Half Yearly Report

BG Group plc

2014 SECOND QUARTER & HALF YEAR RESULTS

Second Quarter Key Points

· Business Performance EPS up 22% to 35.5 cents; Total EPS up 64% to 40.1 cents

· Interim dividend increased 10% to 14.38 cents per share (8.47 pence per share)

· E&P production down 10% at 591 kboed; primarily declines in Egypt and the USA

· LNG segment operating profit up 44%; additional cargo deliveries and favourable realised prices

· Excellent flow rates in Brazil; FPSO 2 at plateau; gross production around 300 kboed in July

· QCLNG remains on track; commissioning of the gas turbine generators underway

· CATS infrastructure asset sale for up to $961 million completed in July

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

"We have delivered a good set of results for the second quarter. E&P performance reflects the growing proportion of oil in the portfolio, principally from Brazil, and the deferral of maintenance shutdown activity in the UK to later in the year. LNG performance reflects additional cargo deliveries and favourable realised prices. There is no change to our full year E&P production volume and LNG operating profit guidance, with lower E&P volumes and fewer LNG cargoes expected in the second half of 2014.

"We also continued to deliver important milestones for our key growth projects. In Brazil, new wells were connected with flow rates exceeding expectations. In Australia, commissioning of the gas turbine generators at the QCLNG liquefaction plant has begun and, subject to the current risk of industrial actionon Curtis Island, we remain on track for first LNG by the end of the year."

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 22) and notes 1 to 3 (pages 30 to 33). 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) and for the half year 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 43.

Second quarter

Revenue and other operating income increased 26% to $5 501 million. LNG delivered volumes were 29% higher, with higher realised prices in Asian and South American markets. While E&P production volumes were lower, revenues benefited from a material increase in oil volumes, particularly from Brazil, combined with higher oil and liquids prices.

Total operating profit increased 11% to $1 992 million, reflecting higher revenues, partly offset by higher operating costs in the Upstream segment and lower LNG cargo margins as a result of an increase in spot purchases.

Net finance costs of $10 million included realised foreign exchange hedge gains of $29 million and other foreign exchange gains of $5 million (2013 net finance costs of $26 million included foreign exchange gains of $18 million).

The tax charge for the quarter reflects a reduction in the Group's expected 2014 effective tax rate (including BG Group's share of joint venture and associates' tax) to 40% from previous guidance of 41%, reflecting certain changes in tax positions in a number of jurisdictions.

Group earnings of $1 209 million and EPS of 35.5 cents increased by 23% and 22% respectively as a result of the increase in total operating profit, combined with the decrease in net finance costs and the reduction in the Group's tax charge.

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

Business Review - Group continued

Free cash flow improved by $95 million to $(507) million primarily as a result of a $128 million reduction in capital investment. Net cash flow from operating activities of $2 125 million decreased by $30 million with lower working capital cash inflow as a result of higher LNG cargo receivables, offset by an increase in operating profit and a reduction in cash tax paid. Net debt was 7% lower at $10 377 million and gearing has reduced to 23.0%, following the sale of six LNG ships.

Capital investment on a cash basis of $2 476 million was almost entirely in the Upstream segment ($2 475 million) and concentrated primarily on the Group's key growth projects in Australia and Brazil. Further details are provided in the Second quarter business highlights section (see page 4) and the Supplementary information: Operating and financial data section (see page 40).

Half year

Revenue and other operating income increased 14% to $10 562 million. While E&P production volumes were lower, revenues benefitted from a material increase in oil volumes, particularly from Brazil, combined with lower hedging losses and higher realised prices in the LNG Shipping & Marketing segment.

Total operating profit increased 2% to $4 001 million, reflecting the higher revenues, partly offset by higher operating costs in the Upstream segment and lower LNG cargo margins as a result of an increase in spot purchases.

Net finance costs of $66 million included realised foreign exchange hedge gains of $17 million and other foreign exchange gains of $4 million (2013 net finance costs of $61 million included foreign exchange gains of $23 million).

Group earnings of $2 361 million and EPS of 69.3 cents both increased 9% as a result of the increase in total operating profit and the lower tax charge.

Free cash flow improved by $589 million to $(354) million primarily reflecting a $481 million reduction in capital investment. Net cash flow from operating activities increased by $105 million as a result of a higher working capital cash inflow.

Capital investment on a cash basis of $4 759 million was almost entirely in the Upstream segment ($4 746 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 40).

The Board has approved the payment of an interim dividend of 14.38 cents per share. This is half of the 2013 total dividend, in accordance with the Board's established policy. The interim dividend has been converted to Sterling at the average of the daily spot rates for the three business days prior to the business day before this announcement and will be paid on 12 September 2014 as 8.47 pence per share to shareholders on the register as at 15 August 2014.

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

Second quarter

Total earnings for the second quarter of 2014 were $1 367 million (40.1 cents per share) and included a post-tax gain of $158 million in respect of disposals, re-measurements and impairments, including a gain of $170 million arising from the sale of six LNG vessels. Total earnings in the second quarter of 2013 were $833 million (24.5 cents per share) and included a post-tax loss of $153 million in respect of disposals, re-measurements and impairments.

Half year

Total earnings for the half year of 2014 were $2 469 million (72.5 cents per share) and included a post-tax gain of $108 million in respect of disposals, re-measurements and impairments, including a gain of $170 million arising from the sale of six LNG vessels, partly offset by exceptional restructuring costs of $65 million. Total earnings in the half year of 2013 were $2 041 million (60.0 cents per share) and included a post-tax loss of $128 million in respect of disposals, re-measurements and impairments.

For further information see Presentation of Non-GAAP measures (page 22) and notes 1 to 3 (pages 30 to 33).

Second quarter business highlights

Aruba

In June, BG Group agreed to acquire a 30% interest in an exploration block, offshore Aruba. The block covers14 356 square kilometres with identified prospectivity in water depths between 400 metres and 1 800 metres.A Production Sharing Agreement is in place and a 3D seismic programme will be completed in 2014. The Group's farm-in agreement is subject to approval by the Compania Arubano di Petroleo N.V., the national oil company.

Australia 

The QCLNG project continues to complete key milestones and, while the Group still has important operational activities to deliver, the project is on schedule for first LNG in the fourth quarter of 2014 and within the Phase 1 $20.4 billion budget.

In the Ruby Jo upstream development area, which is a major supply source in the southern area of the Surat Basin for Train 1, all six field compression stations (FCSs), along with the central processing plant (CPP) they supply, are now operational. Work is proceeding in the Bellevue development area, in the central Surat Basin, comprising three FCSs, the CPP and gas gathering lines. Drilling and installation of upstream infrastructure ahead of Train 2 start-up in 2015 advances at Woleebee Creek in the north of the Surat Basin. This includes one CPP, five FCSs and a water treatment plant.

More than 2 150 wells have been drilled as at the end of the second quarter, with around 1 100 wells available for production or de-watering. Flow rates from these wells continue to be in line with expectations.

At the LNG plant on Curtis Island, commissioning of the gas turbine generators (GTGs) began in the second quarter.It is expected that the first GTG will start providing power to the plant shortly. Fuel gas is expected to be introduced to the plant in the third quarter, allowing commissioning of the refrigeration turbines and compressors to start. This is an important step prior to cooling Train 1 and producing first LNG in the fourth quarter.

In June, the original four-year labour agreement expired between Bechtel, the contractor building the liquefaction plants on Curtis Island, and the unions representing the island-wide workforce. Subsequently, all four unions have been granted protected action ballot orders by the Fair Work Commission, which enables them to ballot their members on taking lawful industrial action. Currently one union, the CFMEU, has received early approval from its members and can now take action with three days' notice. Bechtel continues working to reach a new agreement with its workforce.

Brazil

Production from the Group's Santos Basin interests continues to grow with the connection of additional wells and flow rates exceeding expectations. In May, one well at Lula North East achieved 31 thousand barrels of oil per day (kbopd), while two wells at Sapinhoá South achieved 34 kbopd each. Gross production from 10 wells at the three installed floating production, storage and offloading (FPSO) vessels increased to around 300 kboed in July.FPSO 2 on Sapinhoá South is now producing around its capacity of 120 kbopd from only four producing wells, fewer than originally planned.

During the quarter, FPSO 3 (Lula North-East) had its second permanent well connected, the gas export system commissioned and the second buoyancy supported riser (BSR) system fully installed. The third permanent well is also connected and expected to start producing in the third quarter. Around the end of the year, FPSO 3 is expected to be producing close to its capacity of 120 kbopd from only five producing wells, fewer than originally planned.

Work on the next two FPSOs at Sapinhoá North and Iracema South continued, with both vessels around 95% complete at the end of the quarter. At Sapinhoá North, the operator expects the FPSO to move onto location and achieve first oil in the third quarter of 2014. At Iracema South, pre-installation of the mooring lines are underway and the operator expects first oil in the fourth quarter of 2014. FPSO 6 (Iracema North) is also on budget, around 65% complete at the end of the quarter, and due onstream in the fourth quarter of 2015.

Second quarter business highlights continued

Brazil continued

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. In May, a drill-stem test (DST) was undertaken in the south-west flowing at around 5 kboed, while in June, a further appraisal well began drilling in the north-east with results, including a DST, expected in the fourth quarter. In the same month, an extended well test (EWT) began on the Iara-4 appraisal well in the west. Initial average flow rates of around 29 kbopd were in line with expectations, with testing to continue into the coming months. Data from these activities, as well as any additional appraisal work, will help formulate the development plan for the Iara area which will be submitted in 2015, after the DoC.

The installation licence for the shallow water scope of the Cabiúnas gas pipeline has been awarded, following receipt of the deep water licence in the first quarter. Both the shallow and deep water pipe lay vessels needed for the project have been mobilised in Brazil. The operator expects the Cabiúnas pipeline to be installed in 2015 which will connect to their onshore gas processing plant due to be operational later in 2015.

During the quarter, the consortium completed a formation test on the Sagitário discovery well (BM-S-50) revealing good quality carbonate reservoirs. The consortium continues with the activities outlined in the approved Discovery Evaluation Plan.

Egypt

E&P production was 57 kboed, 52% lower than the same period in 2013 and 14% lower than the first quarter of 2014. These reductions reflect 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. The first Phase 9a well is onstream, however the nine well development will only temporarily offset underlying E&P production declines.

One LNG cargo was lifted by BG Group in the second quarter. With declining upstream production and minimal gas supplies to Egyptian LNG, 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 remains at risk.

In the second quarter of 2014, Upstream and LNG activities in Egypt accounted for 10% of BG Group's production and around 6% of earnings from continuing operations. The Group expects the earnings contribution from Egypt to continue to reduce significantly over time.

At the end of the second quarter, the domestic receivables balance increased to $1.5 billion with $1.2 billion overdue. As at 30 June 2014, the book value of BG Group's investment in Egypt including receivables was$2.8 billion, of which $0.2 billion relates to Egyptian LNG.

In June, BG Group signed a non-binding letter of intent with the Leviathan field partners to examine the possibility of supplying gas to the Egyptian LNG facilities. In July, BG Group and its partners submitted a development plan for the Notus high-pressure high-temperature and Harmatten Deep discoveries in accordance with theEl Burg Offshore concession agreement. These are part of a number of options under consideration. However, release of funds for any further development, including West Delta Deep Marine Phase 9b, remains contingent upon a material improvement in the investment climate including a significant reduction in the outstanding receivable position. Discussions with the Egyptian government are ongoing.

Norway

In July, the Petrojarl Knarr FPSO left its South Korean shipyard, beginning its journey to its permanent location in the Norwegian North Sea which is expected to take around three months. 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 on the journey from South Korea and during subsequent mooring and well connection activities in the field. Given seasonal weather conditions in the North Sea, if mooring and well connection activities are not completed as planned, the next installation window is likely to be the second quarter of 2015.

Second quarter business highlights continued

Tanzania

The Group continues with its appraisal activities, which will help formulate development plans for the potential future upstream and LNG project.

In May, the Taachui-1 well in Block 1 discovered gas within the targeted Cretaceous interval. In June, a DST at Taachui flowed at a stabilised rate of 14 mmscfd. Further technical work is ongoing to evaluate the results of the test and the data gathered from the well. Subsequently, the rig has returned to the Mzia-3 well to conduct a DST.

Upon completion of testing at Mzia-3, the rig will move to Block 4 to drill the Kamba-1 well, targeting a Cretaceous prospect, and further appraise existing Tertiary discoveries in this block.

During the quarter, BG Group awarded a pre-FEED engineering contract for developing its reserves in offshore Blocks 1, 3 and 4. Meanwhile, the Group and the participants in offshore Block 2 continue to work with the Tanzanian government on selecting a site for a potential onshore LNG export facility.

Trinidad and Tobago

In June, BG Group farmed in to the Trinidad and Tobago Deepwater Atlantic Area Blocks 5 and 6, taking 35% equity in both blocks.

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 and associated infrastructure for total proceeds up to £562 million (approximately $961 million), with £39 million (approximately $67 million) deferred.

A post-tax profit on disposal of approximately $700 million will be recorded in BG Group's 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.

Outlook

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 estimates the 2014 impact on Kazakhstan production, if oil prices remain at the level experienced year-to-date, to be around 4 kboed.

In order to optimise the Group's UK asset integrity programme, shutdowns have been rephased from the second and third quarters to the fourth quarter of 2014. Group volumes are now expected to be slightly below the second quarter for the remainder of the year, as this downtime will materially offset production from new developments expected onstream.

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 remains unchanged. The strong performance in the first half of 2014 is not expected to continue into the second half, with forecast lower near-term global LNG prices and an adverse change in the Group's supply and sales mix, including lower delivered volumes.

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. The majority of the contribution from QCLNG will be reported in the Upstream segment of the business.

Outlook continued

The Group's 2014 effective tax rate is now expected to be 40%, down from 41% previously, as a result of certain changes in tax positions in a number of jurisdictions. The Group will provide 2015 effective tax rate guidance in February 2015.

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.

In the second quarter, $30 million pre-tax realised losses and $106 million pre-tax unrealised losses 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 July 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 second 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 second quarter, $29 million pre-tax realised gains and $18 million pre-tax unrealised gains were recognised in the income statement, with a further $11 million realised gains capitalised as assets under construction. For the period of July 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) Margins calculated on the basis of E&P operating profit before exploration charge.

Additional operating and financial data is given on page 40. 

Upstream continued

Second quarter

Revenue and other operating income increased 9% to $3 169 million. While E&P production was 10% lower at 591 kboed, revenues benefited from a material increase in oil volumes, particularly from Brazil, and higher oil and liquid prices. The decrease in production reflected reservoir decline and lower entitlement in Egypt, declines in the USA and a higher number of shutdown days in Trinidad and Tobago and Tunisia. These reductions have been partially offset by new developments coming onstream in Brazil, Bolivia and the UK, although the performance from Jasmine has been lower than expected. E&P production volumes have benefitted from the deferral of shutdown activity in the UK to later in the year. As a result, Group volumes are now expected to be slightly below the second quarter for the remainder of the year, as this downtime will materially offset production from new developments expected onstream. Full year production is expected to be at the lower end of the guidance range of 590 - 630 kboed.

The Group's average realised oil price (unhedged) increased 8% to $110.21 per barrel and the liquids price increased 10% to $91.33 per barrel, reflecting movements in market prices. The average realised gas price per produced therm decreased 3% to 45.90 cents. International gas price realisations were 1% higher, but the average UK realised gas price was 30% lower, reflecting lower market prices.

E&P operating profit, before exploration, of $1 296 million was up slightly, reflecting the increase in revenue and other operating income offset by higher costs. Unit operating expenditure increased to $15.42 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, higher lifting costs in the UK as a result of preparation work ahead of planned shutdowns and higher unit lifting costs in Egypt reflecting lower production.

Other E&P unit costs also increased to $6.84 per boe and included the impact of higher shipping costs and the timing of oil liftings in Brazil.

The unit DD&A charge decreased to $11.06 per boe as a result of reserves maturation in Brazil and reduced depreciation charges in Egypt and the USA following the recognition of impairments in the fourth quarter of 2013, partly offset by the higher cost of new developments in the UK.

Unit E&P EBITDA margin was $2.29 per boe higher at $35.16 per boe, with an increase in unit revenue primarily reflecting a material rise in the share of oil in the portfolio, offset by the higher unit operating and other costs. The unit E&P EBIT margin was $2.45 per boe higher at $24.10 per boe, as a result of the improvement in EBITDA margin coupled with the decrease in unit DD&A charges.

The exploration charge of $117 million decreased 12% as a result of lower well write-offs. Gross exploration expenditure of $325 million included Tanzania ($105 million), Trinidad and Tobago ($65 million) and Australia ($63 million).

BG Group's share of operating profit from liquefaction activities decreased 37% to $71 million, primarily as a result of significantly lower throughput at Egyptian LNG, which is expected to continue for the foreseeable future.

Business development costs of $19 million were incurred as the Group progressed potential integrated LNG projects in western Canada and Tanzania.

Capital investment on a cash basis of $2 475 million included investment in Australia ($1 007 million), Brazil ($690 million), the UK ($127 million), Trinidad and Tobago ($121 million) and Norway ($117 million).

Half year

Revenue and other operating income increased 7% to $6 421 million. While E&P production was 7% lower at 612 kboed, revenues benefitted from a material increase in oil volumes, particularly from Brazil. Production volumes were impacted by 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, partially offset by the continued ramp-up of production from new developments in Brazil, Bolivia and the UK.

The Group's average realised oil price (unhedged) increased 3% to $109.64 per barrel and the liquids prices increased 1% to $89.89 per barrel, reflecting movements in market prices. 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 20% reduction in the average realised UK gas price reflecting lower market prices. 

Half year continued

E&P operating profit, before exploration, of $2 660 million was 3% lower, as the increase in revenue and other operating income was more than offset by higher operating costs. Unit operating expenditure increased to $15.06 per boe, principally as a result of higher royalty and lifting costs from new developments in Brazil, higher royalties in Bolivia, higher lifting costs in the UK as a result of asset integrity work and preparation for the shutdowns later in the year, and higher unit lifting costs in Egypt reflecting lower production.

Other E&P unit costs also increased to $5.64 per boe and included the impact of higher shipping costs and the timing of oil liftings in Brazil.

The unit DD&A charge increased to $11.30 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 unit E&P EBITDA margin was $1.23 per boe higher at $35.31 per boe, as a result of an increase in unit revenue primarily reflecting a material rise in the share of oil in the portfolio, partially offset by the higher unit operating and other costs. The unit E&P EBIT margin was $1.08 per boe higher at $24.01 per boe, with the improvement in EBITDA margin partially offset by the increase in unit DD&A charges.

The exploration charge of $278 million increased 16%. Gross exploration expenditure of $610 million included Tanzania ($133 million), Australia ($113 million) and Trinidad and Tobago ($67 million).

BG Group's share of operating profit from liquefaction activities decreased 24% to $165 million, primarily as a result of lower throughput at Egyptian LNG.

Business development costs of $41 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 $4 746 million included investment in Australia ($2 081 million), Brazil ($1 124 million), the UK ($277 million), Norway ($225 million) and Egypt ($205 million).

LNG Shipping & Marketing

Additional operating and financial data is given on page 40.

Second quarter

Revenue and other operating income was 46% higher reflecting a 29% increase in delivered volumes and favourable pricing resulting from higher realised prices in Asian and South American markets. Revenues in 2013 also included losses from the Group's historical LNG hedging programme which completed in the first quarter of 2014.

Total operating profit increased 44% to $749 million as the impact of increased volumes and lowerhedging losses was partly offset by lower average cargo margins following an increase in spot cargo purchases. The Group continues to expect full year LNG Shipping & Marketing total operating profit to be in the range $2.1 - 2.4 billion, with the remainder of the year reflecting forecast lower near-term global LNG prices and an adverse change in the Group's supply and sales mix, combined with lower delivered volumes.

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

Half year

Revenue and other operating income was 19% higher as a result of lower losses from the Group's historical LNG hedging programme which completed in the first quarter of 2014, combined with a 3% increase in delivered volumes and favourable pricing. Overall volumes increased despite fewer cargoes delivered from Egypt from 14 in 2013 to one in 2014.

Total operating profit increased 14% to $1 441 million reflecting the higher revenues, partially offset by lower average cargo margins primarily as a result of an increase in spot cargo purchases.

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

Interim Management Report

This results announcement also represents BG Group's half-yearly financial report for the purposes of the Disclosure and Transparency Rules (DTR) made by the UK Financial Conduct Authority. In order to comply with the requirements of the DTR, this announcement must contain an Interim Management Report which must include (a) an indication of the important events that have occurred during the first six months of the financial year, and their impact on the condensed set of financial statements, and (b) a description of the principal risks and uncertainties for the remaining six months of the financial year. The principal risks and uncertainties for the remaining six months of the financial year are set out on pages 17 to 20. The important events that occurred during the first six months of the year are set out on pages 1 to 13 and should be read in conjunction with the important events that occurred during the first quarter of the year as set out in BG Group's First Quarter Results released on 1 May 2014. The relevant sections of the Group's First Quarter Results are repeated below without amendment. Where necessary, further updates have been provided in the Second quarter business highlights on pages 4 to 6. Together with the Principal Risks and Uncertainties on pages 17 to 20, and information on the Group's related party transactions on page 21, they form BG Group's Interim Management Report for the purposes of the DTR.

Statement of Directors' responsibilities

Legal Notice

Going Concern

Related Parties

Presentation of Non-GAAP measures

Independent review report to BG Group plc

Introduction

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2014, which comprises the Consolidated Income Statement, Consolidated Statement of Comprehensive Income, Consolidated Balance Sheet, Consolidated Statement of Changes in Equity, Consolidated Cash Flow Statement and Notes 1 to 12. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements (ISRE) 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board (ISRE 2410). To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.

Directors' Responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

As disclosed in Note 1, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting", as adopted by the European Union.

Our Responsibility

Our responsibility is to express to the company a conclusion on the condensed set of financial statements in the half yearly financial report based on our review.

Scope of Review

We conducted our review in accordance with ISRE 2410. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2014 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Ernst & Young LLP

London

30 July 2014

Consolidated Income Statement

Second Quarter

a) See Presentation of Non-GAAP measures (page 22) 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 $1 367 million (2013 $833 million) and from discontinued operations of $nil (2013 $261 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 30 to 39 form an integral part of these condensed financial statements.

Consolidated Income Statement

Half Year

a) See Presentation of Non-GAAP measures (page 22) 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 $2 469 million (2013 $2 041 million) and from discontinued operations of $8 million (2013 $260 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 30 to 39 form an integral part of these condensed financial statements.

For information on dividends paid in the period, see note 9 (page 39).

Consolidated Statement of Comprehensive Income

a) Income tax relating to hedge adjustments is a $56 million charge for the quarter (2013 $26 million charge) and a $78 million charge for the half year (2013 $144 million credit).

b) Income tax relating to the re-measurement of defined benefit pension obligations is a $6 million charge for the quarter (2013 $4 million charge) and a $1 million credit for the half year (2013 $8 million credit).

The notes on pages 30 to 39 form an integral part of these condensed financial statements.

Consolidated Balance Sheet

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

The notes on pages 30 to 39 form an integral part of these condensed financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 30 to 39 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 37).

a) Includes profit before tax from discontinued operations for the quarter of $nil (2013 $271 million) and for the half year of $9 million (2013 $276 million).

b) Includes profit on disposal of non-current assets and impairments of discontinued operations for the quarter of $nil (2013 $245 million) and for the half year of $nil (2013 $241 million).

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

d) The balance at 30 June 2014 includes cash and cash equivalents of $4 968 million (31 December 2013 $6 208 million; 30 June 2013 $4 705 million) and cash included within assets held for sale of $nil (31 December 2013 $nil; 30 June 2013 $nil).

The notes on pages 30 to 39 form an integral part of these condensed financial statements.

Notes

1. Basis of preparation

These results, approved by the Board on 30 July 2014, are the condensed financial statements ('the financial statements') of BG Group plc for the quarter ended and the half year ended 30 June 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, the requirements of the Disclosure and Transparency Rules issued by the Financial Conduct Authority 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 31), 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 June 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

Second quarter and half year: Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a charge of $84 million for the quarter (2013 $67 million credit), of which a credit of $23 million (2013 $35 million) represents non-cash mark-to-market movements on certain gas contracts. For the half year, a charge of $5 million in respect of re-measurements is included within revenue and other operating income (2013 $160 million credit), of which a credit of $100 million represents non-cash mark-to-market movements on certain gas contracts (2013 $41 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 $107 million charge for the quarter (2013 $32 million credit) and a net $105 million charge for the half year (2013 $119 million credit) representing unrealised mark-to-market movements associated with economic hedges, including a charge of $106 million in the quarter and $114 million in the half year associated with Brent oil swaps partially hedging the Group's exposure to commodity prices in 2014.

Second quarter and half year: Operating costs

Operating costs in 2014 include $4 million pre-tax charge (post-tax $3 million) in the quarter and $79 million pre-tax charge (post-tax $65 million) in the half year relating to exceptional restructuring costs in the UK, Egypt and Australia.

Second quarter and half year: Disposals of non-current assets

In 2014, the second quarter 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 second quarter 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 $12 million gain) in the second quarter (post-tax $nil, 2013 $12 million gain) and a pre-tax result of $nil (2013 $22 million gain) in the half year (post-tax $nil, 2013 $22 million gain).

Second quarter and half year: Impairments

In 2014, the second quarter and half year included a pre-tax charge of $40 million (post-tax $38 million gain) in respect of the impairment of certain E&P assets. In 2013, the second quarter and the half year included a pre-tax charge of $233 million (post-tax $113 million) in respect of the impairment of certain E&P assets primarily as a result of reserves revisions.

Second quarter and half year: Other

Other disposals in 2014 resulted in a pre-tax gain of $5 million (2013 $4 million) in the second quarter (post-tax $3 million, 2013 $1 million) and a pre-tax charge of $40 million (2013 $4 million gain) in the half year (post-tax $34 million; 2013 $1 million gain).

2. Disposals, re-measurements and impairments continued

Second quarter and half year: Net finance income/(costs)

Re-measurements presented in net finance income includes foreign exchange movements on 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 an $18 million credit in the second quarter and $31 million credit in the half year 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 $3 061 million (2013 $2 686 million), LNG Shipping & Marketing $2 451 million (2013 $1 719 million) and Other $2 million (2013 $1 million). Intra-group sales are attributable to segments as follows: Upstream $115 million (2013 $226 million) andLNG Shipping & Marketing $nil (2013 $6 million).

b) Business Performance Other operating income is attributable to segments as follows: Upstream $(7) million (2013 $4 million), LNG Shipping & Marketing $(6) million (2013 $(48) million) and Other $nil (2013 $(1) million).

3. Segmental analysis continued