growth in operating profit and unit EBIT and EBITDA margins, with revenue growth outstripping the expected increase in operating and other E&P costs associated with the ramp up of production. This was more than offset by significant reductions in profit in Kazakhstan as a result of the revenue declines and, in the UK, as a result of the increased costs of new developments coming onstream and additional maintenance.

Consequently, the Group's unit E&P EBIT margin was $5.09 per barrel of oil equivalent (boe) lower at $17.69 per boe and the unit EBITDA margin was $4.28 per boe lower at $29.41 per boe.

The Group's average realised oil price (unhedged) decreased 7% to $103.91 per barrel reflecting lower market prices. The liquids price decreased 18% to $79.37 per barrel, reflecting movements in market prices combined with the lower revenue entitlement in Kazakhstan. The average realised gas price per produced therm increased 10% to 50.01 cents, with higher international gas price realisations (up 10%) reflecting favourable changes in the mix of fields, partly offset by lower market prices in the UK.

Unit operating expenditure increased to $17.21 per boe (2013 $13.36 per boe), principally reflecting lower Group volumes combined with: higher royalty costs and special participation fees in Brazil; higher royalties from new developments in Bolivia; and additional maintenance and tariff costs in the UK (the latter following the disposal of the CATS pipeline).

Other E&P unit costs increased to $6.29 per boe (2013 $3.17 per boe) and included the impacts in Brazil of the timing of oil liftings, increased oil shipping activity and elimination of profit associated with the Iara extended well test.

The unit DD&A charge increased to $11.72 per boe (2013 $10.91 per boe) as a result of the higher cost 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, and reserves maturation in Brazil.

The exploration charge of $235 million increased 128% as a result of increased seismic activity in Trinidad and Tobago and Colombia, and well write offs, principally the Block 3 withdrawal in Tanzania ($74 million). Gross exploration expenditure of $303 million included spend in Tanzania ($100 million), Australia ($58 million), Trinidad and Tobago ($54 million), Colombia ($19 million) and the UK ($14 million).

BG Group's share of operating profit from liquefaction activities decreased 11% to $75 million, as a result of significantly lower throughput at Egyptian LNG, which is expected to continue for the foreseeable future, partly offset by higher sales prices at Atlantic LNG Train 1.

Business development costs of $20 million were incurred as the Group progressed potential integrated LNG projects in Tanzania and western Canada.

Capital investment on a cash basis of $2 242 million included investment in Australia ($889 million), Brazil ($592 million), the UK ($121 million), Norway ($119 million) and Egypt ($108 million).

Nine months

Production volumes were 5% lower as a result of reservoir decline and lower entitlement in Egypt, declines in the USA, and a higher number of shutdown days in both Trinidad and Tobago and Tunisia. These declines were partially offset by the continued ramp up of production from new developments in Brazil, Bolivia and the UK.

Revenue and other operating income increased 6% to $9 303 million. This increase was driven mainly by a material increase in Brazil oil volumes, together with higher production from Bolivia and the UK. This was partly offset by: lower net production across other fields; lower revenue entitlement in Kazakhstan; and lower liquids and UK gas prices.

Nine months continued

E&P operating profit before exploration charge at $3 586 million was down 9%. Brazil contributed strong growth in operating profit and unit EBIT and EBITDA margins, with revenue growth outstripping the expected increase in operating and other E&P costs associated with the ramp up of production. This was more than offset by reductions in profit in the UK as a result of the increased costs of new developments coming onstream and additional maintenance, combined with lower revenues in Kazakhstan and Tunisia.

Consequently, the Group's unit E&P EBIT margin was $0.90 per boe lower at $21.98 per boe and the unit E&P EBITDA margin was $0.54 per boe lower at $33.42 per boe.

The Group's average realised oil price (unhedged) was in line with 2013 at $107.75 per barrel. The liquids price decreased 6% to $85.67 per barrel, reflecting movements in market prices coupled with the lower revenue entitlement in Kazakhstan. The Group's average realised gas price per therm increased 5%, as a favourable change in the mix of fields was partly offset by a 16% reduction in the average realised UK gas price reflecting lower market prices.

Unit operating expenditure increased to $15.74 per boe (2013 $11.89 per boe), principally as a result of lower Group volumes combined with: higher royalty costs, special participation fees and lifting costs from new developments in Brazil; higher royalties in Bolivia; and, in the UK, higher lifting costs as a result of additional maintenance and higher tariff costs following the CATS pipeline disposal.

Other E&P unit costs increased to $5.85 per boe (2013 $2.91 per boe) and included the impacts in Brazil of the timing of oil liftings, increased oil shipping activity and eliminations of profit on oil sales from extended well tests.

The unit DD&A charge increased to $11.44 per boe (2013 $11.08 per boe) as a result of the higher cost 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, and reserves maturation in Brazil.

The exploration charge of $513 million increased 50% reflecting higher well write offs and increased seismic activity in Trinidad and Tobago and Colombia. Gross exploration expenditure of $913 million included Tanzania ($233 million), Australia ($171 million), Trinidad and Tobago ($121 million) and the UK ($39 million).

BG Group's share of operating profit from liquefaction activities decreased 21% to $240 million, as a result of significantly lower throughput at Egyptian LNG, partly offset by higher sales prices at Atlantic LNG Train 1.

Business development costs of $11 million were incurred as the Group progressed potential integrated LNG projects in Tanzania and western Canada, and includes the reimbursement of previous business development expenditure from a partner.

Capital investment on a cash basis of $6 988 million included investment in Australia ($2 970 million),Brazil ($1 716 million), the UK ($398 million), Norway ($344 million) and Egypt ($313 million).

LNG Shipping & Marketing

Additional operating and financial data is given on page 33.

Third quarter

Revenue and other operating income was 4% higher, primarily reflecting the hedging losses incurred in 2013 fromthe Group's historical LNG hedging programme, which completed in the first quarter of 2014. Prices in the quarter were in line with those achieved in the third quarter of 2013.

Shipping and marketing operating profit decreased 1% to $622 million with higher costs of supply, primarily reflecting an increase in spot cargo purchases, offsetting the higher revenues.

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

Nine months

Revenue and other operating income was 14% higher as a result of favourable LNG sales prices and higher delivered volumes combined with lower losses from the Group's historical LNG hedging programme, which completed in the first quarter of 2014. Overall volumes increased 2% despite fewer cargoes delivered from Egypt (falling from 19 in 2013 to one in 2014) as a result of the increase in spot cargo purchases.

Shipping and marketing operating profit increased 9% to $2 112 million reflecting the higher revenues, partially offset by higher costs of supply primarily as a result of an increase in spot cargo purchases.

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

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 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 $1 510 million (2013 $1 230 million) and from discontinued operations of $(1) million (2013 $(11) 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 22 to 32 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 and presentationof 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 $3 979 million (2013 $3 271 million) and from discontinued operations of $7 million (2013 $249 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 22 to 32 form an integral part of these condensed financial statements.

For information on dividends paid in the period, see note 9 (page 31).

Consolidated Statement of Comprehensive Income

a) Income tax relating to hedge adjustments is a $121 million credit for the quarter (2013 $180 million charge) and a $43 million credit for the nine months (2013 $36 million charge).

b) Income tax relating to the re-measurement of defined benefit pension obligations is a $1 million credit for the quarter (2013 $4 million charge) and a $2 million credit for the nine months (2013 $4 million credit).

The notes on pages 22 to 32 form an integral part of these condensed financial statements.

Consolidated Balance Sheet

a) As at 30 September 2014, assets classified as held for sale include certain UK North Sea assets.

The notes on pages 22 to 32 form an integral part of these condensed financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 22 to 32 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 29).

a) Includes profit before tax from discontinued operations for the quarter of $nil (2013 $6 million loss) and for the nine months of $9 million (2013 $270 million).

b) Includes profit on disposal of non-current assets and impairments of discontinued operations for the quarter of $nil (2013 $nil) and for the nine months of $nil (2013 $241 million).

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

The notes on pages 22 to 32 form an integral part of these condensed financial statements.

Notes

1. Basis of preparation

These results which are unaudited and approved by the Board on 27 October 2014, are the condensed financial statements ('the financial statements') of BG Group plc for the quarter ended and the nine months ended 30 September 2014. 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 of disposal 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 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.

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 period ended 30 September 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

Third quarter and nine months: Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a credit of $391 million for the quarter (2013 $48 million), of which a credit of $70 million (2013 $28 million) represents non-cash mark-to-market movements on certain gas contracts. For the nine months, a credit of $386 million in respect of re-measurements is included within revenue and other operating income (2013 $208 million), of which a credit of $170 million represents non-cash mark-to-market movements on certain gas contracts (2013 $69 million). 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 $216 million credit for the quarter (2013 $20 million) and a net $111 million credit for the nine months (2013 $139 million) representing unrealised mark-to-market movements associated with economic hedges, including a credit of $213 million in the quarter and $99 million in the nine months associated with Brent oil swaps partially hedging the Group's exposure to commodity prices in 2014. 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 in 2014 include a $79 million pre-tax charge (post-tax $65 million) in the nine months relating to exceptional restructuring costs in the UK, Egypt and Australia.

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

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, and a pre-tax charge of $3 million (post-tax $2 million) as a result of land relinquishments in the USA.

In 2013, the third quarter included a pre-tax profit of $140 million (post-tax $111 million) in respect of the disposal of the Group's remaining 20% equity in the Quintero LNG regasification facility in Chile, partially offset by a pre-tax charge of $10 million (post-tax $8 million) as a result of land relinquishments in the USA. The second quarter of 2013 included a pre-tax charge of $116 million (post-tax $75 million) as a result of land relinquishments in the USA.

Other disposals in 2014 resulted in a pre-tax result to the income statement of $nil (2013 $nil) in the third quarter(post-tax $nil, 2013 $nil) and a pre-tax result of $nil (2013 $22 million gain) in the nine months (post-tax $nil,2013 $22 million gain). 

2. Disposals, re-measurements and impairments continued

Third quarter and nine months: Impairments

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

In 2013, the third quarter and nine months included a pre-tax charge of $75 million (post-tax $40 million) and a pre-tax charge of $303 million (post-tax $148 million) respectively following the impairment of certain E&P assets.

Third quarter and nine months: Other

Other items in 2014 resulted in a pre-tax charge of $2 million (2013 $9 million) in the third quarter (post-tax $3 million, 2013 $3 million) and a pre-tax charge of $42 million (2013 $10 million) in the nine months (post-tax $37 million; 2013 $7 million).

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

Re-measurements presented in net finance costs includes mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk and foreign exchange movements on borrowings and certain intercompany balances. In addition, re-measurements include a charge of $34 million in the third quarter and a charge of $3 million in the nine months 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 $2 792 million (2013 $2 636 million), LNG Shipping & Marketing $1 796 million (2013 $1 789 million) and Other $2 million (2013 $1 million). Intra-group sales are attributable to segments as follows: Upstream $120 million (2013 $144 million) andLNG Shipping & Marketing $2 million (2013 $nil).

b) Business Performance Other operating income is attributable to segments as follows: Upstream $(30) million (2013 $3 million), LNG Shipping & Marketing $21 million (2013 $(33) million) and Other $nil (2013 $1 million).

3. Segmental analysis continued